[Title 40 CFR ]
[Code of Federal Regulations (annual edition) - July 1, 2016 Edition]
[From the U.S. Government Publishing Office]



[[Page i]]

          

          Title 40

Protection of Environment


________________________

Parts 96 to 99

                         Revised as of July 1, 2016

          Containing a codification of documents of general 
          applicability and future effect

          As of July 1, 2016
                    Published by the Office of the Federal Register 
                    National Archives and Records Administration as a 
                    Special Edition of the Federal Register

[[Page ii]]

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[[Page iii]]




                            Table of Contents



                                                                    Page
  Explanation.................................................       v

  Title 40:
          Chapter I--Environmental Protection Agency 
          (Continued)                                                3
  Finding Aids:
      Table of CFR Titles and Chapters........................    1091
      Alphabetical List of Agencies Appearing in the CFR......    1111
      List of CFR Sections Affected...........................    1121

[[Page iv]]





                     ----------------------------

                     Cite this Code: CFR
                     To cite the regulations in 
                       this volume use title, 
                       part and section number. 
                       Thus, 40 CFR 96.1 refers 
                       to title 40, part 96, 
                       section 1.

                     ----------------------------

[[Page v]]



                               EXPLANATION

    The Code of Federal Regulations is a codification of the general and 
permanent rules published in the Federal Register by the Executive 
departments and agencies of the Federal Government. The Code is divided 
into 50 titles which represent broad areas subject to Federal 
regulation. Each title is divided into chapters which usually bear the 
name of the issuing agency. Each chapter is further subdivided into 
parts covering specific regulatory areas.
    Each volume of the Code is revised at least once each calendar year 
and issued on a quarterly basis approximately as follows:

Title 1 through Title 16.................................as of January 1
Title 17 through Title 27..................................as of April 1
Title 28 through Title 41...................................as of July 1
Title 42 through Title 50................................as of October 1

    The appropriate revision date is printed on the cover of each 
volume.

LEGAL STATUS

    The contents of the Federal Register are required to be judicially 
noticed (44 U.S.C. 1507). The Code of Federal Regulations is prima facie 
evidence of the text of the original documents (44 U.S.C. 1510).

HOW TO USE THE CODE OF FEDERAL REGULATIONS

    The Code of Federal Regulations is kept up to date by the individual 
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    To determine whether a Code volume has been amended since its 
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OMB CONTROL NUMBERS

    The Paperwork Reduction Act of 1980 (Pub. L. 96-511) requires 
Federal agencies to display an OMB control number with their information 
collection request.

[[Page vi]]

Many agencies have begun publishing numerous OMB control numbers as 
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PAST PROVISIONS OF THE CODE

    Provisions of the Code that are no longer in force and effect as of 
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[[Page vii]]

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    Oliver A. Potts,
    Director,
    Office of the Federal Register.
    July 1, 2016.







[[Page ix]]



                               THIS TITLE

    Title 40--Protection of Environment is composed of thirty-seven 
volumes. The parts in these volumes are arranged in the following order: 
Parts 1-49, parts 50-51, part 52 (52.01-52.1018), part 52 (52.1019-
52.2019), part 52 (52.2020-end of part 52), parts 53-59, part 60 (60.1-
60.499) , part 60 (60.500-end of part 60, sections), part 60 
(Appendices), parts 61-62, part 63 (63.1-63.599), part 63 (63.600-
63.1199), part 63 (63.1200-63.1439), part 63 (63.1440-63.6175), part 63 
(63.6580-63.8830), part 63 (63.8980-end of part 63), parts 64-71, parts 
72-79, part 80, part 81, parts 82-86, parts 87-95, parts 96-99, parts 
100-135, parts 136-149, parts 150-189, parts 190-259, parts 260-265, 
parts 266-299, parts 300-399, parts 400-424, parts 425-699, parts 700-
722, parts 723-789, parts 790-999, parts 1000-1059, and part 1060 to 
end. The contents of these volumes represent all current regulations 
codified under this title of the CFR as of July 1, 2016.

    Chapter I--Environmental Protection Agency appears in all thirty-
seven volumes. Regulations issued by the Council on Environmental 
Quality, including an Index to Parts 1500 through 1508, appear in the 
volume containing parts 1060 to end. The OMB control numbers for title 
40 appear in Sec.  9.1 of this chapter.

    For this volume, Susannah C. Hurley was Chief Editor. The Code of 
Federal Regulations publication program is under the direction of John 
Hyrum Martinez, assisted by Stephen J. Frattini.

[[Page 1]]



                   TITLE 40--PROTECTION OF ENVIRONMENT




                   (This book contains parts 96 to 99)

  --------------------------------------------------------------------
                                                                    Part

chapter i--Environmental Protection Agency (Continued)......          96

[[Page 3]]



         CHAPTER I--ENVIRONMENTAL PROTECTION AGENCY (CONTINUED)




  --------------------------------------------------------------------


  Editorial Note: Nomenclature changes to chapter I appear at 65 FR 
47324, 47325, Aug. 2, 2000; 66 FR 34375, 34376, June 28, 2001; and 69 FR 
18803, Apr. 9, 2004.

                 SUBCHAPTER C--AIR PROGRAMS (CONTINUED)
Part                                                                Page
96              NOX Budget Trading Program and 
                    Cair NOX and SO2 
                    Trading Programs for State 
                    implementation plans....................           5
97              Federal NOX Budget Trading 
                    Program and CAIR NOX and 
                    SO2 Trading Programs.........         170
98              Mandatory greenhouse gas reporting..........         542
99              [Reserved]

[[Page 5]]



                  SUBCHAPTER C_AIR PROGRAMS (CONTINUED)





PART 96_NOX BUDGET TRADING PROGRAM AND CAIR NOX AND SO2 TRADING 
PROGRAMS FOR STATE IMPLEMENTATION PLANS--Table of Contents



         Subpart A_NOX Budget Trading Program General Provisions

Sec.
96.1 Purpose.
96.2 Definitions.
96.3 Measurements, abbreviations, and acronyms.
96.4 Applicability.
96.5 Retired unit exemption.
96.6 Standard requirements.
96.7 Computation of time.

   Subpart B_Authorized Account Representative for NOX Budget Sources

96.10 Authorization and responsibilities of the NOX 
          authorized account representative.
96.11 Alternate NOX authorized account representative.
96.12 Changing the NOX authorized account representative and 
          the alternate NOX authorized account 
          representative; changes in the owners and operators.
96.13 Account certificate of representation.
96.14 Objections concerning the NOX authorized account 
          representative.

                            Subpart C_Permits

96.20 General NOX Budget trading program permit requirements.
96.21 Submission of NOX Budget permit applications.
96.22 Information requirements for NOX Budget permit 
          applications.
96.23 NOX Budget permit contents.
96.24 Effective date of initial NOX Budget permit.
96.25 NOX Budget permit revisions.

                   Subpart D_Compliance Certification

96.30 Compliance certification report.
96.31 Permitting authority's and Administrator's action on compliance 
          certifications.

                   Subpart E_NOX Allowance Allocations

96.40 State trading program budget.
96.41 Timing requirements for NOX allowance allocations.
96.42 NOX allowance allocations.

                 Subpart F_NOX Allowance Tracking System

96.50 NOX Allowance Tracking System accounts.
96.51 Establishment of accounts.
96.52 NOX Allowance Tracking System responsibilities of 
          NOX authorized account representative.
96.53 Recordation of NOX allowance allocations.
96.54 Compliance.
96.55 Banking.
96.56 Account error.
96.57 Closing of general accounts.

                    Subpart G_NOX Allowance Transfers

96.60 Submission of NOX allowance transfers.
96.61 EPA recordation.
96.62 Notification.

                   Subpart H_Monitoring and Reporting

96.70 General requirements.
96.71 Initial certification and recertification procedures.
96.72 Out of control periods.
96.73 Notifications.
96.74 Recordkeeping and reporting.
96.75 Petitions.
96.76 Additional requirements to provide heat input data for allocations 
          purposes.

                    Subpart I_Individual Unit Opt-ins

96.80 Applicability.
96.81 General.
96.82 NOX authorized account representative.
96.83 Applying for NOX Budget opt-in permit.
96.84 Opt-in process.
96.85 NOX Budget opt-in permit contents.
96.86 Withdrawal from NOX Budget Trading Program.
96.87 Change in regulatory status.
96.88 NOX allowance allocations to opt-in units.

Subpart J--Mobile and Area Sources [Reserved]

Subparts K-Z [Reserved]

      Subpart AA_CAIR NOX Annual Trading Program General Provisions

96.101 Purpose.
96.102 Definitions.
96.103 Measurements, abbreviations, and acronyms.
96.104 Applicability.

[[Page 6]]

96.105 Retired unit exemption.
96.106 Standard requirements.
96.107 Computation of time.
96.108 Appeal procedures.

     Subpart BB_CAIR Designated Representative for CAIR NOX Sources

96.110 Authorization and responsibilities of CAIR designated 
          representative.
96.111 Alternate CAIR designated representative.
96.112 Changing CAIR designated representative and alternate CAIR 
          designated representative; changes in owners and operators.
96.113 Certificate of representation.
96.114 Objections concerning CAIR designated representative.
96.115 Delegation by CAIR designated representative and alternate CAIR 
          designated representative.

                           Subpart CC_Permits

96.120 General CAIR NOX Annual Trading Program permit 
          requirements.
96.121 Submission of CAIR permit applications.
96.122 Information requirements for CAIR permit applications.
96.123 CAIR permit contents and term.
96.124 CAIR permit revisions.

Subpart DD [Reserved]

                Subpart EE_CAIR NOX Allowance Allocations

96.140 State trading budgets.
96.141 Timing requirements for CAIR NOX allowance 
          allocations.
96.142 CAIR NOX allowance allocations.
96.143 Compliance supplement pool.

              Subpart FF_CAIR NOX Allowance Tracking System

96.150 [Reserved]
96.151 Establishment of accounts.
96.152 Responsibilities of CAIR authorized account representative.
96.153 Recordation of CAIR NOX allowance allocations.
96.154 Compliance with CAIR NOX emissions limitation.
96.155 Banking.
96.156 Account error.
96.157 Closing of general accounts.

                 Subpart GG_CAIR NOX Allowance Transfers

96.160 Submission of CAIR NOX allowance transfers.
96.161 EPA recordation.
96.162 Notification.

                   Subpart HH_Monitoring and Reporting

96.170 General requirements.
96.171 Initial certification and recertification procedures.
96.172 Out of control periods.
96.173 Notifications.
96.174 Recordkeeping and reporting.
96.175 Petitions.

                    Subpart II_CAIR NOX Opt-in Units

96.180 Applicability.
96.181 General.
96.182 CAIR designated representative.
96.183 Applying for CAIR opt-in permit.
96.184 Opt-in process.
96.185 CAIR opt-in permit contents.
96.186 Withdrawal from CAIR NOX Annual Trading Program.
96.187 Change in regulatory status.
96.188 CAIR NOX allowance allocations to CAIR NOX 
          opt-in units.

Subparts JJ-ZZ [Reserved]

        Subpart AAA_CAIR SO2; Trading Program General Provisions

96.201 Purpose.
96.202 Definitions.
96.203 Measurements, abbreviations, and acronyms.
96.204 Applicability.
96.205 Retired unit exemption.
96.206 Standard requirements.
96.207 Computation of time.
96.208 Appeal procedures.

     Subpart BBB_CAIR Designated Representative for CAIR SO2 Sources

96.210 Authorization and responsibilities of CAIR designated 
          representative.
96.211 Alternate CAIR designated representative.
96.212 Changing CAIR designated representative and alternate CAIR 
          designated representative; changes in owners and operators.
96.213 Certificate of representation.
96.214 Objections concerning CAIR designated representative.
96.215 Delegation by CAIR designated representative and alternate CAIR 
          designated representative.

                           Subpart CCC_Permits

96.220 General CAIR SO2 Trading Program permit requirements.
96.221 Submission of CAIR permit applications.
96.222 Information requirements for CAIR permit applications.
96.223 CAIR permit contents and term.
96.224 CAIR permit revisions.

[[Page 7]]

Subparts DDD-EEE [Reserved]

             Subpart FFF_CAIR SO2 Allowance Tracking System

96.250 [Reserved]
96.251 Establishment of accounts.
96.252 Responsibilities of CAIR authorized account representative.
96.253 Recordation of CAIR SO2 allowances.
96.254 Compliance with CAIR SO2 emissions limitation.
96.255 Banking.
96.256 Account error.
96.257 Closing of general accounts.

                Subpart GGG_CAIR SO2 Allowance Transfers

96.260 Submission of CAIR SO2 allowance transfers.
96.261 EPA recordation.
96.262 Notification.

                  Subpart HHH_Monitoring and Reporting

96.270 General requirements.
96.271 Initial certification and recertification procedures.
96.272 Out of control periods.
96.273 Notifications.
96.274 Recordkeeping and reporting.
96.275 Petitions.

                    Subpart III_CAIR SO2 Opt-in Units

96.280 Applicability.
96.281 General.
96.282 CAIR designated representative.
96.283 Applying for CAIR opt-in permit.
96.284 Opt-in process.
96.285 CAIR opt-in permit contents.
96.286 Withdrawal from CAIR SO2 Trading Program.
96.287 Change in regulatory status.
96.288 CAIR SO2 allowance allocations to CAIR SO2 
          opt-in units.

Subparts JJJ-ZZZ [Reserved]

  Subpart AAAA_CAIR NOXOzone Season Trading Program General Provisions

96.301 Purpose.
96.302 Definitions.
96.303 Measurements, abbreviations, and acronyms.
96.304 Applicability.
96.305 Retired unit exemption.
96.306 Standard requirements.
96.307 Computation of time.
96.308 Appeal procedures.

 Subpart BBBB_CAIR Designated Representative for CAIR NOX Ozone Season 
                                 Sources

96.310 Authorization and responsibilities of CAIR designated 
          representative.
96.311 Alternate CAIR designated representative.
96.312 Changing CAIR designated representative and alternate CAIR 
          designated representative; changes in owners and operators.
96.313 Certificate of representation.
96.314 Objections concerning CAIR designated representative.
96.315 Delegation by CAIR designated representative and alternate CAIR 
          designated representative.

                          Subpart CCCC_Permits

96.320 General CAIR NOX Ozone Season Trading Program permit 
          requirements.
96.321 Submission of CAIR permit applications.
96.322 Information requirements for CAIR permit applications.
96.323 CAIR permit contents and term.
96.324 CAIR permit revisions.

Subpart DDDD [Reserved]

        Subpart EEEE_CAIR NOX Ozone Season Allowance Allocations

96.340 State trading budgets.
96.341 Timing requirements for CAIR NOX Ozone Season 
          allowance allocations.
96.342 CAIR NOX Ozone Season allowance allocations.

      Subpart FFFF_CAIR NOX Ozone Season Allowance Tracking System

96.350 [Reserved]
96.351 Establishment of accounts.
96.352 Responsibilities of CAIR authorized account representative.
96.353 Recordation of CAIR NOX Ozone Season allowance 
          allocations.
96.354 Compliance with CAIR NOX emissions limitation.
96.355 Banking.
96.356 Account error.
96.357 Closing of general accounts.

         Subpart GGGG_CAIR NOX Ozone Season Allowance Transfers

96.360 Submission of CAIR NOX Ozone Season allowance 
          transfers.
96.361 EPA recordation.
96.362 Notification.

[[Page 8]]

                  Subpart HHHH_Monitoring and Reporting

96.370 General requirements.
96.371 Initial certification and recertification procedures.
96.372 Out of control periods.
96.373 Notifications.
96.374 Recordkeeping and reporting.
96.375 Petitions.

             Subpart IIII_CAIR NOX Ozone Season Opt-in Units

96.380 Applicability.
96.381 General.
96.382 CAIR designated representative.
96.383 Applying for CAIR opt-in permit.
96.384 Opt-in process.
96.385 CAIR opt-in permit contents.
96.386 Withdrawal from CAIR NOX Ozone Season Trading Program.
96.387 Change in regulatory status.
96.388 CAIR NOX Ozone Season allowance allocations to CAIR 
          NOX Ozone Season opt-in units.

    Authority: 42 U.S.C. 7401, 7403, 7410, 7601, and 7651, et seq.

    Source: 63 FR 57514, Oct. 27, 1998, unless otherwise noted.



         Subpart A_NOX Budget Trading Program General Provisions



Sec. 96.1  Purpose.

    This part establishes general provisions and the applicability, 
permitting, allowance, excess emissions, monitoring, and opt-in 
provisions for the NOX Budget Trading Program for State 
implementation plans as a means of mitigating the interstate transport 
of ozone and nitrogen oxides, an ozone precursor. The owner or operator 
of a unit, or any other person, shall comply with requirements of this 
part as a matter of federal law only to the extent a State that has 
jurisdiction over the unit incorporates by reference provisions of this 
part, or otherwise adopts such requirements of this part, and requires 
compliance, the State submits to the Administrator a State 
implementation plan including such adoption and such compliance 
requirement, and the Administrator approves the portion of the State 
implementation plan including such adoption and such compliance 
requirement. To the extent a State adopts requirements of this part, 
including at a minimum the requirements of subpart A (except for Sec. 
96.4(b)), subparts B through D, subpart F (except for Sec. 96.55(c)), 
and subparts G and H of this part, the State authorizes the 
Administrator to assist the State in implementing the NOX 
Budget Trading Program by carrying out the functions set forth for the 
Administrator in such requirements.



Sec. 96.2  Definitions.

    The terms used in this part shall have the meanings set forth in 
this section as follows:
    Account certificate of representation means the completed and signed 
submission required by subpart B of this part for certifying the 
designation of a NOX authorized account representative for a 
NOX Budget source or a group of identified NOX 
Budget sources who is authorized to represent the owners and operators 
of such source or sources and of the NOX Budget units at such 
source or sources with regard to matters under the NOX Budget 
Trading Program.
    Account number means the identification number given by the 
Administrator to each NOX Allowance Tracking System account.
    Acid Rain emissions limitation means, as defined in Sec. 72.2 of 
this chapter, a limitation on emissions of sulfur dioxide or nitrogen 
oxides under the Acid Rain Program under title IV of the CAA.
    Administrator means the Administrator of the United States 
Environmental Protection Agency or the Administrator's duly authorized 
representative.
    Allocate or allocation means the determination by the permitting 
authority or the Administrator of the number of NOX 
allowances to be initially credited to a NOX Budget unit or 
an allocation set-aside.
    Automated data acquisition and handling system or DAHS means that 
component of the CEMS, or other emissions monitoring system approved for 
use under subpart H of this part, designed to interpret and convert 
individual output signals from pollutant concentration monitors, flow 
monitors, diluent gas monitors, and other component parts of the 
monitoring system to produce a continuous record of the

[[Page 9]]

measured parameters in the measurement units required by subpart H of 
this part.
    Boiler means an enclosed fossil or other fuel-fired combustion 
device used to produce heat and to transfer heat to recirculating water, 
steam, or other medium.
    CAA means the CAA, 42 U.S.C. 7401, et seq., as amended by Pub. L. 
No. 101-549 (November 15, 1990).
    Combined cycle system means a system comprised of one or more 
combustion turbines, heat recovery steam generators, and steam turbines 
configured to improve overall efficiency of electricity generation or 
steam production.
    Combustion turbine means an enclosed fossil or other fuel-fired 
device that is comprised of a compressor, a combustor, and a turbine, 
and in which the flue gas resulting from the combustion of fuel in the 
combustor passes through the turbine, rotating the turbine.
    Commence commercial operation means, with regard to a unit that 
serves a generator, to have begun to produce steam, gas, or other heated 
medium used to generate electricity for sale or use, including test 
generation. Except as provided in Sec. 96.5, for a unit that is a 
NOX Budget unit under Sec. 96.4 on the date the unit 
commences commercial operation, such date shall remain the unit's date 
of commencement of commercial operation even if the unit is subsequently 
modified, reconstructed, or repowered. Except as provided in Sec. 96.5 
or subpart I of this part, for a unit that is not a NOX 
Budget unit under Sec. 96.4 on the date the unit commences commercial 
operation, the date the unit becomes a NOX Budget unit under 
Sec. 96.4 shall be the unit's date of commencement of commercial 
operation.
    Commence operation means to have begun any mechanical, chemical, or 
electronic process, including, with regard to a unit, start-up of a 
unit's combustion chamber. Except as provided in Sec. 96.5, for a unit 
that is a NOX Budget unit under Sec. 96.4 on the date of 
commencement of operation, such date shall remain the unit's date of 
commencement of operation even if the unit is subsequently modified, 
reconstructed, or repowered. Except as provided in Sec. 96.5 or subpart 
I of this part, for a unit that is not a NOX Budget unit 
under Sec. 96.4 on the date of commencement of operation, the date the 
unit becomes a NOX Budget unit under Sec. 96.4 shall be the 
unit's date of commencement of operation.
    Common stack means a single flue through which emissions from two or 
more units are exhausted.
    Compliance account means a NOX Allowance Tracking System 
account, established by the Administrator for a NOX Budget 
unit under subpart F of this part, in which the NOX allowance 
allocations for the unit are initially recorded and in which are held 
NOX allowances available for use by the unit for a control 
period for the purpose of meeting the unit's NOX Budget 
emissions limitation.
    Compliance certification means a submission to the permitting 
authority or the Administrator, as appropriate, that is required under 
subpart D of this part to report a NOX Budget source's or a 
NOX Budget unit's compliance or noncompliance with this part 
and that is signed by the NOX authorized account 
representative in accordance with subpart B of this part.
    Continuous emission monitoring system or CEMS means the equipment 
required under subpart H of this part to sample, analyze, measure, and 
provide, by readings taken at least once every 15 minutes of the 
measured parameters, a permanent record of nitrogen oxides emissions, 
expressed in tons per hour for nitrogen oxides. The following systems 
are component parts included, consistent with part 75 of this chapter, 
in a continuous emission monitoring system:
    (1) Flow monitor;
    (2) Nitrogen oxides pollutant concentration monitors;
    (3) Diluent gas monitor (oxygen or carbon dioxide) when such 
monitoring is required by subpart H of this part;
    (4) A continuous moisture monitor when such monitoring is required 
by subpart H of this part; and
    (5) An automated data acquisition and handling system.
    Control period means the period beginning May 1 of a year and ending 
on September 30 of the same year, inclusive.
    Emissions means air pollutants exhausted from a unit or source into 
the

[[Page 10]]

atmosphere, as measured, recorded, and reported to the Administrator by 
the NOX authorized account representative and as determined 
by the Administrator in accordance with subpart H of this part.
    Energy Information Administration means the Energy Information 
Administration of the United States Department of Energy.
    Excess emissions means any tonnage of nitrogen oxides emitted by a 
NOX Budget unit during a control period that exceeds the 
NOX Budget emissions limitation for the unit.
    Fossil fuel means natural gas, petroleum, coal, or any form of 
solid, liquid, or gaseous fuel derived from such material.
    Fossil fuel-fired means, with regard to a unit:
    (1) The combustion of fossil fuel, alone or in combination with any 
other fuel, where fossil fuel actually combusted comprises more than 50 
percent of the annual heat input on a Btu basis during any year starting 
in 1995 or, if a unit had no heat input starting in 1995, during the 
last year of operation of the unit prior to 1995; or
    (2) The combustion of fossil fuel, alone or in combination with any 
other fuel, where fossil fuel is projected to comprise more than 50 
percent of the annual heat input on a Btu basis during any year; 
provided that the unit shall be ``fossil fuel-fired'' as of the date, 
during such year, on which the unit begins combusting fossil fuel.
    General account means a NOX Allowance Tracking System 
account, established under subpart F of this part, that is not a 
compliance account or an overdraft account.
    Generator means a device that produces electricity.
    Heat input means the product (in mmBtu/time) of the gross calorific 
value of the fuel (in Btu/lb) and the fuel feed rate into a combustion 
device (in mass of fuel/time), as measured, recorded, and reported to 
the Administrator by the NOX authorized account 
representative and as determined by the Administrator in accordance with 
subpart H of this part, and does not include the heat derived from 
preheated combustion air, recirculated flue gases, or exhaust from other 
sources.
    Life-of-the-unit, firm power contractual arrangement means a unit 
participation power sales agreement under which a utility or industrial 
customer reserves, or is entitled to receive, a specified amount or 
percentage of nameplate capacity and associated energy from any 
specified unit and pays its proportional amount of such unit's total 
costs, pursuant to a contract:
    (1) For the life of the unit;
    (2) For a cumulative term of no less than 30 years, including 
contracts that permit an election for early termination; or
    (3) For a period equal to or greater than 25 years or 70 percent of 
the economic useful life of the unit determined as of the time the unit 
is built, with option rights to purchase or release some portion of the 
nameplate capacity and associated energy generated by the unit at the 
end of the period.
    Maximum design heat input means the ability of a unit to combust a 
stated maximum amount of fuel per hour on a steady state basis, as 
determined by the physical design and physical characteristics of the 
unit.
    Maximum potential hourly heat input means an hourly heat input used 
for reporting purposes when a unit lacks certified monitors to report 
heat input. If the unit intends to use appendix D of part 75 of this 
chapter to report heat input, this value should be calculated, in 
accordance with part 75 of this chapter, using the maximum fuel flow 
rate and the maximum gross calorific value. If the unit intends to use a 
flow monitor and a diluent gas monitor, this value should be reported, 
in accordance with part 75 of this chapter, using the maximum potential 
flowrate and either the maximum carbon dioxide concentration (in percent 
CO2) or the minimum oxygen concentration (in percent 
O2).
    Maximum potential NOX emission rate means the emission 
rate of nitrogen oxides (in lb/mmBtu) calculated in accordance with 
section 3 of appendix F of part 75 of this chapter, using the maximum 
potential nitrogen oxides concentration as defined in section 2 of 
appendix A of part 75 of this chapter,

[[Page 11]]

and either the maximum oxygen concentration (in percent O2) 
or the minimum carbon dioxide concentration (in percent CO2), 
under all operating conditions of the unit except for unit start up, 
shutdown, and upsets.
    Maximum rated hourly heat input means a unit-specific maximum hourly 
heat input (mmBtu) which is the higher of the manufacturer's maximum 
rated hourly heat input or the highest observed hourly heat input.
    Monitoring system means any monitoring system that meets the 
requirements of subpart H of this part, including a continuous emissions 
monitoring system, an excepted monitoring system, or an alternative 
monitoring system.
    Most stringent State or Federal NOX emissions limitation 
means, with regard to a NOX Budget opt-in source, the lowest 
NOX emissions limitation (in terms of lb/mmBtu) that is 
applicable to the unit under State or Federal law, regardless of the 
averaging period to which the emissions limitation applies.
    Nameplate capacity means the maximum electrical generating output 
(in MWe) that a generator can sustain over a specified period of time 
when not restricted by seasonal or other deratings as measured in 
accordance with the United States Department of Energy standards.
    Non-title V permit means a federally enforceable permit administered 
by the permitting authority pursuant to the CAA and regulatory authority 
under the CAA, other than title V of the CAA and part 70 or 71 of this 
chapter.
    NOX allowance means an authorization by the permitting 
authority or the Administrator under the NOX Budget Trading 
Program to emit up to one ton of nitrogen oxides during the control 
period of the specified year or of any year thereafter.
    NOX allowance deduction or deduct NOX 
allowances means the permanent withdrawal of NOX allowances 
by the Administrator from a NOX Allowance Tracking System 
compliance account or overdraft account to account for the number of 
tons of NOX emissions from a NOX Budget unit for a 
control period, determined in accordance with subpart H of this part, or 
for any other allowance surrender obligation under this part.
    NOX allowances held or hold NOX allowances 
means the NOX allowances recorded by the Administrator, or 
submitted to the Administrator for recordation, in accordance with 
subparts F and G of this part, in a NOX Allowance Tracking 
System account.
    NOX Allowance Tracking System means the system by which 
the Administrator records allocations, deductions, and transfers of 
NOX allowances under the NOX Budget Trading 
Program.
    NOX Allowance Tracking System account means an account in 
the NOX Allowance Tracking System established by the 
Administrator for purposes of recording the allocation, holding, 
transferring, or deducting of NOX allowances.
    NOX allowance transfer deadline means midnight of 
November 30 or, if November 30 is not a business day, midnight of the 
first business day thereafter and is the deadline by which 
NOX allowances may be submitted for recordation in a 
NOX Budget unit's compliance account, or the overdraft 
account of the source where the unit is located, in order to meet the 
unit's NOX Budget emissions limitation for the control period 
immediately preceding such deadline.
    NOX authorized account representative means, for a 
NOX Budget source or NOX Budget unit at the 
source, the natural person who is authorized by the owners and operators 
of the source and all NOX Budget units at the source, in 
accordance with subpart B of this part, to represent and legally bind 
each owner and operator in matters pertaining to the NOX 
Budget Trading Program or, for a general account, the natural person who 
is authorized, in accordance with subpart F of this part, to transfer or 
otherwise dispose of NOX allowances held in the general 
account.
    NOX Budget emissions limitation means, for a 
NOX Budget unit, the tonnage equivalent of the NOX 
allowances available for compliance deduction for the unit and for a 
control period under Sec. 96.54(a) and (b), adjusted by any deductions 
of such NOX allowances to account for actual utilization 
under Sec. 96.42(e) for the control period or to account for excess 
emissions for a prior

[[Page 12]]

control period under Sec. 96.54(d) or to account for withdrawal from 
the NOX Budget Program, or for a change in regulatory status, 
for a NOX Budget opt-in source under Sec. 96.86 or Sec. 
96.87.
    NOX Budget opt-in permit means a NOX Budget 
permit covering a NOX Budget opt-in source.
    NOX Budget opt-in source means a unit that has been 
elected to become a NOX Budget unit under the NOX 
Budget Trading Program and whose NOX Budget opt-in permit has 
been issued and is in effect under subpart I of this part.
    NOX Budget permit means the legally binding and federally 
enforceable written document, or portion of such document, issued by the 
permitting authority under this part, including any permit revisions, 
specifying the NOX Budget Trading Program requirements 
applicable to a NOX Budget source, to each NOX 
Budget unit at the NOX Budget source, and to the owners and 
operators and the NOX authorized account representative of 
the NOX Budget source and each NOX Budget unit.
    NOX Budget source means a source that includes one or 
more NOX Budget units.
    NOX Budget Trading Program means a multi-state nitrogen 
oxides air pollution control and emission reduction program established 
in accordance with this part and pursuant to Sec. 51.121 of this 
chapter, as a means of mitigating the interstate transport of ozone and 
nitrogen oxides, an ozone precursor.
    NOX Budget unit means a unit that is subject to the 
NOX Budget Trading Program emissions limitation under Sec. 
96.4 or Sec. 96.80.
    Operating means, with regard to a unit under Sec. Sec. 96.22(d)(2) 
and 96.80, having documented heat input for more than 876 hours in the 6 
months immediately preceding the submission of an application for an 
initial NOX Budget permit under Sec. 96.83(a).
    Operator means any person who operates, controls, or supervises a 
NOX Budget unit, a NOX Budget source, or unit for 
which an application for a NOX Budget opt-in permit under 
Sec. 96.83 is submitted and not denied or withdrawn and shall include, 
but not be limited to, any holding company, utility system, or plant 
manager of such a unit or source.
    Opt-in means to be elected to become a NOX Budget unit 
under the NOX Budget Trading Program through a final, 
effective NOX Budget opt-in permit under subpart I of this 
part.
    Overdraft account means the NOX Allowance Tracking System 
account, established by the Administrator under subpart F of this part, 
for each NOX Budget source where there are two or more 
NOX Budget units.
    Owner means any of the following persons:
    (1) Any holder of any portion of the legal or equitable title in a 
NOX Budget unit or in a unit for which an application for a 
NOX Budget opt-in permit under Sec. 96.83 is submitted and 
not denied or withdrawn; or
    (2) Any holder of a leasehold interest in a NOX Budget 
unit or in a unit for which an application for a NOX Budget 
opt-in permit under Sec. 96.83 is submitted and not denied or 
withdrawn; or
    (3) Any purchaser of power from a NOX Budget unit or from 
a unit for which an application for a NOX Budget opt-in 
permit under Sec. 96.83 is submitted and not denied or withdrawn under 
a life-of-the-unit, firm power contractual arrangement. However, unless 
expressly provided for in a leasehold agreement, owner shall not include 
a passive lessor, or a person who has an equitable interest through such 
lessor, whose rental payments are not based, either directly or 
indirectly, upon the revenues or income from the NOX Budget 
unit or the unit for which an application for a NOX Budget 
opt-in permit under Sec. 96.83 is submitted and not denied or 
withdrawn; or
    (4) With respect to any general account, any person who has an 
ownership interest with respect to the NOX allowances held in 
the general account and who is subject to the binding agreement for the 
NOX authorized account representative to represent that 
person's ownership interest with respect to NOX allowances.
    Permitting authority means the State air pollution control agency, 
local agency, other State agency, or other agency authorized by the 
Administrator to issue or revise permits to meet the requirements of the 
NOX

[[Page 13]]

Budget Trading Program in accordance with subpart C of this part.
    Receive or receipt of means, when referring to the permitting 
authority or the Administrator, to come into possession of a document, 
information, or correspondence (whether sent in writing or by authorized 
electronic transmission), as indicated in an official correspondence 
log, or by a notation made on the document, information, or 
correspondence, by the permitting authority or the Administrator in the 
regular course of business.
    Recordation, record, or recorded means, with regard to 
NOX allowances, the movement of NOX allowances by 
the Administrator from one NOX Allowance Tracking System 
account to another, for purposes of allocation, transfer, or deduction.
    Reference method means any direct test method of sampling and 
analyzing for an air pollutant as specified in appendix A of part 60 of 
this chapter.
    Serial number means, when referring to NOX allowances, 
the unique identification number assigned to each NOX 
allowance by the Administrator, under Sec. 96.53(c).
    Source means any governmental, institutional, commercial, or 
industrial structure, installation, plant, building, or facility that 
emits or has the potential to emit any regulated air pollutant under the 
CAA. For purposes of section 502(c) of the CAA, a ``source,'' including 
a ``source'' with multiple units, shall be considered a single 
``facility.''
    State means one of the 48 contiguous States and the District of 
Columbia specified in Sec. 51.121 of this chapter, or any non-federal 
authority in or including such States or the District of Columbia 
(including local agencies, and Statewide agencies) or any eligible 
Indian tribe in an area of such State or the District of Columbia, that 
adopts a NOX Budget Trading Program pursuant to Sec. 51.121 
of this chapter. To the extent a State incorporates by reference the 
provisions of this part, the term ``State'' shall mean the incorporating 
State. The term ``State'' shall have its conventional meaning where such 
meaning is clear from the context.
    State trading program budget means the total number of 
NOX tons apportioned to all NOX Budget units in a 
given State, in accordance with the NOX Budget Trading 
Program, for use in a given control period.
    Submit or serve means to send or transmit a document, information, 
or correspondence to the person specified in accordance with the 
applicable regulation:
    (1) In person;
    (2) By United States Postal Service; or
    (3) By other means of dispatch or transmission and delivery. 
Compliance with any ``submission,'' ``service,'' or ``mailing'' deadline 
shall be determined by the date of dispatch, transmission, or mailing 
and not the date of receipt.
    Title V operating permit means a permit issued under title V of the 
CAA and part 70 or part 71 of this chapter.
    Title V operating permit regulations means the regulations that the 
Administrator has approved or issued as meeting the requirements of 
title V of the CAA and part 70 or 71 of this chapter.
    Ton or tonnage means any ``short ton'' (i.e., 2,000 pounds). For the 
purpose of determining compliance with the NOX Budget 
emissions limitation, total tons for a control period shall be 
calculated as the sum of all recorded hourly emissions (or the tonnage 
equivalent of the recorded hourly emissions rates) in accordance with 
subpart H of this part, with any remaining fraction of a ton equal to or 
greater than 0.50 ton deemed to equal one ton and any fraction of a ton 
less than 0.50 ton deemed to equal zero tons.
    Unit means a fossil fuel-fired stationary boiler, combustion 
turbine, or combined cycle system.
    Unit load means the total (i.e., gross) output of a unit in any 
control period (or other specified time period) produced by combusting a 
given heat input of fuel, expressed in terms of:
    (1) The total electrical generation (MWe) produced by the unit, 
including generation for use within the plant; or
    (2) In the case of a unit that uses heat input for purposes other 
than electrical generation, the total steam pressure (psia) produced by 
the unit, including steam for use by the unit.
    Unit operating day means a calendar day in which a unit combusts any 
fuel.

[[Page 14]]

    Unit operating hour or hour of unit operation means any hour (or 
fraction of an hour) during which a unit combusts any fuel.
    Utilization means the heat input (expressed in mmBtu/time) for a 
unit. The unit's total heat input for the control period in each year 
will be determined in accordance with part 75 of this chapter if the 
NOX Budget unit was otherwise subject to the requirements of 
part 75 of this chapter for the year, or will be based on the best 
available data reported to the Administrator for the unit if the unit 
was not otherwise subject to the requirements of part 75 of this chapter 
for the year.



Sec. 96.3  Measurements, abbreviations, and acronyms.

    Measurements, abbreviations, and acronyms used in this part are 
defined as follows:

Btu--British thermal unit.
hr--hour.
Kwh--kilowatt hour.
lb--pounds.
mmBtu--million Btu.
MWe--megawatt electrical.
ton--2000 pounds.
CO2--carbon dioxide.
NOX--nitrogen oxides.
O2--oxygen.



Sec. 96.4  Applicability.

    (a) The following units in a State shall be NOX Budget 
units, and any source that includes one or more such units shall be a 
NOX Budget source, subject to the requirements of this part:
    (1) Any unit that, any time on or after January 1, 1995, serves a 
generator with a nameplate capacity greater than 25 MWe and sells any 
amount of electricity; or
    (2) Any unit that is not a unit under paragraph (a) of this section 
and that has a maximum design heat input greater than 250 mmBtu/hr.
    (b) Notwithstanding paragraph (a) of this section, a unit under 
paragraph (a) of this section shall be subject only to the requirements 
of this paragraph (b) if the unit has a federally enforceable permit 
that meets the requirements of paragraph (b)(1) of this section and 
restricts the unit to burning only natural gas or fuel oil during a 
control period in 2003 or later and each control period thereafter and 
restricts the unit's operating hours during each such control period to 
the number of hours (determined in accordance with paragraph (b)(1)(ii) 
and (iii) of this section) that limits the unit's potential 
NOX mass emissions for the control period to 25 tons or less. 
Notwithstanding paragraph (a) of this section, starting with the 
effective date of such federally enforceable permit, the unit shall not 
be a NOX Budget unit.
    (1) For each control period under paragraph (b) of this section, the 
federally enforceable permit must:
    (i) Restrict the unit to burning only natural gas or fuel oil.
    (ii) Restrict the unit's operating hours to the number calculated by 
dividing 25 tons of potential NOX mass emissions by the 
unit's maximum potential hourly NOX mass emissions.
    (iii) Require that the unit's potential NOX mass 
emissions shall be calculated as follows:
    (A) Select the default NOX emission rate in Table 2 of 
Sec. 75.19 of this chapter that would otherwise be applicable assuming 
that the unit burns only the type of fuel (i.e., only natural gas or 
only fuel oil) that has the highest default NOX emission 
factor of any type of fuel that the unit is allowed to burn under the 
fuel use restriction in paragraph (b)(1)(i) of this section; and
    (B) Multiply the default NOX emission rate under 
paragraph (b)(1)(iii)(A) of this section by the unit's maximum rated 
hourly heat input. The owner or operator of the unit may petition the 
permitting authority to use a lower value for the unit's maximum rated 
hourly heat input than the value as defined under Sec. 96.2. The 
permitting authority may approve such lower value if the owner or 
operator demonstrates that the maximum hourly heat input specified by 
the manufacturer or the highest observed hourly heat input, or both, are 
not representative, and that such lower value is representative, of the 
unit's current capabilities because modifications have been made to the 
unit, limiting its capacity permanently.
    (iv) Require that the owner or operator of the unit shall retain at 
the source that includes the unit, for 5 years, records demonstrating 
that the

[[Page 15]]

operating hours restriction, the fuel use restriction, and the other 
requirements of the permit related to these restrictions were met.
    (v) Require that the owner or operator of the unit shall report the 
unit's hours of operation (treating any partial hour of operation as a 
whole hour of operation) during each control period to the permitting 
authority by November 1 of each year for which the unit is subject to 
the federally enforceable permit.
    (2) The permitting authority that issues the federally enforceable 
permit with the fuel use restriction under paragraph (b)(1)(i) and the 
operating hours restriction under paragraphs (b)(1)(ii) and (iii) of 
this section will notify the Administrator in writing of each unit under 
paragraph (a) of this section whose federally enforceable permit issued 
by the permitting authority includes such restrictions. The permitting 
authority will also notify the Administrator in writing of each unit 
under paragraph (a) of this section whose federally enforceable permit 
issued by the permitting authority is revised to remove any such 
restriction, whose federally enforceable permit issued by the permitting 
authority includes any such restriction that is no longer applicable, or 
which does not comply with any such restriction.
    (3) If, for any control period under paragraph (b) of this section, 
the fuel use restriction under paragraph (b)(1)(i) of this section or 
the operating hours restriction under paragraphs (b)(1)(ii) and (iii) of 
this section is removed from the unit's federally enforceable permit or 
otherwise becomes no longer applicable or if, for any such control 
period, the unit does not comply with the fuel use restriction under 
paragraph (b)(1)(i) of this section or the operating hours restriction 
under paragraphs (b)(1)(ii) and (iii) of this section, the unit shall be 
a NOX Budget unit, subject to the requirements of this part. 
Such unit shall be treated as commencing operation and, for a unit under 
paragraph (a)(1) of this section, commencing commercial operation on 
September 30 of the control period for which the fuel use restriction or 
the operating hours restriction is no longer applicable or during which 
the unit does not comply with the fuel use restriction or the operating 
hours restriction.



Sec. 96.5  Retired unit exemption.

    (a) This section applies to any NOX Budget unit, other 
than a NOX Budget opt-in source, that is permanently retired.
    (b)(1) Any NOX Budget unit, other than a NOX 
Budget opt-in source, that is permanently retired shall be exempt from 
the NOX Budget Trading Program, except for the provisions of 
this section, Sec. Sec. 96.2, 96.3, 96.4, 96.7 and subparts E, F, and G 
of this part.
    (2) The exemption under paragraph (b)(1) of this section shall 
become effective the day on which the unit is permanently retired. 
Within 30 days of permanent retirement, the NOX authorized 
account representative (authorized in accordance with subpart B of this 
part) shall submit a statement to the permitting authority otherwise 
responsible for administering any NOX Budget permit for the 
unit. A copy of the statement shall be submitted to the Administrator. 
The statement shall state (in a format prescribed by the permitting 
authority) that the unit is permanently retired and will comply with the 
requirements of paragraph (c) of this section.
    (3) After receipt of the notice under paragraph (b)(2) of this 
section, the permitting authority will amend any permit covering the 
source at which the unit is located to add the provisions and 
requirements of the exemption under paragraphs (b)(1) and (c) of this 
section.
    (c) Special provisions. (1) A unit exempt under this section shall 
not emit any nitrogen oxides, starting on the date that the exemption 
takes effect. The owners and operators of the unit will be allocated 
allowances in accordance with subpart E of this part.
    (2)(i) A unit exempt under this section and located at a source that 
is required, or but for this exemption would be required, to have a 
title V operating permit shall not resume operation unless the 
NOX authorized account representative of the source submits a 
complete NOX Budget permit application under Sec. 96.22 for 
the unit not less than 18 months (or such lesser time provided under the 
permitting

[[Page 16]]

authority's title V operating permits regulations for final action on a 
permit application) prior to the later of May 1, 2003 or the date on 
which the unit is to first resume operation.
    (ii) A unit exempt under this section and located at a source that 
is required, or but for this exemption would be required, to have a non-
title V permit shall not resume operation unless the NOX 
authorized account representative of the source submits a complete 
NOX Budget permit application under Sec. 96.22 for the unit 
not less than 18 months (or such lesser time provided under the 
permitting authority's non-title V permits regulations for final action 
on a permit application) prior to the later of May 1, 2003 or the date 
on which the unit is to first resume operation.
    (3) The owners and operators and, to the extent applicable, the 
NOX authorized account representative of a unit exempt under 
this section shall comply with the requirements of the NOX 
Budget Trading Program concerning all periods for which the exemption is 
not in effect, even if such requirements arise, or must be complied 
with, after the exemption takes effect.
    (4) A unit that is exempt under this section is not eligible to be a 
NOX Budget opt-in source under subpart I of this part.
    (5) For a period of 5 years from the date the records are created, 
the owners and operators of a unit exempt under this section shall 
retain at the source that includes the unit, records demonstrating that 
the unit is permanently retired. The 5-year period for keeping records 
may be extended for cause, at any time prior to the end of the period, 
in writing by the permitting authority or the Administrator. The owners 
and operators bear the burden of proof that the unit is permanently 
retired.
    (6) Loss of exemption. (i) On the earlier of the following dates, a 
unit exempt under paragraph (b) of this section shall lose its 
exemption:
    (A) The date on which the NOX authorized account 
representative submits a NOX Budget permit application under 
paragraph (c)(2) of this section; or
    (B) The date on which the NOX authorized account 
representative is required under paragraph (c)(2) of this section to 
submit a NOX Budget permit application.
    (ii) For the purpose of applying monitoring requirements under 
subpart H of this part, a unit that loses its exemption under this 
section shall be treated as a unit that commences operation or 
commercial operation on the first date on which the unit resumes 
operation.



Sec. 96.6  Standard requirements.

    (a) Permit Requirements. (1) The NOX authorized account 
representative of each NOX Budget source required to have a 
federally enforceable permit and each NOX Budget unit 
required to have a federally enforceable permit at the source shall:
    (i) Submit to the permitting authority a complete NOX 
Budget permit application under Sec. 96.22 in accordance with the 
deadlines specified in Sec. 96.21(b) and (c);
    (ii) Submit in a timely manner any supplemental information that the 
permitting authority determines is necessary in order to review a 
NOX Budget permit application and issue or deny a 
NOX Budget permit.
    (2) The owners and operators of each NOX Budget source 
required to have a federally enforceable permit and each NOX 
Budget unit required to have a federally enforceable permit at the 
source shall have a NOX Budget permit issued by the 
permitting authority and operate the unit in compliance with such 
NOX Budget permit.
    (3) The owners and operators of a NOX Budget source that 
is not otherwise required to have a federally enforceable permit are not 
required to submit a NOX Budget permit application, and to 
have a NOX Budget permit, under subpart C of this part for 
such NOX Budget source.
    (b) Monitoring requirements. (1) The owners and operators and, to 
the extent applicable, the NOX authorized account 
representative of each NOX Budget source and each 
NOX Budget unit at the source shall comply with the 
monitoring requirements of subpart H of this part.
    (2) The emissions measurements recorded and reported in accordance 
with

[[Page 17]]

subpart H of this part shall be used to determine compliance by the unit 
with the NOX Budget emissions limitation under paragraph (c) 
of this section.
    (c) Nitrogen oxides requirements. (1) The owners and operators of 
each NOX Budget source and each NOX Budget unit at 
the source shall hold NOX allowances available for compliance 
deductions under Sec. 96.54, as of the NOX allowance 
transfer deadline, in the unit's compliance account and the source's 
overdraft account in an amount not less than the total NOX 
emissions for the control period from the unit, as determined in 
accordance with subpart H of this part, plus any amount necessary to 
account for actual utilization under Sec. 96.42(e) for the control 
period.
    (2) Each ton of nitrogen oxides emitted in excess of the 
NOX Budget emissions limitation shall constitute a separate 
violation of this part, the CAA, and applicable State law.
    (3) A NOX Budget unit shall be subject to the 
requirements under paragraph (c)(1) of this section starting on the 
later of May 1, 2003 or the date on which the unit commences operation.
    (4) NOX allowances shall be held in, deducted from, or 
transferred among NOX Allowance Tracking System accounts in 
accordance with subparts E, F, G, and I of this part.
    (5) A NOX allowance shall not be deducted, in order to 
comply with the requirements under paragraph (c)(1) of this section, for 
a control period in a year prior to the year for which the 
NOX allowance was allocated.
    (6) A NOX allowance allocated by the permitting authority 
or the Administrator under the NOX Budget Trading Program is 
a limited authorization to emit one ton of nitrogen oxides in accordance 
with the NOX Budget Trading Program. No provision of the 
NOX Budget Trading Program, the NOX Budget permit 
application, the NOX Budget permit, or an exemption under 
Sec. 96.5 and no provision of law shall be construed to limit the 
authority of the United States or the State to terminate or limit such 
authorization.
    (7) A NOX allowance allocated by the permitting authority 
or the Administrator under the NOX Budget Trading Program 
does not constitute a property right.
    (8) Upon recordation by the Administrator under subpart F, G, or I 
of this part, every allocation, transfer, or deduction of a 
NOX allowance to or from a NOX Budget unit's 
compliance account or the overdraft account of the source where the unit 
is located is deemed to amend automatically, and become a part of, any 
NOX Budget permit of the NOX Budget unit by 
operation of law without any further review.
    (d) Excess emissions requirements. (1) The owners and operators of a 
NOX Budget unit that has excess emissions in any control 
period shall:
    (i) Surrender the NOX allowances required for deduction 
under Sec. 96.54(d)(1); and
    (ii) Pay any fine, penalty, or assessment or comply with any other 
remedy imposed under Sec. 96.54(d)(3).
    (e) Recordkeeping and Reporting requirements. (1) Unless otherwise 
provided, the owners and operators of the NOX Budget source 
and each NOX Budget unit at the source shall keep on site at 
the source each of the following documents for a period of 5 years from 
the date the document is created. This period may be extended for cause, 
at any time prior to the end of 5 years, in writing by the permitting 
authority or the Administrator.
    (i) The account certificate of representation for the NOX 
authorized account representative for the source and each NOX 
Budget unit at the source and all documents that demonstrate the truth 
of the statements in the account certificate of representation, in 
accordance with Sec. 96.13; provided that the certificate and documents 
shall be retained on site at the source beyond such 5-year period until 
such documents are superseded because of the submission of a new account 
certificate of representation changing the NOX authorized 
account representative.
    (ii) All emissions monitoring information, in accordance with 
subpart H of this part; provided that to the extent that subpart H of 
this part provides for a 3-year period for recordkeeping, the 3-year 
period shall apply.
    (iii) Copies of all reports, compliance certifications, and other 
submissions and all records made or required under the NOX 
Budget Trading Program.

[[Page 18]]

    (iv) Copies of all documents used to complete a NOX 
Budget permit application and any other submission under the 
NOX Budget Trading Program or to demonstrate compliance with 
the requirements of the NOX Budget Trading Program.
    (2) The NOX authorized account representative of a 
NOX Budget source and each NOX Budget unit at the 
source shall submit the reports and compliance certifications required 
under the NOX Budget Trading Program, including those under 
subparts D, H, or I of this part.
    (f) Liability. (1) Any person who knowingly violates any requirement 
or prohibition of the NOX Budget Trading Program, a 
NOX Budget permit, or an exemption under Sec. 96.5 shall be 
subject to enforcement pursuant to applicable State or Federal law.
    (2) Any person who knowingly makes a false material statement in any 
record, submission, or report under the NOX Budget Trading 
Program shall be subject to criminal enforcement pursuant to the 
applicable State or Federal law.
    (3) No permit revision shall excuse any violation of the 
requirements of the NOX Budget Trading Program that occurs 
prior to the date that the revision takes effect.
    (4) Each NOX Budget source and each NOX Budget 
unit shall meet the requirements of the NOX Budget Trading 
Program.
    (5) Any provision of the NOX Budget Trading Program that 
applies to a NOX Budget source (including a provision 
applicable to the NOX authorized account representative of a 
NOX Budget source) shall also apply to the owners and 
operators of such source and of the NOX Budget units at the 
source.
    (6) Any provision of the NOX Budget Trading Program that 
applies to a NOX Budget unit (including a provision 
applicable to the NOX authorized account representative of a 
NOX budget unit) shall also apply to the owners and operators 
of such unit. Except with regard to the requirements applicable to units 
with a common stack under subpart H of this part, the owners and 
operators and the NOX authorized account representative of 
one NOX Budget unit shall not be liable for any violation by 
any other NOX Budget unit of which they are not owners or 
operators or the NOX authorized account representative and 
that is located at a source of which they are not owners or operators or 
the NOX authorized account representative.
    (g) Effect on other authorities. No provision of the NOX 
Budget Trading Program, a NOX Budget permit application, a 
NOX Budget permit, or an exemption under Sec. 96.5 shall be 
construed as exempting or excluding the owners and operators and, to the 
extent applicable, the NOX authorized account representative 
of a NOX Budget source or NOX Budget unit from 
compliance with any other provision of the applicable, approved State 
implementation plan, a federally enforceable permit, or the CAA.



Sec. 96.7  Computation of time.

    (a) Unless otherwise stated, any time period scheduled, under the 
NOX Budget Trading Program, to begin on the occurrence of an 
act or event shall begin on the day the act or event occurs.
    (b) Unless otherwise stated, any time period scheduled, under the 
NOX Budget Trading Program, to begin before the occurrence of 
an act or event shall be computed so that the period ends the day before 
the act or event occurs.
    (c) Unless otherwise stated, if the final day of any time period, 
under the NOX Budget Trading Program, falls on a weekend or a 
State or Federal holiday, the time period shall be extended to the next 
business day.



 Subpart B_NOX Authorized Account Representative for NOX Budget Sources



Sec. 96.10  Authorization and responsibilities of the NOX authorized
account representative.

    (a) Except as provided under Sec. 96.11, each NOX Budget 
source, including all NOX Budget units at the source, shall 
have one and only one NOX authorized account representative, 
with regard to all matters under the NOX Budget Trading 
Program concerning the source or any NOX Budget unit at the 
source.

[[Page 19]]

    (b) The NOX authorized account representative of the 
NOX Budget source shall be selected by an agreement binding 
on the owners and operators of the source and all NOX Budget 
units at the source.
    (c) Upon receipt by the Administrator of a complete account 
certificate of representation under Sec. 96.13, the NOX 
authorized account representative of the source shall represent and, by 
his or her representations, actions, inactions, or submissions, legally 
bind each owner and operator of the NOX Budget source 
represented and each NOX Budget unit at the source in all 
matters pertaining to the NOX Budget Trading Program, not 
withstanding any agreement between the NOX authorized account 
representative and such owners and operators. The owners and operators 
shall be bound by any decision or order issued to the NOX 
authorized account representative by the permitting authority, the 
Administrator, or a court regarding the source or unit.
    (d) No NOX Budget permit shall be issued, and no 
NOX Allowance Tracking System account shall be established 
for a NOX Budget unit at a source, until the Administrator 
has received a complete account certificate of representation under 
Sec. 96.13 for a NOX authorized account representative of 
the source and the NOX Budget units at the source.
    (e)(1) Each submission under the NOX Budget Trading 
Program shall be submitted, signed, and certified by the NOX 
authorized account representative for each NOX Budget source 
on behalf of which the submission is made. Each such submission shall 
include the following certification statement by the NOX 
authorized account representative: ``I am authorized to make this 
submission on behalf of the owners and operators of the NOX 
Budget sources or NOX Budget units for which the submission 
is made. I certify under penalty of law that I have personally examined, 
and am familiar with, the statements and information submitted in this 
document and all its attachments. Based on my inquiry of those 
individuals with primary responsibility for obtaining the information, I 
certify that the statements and information are to the best of my 
knowledge and belief true, accurate, and complete. I am aware that there 
are significant penalties for submitting false statements and 
information or omitting required statements and information, including 
the possibility of fine or imprisonment.''
    (2) The permitting authority and the Administrator will accept or 
act on a submission made on behalf of owner or operators of a 
NOX Budget source or a NOX Budget unit only if the 
submission has been made, signed, and certified in accordance with 
paragraph (e)(1) of this section.



Sec. 96.11  Alternate NOX authorized account representative.

    (a) An account certificate of representation may designate one and 
only one alternate NOX authorized account representative who 
may act on behalf of the NOX authorized account 
representative. The agreement by which the alternate NOX 
authorized account representative is selected shall include a procedure 
for authorizing the alternate NOX authorized account 
representative to act in lieu of the NOX authorized account 
representative.
    (b) Upon receipt by the Administrator of a complete account 
certificate of representation under Sec. 96.13, any representation, 
action, inaction, or submission by the alternate NOX 
authorized account representative shall be deemed to be a 
representation, action, inaction, or submission by the NOX 
authorized account representative.
    (c) Except in this section and Sec. Sec. 96.10(a), 96.12, 96.13, 
and 96.51, whenever the term ``NOX authorized account 
representative'' is used in this part, the term shall be construed to 
include the alternate NOX authorized account representative.



Sec. 96.12  Changing the NOX authorized account representative and 
the alternate NOX authorized account representative; changes in the
owners and operators.

    (a) Changing the NOX authorized account representative. 
The NOX authorized account representative may be changed at 
any time upon receipt by the Administrator of a superseding

[[Page 20]]

complete account certificate of representation under Sec. 96.13. 
Notwithstanding any such change, all representations, actions, 
inactions, and submissions by the previous NOX authorized 
account representative prior to the time and date when the Administrator 
receives the superseding account certificate of representation shall be 
binding on the new NOX authorized account representative and 
the owners and operators of the NOX Budget source and the 
NOX Budget units at the source.
    (b) Changing the alternate NOX authorized account 
representative. The alternate NOX authorized account 
representative may be changed at any time upon receipt by the 
Administrator of a superseding complete account certificate of 
representation under Sec. 96.13. Notwithstanding any such change, all 
representations, actions, inactions, and submissions by the previous 
alternate NOX authorized account representative prior to the 
time and date when the Administrator receives the superseding account 
certificate of representation shall be binding on the new alternate 
NOX authorized account representative and the owners and 
operators of the NOX Budget source and the NOX 
Budget units at the source.
    (c) Changes in the owners and operators. (1) In the event a new 
owner or operator of a NOX Budget source or a NOX 
Budget unit is not included in the list of owners and operators 
submitted in the account certificate of representation, such new owner 
or operator shall be deemed to be subject to and bound by the account 
certificate of representation, the representations, actions, inactions, 
and submissions of the NOX authorized account representative 
and any alternate NOX authorized account representative of 
the source or unit, and the decisions, orders, actions, and inactions of 
the permitting authority or the Administrator, as if the new owner or 
operator were included in such list.
    (2) Within 30 days following any change in the owners and operators 
of a NOX Budget source or a NOX Budget unit, 
including the addition of a new owner or operator, the NOX 
authorized account representative or alternate NOX authorized 
account representative shall submit a revision to the account 
certificate of representation amending the list of owners and operators 
to include the change.



Sec. 96.13  Account certificate of representation.

    (a) A complete account certificate of representation for a 
NOX authorized account representative or an alternate 
NOX authorized account representative shall include the 
following elements in a format prescribed by the Administrator:
    (1) Identification of the NOX Budget source and each 
NOX Budget unit at the source for which the account 
certificate of representation is submitted.
    (2) The name, address, e-mail address (if any), telephone number, 
and facsimile transmission number (if any) of the NOX 
authorized account representative and any alternate NOX 
authorized account representative.
    (3) A list of the owners and operators of the NOX Budget 
source and of each NOX Budget unit at the source.
    (4) The following certification statement by the NOX 
authorized account representative and any alternate NOX 
authorized account representative: ``I certify that I was selected as 
the NOX authorized account representative or alternate 
NOX authorized account representative, as applicable, by an 
agreement binding on the owners and operators of the NOX 
Budget source and each NOX Budget unit at the source. I 
certify that I have all the necessary authority to carry out my duties 
and responsibilities under the NOX Budget Trading Program on 
behalf of the owners and operators of the NOX Budget source 
and of each NOX Budget unit at the source and that each such 
owner and operator shall be fully bound by my representations, actions, 
inactions, or submissions and by any decision or order issued to me by 
the permitting authority, the Administrator, or a court regarding the 
source or unit.''
    (5) The signature of the NOX authorized account 
representative and any alternate NOX authorized account 
representative and the dates signed.
    (b) Unless otherwise required by the permitting authority or the 
Administrator, documents of agreement referred to in the account 
certificate of

[[Page 21]]

representation shall not be submitted to the permitting authority or the 
Administrator. Neither the permitting authority nor the Administrator 
shall be under any obligation to review or evaluate the sufficiency of 
such documents, if submitted.



Sec. 96.14  Objections concerning the NOX authorized account
representative.

    (a) Once a complete account certificate of representation under 
Sec. 96.13 has been submitted and received, the permitting authority 
and the Administrator will rely on the account certificate of 
representation unless and until a superseding complete account 
certificate of representation under Sec. 96.13 is received by the 
Administrator.
    (b) Except as provided in Sec. 96.12(a) or (b), no objection or 
other communication submitted to the permitting authority or the 
Administrator concerning the authorization, or any representation, 
action, inaction, or submission of the NOX authorized account 
representative shall affect any representation, action, inaction, or 
submission of the NOX authorized account representative or 
the finality of any decision or order by the permitting authority or the 
Administrator under the NOX Budget Trading Program.
    (c) Neither the permitting authority nor the Administrator will 
adjudicate any private legal dispute concerning the authorization or any 
representation, action, inaction, or submission of any NOX 
authorized account representative, including private legal disputes 
concerning the proceeds of NOX allowance transfers.



                            Subpart C_Permits



Sec. 96.20  General NOX Budget trading program permit requirements.

    (a) For each NOX Budget source required to have a 
federally enforceable permit, such permit shall include a NOX 
Budget permit administered by the permitting authority.
    (1) For NOX Budget sources required to have a title V 
operating permit, the NOX Budget portion of the title V 
permit shall be administered in accordance with the permitting 
authority's title V operating permits regulations promulgated under part 
70 or 71 of this chapter, except as provided otherwise by this subpart 
or subpart I of this part. The applicable provisions of such title V 
operating permits regulations shall include, but are not limited to, 
those provisions addressing operating permit applications, operating 
permit application shield, operating permit duration, operating permit 
shield, operating permit issuance, operating permit revision and 
reopening, public participation, State review, and review by the 
Administrator.
    (2) For NOX Budget sources required to have a non-title V 
permit, the NOX Budget portion of the non-title V permit 
shall be administered in accordance with the permitting authority's 
regulations promulgated to administer non-title V permits, except as 
provided otherwise by this subpart or subpart I of this part. The 
applicable provisions of such non-title V permits regulations may 
include, but are not limited to, provisions addressing permit 
applications, permit application shield, permit duration, permit shield, 
permit issuance, permit revision and reopening, public participation, 
State review, and review by the Administrator.
    (b) Each NOX Budget permit (including a draft or proposed 
NOX Budget permit, if applicable) shall contain all 
applicable NOX Budget Trading Program requirements and shall 
be a complete and segregable portion of the permit under paragraph (a) 
of this section.



Sec. 96.21  Submission of NOX Budget permit applications.

    (a) Duty to apply. The NOX authorized account 
representative of any NOX Budget source required to have a 
federally enforceable permit shall submit to the permitting authority a 
complete NOX Budget permit application under Sec. 96.22 by 
the applicable deadline in paragraph (b) of this section.
    (b)(1) For NOX Budget sources required to have a title V 
operating permit:
    (i) For any source, with one or more NOX Budget units 
under Sec. 96.4 that commence operation before January 1, 2000, the 
NOX authorized account representative shall submit a complete 
NOX Budget permit application under Sec. 96.22 covering such 
NOX Budget units to the permitting authority at least 18

[[Page 22]]

months (or such lesser time provided under the permitting authority's 
title V operating permits regulations for final action on a permit 
application) before May 1, 2003.
    (ii) For any source, with any NOX Budget unit under Sec. 
96.4 that commences operation on or after January 1, 2000, the 
NOX authorized account representative shall submit a complete 
NOX Budget permit application under Sec. 96.22 covering such 
NOX Budget unit to the permitting authority at least 18 
months (or such lesser time provided under the permitting authority's 
title V operating permits regulations for final action on a permit 
application) before the later of May 1, 2003 or the date on which the 
NOX Budget unit commences operation.
    (2) For NOX Budget sources required to have a non-title V 
permit:
    (i) For any source, with one or more NOX Budget units 
under Sec. 96.4 that commence operation before January 1, 2000, the 
NOX authorized account representative shall submit a complete 
NOX Budget permit application under Sec. 96.22 covering such 
NOX Budget units to the permitting authority at least 18 
months (or such lesser time provided under the permitting authority's 
non-title V permits regulations for final action on a permit 
application) before May 1, 2003.
    (ii) For any source, with any NOX Budget unit under Sec. 
96.4 that commences operation on or after January 1, 2000, the 
NOX authorized account representative shall submit a complete 
NOX Budget permit application under Sec. 96.22 covering such 
NOX Budget unit to the permitting authority at least 18 
months (or such lesser time provided under the permitting authority's 
non-title V permits regulations for final action on a permit 
application) before the later of May 1, 2003 or the date on which the 
NOX Budget unit commences operation.
    (c) Duty to reapply. (1) For a NOX Budget source required 
to have a title V operating permit, the NOX authorized 
account representative shall submit a complete NOX Budget 
permit application under Sec. 96.22 for the NOX Budget 
source covering the NOX Budget units at the source in 
accordance with the permitting authority's title V operating permits 
regulations addressing operating permit renewal.
    (2) For a NOX Budget source required to have a non-title 
V permit, the NOX authorized account representative shall 
submit a complete NOX Budget permit application under Sec. 
96.22 for the NOX Budget source covering the NOX 
Budget units at the source in accordance with the permitting authority's 
non-title V permits regulations addressing permit renewal.



Sec. 96.22  Information requirements for NOX Budget permit 
applications.

    A complete NOX Budget permit application shall include 
the following elements concerning the NOX Budget source for 
which the application is submitted, in a format prescribed by the 
permitting authority:
    (a) Identification of the NOX Budget source, including 
plant name and the ORIS (Office of Regulatory Information Systems) or 
facility code assigned to the source by the Energy Information 
Administration, if applicable;
    (b) Identification of each NOX Budget unit at the 
NOX Budget source and whether it is a NOX Budget 
unit under Sec. 96.4 or under subpart I of this part;
    (c) The standard requirements under Sec. 96.6; and
    (d) For each NOX Budget opt-in unit at the NOX 
Budget source, the following certification statements by the 
NOX authorized account representative:
    (1) ``I certify that each unit for which this permit application is 
submitted under subpart I of this part is not a NOX Budget 
unit under 40 CFR 96.4 and is not covered by a retired unit exemption 
under 40 CFR 96.5 that is in effect.''
    (2) If the application is for an initial NOX Budget opt-
in permit, ``I certify that each unit for which this permit application 
is submitted under subpart I is currently operating, as that term is 
defined under 40 CFR 96.2.''



Sec. 96.23  NOX Budget permit contents.

    (a) Each NOX Budget permit (including any draft or 
proposed NOX Budget permit, if applicable) will contain, in a 
format prescribed by the permitting authority, all elements required for 
a

[[Page 23]]

complete NOX Budget permit application under Sec. 96.22 as 
approved or adjusted by the permitting authority.
    (b) Each NOX Budget permit is deemed to incorporate 
automatically the definitions of terms under Sec. 96.2 and, upon 
recordation by the Administrator under subparts F, G, or I of this part, 
every allocation, transfer, or deduction of a NOX allowance 
to or from the compliance accounts of the NOX Budget units 
covered by the permit or the overdraft account of the NOX 
Budget source covered by the permit.



Sec. 96.24  Effective date of initial NOX Budget permit.

    The initial NOX Budget permit covering a NOX 
Budget unit for which a complete NOX Budget permit 
application is timely submitted under Sec. 96.21(b) shall become 
effective by the later of:
    (a) May 1, 2003;
    (b) May 1 of the year in which the NOX Budget unit 
commences operation, if the unit commences operation on or before May 1 
of that year;
    (c) The date on which the NOX Budget unit commences 
operation, if the unit commences operation during a control period; or
    (d) May 1 of the year following the year in which the NOX 
Budget unit commences operation, if the unit commences operation on or 
after October 1 of the year.



Sec. 96.25  NOX Budget permit revisions.

    (a) For a NOX Budget source with a title V operating 
permit, except as provided in Sec. 96.23(b), the permitting authority 
will revise the NOX Budget permit, as necessary, in 
accordance with the permitting authority's title V operating permits 
regulations addressing permit revisions.
    (b) For a NOX Budget source with a non-title V permit, 
except as provided in Sec. 96.23(b), the permitting authority will 
revise the NOX Budget permit, as necessary, in accordance 
with the permitting authority's non-title V permits regulations 
addressing permit revisions.



                   Subpart D_Compliance Certification



Sec. 96.30  Compliance certification report.

    (a) Applicability and deadline. For each control period in which one 
or more NOX Budget units at a source are subject to the 
NOX Budget emissions limitation, the NOX 
authorized account representative of the source shall submit to the 
permitting authority and the Administrator by November 30 of that year, 
a compliance certification report for each source covering all such 
units.
    (b) Contents of report. The NOX authorized account 
representative shall include in the compliance certification report 
under paragraph (a) of this section the following elements, in a format 
prescribed by the Administrator, concerning each unit at the source and 
subject to the NOX Budget emissions limitation for the 
control period covered by the report:
    (1) Identification of each NOX Budget unit;
    (2) At the NOX authorized account representative's 
option, the serial numbers of the NOX allowances that are to 
be deducted from each unit's compliance account under Sec. 96.54 for 
the control period;
    (3) At the NOX authorized account representative's 
option, for units sharing a common stack and having NOX 
emissions that are not monitored separately or apportioned in accordance 
with subpart H of this part, the percentage of allowances that is to be 
deducted from each unit's compliance account under Sec. 96.54(e); and
    (4) The compliance certification under paragraph (c) of this 
section.
    (c) Compliance certification. In the compliance certification report 
under paragraph (a) of this section, the NOX authorized 
account representative shall certify, based on reasonable inquiry of 
those persons with primary responsibility for operating the source and 
the NOX Budget units at the source in compliance with the 
NOX Budget Trading Program, whether each NOX 
Budget unit for which the compliance certification is submitted was 
operated during the calendar year covered by

[[Page 24]]

the report in compliance with the requirements of the NOX 
Budget Trading Program applicable to the unit, including:
    (1) Whether the unit was operated in compliance with the 
NOX Budget emissions limitation;
    (2) Whether the monitoring plan that governs the unit has been 
maintained to reflect the actual operation and monitoring of the unit, 
and contains all information necessary to attribute NOX 
emissions to the unit, in accordance with subpart H of this part;
    (3) Whether all the NOX emissions from the unit, or a 
group of units (including the unit) using a common stack, were monitored 
or accounted for through the missing data procedures and reported in the 
quarterly monitoring reports, including whether conditional data were 
reported in the quarterly reports in accordance with subpart H of this 
part. If conditional data were reported, the owner or operator shall 
indicate whether the status of all conditional data has been resolved 
and all necessary quarterly report resubmissions has been made;
    (4) Whether the facts that form the basis for certification under 
subpart H of this part of each monitor at the unit or a group of units 
(including the unit) using a common stack, or for using an excepted 
monitoring method or alternative monitoring method approved under 
subpart H of this part, if any, has changed; and
    (5) If a change is required to be reported under paragraph (c)(4) of 
this section, specify the nature of the change, the reason for the 
change, when the change occurred, and how the unit's compliance status 
was determined subsequent to the change, including what method was used 
to determine emissions when a change mandated the need for monitor 
recertification.



Sec. 96.31  Permitting authority's and Administrator's action on
compliance certifications.

    (a) The permitting authority or the Administrator may review and 
conduct independent audits concerning any compliance certification or 
any other submission under the NOX Budget Trading Program and 
make appropriate adjustments of the information in the compliance 
certifications or other submissions.
    (b) The Administrator may deduct NOX allowances from or 
transfer NOX allowances to a unit's compliance account or a 
source's overdraft account based on the information in the compliance 
certifications or other submissions, as adjusted under paragraph (a) of 
this section.



                   Subpart E_NOX Allowance Allocations



Sec. 96.40  State trading program budget.

    The State trading program budget allocated by the permitting 
authority under Sec. 96.42 for a control period will equal the total 
number of tons of NOX emissions apportioned to the 
NOX Budget units under Sec. 96.4 in the State for the 
control period, as determined by the applicable, approved State 
implementation plan.



Sec. 96.41  Timing requirements for NOX allowance allocations.

    (a) By September 30, 1999, the permitting authority will submit to 
the Administrator the NOX allowance allocations, in 
accordance with Sec. 96.42, for the control periods in 2003, 2004, and 
2005.
    (b) By April 1, 2003 and April 1 of each year thereafter, the 
permitting authority will submit to the Administrator the NOX 
allowance allocations, in accordance with Sec. 96.42, for the control 
period in the year that is three years after the year of the applicable 
deadline for submission under this paragraph (b). If the permitting 
authority fails to submit to the Administrator the NOX 
allowance allocations in accordance with this paragraph (b), the 
Administrator will allocate, for the applicable control period, the same 
number of NOX allowances as were allocated for the preceding 
control period.
    (c) By April 1, 2004 and April 1 of each year thereafter, the 
permitting authority will submit to the Administrator the NOX 
allowance allocations, in accordance with Sec. 96.42, for any 
NOX allowances remaining in the allocation set-aside for the 
prior control period.

[[Page 25]]



Sec. 96.42  NOX allowance allocations.

    (a)(1) The heat input (in mmBtu) used for calculating NOX 
allowance allocations for each NOX Budget unit under Sec. 
96.4 will be:
    (i) For a NOX allowance allocation under Sec. 96.41(a), 
the average of the two highest amounts of the unit's heat input for the 
control periods in 1995, 1996, and 1997 if the unit is under Sec. 
96.4(a)(1) or the control period in 1995 if the unit is under Sec. 
96.4(a)(2); and
    (ii) For a NOX allowance allocation under Sec. 96.41(b), 
the unit's heat input for the control period in the year that is four 
years before the year for which the NOX allocation is being 
calculated.
    (2) The unit's total heat input for the control period in each year 
specified under paragraph (a)(1) of this section will be determined in 
accordance with part 75 of this chapter if the NOX Budget 
unit was otherwise subject to the requirements of part 75 of this 
chapter for the year, or will be based on the best available data 
reported to the permitting authority for the unit if the unit was not 
otherwise subject to the requirements of part 75 of this chapter for the 
year.
    (b) For each control period under Sec. 96.41, the permitting 
authority will allocate to all NOX Budget units under Sec. 
96.4(a)(1) in the State that commenced operation before May 1 of the 
period used to calculate heat input under paragraph (a)(1) of this 
section, a total number of NOX allowances equal to 95 percent 
in 2003, 2004, and 2005, or 98 percent thereafter, of the tons of 
NOX emissions in the State trading program budget apportioned 
to electric generating units under Sec. 96.40 in accordance with the 
following procedures:
    (1) The permitting authority will allocate NOX allowances 
to each NOX Budget unit under Sec. 96.4(a)(1) in an amount 
equaling 0.15 lb/mmBtu multiplied by the heat input determined under 
paragraph (a) of this section, rounded to the nearest whole 
NOX allowance as appropriate.
    (2) If the initial total number of NOX allowances 
allocated to all NOX Budget units under Sec. 96.4(a)(1) in 
the State for a control period under paragraph (b)(1) of this section 
does not equal 95 percent in 2003, 2004, and 2005, or 98 percent 
thereafter, of the number of tons of NOX emissions in the 
State trading program budget apportioned to electric generating units, 
the permitting authority will adjust the total number of NOX 
allowances allocated to all such NOX Budget units for the 
control period under paragraph (b)(1) of this section so that the total 
number of NOX allowances allocated equals 95 percent in 2003, 
2004, and 2005, or 98 percent thereafter, of the number of tons of 
NOX emissions in the State trading program budget apportioned 
to electric generating units. This adjustment will be made by: 
multiplying each unit's allocation by 95 percent in 2003, 2004, and 
2005, or 98 percent thereafter, of the number of tons of NOX 
emissions in the State trading program budget apportioned to electric 
generating units divided by the total number of NOX 
allowances allocated under paragraph (b)(1) of this section, and 
rounding to the nearest whole NOX allowance as appropriate.
    (c) For each control period under Sec. 96.41, the permitting 
authority will allocate to all NOX Budget units under Sec. 
96.4(a)(2) in the State that commenced operation before May 1 of the 
period used to calculate heat input under paragraph (a)(1) of this 
section, a total number of NOX allowances equal to 95 percent 
in 2003, 2004, and 2005, or 98 percent thereafter, of the tons of 
NOX emissions in the State trading program budget apportioned 
to non-electric generating units under Sec. 96.40 in accordance with 
the following procedures:
    (1) The permitting authority will allocate NOX allowances 
to each NOX Budget unit under Sec. 96.4(a)(2) in an amount 
equaling 0.17 lb/mmBtu multiplied by the heat input determined under 
paragraph (a) of this section, rounded to the nearest whole 
NOX allowance as appropriate.
    (2) If the initial total number of NOX allowances 
allocated to all NOX Budget units under Sec. 96.4(a)(2) in 
the State for a control period under paragraph (c)(1) of this section 
does not equal 95 percent in 2003, 2004, and 2005, or 98 percent 
thereafter, of the number of tons of NOX emissions in the 
State trading program budget apportioned to non-electric generating 
units, the permitting authority will adjust the total number of 
NOX allowances allocated to

[[Page 26]]

all such NOX Budget units for the control period under 
paragraph (c)(1) of this section so that the total number of 
NOX allowances allocated equals 95 percent in 2003, 2004, and 
2005, or 98 percent thereafter, of the number of tons of NOX 
emissions in the State trading program budget apportioned to non-
electric generating units. This adjustment will be made by: multiplying 
each unit's allocation by 95 percent in 2003, 2004, and 2005, or 98 
percent thereafter, of the number of tons of NOX emissions in 
the State trading program budget apportioned to non-electric generating 
units divided by the total number of NOX allowances allocated 
under paragraph (c)(1) of this section, and rounding to the nearest 
whole NOX allowance as appropriate.
    (d) For each control period under Sec. 96.41, the permitting 
authority will allocate NOX allowances to NOX 
Budget units under Sec. 96.4 in the State that commenced operation, or 
is projected to commence operation, on or after May 1 of the period used 
to calculate heat input under paragraph (a)(1) of this section, in 
accordance with the following procedures:
    (1) The permitting authority will establish one allocation set-aside 
for each control period. Each allocation set-aside will be allocated 
NOX allowances equal to 5 percent in 2003, 2004, and 2005, or 
2 percent thereafter, of the tons of NOX emissions in the 
State trading program budget under Sec. 96.40, rounded to the nearest 
whole NOX allowance as appropriate.
    (2) The NOX authorized account representative of a 
NOX Budget unit under paragraph (d) of this section may 
submit to the permitting authority a request, in writing or in a format 
specified by the permitting authority, to be allocated NOX 
allowances for no more than five consecutive control periods under Sec. 
96.41, starting with the control period during which the NOX 
Budget unit commenced, or is projected to commence, operation and ending 
with the control period preceding the control period for which it will 
receive an allocation under paragraph (b) or (c) of this section. The 
NOX allowance allocation request must be submitted prior to 
May 1 of the first control period for which the NOX allowance 
allocation is requested and after the date on which the permitting 
authority issues a permit to construct the NOX Budget unit.
    (3) In a NOX allowance allocation request under paragraph 
(d)(2) of this section, the NOX authorized account 
representative for units under Sec. 96.4(a)(1) may request for a 
control period NOX allowances in an amount that does not 
exceed 0.15 lb/mmBtu multiplied by the NOX Budget unit's 
maximum design heat input (in mmBtu/hr) multiplied by the number of 
hours remaining in the control period starting with the first day in the 
control period on which the unit operated or is projected to operate.
    (4) In a NOX allowance allocation request under paragraph 
(d)(2) of this section, the NOX authorized account 
representative for units under Sec. 96.4(a)(2) may request for a 
control period NOX allowances in an amount that does not 
exceed 0.17 lb/mmBtu multiplied by the NOX Budget unit's 
maximum design heat input (in mmBtu/hr) multiplied by the number of 
hours remaining in the control period starting with the first day in the 
control period on which the unit operated or is projected to operate.
    (5) The permitting authority will review, and allocate 
NOX allowances pursuant to, each NOX allowance 
allocation request under paragraph (d)(2) of this section in the order 
that the request is received by the permitting authority.
    (i) Upon receipt of the NOX allowance allocation request, 
the permitting authority will determine whether, and will make any 
necessary adjustments to the request to ensure that, for units under 
Sec. 96.4(a)(1), the control period and the number of allowances 
specified are consistent with the requirements of paragraphs (d)(2) and 
(3) of this section and, for units under Sec. 96.4(a)(2), the control 
period and the number of allowances specified are consistent with the 
requirements of paragraphs (d)(2) and (4) of this section.
    (ii) If the allocation set-aside for the control period for which 
NOX allowances are requested has an amount of NOX 
allowances not less than the number requested (as adjusted under 
paragraph (d)(5)(i) of this section), the permitting authority will 
allocate the

[[Page 27]]

amount of the NOX allowances requested (as adjusted under 
paragraph (d)(5)(i) of this section) to the NOX Budget unit.
    (iii) If the allocation set-aside for the control period for which 
NOX allowances are requested has a smaller amount of 
NOX allowances than the number requested (as adjusted under 
paragraph (d)(5)(i) of this section), the permitting authority will deny 
in part the request and allocate only the remaining number of 
NOX allowances in the allocation set-aside to the 
NOX Budget unit.
    (iv) Once an allocation set-aside for a control period has been 
depleted of all NOX allowances, the permitting authority will 
deny, and will not allocate any NOX allowances pursuant to, 
any NOX allowance allocation request under which 
NOX allowances have not already been allocated for the 
control period.
    (6) Within 60 days of receipt of a NOX allowance 
allocation request, the permitting authority will take appropriate 
action under paragraph (d)(5) of this section and notify the 
NOX authorized account representative that submitted the 
request and the Administrator of the number of NOX allowances 
(if any) allocated for the control period to the NOX Budget 
unit.
    (e) For a NOX Budget unit that is allocated 
NOX allowances under paragraph (d) of this section for a 
control period, the Administrator will deduct NOX allowances 
under Sec. 96.54(b) or (e) to account for the actual utilization of the 
unit during the control period. The Administrator will calculate the 
number of NOX allowances to be deducted to account for the 
unit's actual utilization using the following formulas and rounding to 
the nearest whole NOX allowance as appropriate, provided that 
the number of NOX allowances to be deducted shall be zero if 
the number calculated is less than zero:

NOX allowances deducted for actual utilization for units 
under Sec. 96.4(a)(1) = (Unit's NOX allowances allocated for 
control period)-(Unit's actual control period utilization x 0.15 lb/
mmBtu); and
NOX allowances deducted for actual utilization for units 
under Sec. 96.4(a)(2) = (Unit's NOX allowances allocated for 
control period)-(Unit's actual control period utilization x 0.17 lb/
mmBtu)

Where:

``Unit's NOX allowances allocated for control period'' is the 
          number of NOX allowances allocated to the unit for 
          the control period under paragraph (d) of this section; and
``Unit's actual control period utilization'' is the utilization (in 
          mmBtu), as defined in Sec. 96.2, of the unit during the 
          control period.

    (f) After making the deductions for compliance under Sec. 96.54(b) 
or (e) for a control period, the Administrator will notify the 
permitting authority whether any NOX allowances remain in the 
allocation set-aside for the control period. The permitting authority 
will allocate any such NOX allowances to the NOX 
Budget units in the State using the following formula and rounding to 
the nearest whole NOX allowance as appropriate:

Unit's share of NOX allowances remaining in allocation set-
aside = Total NOX allowances remaining in allocation set-
aside x (Unit's NOX allowance allocation / State trading 
program budget excluding allocation set-aside)

Where:

``Total NOX allowances remaining in allocation set-aside'' is 
          the total number of NOX allowances remaining in the 
          allocation set-aside for the control period to which the 
          allocation set-aside applies;
``Unit's NOX allowance allocation'' is the number of 
          NOX allowances allocated under paragraph (b) or (c) 
          of this section to the unit for the control period to which 
          the allocation set-aside applies; and
``State trading program budget excluding allocation set-aside'' is the 
          State trading program budget under Sec. 96.40 for the control 
          period to which the allocation set-aside applies multiplied by 
          95 percent if the control period is in 2003, 2004, or 2005 or 
          98 percent if the control period is in any year thereafter, 
          rounded to the nearest whole NOX allowance as 
          appropriate.

[63 FR 57514, Oct. 27, 1998, as amended at 63 FR 71225, Dec. 24, 1998]

[[Page 28]]



                 Subpart F_NOX Allowance Tracking System



Sec. 96.50  NOX Allowance Tracking System accounts.

    (a) Nature and function of compliance accounts and overdraft 
accounts. Consistent with Sec. 96.51(a), the Administrator will 
establish one compliance account for each NOX Budget unit and 
one overdraft account for each source with one or more NOX 
Budget units. Allocations of NOX allowances pursuant to 
subpart E of this part or Sec. 96.88 and deductions or transfers of 
NOX allowances pursuant to Sec. 96.31, Sec. 96.54, Sec. 
96.56, subpart G of this part, or subpart I of this part will be 
recorded in the compliance accounts or overdraft accounts in accordance 
with this subpart.
    (b) Nature and function of general accounts. Consistent with Sec. 
96.51(b), the Administrator will establish, upon request, a general 
account for any person. Transfers of allowances pursuant to subpart G of 
this part will be recorded in the general account in accordance with 
this subpart.



Sec. 96.51  Establishment of accounts.

    (a) Compliance accounts and overdraft accounts. Upon receipt of a 
complete account certificate of representation under Sec. 96.13, the 
Administrator will establish:
    (1) A compliance account for each NOX Budget unit for 
which the account certificate of representation was submitted; and
    (2) An overdraft account for each source for which the account 
certificate of representation was submitted and that has two or more 
NOX Budget units.
    (b) General accounts. (1) Any person may apply to open a general 
account for the purpose of holding and transferring allowances. A 
complete application for a general account shall be submitted to the 
Administrator and shall include the following elements in a format 
prescribed by the Administrator:
    (i) Name, mailing address, e-mail address (if any), telephone 
number, and facsimile transmission number (if any) of the NOX 
authorized account representative and any alternate NOX 
authorized account representative;
    (ii) At the option of the NOX authorized account 
representative, organization name and type of organization;
    (iii) A list of all persons subject to a binding agreement for the 
NOX authorized account representative or any alternate 
NOX authorized account representative to represent their 
ownership interest with respect to the allowances held in the general 
account;
    (iv) The following certification statement by the NOX 
authorized account representative and any alternate NOX 
authorized account representative: ``I certify that I was selected as 
the NOX authorized account representative or the 
NOX alternate authorized account representative, as 
applicable, by an agreement that is binding on all persons who have an 
ownership interest with respect to allowances held in the general 
account. I certify that I have all the necessary authority to carry out 
my duties and responsibilities under the NOX Budget Trading 
Program on behalf of such persons and that each such person shall be 
fully bound by my representations, actions, inactions, or submissions 
and by any order or decision issued to me by the Administrator or a 
court regarding the general account.''
    (v) The signature of the NOX authorized account 
representative and any alternate NOX authorized account 
representative and the dates signed.
    (vi) Unless otherwise required by the permitting authority or the 
Administrator, documents of agreement referred to in the account 
certificate of representation shall not be submitted to the permitting 
authority or the Administrator. Neither the permitting authority nor the 
Administrator shall be under any obligation to review or evaluate the 
sufficiency of such documents, if submitted.
    (2) Upon receipt by the Administrator of a complete application for 
a general account under paragraph (b)(1) of this section:
    (i) The Administrator will establish a general account for the 
person or persons for whom the application is submitted.
    (ii) The NOX authorized account representative and any 
alternate NOX authorized account representative for the 
general account shall represent and, by

[[Page 29]]

his or her representations, actions, inactions, or submissions, legally 
bind each person who has an ownership interest with respect to 
NOX allowances held in the general account in all matters 
pertaining to the NOX Budget Trading Program, not 
withstanding any agreement between the NOX authorized account 
representative or any alternate NOX authorized account 
representative and such person. Any such person shall be bound by any 
order or decision issued to the NOX authorized account 
representative or any alternate NOX authorized account 
representative by the Administrator or a court regarding the general 
account.
    (iii) Each submission concerning the general account shall be 
submitted, signed, and certified by the NOX authorized 
account representative or any alternate NOX authorized 
account representative for the persons having an ownership interest with 
respect to NOX allowances held in the general account. Each 
such submission shall include the following certification statement by 
the NOX authorized account representative or any alternate 
NOX authorized account representative any: ``I am authorized 
to make this submission on behalf of the persons having an ownership 
interest with respect to the NOX allowances held in the 
general account. I certify under penalty of law that I have personally 
examined, and am familiar with, the statements and information submitted 
in this document and all its attachments. Based on my inquiry of those 
individuals with primary responsibility for obtaining the information, I 
certify that the statements and information are to the best of my 
knowledge and belief true, accurate, and complete. I am aware that there 
are significant penalties for submitting false statements and 
information or omitting required statements and information, including 
the possibility of fine or imprisonment.''
    (iv) The Administrator will accept or act on a submission concerning 
the general account only if the submission has been made, signed, and 
certified in accordance with paragraph (b)(2)(iii) of this section.
    (3)(i) An application for a general account may designate one and 
only one NOX authorized account representative and one and 
only one alternate NOX authorized account representative who 
may act on behalf of the NOX authorized account 
representative. The agreement by which the alternate NOX 
authorized account representative is selected shall include a procedure 
for authorizing the alternate NOX authorized account 
representative to act in lieu of the NOX authorized account 
representative.
    (ii) Upon receipt by the Administrator of a complete application for 
a general account under paragraph (b)(1) of this section, any 
representation, action, inaction, or submission by any alternate 
NOX authorized account representative shall be deemed to be a 
representation, action, inaction, or submission by the NOX 
authorized account representative.
    (4)(i) The NOX authorized account representative for a 
general account may be changed at any time upon receipt by the 
Administrator of a superseding complete application for a general 
account under paragraph (b)(1) of this section. Notwithstanding any such 
change, all representations, actions, inactions, and submissions by the 
previous NOX authorized account representative prior to the 
time and date when the Administrator receives the superseding 
application for a general account shall be binding on the new 
NOX authorized account representative and the persons with an 
ownership interest with respect to the allowances in the general 
account.
    (ii) The alternate NOX authorized account representative 
for a general account may be changed at any time upon receipt by the 
Administrator of a superseding complete application for a general 
account under paragraph (b)(1) of this section. Notwithstanding any such 
change, all representations, actions, inactions, and submissions by the 
previous alternate NOX authorized account representative 
prior to the time and date when the Administrator receives the 
superseding application for a general account shall be binding on the 
new alternate NOX authorized account representative and the 
persons with an ownership interest with respect to the allowances in the 
general account.

[[Page 30]]

    (iii)(A) In the event a new person having an ownership interest with 
respect to NOX allowances in the general account is not 
included in the list of such persons in the account certificate of 
representation, such new person shall be deemed to be subject to and 
bound by the account certificate of representation, the representation, 
actions, inactions, and submissions of the NOX authorized 
account representative and any alternate NOX authorized 
account representative of the source or unit, and the decisions, orders, 
actions, and inactions of the Administrator, as if the new person were 
included in such list.
    (B) Within 30 days following any change in the persons having an 
ownership interest with respect to NOX allowances in the 
general account, including the addition of persons, the NOX 
authorized account representative or any alternate NOX 
authorized account representative shall submit a revision to the 
application for a general account amending the list of persons having an 
ownership interest with respect to the NOX allowances in the 
general account to include the change.
    (5)(i) Once a complete application for a general account under 
paragraph (b)(1) of this section has been submitted and received, the 
Administrator will rely on the application unless and until a 
superseding complete application for a general account under paragraph 
(b)(1) of this section is received by the Administrator.
    (ii) Except as provided in paragraph (b)(4) of this section, no 
objection or other communication submitted to the Administrator 
concerning the authorization, or any representation, action, inaction, 
or submission of the NOX authorized account representative or 
any alternate NOX authorized account representative for a 
general account shall affect any representation, action, inaction, or 
submission of the NOX authorized account representative or 
any alternate NOX authorized account representative or the 
finality of any decision or order by the Administrator under the 
NOX Budget Trading Program.
    (iii) The Administrator will not adjudicate any private legal 
dispute concerning the authorization or any representation, action, 
inaction, or submission of the NOX authorized account 
representative or any alternate NOX authorized account 
representative for a general account, including private legal disputes 
concerning the proceeds of NOX allowance transfers.
    (c) Account identification. The Administrator will assign a unique 
identifying number to each account established under paragraph (a) or 
(b) of this section.



Sec. 96.52  NOX Allowance Tracking System responsibilities of NOX
authorized account representative.

    (a) Following the establishment of a NOX Allowance 
Tracking System account, all submissions to the Administrator pertaining 
to the account, including, but not limited to, submissions concerning 
the deduction or transfer of NOX allowances in the account, 
shall be made only by the NOX authorized account 
representative for the account.
    (b) Authorized account representative identification. The 
Administrator will assign a unique identifying number to each 
NOX authorized account representative.



Sec. 96.53  Recordation of NOX allowance allocations.

    (a) The Administrator will record the NOX allowances for 
2003 in the NOX Budget units' compliance accounts and the 
allocation set-asides, as allocated under subpart E of this part. The 
Administrator will also record the NOX allowances allocated 
under Sec. 96.88(a)(1) for each NOX Budget opt-in source in 
its compliance account.
    (b) Each year, after the Administrator has made all deductions from 
a NOX Budget unit's compliance account and the overdraft 
account pursuant to Sec. 96.54, the Administrator will record 
NOX allowances, as allocated to the unit under subpart E of 
this part or under Sec. 96.88(a)(2), in the compliance account for the 
year after the last year for which allowances were previously allocated 
to the compliance account. Each year, the Administrator will also record 
NOX allowances, as allocated under subpart E of this part, in 
the allocation set-aside for the year after the last year for which 
allowances were

[[Page 31]]

previously allocated to an allocation set-aside.
    (c) Serial numbers for allocated NOX allowances. When 
allocating NOX allowances to and recording them in an 
account, the Administrator will assign each NOX allowance a 
unique identification number that will include digits identifying the 
year for which the NOX allowance is allocated.



Sec. 96.54  Compliance.

    (a) NOX allowance transfer deadline. The NOX 
allowances are available to be deducted for compliance with a unit's 
NOX Budget emissions limitation for a control period in a 
given year only if the NOX allowances:
    (1) Were allocated for a control period in a prior year or the same 
year; and
    (2) Are held in the unit's compliance account, or the overdraft 
account of the source where the unit is located, as of the 
NOX allowance transfer deadline for that control period or 
are transferred into the compliance account or overdraft account by a 
NOX allowance transfer correctly submitted for recordation 
under Sec. 96.60 by the NOX allowance transfer deadline for 
that control period.
    (b) Deductions for compliance. (1) Following the recordation, in 
accordance with Sec. 96.61, of NOX allowance transfers 
submitted for recordation in the unit's compliance account or the 
overdraft account of the source where the unit is located by the 
NOX allowance transfer deadline for a control period, the 
Administrator will deduct NOX allowances available under 
paragraph (a) of this section to cover the unit's NOX 
emissions (as determined in accordance with subpart H of this part), or 
to account for actual utilization under Sec. 96.42(e), for the control 
period:
    (i) From the compliance account; and
    (ii) Only if no more NOX allowances available under 
paragraph (a) of this section remain in the compliance account, from the 
overdraft account. In deducting allowances for units at the source from 
the overdraft account, the Administrator will begin with the unit having 
the compliance account with the lowest NOX Allowance Tracking 
System account number and end with the unit having the compliance 
account with the highest NOX Allowance Tracking System 
account number (with account numbers sorted beginning with the left-most 
character and ending with the right-most character and the letter 
characters assigned values in alphabetical order and less than all 
numeric characters).
    (2) The Administrator will deduct NOX allowances first 
under paragraph (b)(1)(i) of this section and then under paragraph 
(b)(1)(ii) of this section:
    (i) Until the number of NOX allowances deducted for the 
control period equals the number of tons of NOX emissions, 
determined in accordance with subpart H of this part, from the unit for 
the control period for which compliance is being determined, plus the 
number of NOX allowances required for deduction to account 
for actual utilization under Sec. 96.42(e) for the control period; or
    (ii) Until no more NOX allowances available under 
paragraph (a) of this section remain in the respective account.
    (c)(1) Identification of NOX allowances by serial number. 
The NOX authorized account representative for each compliance 
account may identify by serial number the NOX allowances to 
be deducted from the unit's compliance account under paragraph (b), (d), 
or (e) of this section. Such identification shall be made in the 
compliance certification report submitted in accordance with Sec. 
96.30.
    (2) First-in, first-out. The Administrator will deduct 
NOX allowances for a control period from the compliance 
account, in the absence of an identification or in the case of a partial 
identification of NOX allowances by serial number under 
paragraph (c)(1) of this section, or the overdraft account on a first-
in, first-out (FIFO) accounting basis in the following order:
    (i) Those NOX allowances that were allocated for the 
control period to the unit under subpart E or I of this part;
    (ii) Those NOX allowances that were allocated for the 
control period to any unit and transferred and recorded in the account 
pursuant to subpart G of this part, in order of their date of 
recordation;
    (iii) Those NOX allowances that were allocated for a 
prior control period to

[[Page 32]]

the unit under subpart E or I of this part; and
    (iv) Those NOX allowances that were allocated for a prior 
control period to any unit and transferred and recorded in the account 
pursuant to subpart G of this part, in order of their date of 
recordation.
    (d) Deductions for excess emissions. (1) After making the deductions 
for compliance under paragraph (b) of this section, the Administrator 
will deduct from the unit's compliance account or the overdraft account 
of the source where the unit is located a number of NOX 
allowances, allocated for a control period after the control period in 
which the unit has excess emissions, equal to three times the number of 
the unit's excess emissions.
    (2) If the compliance account or overdraft account does not contain 
sufficient NOX allowances, the Administrator will deduct the 
required number of NOX allowances, regardless of the control 
period for which they were allocated, whenever NOX allowances 
are recorded in either account.
    (3) Any allowance deduction required under paragraph (d) of this 
section shall not affect the liability of the owners and operators of 
the NOX Budget unit for any fine, penalty, or assessment, or 
their obligation to comply with any other remedy, for the same 
violation, as ordered under the CAA or applicable State law. The 
following guidelines will be followed in assessing fines, penalties or 
other obligations:
    (i) For purposes of determining the number of days of violation, if 
a NOX Budget unit has excess emissions for a control period, 
each day in the control period (153 days) constitutes a day in violation 
unless the owners and operators of the unit demonstrate that a lesser 
number of days should be considered.
    (ii) Each ton of excess emissions is a separate violation.
    (e) Deductions for units sharing a common stack. In the case of 
units sharing a common stack and having emissions that are not 
separately monitored or apportioned in accordance with subpart H of this 
part:
    (1) The NOX authorized account representative of the 
units may identify the percentage of NOX allowances to be 
deducted from each such unit's compliance account to cover the unit's 
share of NOX emissions from the common stack for a control 
period. Such identification shall be made in the compliance 
certification report submitted in accordance with Sec. 96.30.
    (2) Notwithstanding paragraph (b)(2)(i) of this section, the 
Administrator will deduct NOX allowances for each such unit 
until the number of NOX allowances deducted equals the unit's 
identified percentage (under paragraph (e)(1) of this section) of the 
number of tons of NOX emissions, as determined in accordance 
with subpart H of this part, from the common stack for the control 
period for which compliance is being determined or, if no percentage is 
identified, an equal percentage for each such unit, plus the number of 
allowances required for deduction to account for actual utilization 
under Sec. 96.42(e) for the control period.
    (f) The Administrator will record in the appropriate compliance 
account or overdraft account all deductions from such an account 
pursuant to paragraphs (b), (d), or (e) of this section.



Sec. 96.55  Banking.

    (a) NOX allowances may be banked for future use or 
transfer in a compliance account, an overdraft account, or a general 
account, as follows:
    (1) Any NOX allowance that is held in a compliance 
account, an overdraft account, or a general account will remain in such 
account unless and until the NOX allowance is deducted or 
transferred under Sec. 96.31, Sec. 96.54, Sec. 96.56, subpart G of 
this part, or subpart I of this part.
    (2) The Administrator will designate, as a ``banked'' NOX 
allowance, any NOX allowance that remains in a compliance 
account, an overdraft account, or a general account after the 
Administrator has made all deductions for a given control period from 
the compliance account or overdraft account pursuant to Sec. 96.54.
    (b) Each year starting in 2004, after the Administrator has 
completed the designation of banked NOX allowances under 
paragraph (a)(2) of this section and before May 1 of the year, the 
Administrator will determine the extent to which banked NOX 
allowances may

[[Page 33]]

be used for compliance in the control period for the current year, as 
follows:
    (1) The Administrator will determine the total number of banked 
NOX allowances held in compliance accounts, overdraft 
accounts, or general accounts.
    (2) If the total number of banked NOX allowances 
determined, under paragraph (b)(1) of this section, to be held in 
compliance accounts, overdraft accounts, or general accounts is less 
than or equal to 10% of the sum of the State trading program budgets for 
the control period for the States in which NOX Budget units 
are located, any banked NOX allowance may be deducted for 
compliance in accordance with Sec. 96.54.
    (3) If the total number of banked NOX allowances 
determined, under paragraph (b)(1) of this section, to be held in 
compliance accounts, overdraft accounts, or general accounts exceeds 10% 
of the sum of the State trading program budgets for the control period 
for the States in which NOX Budget units are located, any 
banked allowance may be deducted for compliance in accordance with Sec. 
96.54, except as follows:
    (i) The Administrator will determine the following ratio: 0.10 
multiplied by the sum of the State trading program budgets for the 
control period for the States in which NOX Budget units are 
located and divided by the total number of banked NOX 
allowances determined, under paragraph (b)(1) of this section, to be 
held in compliance accounts, overdraft accounts, or general accounts.
    (ii) The Administrator will multiply the number of banked 
NOX allowances in each compliance account or overdraft 
account. The resulting product is the number of banked NOX 
allowances in the account that may be deducted for compliance in 
accordance with Sec. 96.54. Any banked NOX allowances in 
excess of the resulting product may be deducted for compliance in 
accordance with Sec. 96.54, except that, if such NOX 
allowances are used to make a deduction, two such NOX 
allowances must be deducted for each deduction of one NOX 
allowance required under Sec. 96.54.
    (c) Any NOX Budget unit may reduce its NOX 
emission rate in the 2001 or 2002 control period, the owner or operator 
of the unit may request early reduction credits, and the permitting 
authority may allocate NOX allowances in 2003 to the unit in 
accordance with the following requirements.
    (1) Each NOX Budget unit for which the owner or operator 
requests any early reduction credits under paragraph (c)(4) of this 
section shall monitor NOX emissions in accordance with 
subpart H of this part starting in the 2000 control period and for each 
control period for which such early reduction credits are requested. The 
unit's monitoring system availability shall be not less than 90 percent 
during the 2000 control period, and the unit must be in compliance with 
any applicable State or Federal emissions or emissions-related 
requirements.
    (2) NOX emission rate and heat input under paragraphs 
(c)(3) through (5) of this section shall be determined in accordance 
with subpart H of this part.
    (3) Each NOX Budget unit for which the owner or operator 
requests any early reduction credits under paragraph (c)(4) of this 
section shall reduce its NOX emission rate, for each control 
period for which early reduction credits are requested, to less than 
both 0.25 lb/mmBtu and 80 percent of the unit's NOX emission 
rate in the 2000 control period.
    (4) The NOX authorized account representative of a 
NOX Budget unit that meets the requirements of paragraphs 
(c)(1)and (3) of this section may submit to the permitting authority a 
request for early reduction credits for the unit based on NOX 
emission rate reductions made by the unit in the control period for 2001 
or 2002 in accordance with paragraph (c)(3) of this section.
    (i) In the early reduction credit request, the NOX 
authorized account may request early reduction credits for such control 
period in an amount equal to the unit's heat input for such control 
period multiplied by the difference between 0.25 lb/mmBtu and the unit's 
NOX emission rate for such control period, divided by 2000 
lb/ton, and rounded to the nearest ton.
    (ii) The early reduction credit request must be submitted, in a 
format specified by the permitting authority, by October 31 of the year 
in which the NOX emission rate reductions on which

[[Page 34]]

the request is based are made or such later date approved by the 
permitting authority.
    (5) The permitting authority will allocate NOX 
allowances, to NOX Budget units meeting the requirements of 
paragraphs (c)(1) and (3) of this section and covered by early reduction 
requests meeting the requirements of paragraph (c)(4)(ii) of this 
section, in accordance with the following procedures:
    (i) Upon receipt of each early reduction credit request, the 
permitting authority will accept the request only if the requirements of 
paragraphs (c)(1), (c)(3), and (c)(4)(ii) of this section are met and, 
if the request is accepted, will make any necessary adjustments to the 
request to ensure that the amount of the early reduction credits 
requested meets the requirement of paragraphs (c)(2) and (4) of this 
section.
    (ii) If the State's compliance supplement pool has an amount of 
NOX allowances not less than the number of early reduction 
credits in all accepted early reduction credit requests for 2001 and 
2002 (as adjusted under paragraph (c)(5)(i) of this section), the 
permitting authority will allocate to each NOX Budget unit 
covered by such accepted requests one allowance for each early reduction 
credit requested (as adjusted under paragraph (c)(5)(i) of this 
section).
    (iii) If the State's compliance supplement pool has a smaller amount 
of NOX allowances than the number of early reduction credits 
in all accepted early reduction credit requests for 2001 and 2002 (as 
adjusted under paragraph (c)(5)(i) of this section), the permitting 
authority will allocate NOX allowances to each NOX 
Budget unit covered by such accepted requests according to the following 
formula:

Unit's allocated early reduction credits = [(Unit's adjusted early 
reduction credits) / (Total adjusted early reduction credits requested 
by all units)] x (Available NOX allowances from the State's 
compliance supplement pool)

where:

``Unit's adjusted early reduction credits'' is the number of early 
          reduction credits for the unit for 2001 and 2002 in accepted 
          early reduction credit requests, as adjusted under paragraph 
          (c)(5)(i) of this section.
``Total adjusted early reduction credits requested by all units'' is the 
          number of early reduction credits for all units for 2001 and 
          2002 in accepted early reduction credit requests, as adjusted 
          under paragraph (c)(5)(i) of this section.
``Available NOX allowances from the State's compliance 
          supplement pool'' is the number of NOX allowances 
          in the State's compliance supplement pool and available for 
          early reduction credits for 2001 and 2002.

    (6) By May 1, 2003, the permitting authority will submit to the 
Administrator the allocations of NOX allowances determined 
under paragraph (c)(5) of this section. The Administrator will record 
such allocations to the extent that they are consistent with the 
requirements of paragraphs (c)(1) through (5) of this section.
    (7) NOX allowances recorded under paragraph (c)(6) of 
this section may be deducted for compliance under Sec. 96.54 for the 
control periods in 2003 or 2004. Notwithstanding paragraph (a) of this 
section, the Administrator will deduct as retired any NOX 
allowance that is recorded under paragraph (c)(6) of this section and is 
not deducted for compliance in accordance with Sec. 96.54 for the 
control period in 2003 or 2004.
    (8) NOX allowances recorded under paragraph (c)(6) of 
this section are treated as banked allowances in 2004 for the purposes 
of paragraphs (a) and (b) of this section.



Sec. 96.56  Account error.

    The Administrator may, at his or her sole discretion and on his or 
her own motion, correct any error in any NOX Allowance 
Tracking System account. Within 10 business days of making such 
correction, the Administrator will notify the NOX authorized 
account representative for the account.



Sec. 96.57  Closing of general accounts.

    (a) The NOX authorized account representative of a 
general account may instruct the Administrator to close the account by 
submitting a statement requesting deletion of the account from the 
NOX Allowance Tracking System and by correctly submitting for 
recordation under Sec. 96.60 an allowance transfer of all 
NOX allowances in the

[[Page 35]]

account to one or more other NOX Allowance Tracking System 
accounts.
    (b) If a general account shows no activity for a period of a year or 
more and does not contain any NOX allowances, the 
Administrator may notify the NOX authorized account 
representative for the account that the account will be closed and 
deleted from the NOX Allowance Tracking System following 20 
business days after the notice is sent. The account will be closed after 
the 20-day period unless before the end of the 20-day period the 
Administrator receives a correctly submitted transfer of NOX 
allowances into the account under Sec. 96.60 or a statement submitted 
by the NOX authorized account representative demonstrating to 
the satisfaction of the Administrator good cause as to why the account 
should not be closed.



                    Subpart G_NOX Allowance Transfers



Sec. 96.60  Submission of NOX allowance transfers.

    The NOX authorized account representatives seeking 
recordation of a NOX allowance transfer shall submit the 
transfer to the Administrator. To be considered correctly submitted, the 
NOX allowance transfer shall include the following elements 
in a format specified by the Administrator:
    (a) The numbers identifying both the transferor and transferee 
accounts;
    (b) A specification by serial number of each NOX 
allowance to be transferred; and
    (c) The printed name and signature of the NOX authorized 
account representative of the transferor account and the date signed.



Sec. 96.61  EPA recordation.

    (a) Within 5 business days of receiving a NOX allowance 
transfer, except as provided in paragraph (b) of this section, the 
Administrator will record a NOX allowance transfer by moving 
each NOX allowance from the transferor account to the 
transferee account as specified by the request, provided that:
    (1) The transfer is correctly submitted under Sec. 96.60;
    (2) The transferor account includes each NOX allowance 
identified by serial number in the transfer; and
    (3) The transfer meets all other requirements of this part.
    (b) A NOX allowance transfer that is submitted for 
recordation following the NOX allowance transfer deadline and 
that includes any NOX allowances allocated for a control 
period prior to or the same as the control period to which the 
NOX allowance transfer deadline applies will not be recorded 
until after completion of the process of recordation of NOX 
allowance allocations in Sec. 96.53(b).
    (c) Where a NOX allowance transfer submitted for 
recordation fails to meet the requirements of paragraph (a) of this 
section, the Administrator will not record such transfer.



Sec. 96.62  Notification.

    (a) Notification of recordation. Within 5 business days of 
recordation of a NOX allowance transfer under Sec. 96.61, 
the Administrator will notify each party to the transfer. Notice will be 
given to the NOX authorized account representatives of both 
the transferror and transferee accounts.
    (b) Notification of non-recordation. Within 10 business days of 
receipt of a NOX allowance transfer that fails to meet the 
requirements of Sec. 96.61(a), the Administrator will notify the 
NOX authorized account representatives of both accounts 
subject to the transfer of:
    (1) A decision not to record the transfer, and (2) The reasons for 
such non-recordation.
    (c) Nothing in this section shall preclude the submission of a 
NOX allowance transfer for recordation following notification 
of non-recordation.



                   Subpart H_Monitoring and Reporting



Sec. 96.70  General requirements.

    The owners and operators, and to the extent applicable, the 
NOX authorized account representative of a NOX 
Budget unit, shall comply with the monitoring and reporting requirements 
as provided in this subpart and in subpart

[[Page 36]]

H of part 75 of this chapter. For purposes of complying with such 
requirements, the definitions in Sec. 96.2 and in Sec. 72.2 of this 
chapter shall apply, and the terms ``affected unit,'' ``designated 
representative,'' and ``continuous emission monitoring system'' (or 
``CEMS'') in part 75 of this chapter shall be replaced by the terms 
``NOX Budget unit,'' ``NOX authorized account 
representative,'' and ``continuous emission monitoring system'' (or 
``CEMS''), respectively, as defined in Sec. 96.2.
    (a) Requirements for installation, certification, and data 
accounting. The owner or operator of each NOX Budget unit 
must meet the following requirements. These provisions also apply to a 
unit for which an application for a NOX Budget opt-in permit 
is submitted and not denied or withdrawn, as provided in subpart I of 
this part:
    (1) Install all monitoring systems required under this subpart for 
monitoring NOX mass. This includes all systems required to 
monitor NOX emission rate, NOX concentration, heat 
input, and flow, in accordance with Sec. Sec. 75.72 and 75.76.
    (2) Install all monitoring systems for monitoring heat input, if 
required under Sec. 96.76 for developing NOX allowance 
allocations.
    (3) Successfully complete all certification tests required under 
Sec. 96.71 and meet all other provisions of this subpart and part 75 of 
this chapter applicable to the monitoring systems under paragraphs 
(a)(1) and (2) of this section.
    (4) Record, and report data from the monitoring systems under 
paragraphs (a)(1) and (2) of this section.
    (b) Compliance dates. The owner or operator must meet the 
requirements of paragraphs (a)(1) through (a)(3) of this section on or 
before the following dates and must record and report data on and after 
the following dates:
    (1) NOX Budget units for which the owner or operator 
intends to apply for early reduction credits under Sec. 96.55(d) must 
comply with the requirements of this subpart by May 1, 2000.
    (2) Except for NOX Budget units under paragraph (b)(1) of 
this section, NOX Budget units under Sec. 96.4 that commence 
operation before January 1, 2002, must comply with the requirements of 
this subpart by May 1, 2002.
    (3) NOX Budget units under Sec. 96.4 that commence 
operation on or after January 1, 2002 and that report on an annual basis 
under Sec. 96.74(d) must comply with the requirements of this subpart 
by the later of the following dates:
    (i) May 1, 2002; or
    (ii) The earlier of:
    (A) 180 days after the date on which the unit commences operation 
or, (B) For units under Sec. 96.4(a)(1), 90 days after the date on 
which the unit commences commercial operation.
    (4) NOX Budget units under Sec. 96.4 that commence 
operation on or after January 1, 2002 and that report on a control 
season basis under Sec. 96.74(d) must comply with the requirements of 
this subpart by the later of the following dates:
    (i) The earlier of:
    (A) 180 days after the date on which the unit commences operation 
or,
    (B) For units under Sec. 96.4(a)(1), 90 days after the date on 
which the unit commences commercial operation.
    (ii) However, if the applicable deadline under paragraph (b)(4)(i) 
section does not occur during a control period, May 1; immediately 
following the date determined in accordance with paragraph (b)(4)(i) of 
this section.
    (5) For a NOX Budget unit with a new stack or flue for 
which construction is completed after the applicable deadline under 
paragraph (b)(1), (b)(2) or (b)(3) of this section or subpart I of this 
part:
    (i) 90 days after the date on which emissions first exit to the 
atmosphere through the new stack or flue;
    (ii) However, if the unit reports on a control season basis under 
Sec. 96.74(d) and the applicable deadline under paragraph (b)(5)(i) of 
this section does not occur during the control period, May 1 immediately 
following the applicable deadline in paragraph (b)(5)(i) of this 
section.
    (6) For a unit for which an application for a NOX Budget 
opt in permit is submitted and not denied or withdrawn, the compliance 
dates specified under subpart I of this part.
    (c) Reporting data prior to initial certification. (1) The owner or 
operator of a NOX Budget unit that misses the certification 
deadline under paragraph (b)(1) of this section is not eligible to apply 
for early reduction credits. The owner or operator of the unit becomes

[[Page 37]]

subject to the certification deadline under paragraph (b)(2) of this 
section.
    (2) The owner or operator of a NOX Budget under 
paragraphs (b)(3) or (b)(4) of this section must determine, record and 
report NOX mass, heat input (if required for purposes of 
allocations) and any other values required to determine NOX 
Mass (e.g. NOX emission rate and heat input or NOX 
concentration and stack flow) using the provisions of Sec. 75.70(g) of 
this chapter, from the date and hour that the unit starts operating 
until all required certification tests are successfully completed.
    (d) Prohibitions. (1) No owner or operator of a NOX 
Budget unit or a non-NOX Budget unit monitored under Sec. 
75.72(b)(2)(ii) shall use any alternative monitoring system, alternative 
reference method, or any other alternative for the required continuous 
emission monitoring system without having obtained prior written 
approval in accordance with Sec. 96.75.
    (2) No owner or operator of a NOX Budget unit or a non-
NOX Budget unit monitored under Sec. 75.72(b)(2)(ii) shall 
operate the unit so as to discharge, or allow to be discharged, 
NOX emissions to the atmosphere without accounting for all 
such emissions in accordance with the applicable provisions of this 
subpart and part 75 of this chapter except as provided for in Sec. 
75.74 of this chapter.
    (3) No owner or operator of a NOX Budget unit or a non-
NOX Budget unit monitored under Sec. 75.72(b)(2)(ii) shall 
disrupt the continuous emission monitoring system, any portion thereof, 
or any other approved emission monitoring method, and thereby avoid 
monitoring and recording NOX mass emissions discharged into 
the atmosphere, except for periods of recertification or periods when 
calibration, quality assurance testing, or maintenance is performed in 
accordance with the applicable provisions of this subpart and part 75 of 
this chapter except as provided for in Sec. 75.74 of this chapter.
    (4) No owner or operator of a NOX Budget unit or a non-
NOX Budget unit monitored under Sec. 75.72(b)(2)(ii) shall 
retire or permanently discontinue use of the continuous emission 
monitoring system, any component thereof, or any other approved emission 
monitoring system under this subpart, except under any one of the 
following circumstances:
    (i) During the period that the unit is covered by a retired unit 
exemption under Sec. 96.5 that is in effect;
    (ii) The owner or operator is monitoring emissions from the unit 
with another certified monitoring system approved, in accordance with 
the applicable provisions of this subpart and part 75 of this chapter, 
by the permitting authority for use at that unit that provides emission 
data for the same pollutant or parameter as the retired or discontinued 
monitoring system; or
    (iii) The NOX authorized account representative submits 
notification of the date of certification testing of a replacement 
monitoring system in accordance with Sec. 96.71(b)(2).



Sec. 96.71  Initial certification and recertification procedures.

    (a) The owner or operator of a NOX Budget unit that is 
subject to an Acid Rain emissions limitation shall comply with the 
initial certification and recertification procedures of part 75 of this 
chapter, except that:
    (1) If, prior to January 1, 1998, the Administrator approved a 
petition under Sec. 75.17(a) or (b) of this chapter for apportioning 
the NOX emission rate measured in a common stack or a 
petition under Sec. 75.66 of this chapter for an alternative to a 
requirement in Sec. 75.17 of this chapter, the NOX 
authorized account representative shall resubmit the petition to the 
Administrator under Sec. 96.75(a) to determine if the approval applies 
under the NOX Budget Trading Program.
    (2) For any additional CEMS required under the common stack 
provisions in Sec. 75.72 of this chapter, or for any NOX 
concentration CEMS used under the provisions of Sec. 75.71(a)(2) of 
this chapter, the owner or operator shall meet the requirements of 
paragraph (b) of this section.
    (b) The owner or operator of a NOX Budget unit that is 
not subject to an Acid Rain emissions limitation shall comply with the 
following initial certification and recertification procedures, except 
that the owner or operator of a unit that qualifies to use the

[[Page 38]]

low mass emissions excepted monitoring methodology under Sec. 75.19 
shall also meet the requirements of paragraph (c) of this section and 
the owner or operator of a unit that qualifies to use an alternative 
monitoring system under subpart E of part 75 of this chapter shall also 
meet the requirements of paragraph (d) of this section. The owner or 
operator of a NOX Budget unit that is subject to an Acid Rain 
emissions limitation, but requires additional CEMS under the common 
stack provisions in Sec. 75.72 of this chapter, or that uses a 
NOX concentration CEMS under Sec. 75.71(a)(2) of this 
chapter also shall comply with the following initial certification and 
recertification procedures.
    (1) Requirements for initial certification. The owner or operator 
shall ensure that each monitoring system required by subpart H of part 
75 of this chapter (which includes the automated data acquisition and 
handling system) successfully completes all of the initial certification 
testing required under Sec. 75.20 of this chapter. The owner or 
operator shall ensure that all applicable certification tests are 
successfully completed by the deadlines specified in Sec. 96.70(b). In 
addition, whenever the owner or operator installs a monitoring system in 
order to meet the requirements of this part in a location where no such 
monitoring system was previously installed, initial certification 
according to Sec. 75.20 is required.
    (2) Requirements for recertification. Whenever the owner or operator 
makes a replacement, modification, or change in a certified monitoring 
system that the Administrator or the permitting authority determines 
significantly affects the ability of the system to accurately measure or 
record NOX mass emissions or heat input or to meet the 
requirements of Sec. 75.21 of this chapter or appendix B to part 75 of 
this chapter, the owner or operator shall recertify the monitoring 
system according to Sec. 75.20(b) of this chapter. Furthermore, 
whenever the owner or operator makes a replacement, modification, or 
change to the flue gas handling system or the unit's operation that the 
Administrator or the permitting authority determines to significantly 
change the flow or concentration profile, the owner or operator shall 
recertify the continuous emissions monitoring system according to Sec. 
75.20(b) of this chapter. Examples of changes which require 
recertification include: replacement of the analyzer, change in location 
or orientation of the sampling probe or site, or changing of flow rate 
monitor polynomial coefficients.
    (3) Certification approval process for initial certifications and 
recertification--(i) Notification of certification. The NOX 
authorized account representative shall submit to the permitting 
authority, the appropriate EPA Regional Office and the permitting 
authority a written notice of the dates of certification in accordance 
with Sec. 96.73.
    (ii) Certification application. The NOX authorized 
account representative shall submit to the permitting authority a 
certification application for each monitoring system required under 
subpart H of part 75 of this chapter. A complete certification 
application shall include the information specified in subpart H of part 
75 of this chapter.
    (iii) Except for units using the low mass emission excepted 
methodology under Sec. 75.19 of this chapter, the provisional 
certification date for a monitor shall be determined using the 
procedures set forth in Sec. 75.20(a)(3) of this chapter. A 
provisionally certified monitor may be used under the NOX 
Budget Trading Program for a period not to exceed 120 days after receipt 
by the permitting authority of the complete certification application 
for the monitoring system or component thereof under paragraph 
(b)(3)(ii) of this section. Data measured and recorded by the 
provisionally certified monitoring system or component thereof, in 
accordance with the requirements of part 75 of this chapter, will be 
considered valid quality-assured data (retroactive to the date and time 
of provisional certification), provided that the permitting authority 
does not invalidate the provisional certification by issuing a notice of 
disapproval within 120 days of receipt of the complete certification 
application by the permitting authority.

[[Page 39]]

    (iv) Certification application formal approval process. The 
permitting authority will issue a written notice of approval or 
disapproval of the certification application to the owner or operator 
within 120 days of receipt of the complete certification application 
under paragraph (b)(3)(ii) of this section. In the event the permitting 
authority does not issue such a notice within such 120-day period, each 
monitoring system which meets the applicable performance requirements of 
part 75 of this chapter and is included in the certification application 
will be deemed certified for use under the NOX Budget Trading 
Program.
    (A) Approval notice. If the certification application is complete 
and shows that each monitoring system meets the applicable performance 
requirements of part 75 of this chapter, then the permitting authority 
will issue a written notice of approval of the certification application 
within 120 days of receipt.
    (B) Incomplete application notice. A certification application will 
be considered complete when all of the applicable information required 
to be submitted under paragraph (b)(3)(ii) of this section has been 
received by the permitting authority. If the certification application 
is not complete, then the permitting authority will issue a written 
notice of incompleteness that sets a reasonable date by which the 
NOX authorized account representative must submit the 
additional information required to complete the certification 
application. If the NOX authorized account representative 
does not comply with the notice of incompleteness by the specified date, 
then the permitting authority may issue a notice of disapproval under 
paragraph (b)(3)(iv)(C) of this section.
    (C) Disapproval notice. If the certification application shows that 
any monitoring system or component thereof does not meet the performance 
requirements of this part, or if the certification application is 
incomplete and the requirement for disapproval under paragraph 
(b)(3)(iv)(B) of this section has been met, the permitting authority 
will issue a written notice of disapproval of the certification 
application. Upon issuance of such notice of disapproval, the 
provisional certification is invalidated by the permitting authority and 
the data measured and recorded by each uncertified monitoring system or 
component thereof shall not be considered valid quality-assured data 
beginning with the date and hour of provisional certification. The owner 
or operator shall follow the procedures for loss of certification in 
paragraph (b)(3)(v) of this section for each monitoring system or 
component thereof which is disapproved for initial certification.
    (D) Audit decertification. The permitting authority may issue a 
notice of disapproval of the certification status of a monitor in 
accordance with Sec. 96.72(b).
    (v) Procedures for loss of certification. If the permitting 
authority issues a notice of disapproval of a certification application 
under paragraph (b)(3)(iv)(C) of this section or a notice of disapproval 
of certification status under paragraph (b)(3)(iv)(D) of this section, 
then:
    (A) The owner or operator shall substitute the following values, for 
each hour of unit operation during the period of invalid data beginning 
with the date and hour of provisional certification and continuing until 
the time, date, and hour specified under Sec. 75.20(a)(5)(i) of this 
chapter:
    (1) For units using or intending to monitor for NOX 
emission rate and heat input or for units using the low mass emission 
excepted methodology under Sec. 75.19 of this chapter, the maximum 
potential NOX emission rate and the maximum potential hourly 
heat input of the unit.
    (2) For units intending to monitor for NOX mass emissions 
using a NOX pollutant concentration monitor and a flow 
monitor, the maximum potential concentration of NOX and the 
maximum potential flow rate of the unit under section 2.1 of appendix A 
of part 75 of this chapter;
    (B) The NOX authorized account representative shall 
submit a notification of certification retest dates and a new 
certification application in accordance with paragraphs (b)(3)(i) and 
(ii) of this section; and

[[Page 40]]

    (C) The owner or operator shall repeat all certification tests or 
other requirements that were failed by the monitoring system, as 
indicated in the permitting authority's notice of disapproval, no later 
than 30 unit operating days after the date of issuance of the notice of 
disapproval.
    (c) Initial certification and recertification procedures for low 
mass emission units using the excepted methodologies under Sec. 75.19 
of this chapter. The owner or operator of a gas-fired or oil-fired unit 
using the low mass emissions excepted methodology under Sec. 75.19 of 
this chapter shall meet the applicable general operating requirements of 
Sec. 75.10 of this chapter, the applicable requirements of Sec. 75.19 
of this chapter, and the applicable certification requirements of Sec. 
96.71 of this chapter, except that the excepted methodology shall be 
deemed provisionally certified for use under the NOX Budget 
Trading Program, as of the following dates:
    (1) For units that are reporting on an annual basis under Sec. 
96.74(d);
    (i) For a unit that has commences operation before its compliance 
deadline under Sec. 96.71(b), from January 1 of the year following 
submission of the certification application for approval to use the low 
mass emissions excepted methodology under Sec. 75.19 of this chapter 
until the completion of the period for the permitting authority review; 
or
    (ii) For a unit that commences operation after its compliance 
deadline under Sec. 96.71(b), the date of submission of the 
certification application for approval to use the low mass emissions 
excepted methodology under Sec. 75.19 of this chapter until the 
completion of the period for permitting authority review, or
    (2) For units that are reporting on a control period basis under 
Sec. 96.74(b)(3)(ii) of this part:
    (i) For a unit that commenced operation before its compliance 
deadline under Sec. 96.71(b), where the certification application is 
submitted before May 1, from May 1 of the year of the submission of the 
certification application for approval to use the low mass emissions 
excepted methodology under Sec. 75.19 of this chapter until the 
completion of the period for the permitting authority review; or
    (ii) For a unit that commenced operation before its compliance 
deadline under Sec. 96.71(b), where the certification application is 
submitted after May 1, from May 1 of the year following submission of 
the certification application for approval to use the low mass emissions 
excepted methodology under Sec. 75.19 of this chapter until the 
completion of the period for the permitting authority review; or
    (iii) For a unit that commences operation after its compliance 
deadline under Sec. 96.71(b), where the unit commences operation before 
May 1, from May 1 of the year that the unit commenced operation, until 
the completion of the period for the permitting authority's review.
    (iv) For a unit that has not operated after its compliance deadline 
under Sec. 96.71(b), where the certification application is submitted 
after May 1, but before October 1st, from the date of submission of a 
certification application for approval to use the low mass emissions 
excepted methodology under Sec. 75.19 of this chapter until the 
completion of the period for the permitting authority's review.
    (d) Certification/recertification procedures for alternative 
monitoring systems. The NOX authorized account representative 
representing the owner or operator of each unit applying to monitor 
using an alternative monitoring system approved by the Administrator 
and, if applicable, the permitting authority under subpart E of part 75 
of this chapter shall apply for certification to the permitting 
authority prior to use of the system under the NOX Trading 
Program. The NOX authorized account representative shall 
apply for recertification following a replacement, modification or 
change according to the procedures in paragraph (b) of this section. The 
owner or operator of an alternative monitoring system shall comply with 
the notification and application requirements for certification 
according to the procedures specified in paragraph (b)(3) of this 
section and Sec. 75.20(f) of this chapter .



Sec. 96.72  Out of control periods.

    (a) Whenever any monitoring system fails to meet the quality 
assurance requirements of appendix B of part 75 of

[[Page 41]]

this chapter, data shall be substituted using the applicable procedures 
in subpart D, appendix D, or appendix E of part 75 of this chapter.
    (b) Audit decertification. Whenever both an audit of a monitoring 
system and a review of the initial certification or recertification 
application reveal that any system or component should not have been 
certified or recertified because it did not meet a particular 
performance specification or other requirement under Sec. 96.71 or the 
applicable provisions of part 75 of this chapter, both at the time of 
the initial certification or recertification application submission and 
at the time of the audit, the permitting authority will issue a notice 
of disapproval of the certification status of such system or component. 
For the purposes of this paragraph, an audit shall be either a field 
audit or an audit of any information submitted to the permitting 
authority or the Administrator. By issuing the notice of disapproval, 
the permitting authority revokes prospectively the certification status 
of the system or component. The data measured and recorded by the system 
or component shall not be considered valid quality-assured data from the 
date of issuance of the notification of the revoked certification status 
until the date and time that the owner or operator completes 
subsequently approved initial certification or recertification tests. 
The owner or operator shall follow the initial certification or 
recertification procedures in Sec. 96.71 for each disapproved system.



Sec. 96.73  Notifications.

    The NOX authorized account representative for a 
NOX Budget unit shall submit written notice to the permitting 
authority and the Administrator in accordance with Sec. 75.61 of this 
chapter, except that if the unit is not subject to an Acid Rain 
emissions limitation, the notification is only required to be sent to 
the permitting authority.



Sec. 96.74  Recordkeeping and reporting.

    (a) General provisions. (1) The NOX authorized account 
representative shall comply with all recordkeeping and reporting 
requirements in this section and with the requirements of Sec. 
96.10(e).
    (2) If the NOX authorized account representative for a 
NOX Budget unit subject to an Acid Rain Emission limitation 
who signed and certified any submission that is made under subpart F or 
G of part 75 of this chapter and which includes data and information 
required under this subpart or subpart H of part 75 of this chapter is 
not the same person as the designated representative or the alternative 
designated representative for the unit under part 72 of this chapter, 
the submission must also be signed by the designated representative or 
the alternative designated representative.
    (b) Monitoring plans. (1) The owner or operator of a unit subject to 
an Acid Rain emissions limitation shall comply with requirements of 
Sec. 75.62 of this chapter, except that the monitoring plan shall also 
include all of the information required by subpart H of part 75 of this 
chapter.
    (2) The owner or operator of a unit that is not subject to an Acid 
Rain emissions limitation shall comply with requirements of Sec. 75.62 
of this chapter, except that the monitoring plan is only required to 
include the information required by subpart H of part 75 of this 
chapter.
    (c) Certification applications. The NOX authorized 
account representative shall submit an application to the permitting 
authority within 45 days after completing all initial certification or 
recertification tests required under Sec. 96.71 including the 
information required under subpart H of part 75 of this chapter.
    (d) Quarterly reports. The NOX authorized account 
representative shall submit quarterly reports, as follows:
    (1) If a unit is subject to an Acid Rain emission limitation or if 
the owner or operator of the NOX budget unit chooses to meet 
the annual reporting requirements of this subpart H, the NOX 
authorized account representative shall submit a quarterly report for 
each calendar quarter beginning with:
    (i) For units that elect to comply with the early reduction credit 
provisions under Sec. 96.55 of this part, the CALENDER quarter that 
includes the date of initial provisional certification

[[Page 42]]

under Sec. 96.71(b)(3)(iii). Data shall be reported from the date and 
hour corresponding to the date and hour of provisional certification; or
    (ii) For units commencing operation prior to May 1, 2002 that are 
not required to certify monitors by May 1, 2000 under Sec. 96.70(b)(1), 
the earlier of the CALENDER quarter that includes the date of initial 
provisional certification under Sec. 96.71(b)(3)(iii) or, if the 
certification tests are not completed by May 1, 2002, the partial 
CALENDER quarter from May 1, 2002 through June 30, 2002. Data shall be 
recorded and reported from the earlier of the date and hour 
corresponding to the date and hour of provisional certification or the 
first hour on May 1, 2002; or
    (iii) For a unit that commences operation after May 1, 2002, the 
calendar quarter in which the unit commences operation, Data shall be 
reported from the date and hour corresponding to when the unit commenced 
operation.
    (2) If a NOX budget unit is not subject to an Acid Rain 
emission limitation, then the NOX authorized account 
representative shall either:
    (i) Meet all of the requirements of part 75 related to monitoring 
and reporting NOX mass emissions during the entire year and 
meet the reporting deadlines specified in paragraph (d)(1) of this 
section; or
    (ii) Submit quarterly reports only for the periods from the earlier 
of May 1 or the date and hour that the owner or operator successfully 
completes all of the recertification tests required under Sec. 
75.74(d)(3) through September 30 of each year in accordance with the 
provisions of Sec. 75.74(b) of this chapter. The NOX 
authorized account representative shall submit a quarterly report for 
each calendar quarter, beginning with:
    (A) For units that elect to comply with the early reduction credit 
provisions under Sec. 96.55, the CALENDER quarter that includes the 
date of initial provisional certification under Sec. 96.71(b)(3)(iii). 
Data shall be reported from the date and hour corresponding to the date 
and hour of provisional certification; or
    (B) For units commencing operation prior to May 1, 2002 that are not 
required to certify monitors by May 1, 2000 under Sec. 96.70(b)(1), the 
earlier of the CALENDER quarter that includes the date of initial 
provisional certification under Sec. 96.71(b)(3)(iii), or if the 
certification tests are not completed by May 1, 2002, the partial 
CALENDER quarter from May 1, 2002 through June 30, 2002. Data shall be 
reported from the earlier of the date and hour corresponding to the date 
and hour of provisional certification or the first hour of May 1, 2002; 
or
    (C) For units that commence operation after May 1, 2002 during the 
control period, the CALENDER quarter in which the unit commences 
operation. Data shall be reported from the date and hour corresponding 
to when the unit commenced operation; or
    (D) For units that commence operation after May 1, 2002 and before 
May 1 of the year in which the unit commences operation, the earlier of 
the CALENDER quarter that includes the date of initial provisional 
certification under Sec. 96.71(b)(3)(iii) or, if the certification 
tests are not completed by May 1 of the year in which the unit commences 
operation, May 1 of the year in which the unit commences operation. Data 
shall be reported from the earlier of the date and hour corresponding to 
the date and hour of provisional certification or the first hour of May 
1 of the year after the unit commences operation.
    (E) For units that commence operation after May 1, 2002 and after 
September 30 of the year in which the unit commences operation, the 
earlier of the CALENDER quarter that includes the date of initial 
provisional certification under Sec. 96.71(b)(3)(iii) or, if the 
certification tests are not completed by May 1 of the year after the 
unit commences operation, May 1 of the year after the unit commences 
operation. Data shall be reported from the earlier of the date and hour 
corresponding to the date and hour of provisional certification or the 
first hour of May 1 of the year after the unit commences operation.
    (3) The NOX authorized account representative shall 
submit each quarterly report to the Administrator within 30 days 
following the end of the calendar quarter covered by the report. 
Quarterly reports shall be submitted in the manner specified in subpart 
H of part

[[Page 43]]

75 of this chapter and Sec. 75.64 of this chapter.
    (i) For units subject to an Acid Rain Emissions limitation, 
quarterly reports shall include all of the data and information required 
in subpart H of part 75 of this chapter for each NOX Budget 
unit (or group of units using a common stack) as well as information 
required in subpart G of part 75 of this chapter.
    (ii) For units not subject to an Acid Rain Emissions limitation, 
quarterly reports are only required to include all of the data and 
information required in subpart H of part 75 of this chapter for each 
NOX Budget unit (or group of units using a common stack).
    (4) Compliance certification. The NOX authorized account 
representative shall submit to the Administrator a compliance 
certification in support of each quarterly report based on reasonable 
inquiry of those persons with primary responsibility for ensuring that 
all of the unit's emissions are correctly and fully monitored. The 
certification shall state that:
    (i) The monitoring data submitted were recorded in accordance with 
the applicable requirements of this subpart and part 75 of this chapter, 
including the quality assurance procedures and specifications; and
    (ii) For a unit with add-on NOX emission controls and for 
all hours where data are substituted in accordance with Sec. 
75.34(a)(1) of this chapter, the add-on emission controls were operating 
within the range of parameters listed in the monitoring plan and the 
substitute values do not systematically underestimate NOX 
emissions; and
    (iii) For a unit that is reporting on a control period basis under 
Sec. 96.74(d) the NOX emission rate and NOX 
concentration values substituted for missing data under subpart D of 
part 75 of this chapter are calculated using only values from a control 
period and do not systematically underestimate NOX emissions.



Sec. 96.75  Petitions.

    (a) The NOX authorized account representative of a 
NOX Budget unit that is subject to an Acid Rain emissions 
limitation may submit a petition under Sec. 75.66 of this chapter to 
the Administrator requesting approval to apply an alternative to any 
requirement of this subpart.
    (1) Application of an alternative to any requirement of this subpart 
is in accordance with this subpart only to the extent that the petition 
is approved by the Administrator, in consultation with the permitting 
authority.
    (2) Notwithstanding paragraph (a)(1) of this section, if the 
petition requests approval to apply an alternative to a requirement 
concerning any additional CEMS required under the common stack 
provisions of Sec. 75.72 of this chapter, the petition is governed by 
paragraph (b) of this section.
    (b) The NOX authorized account representative of a 
NOX Budget unit that is not subject to an Acid Rain emissions 
limitation may submit a petition under Sec. 75.66 of this chapter to 
the permitting authority and the Administrator requesting approval to 
apply an alternative to any requirement of this subpart.
    (1) The NOX authorized account representative of a 
NOX Budget unit that is subject to an Acid Rain emissions 
limitation may submit a petition under Sec. 75.66 of this chapter to 
the permitting authority and the Administrator requesting approval to 
apply an alternative to a requirement concerning any additional CEMS 
required under the common stack provisions of Sec. 75.72 of this 
chapter or a NOX concentration CEMS used under 75.71(a)(2) of 
this chapter.
    (2) Application of an alternative to any requirement of this subpart 
is in accordance with this subpart only to the extent the petition under 
paragraph (b) of this section is approved by both the permitting 
authority and the Administrator.



Sec. 96.76  Additional requirements to provide heat input data for
allocations purposes.

    (a) The owner or operator of a unit that elects to monitor and 
report NOX Mass emissions using a NOX 
concentration system and a flow system shall also monitor and report 
heat input at the unit level using the procedures set forth in part 75 
of this chapter for any source located in a state developing

[[Page 44]]

source allocations based upon heat input.
    (b) The owner or operator of a unit that monitor and report 
NOX Mass emissions using a NOX concentration 
system and a flow system shall also monitor and report heat input at the 
unit level using the procedures set forth in part 75 of this chapter for 
any source that is applying for early reduction credits under Sec. 
96.55.



                    Subpart I_Individual Unit Opt-ins



Sec. 96.80  Applicability.

    A unit that is in the State, is not a NOX Budget unit 
under Sec. 96.4, vents all of its emissions to a stack, and is 
operating, may qualify, under this subpart, to become a NOX 
Budget opt-in source. A unit that is a NOX Budget unit, is 
covered by a retired unit exemption under Sec. 96.5 that is in effect, 
or is not operating is not eligible to become a NOX Budget 
opt-in source.



Sec. 96.81  General.

    Except otherwise as provided in this part, a NOX Budget 
opt-in source shall be treated as a NOX Budget unit for 
purposes of applying subparts A through H of this part.



Sec. 96.82  NOX authorized account representative.

    A unit for which an application for a NOX Budget opt-in 
permit is submitted and not denied or withdrawn, or a NOX 
Budget opt-in source, located at the same source as one or more 
NOX Budget units, shall have the same NOX 
authorized account representative as such NOX Budget units.



Sec. 96.83  Applying for NOX Budget opt-in permit.

    (a) Applying for initial NOX Budget opt-in permit. In 
order to apply for an initial NOX Budget opt-in permit, the 
NOX authorized account representative of a unit qualified 
under Sec. 96.80 may submit to the permitting authority at any time, 
except as provided under Sec. 96.86(g):
    (1) A complete NOX Budget permit application under Sec. 
96.22;
    (2) A monitoring plan submitted in accordance with subpart H of this 
part; and
    (3) A complete account certificate of representation under Sec. 
96.13, if no NOX authorized account representative has been 
previously designated for the unit.
    (b) Duty to reapply. The NOX authorized account 
representative of a NOX Budget opt-in source shall submit a 
complete NOX Budget permit application under Sec. 96.22 to 
renew the NOX Budget opt-in permit in accordance with Sec. 
96.21(c) and, if applicable, an updated monitoring plan in accordance 
with subpart H of this part.



Sec. 96.84  Opt-in process.

    The permitting authority will issue or deny a NOX Budget 
opt-in permit for a unit for which an initial application for a 
NOX Budget opt-in permit under Sec. 96.83 is submitted, in 
accordance with Sec. 96.20 and the following:
    (a) Interim review of monitoring plan. The permitting authority will 
determine, on an interim basis, the sufficiency of the monitoring plan 
accompanying the initial application for a NOX Budget opt-in 
permit under Sec. 96.83. A monitoring plan is sufficient, for purposes 
of interim review, if the plan appears to contain information 
demonstrating that the NOX emissions rate and heat input of 
the unit are monitored and reported in accordance with subpart H of this 
part. A determination of sufficiency shall not be construed as 
acceptance or approval of the unit's monitoring plan.
    (b) If the permitting authority determines that the unit's 
monitoring plan is sufficient under paragraph (a) of this section and 
after completion of monitoring system certification under subpart H of 
this part, the NOX emissions rate and the heat input of the 
unit shall be monitored and reported in accordance with subpart H of 
this part for one full control period during which monitoring system 
availability is not less than 90 percent and during which the unit is in 
full compliance with any applicable State or Federal emissions or 
emissions-related requirements. Solely for purposes of applying the 
requirements in the prior sentence, the unit shall be treated as a 
``NOX Budget unit'' prior to issuance of a NOX 
Budget opt-in permit covering the unit.

[[Page 45]]

    (c) Based on the information monitored and reported under paragraph 
(b) of this section, the unit's baseline heat rate shall be calculated 
as the unit's total heat input (in mmBtu) for the control period and the 
unit's baseline NOX emissions rate shall be calculated as the 
unit's total NOX emissions (in lb) for the control period 
divided by the unit's baseline heat rate.
    (d) After calculating the baseline heat input and the baseline 
NOX emissions rate for the unit under paragraph (c) of this 
section, the permitting authority will serve a draft NOX 
Budget opt-in permit on the NOX authorized account 
representative of the unit.
    (e) Confirmation of intention to opt-in. Within 20 days after the 
issuance of the draft NOX Budget opt-in permit, the 
NOX authorized account representative of the unit must submit 
to the permitting authority a confirmation of the intention to opt in 
the unit or a withdrawal of the application for a NOX Budget 
opt-in permit under Sec. 96.83. The permitting authority will treat the 
failure to make a timely submission as a withdrawal of the 
NOX Budget opt-in permit application.
    (f) Issuance of draft NOX Budget opt-in permit. If the 
NOX authorized account representative confirms the intention 
to opt-in the unit under paragraph (e) of this section, the permitting 
authority will issue the draft NOX Budget opt-in permit in 
accordance with Sec. 96.20.
    (g) Notwithstanding paragraphs (a) through (f) of this section, if 
at any time before issuance of a draft NOX Budget opt-in 
permit for the unit, the permitting authority determines that the unit 
does not qualify as a NOX Budget opt-in source under Sec. 
96.80, the permitting authority will issue a draft denial of a 
NOX Budget opt-in permit for the unit in accordance with 
Sec. 96.20.
    (h) Withdrawal of application for NOX Budget opt-in 
permit. A NOX authorized account representative of a unit may 
withdraw its application for a NOX Budget opt-in permit under 
Sec. 96.83 at any time prior to the issuance of the final 
NOX Budget opt-in permit. Once the application for a 
NOX Budget opt-in permit is withdrawn, a NOX 
authorized account representative wanting to reapply must submit a new 
application for a NOX Budget permit under Sec. 96.83.
    (i) Effective date. The effective date of the initial NOX 
Budget opt-in permit shall be May 1 of the first control period starting 
after the issuance of the initial NOX Budget opt-in permit by 
the permitting authority. The unit shall be a NOX Budget opt-
in source and a NOX Budget unit as of the effective date of 
the initial NOX Budget opt-in permit.



Sec. 96.85  NOX Budget opt-in permit contents.

    (a) Each NOX Budget opt-in permit (including any draft or 
proposed NOX Budget opt-in permit, if applicable) will 
contain all elements required for a complete NOX Budget opt-
in permit application under Sec. 96.22 as approved or adjusted by the 
permitting authority.
    (b) Each NOX Budget opt-in permit is deemed to 
incorporate automatically the definitions of terms under Sec. 96.2 and, 
upon recordation by the Administrator under subpart F, G, or I of this 
part, every allocation, transfer, or deduction of NOX 
allowances to or from the compliance accounts of each NOX 
Budget opt-in source covered by the NOX Budget opt-in permit 
or the overdraft account of the NOX Budget source where the 
NOX Budget opt-in source is located.



Sec. 96.86  Withdrawal from NOX Budget Trading Program.

    (a) Requesting withdrawal. To withdraw from the NOX 
Budget Trading Program, the NOX authorized account 
representative of a NOX Budget opt-in source shall submit to 
the permitting authority a request to withdraw effective as of a 
specified date prior to May 1 or after September 30. The submission 
shall be made no later than 90 days prior to the requested effective 
date of withdrawal.
    (b) Conditions for withdrawal. Before a NOX Budget opt-in 
source covered by a request under paragraph (a) of this section may 
withdraw from the NOX Budget Trading Program and the 
NOX Budget opt-in permit may be terminated under paragraph 
(e) of this section, the following conditions must be met:
    (1) For the control period immediately before the withdrawal is to 
be effective, the NOX authorized account representative must 
submit or must

[[Page 46]]

have submitted to the permitting authority an annual compliance 
certification report in accordance with Sec. 96.30.
    (2) If the NOX Budget opt-in source has excess emissions 
for the control period immediately before the withdrawal is to be 
effective, the Administrator will deduct or has deducted from the 
NOX Budget opt-in source's compliance account, or the 
overdraft account of the NOX Budget source where the 
NOX Budget opt-in source is located, the full amount required 
under Sec. 96.54(d) for the control period.
    (3) After the requirements for withdrawal under paragraphs (b)(1) 
and (2) of this section are met, the Administrator will deduct from the 
NOX Budget opt-in source's compliance account, or the 
overdraft account of the NOX Budget source where the 
NOX Budget opt-in source is located, NOX 
allowances equal in number to and allocated for the same or a prior 
control period as any NOX allowances allocated to that source 
under Sec. 96.88 for any control period for which the withdrawal is to 
be effective. The Administrator will close the NOX Budget 
opt-in source's compliance account and will establish, and transfer any 
remaining allowances to, a new general account for the owners and 
operators of the NOX Budget opt-in source. The NOX 
authorized account representative for the NOX Budget opt-in 
source shall become the NOX authorized account representative 
for the general account.
    (c) A NOX Budget opt-in source that withdraws from the 
NOX Budget Trading Program shall comply with all requirements 
under the NOX Budget Trading Program concerning all years for 
which such NOX Budget opt-in source was a NOX 
Budget opt-in source, even if such requirements arise or must be 
complied with after the withdrawal takes effect.
    (d) Notification. (1) After the requirements for withdrawal under 
paragraphs (a) and (b) of this section are met (including deduction of 
the full amount of NOX allowances required), the permitting 
authority will issue a notification to the NOX authorized 
account representative of the NOX Budget opt-in source of the 
acceptance of the withdrawal of the NOX Budget opt-in source 
as of a specified effective date that is after such requirements have 
been met and that is prior to May 1 or after September 30.
    (2) If the requirements for withdrawal under paragraphs (a) and (b) 
of this section are not met, the permitting authority will issue a 
notification to the NOX authorized account representative of 
the NOX Budget opt-in source that the NOX Budget 
opt-in source's request to withdraw is denied. If the NOX 
Budget opt-in source's request to withdraw is denied, the NOX 
Budget opt-in source shall remain subject to the requirements for a 
NOX Budget opt-in source.
    (e) Permit amendment. After the permitting authority issues a 
notification under paragraph (d)(1) of this section that the 
requirements for withdrawal have been met, the permitting authority will 
revise the NOX Budget permit covering the NOX 
Budget opt-in source to terminate the NOX Budget opt-in 
permit as of the effective date specified under paragraph (d)(1) of this 
section. A NOX Budget opt-in source shall continue to be a 
NOX Budget opt-in source until the effective date of the 
termination.
    (f) Reapplication upon failure to meet conditions of withdrawal. If 
the permitting authority denies the NOX Budget opt-in 
source's request to withdraw, the NOX authorized account 
representative may submit another request to withdraw in accordance with 
paragraphs (a) and (b) of this section.
    (g) Ability to return to the NOX Budget Trading Program. 
Once a NOX Budget opt-in source withdraws from the 
NOX Budget Trading Program and its NOX Budget opt-
in permit is terminated under this section, the NOX authority 
account representative may not submit another application for a 
NOX Budget opt-in permit under Sec. 96.83 for the unit prior 
to the date that is 4 years after the date on which the terminated 
NOX Budget opt-in permit became effective.



Sec. 96.87  Change in regulatory status.

    (a) Notification. When a NOX Budget opt-in source becomes 
a NOX Budget unit under Sec. 96.4, the NOX 
authorized account representative shall notify in writing the permitting 
authority and the Administrator of such change in

[[Page 47]]

the NOX Budget opt-in source's regulatory status, within 30 
days of such change.
    (b) Permitting authority's and Administrator's action. (1)(i) When 
the NOX Budget opt-in source becomes a NOX Budget 
unit under Sec. 96.4, the permitting authority will revise the 
NOX Budget opt-in source's NOX Budget opt-in 
permit to meet the requirements of a NOX Budget permit under 
Sec. 96.23 as of an effective date that is the date on which such 
NOX Budget opt-in source becomes a NOX Budget unit 
under Sec. 96.4.
    (ii)(A) The Administrator will deduct from the compliance account 
for the NOX Budget unit under paragraph (b)(1)(i) of this 
section, or the overdraft account of the NOX Budget source 
where the unit is located, NOX allowances equal in number to 
and allocated for the same or a prior control period as:
    (1) Any NOX allowances allocated to the NOX 
Budget unit (as a NOX Budget opt-in source) under Sec. 96.88 
for any control period after the last control period during which the 
unit's NOX Budget opt-in permit was effective; and
    (2) If the effective date of the NOX Budget permit 
revision under paragraph (b)(1)(i) of this section is during a control 
period, the NOX allowances allocated to the NOX 
Budget unit (as a NOX Budget opt-in source) under Sec. 96.88 
for the control period multiplied by the ratio of the number of days, in 
the control period, starting with the effective date of the permit 
revision under paragraph (b)(1)(i) of this section, divided by the total 
number of days in the control period.
    (B) The NOX authorized account representative shall 
ensure that the compliance account of the NOX Budget unit 
under paragraph (b)(1)(i) of this section, or the overdraft account of 
the NOX Budget source where the unit is located, includes the 
NOX allowances necessary for completion of the deduction 
under paragraph (b)(1)(ii)(A) of this section. If the compliance account 
or overdraft account does not contain sufficient NOX 
allowances, the Administrator will deduct the required number of 
NOX allowances, regardless of the control period for which 
they were allocated, whenever NOX allowances are recorded in 
either account.
    (iii)(A) For every control period during which the NOX 
Budget permit revised under paragraph (b)(1)(i) of this section is 
effective, the NOX Budget unit under paragraph (b)(1)(i) of 
this section will be treated, solely for purposes of NOX 
allowance allocations under Sec. 96.42, as a unit that commenced 
operation on the effective date of the NOX Budget permit 
revision under paragraph (b)(1)(i) of this section and will be allocated 
NOX allowances under Sec. 96.42.
    (B) Notwithstanding paragraph (b)(1)(iii)(A) of this section, if the 
effective date of the NOX Budget permit revision under 
paragraph (b)(1)(i) of this section is during a control period, the 
following number of NOX allowances will be allocated to the 
NOX Budget unit under paragraph (b)(1)(i) of this section 
under Sec. 96.42 for the control period: the number of NOX 
allowances otherwise allocated to the NOX Budget unit under 
Sec. 96.42 for the control period multiplied by the ratio of the number 
of days, in the control period, starting with the effective date of the 
permit revision under paragraph (b)(1)(i) of this section, divided by 
the total number of days in the control period.
    (2)(i) When the NOX authorized account representative of 
a NOX Budget opt-in source does not renew its NOX 
Budget opt-in permit under Sec. 96.83(b), the Administrator will deduct 
from the NOX Budget opt-in unit's compliance account, or the 
overdraft account of the NOX Budget source where the 
NOX Budget opt-in source is located, NOX 
allowances equal in number to and allocated for the same or a prior 
control period as any NOX allowances allocated to the 
NOX Budget opt-in source under Sec. 96.88 for any control 
period after the last control period for which the NOX Budget 
opt-in permit is effective. The NOX authorized account 
representative shall ensure that the NOX Budget opt-in 
source's compliance account or the overdraft account of the 
NOX Budget source where the NOX Budget opt-in 
source is located includes the NOX allowances necessary for 
completion of such deduction. If the compliance account or overdraft 
account does not contain sufficient NOX allowances, the 
Administrator will deduct the required number of NOX 
allowances, regardless

[[Page 48]]

of the control period for which they were allocated, whenever 
NOX allowances are recorded in either account.
    (ii) After the deduction under paragraph (b)(2)(i) of this section 
is completed, the Administrator will close the NOX Budget 
opt-in source's compliance account. If any NOX allowances 
remain in the compliance account after completion of such deduction and 
any deduction under Sec. 96.54, the Administrator will close the 
NOX Budget opt-in source's compliance account and will 
establish, and transfer any remaining allowances to, a new general 
account for the owners and operators of the NOX Budget opt-in 
source. The NOX authorized account representative for the 
NOX Budget opt-in source shall become the NOX 
authorized account representative for the general account.



Sec. 96.88  NOX allowance allocations to opt-in units.

    (a) NOX allowance allocation. (1) By December 31 
immediately before the first control period for which the NOX 
Budget opt-in permit is effective, the permitting authority will 
allocate NOX allowances to the NOX Budget opt-in 
source and submit to the Administrator the allocation for the control 
period in accordance with paragraph (b) of this section.
    (2) By no later than December 31, after the first control period for 
which the NOX Budget opt-in permit is in effect, and December 
31 of each year thereafter, the permitting authority will allocate 
NOX allowances to the NOX Budget opt-in source, 
and submit to the Administrator allocations for the next control period, 
in accordance with paragraph (b) of this section.
    (b) For each control period for which the NOX Budget opt-
in source has an approved NOX Budget opt-in permit, the 
NOX Budget opt-in source will be allocated NOX 
allowances in accordance with the following procedures:
    (1) The heat input (in mmBtu) used for calculating NOX 
allowance allocations will be the lesser of:
    (i) The NOX Budget opt-in source's baseline heat input 
determined pursuant to Sec. 96.84(c); or
    (ii) The NOX Budget opt-in source's heat input, as 
determined in accordance with subpart H of this part, for the control 
period in the year prior to the year of the control period for which the 
NOX allocations are being calculated.
    (2) The permitting authority will allocate NOX allowances 
to the NOX Budget opt-in source in an amount equaling the 
heat input (in mmBtu) determined under paragraph (b)(1) of this section 
multiplied by the lesser of:
    (i) The NOX Budget opt-in source's baseline 
NOX emissions rate (in lb/mmBtu) determined pursuant to Sec. 
96.84(c); or
    (ii) The most stringent State or Federal NOX emissions 
limitation applicable to the NOX Budget opt-in source during 
the control period.

Subpart J--Mobile and Area Sources [Reserved]

Subparts K-Z [Reserved]



      Subpart AA_CAIR NOX Annual Trading Program General Provisions

    Source: 70 FR 25339, May 12, 2005, unless otherwise noted.



Sec. 96.101  Purpose.

    This subpart and subparts BB through II establish the model rule 
comprising general provisions and the designated representative, 
permitting, allowance, monitoring, and opt-in provisions for the State 
Clean Air Interstate Rule (CAIR) NOX Annual Trading Program, 
under section 110 of the Clean Air Act and Sec. 51.123 of this chapter, 
as a means of mitigating interstate transport of fine particulates and 
nitrogen oxides. The owner or operator of a unit or a source shall 
comply with the requirements of this subpart and subparts BB through II 
as a matter of federal law only if the State with jurisdiction over the 
unit and the source incorporates by reference such subparts or otherwise 
adopts the requirements of such subparts in accordance with Sec. 
51.123(o)(1) or (2) of this chapter, the State submits to the 
Administrator one or more revisions of the State implementation plan 
that include such adoption, and the Administrator approves such 
revisions. If the State

[[Page 49]]

adopts the requirements of such subparts in accordance with Sec. 
51.123(o)(1) or (2) of this chapter, then the State authorizes the 
Administrator to assist the State in implementing the CAIR 
NOX Annual Trading Program by carrying out the functions set 
forth for the Administrator in such subparts.



Sec. 96.102  Definitions.

    The terms used in this subpart and subparts BB through II shall have 
the meanings set forth in this section as follows:
    Account number means the identification number given by the 
Administrator to each CAIR NOX Allowance Tracking System 
account.
    Acid Rain emissions limitation means a limitation on emissions of 
sulfur dioxide or nitrogen oxides under the Acid Rain Program.
    Acid Rain Program means a multi-state sulfur dioxide and nitrogen 
oxides air pollution control and emission reduction program established 
by the Administrator under title IV of the CAA and parts 72 through 78 
of this chapter.
    Administrator means the Administrator of the United States 
Environmental Protection Agency or the Administrator's duly authorized 
representative.
    Allocate or allocation means, with regard to CAIR NOX 
allowances, the determination by a permitting authority or the 
Administrator of the amount of such CAIR NOX allowances to be 
initially credited to a CAIR NOX unit, a new unit set-aside, 
or other entity.
    Allowance transfer deadline means, for a control period, midnight of 
March 1 (if it is a business day), or midnight of the first business day 
thereafter (if March 1 is not a business day), immediately following the 
control period and is the deadline by which a CAIR NOX 
allowance transfer must be submitted for recordation in a CAIR 
NOX source's compliance account in order to be used to meet 
the source's CAIR NOX emissions limitation for such control 
period in accordance with Sec. 96.154.
    Alternate CAIR designated representative means, for a CAIR 
NOX source and each CAIR NOX unit at the source, 
the natural person who is authorized by the owners and operators of the 
source and all such units at the source, in accordance with subparts BB 
and II of this part, to act on behalf of the CAIR designated 
representative in matters pertaining to the CAIR NOX Annual 
Trading Program. If the CAIR NOX source is also a CAIR 
SO2 source, then this natural person shall be the same person 
as the alternate CAIR designated representative under the CAIR 
SO2 Trading Program. If the CAIR NOX source is 
also a CAIR NOX Ozone Season source, then this natural person 
shall be the same person as the alternate CAIR designated representative 
under the CAIR NOX Ozone Season Trading Program. If the CAIR 
NOX source is also subject to the Acid Rain Program, then 
this natural person shall be the same person as the alternate designated 
representative under the Acid Rain Program. If the CAIR NOX 
source is also subject to the Hg Budget Trading Program, then this 
natural person shall be the same person as the alternate Hg designated 
representative under the Hg Budget Trading Program.
    Automated data acquisition and handling system or DAHS means that 
component of the continuous emission monitoring system, or other 
emissions monitoring system approved for use under subpart HH of this 
part, designed to interpret and convert individual output signals from 
pollutant concentration monitors, flow monitors, diluent gas monitors, 
and other component parts of the monitoring system to produce a 
continuous record of the measured parameters in the measurement units 
required by subpart HH of this part.
    Biomass means--
    (1) Any organic material grown for the purpose of being converted to 
energy;
    (2) Any organic byproduct of agriculture that can be converted into 
energy; or
    (3) Any material that can be converted into energy and is 
nonmerchantable for other purposes, that is segregated from other 
nonmerchantable material, and that is;
    (i) A forest-related organic resource, including mill residues, 
precommercial thinnings, slash, brush, or byproduct from conversion of 
trees to merchantable material; or

[[Page 50]]

    (ii) A wood material, including pallets, crates, dunnage, 
manufacturing and construction materials (other than pressure-treated, 
chemically-treated, or painted wood products), and landscape or right-
of-way tree trimmings.
    Boiler means an enclosed fossil- or other-fuel-fired combustion 
device used to produce heat and to transfer heat to recirculating water, 
steam, or other medium.
    Bottoming-cycle cogeneration unit means a cogeneration unit in which 
the energy input to the unit is first used to produce useful thermal 
energy and at least some of the reject heat from the useful thermal 
energy application or process is then used for electricity production.
    CAIR authorized account representative means, with regard to a 
general account, a responsible natural person who is authorized, in 
accordance with subparts BB, FF, and II of this part, to transfer and 
otherwise dispose of CAIR NOX allowances held in the general 
account and, with regard to a compliance account, the CAIR designated 
representative of the source.
    CAIR designated representative means, for a CAIR NOX 
source and each CAIR NOX unit at the source, the natural 
person who is authorized by the owners and operators of the source and 
all such units at the source, in accordance with subparts BB and II of 
this part, to represent and legally bind each owner and operator in 
matters pertaining to the CAIR NOX Annual Trading Program. If 
the CAIR NOX source is also a CAIR SO2 source, 
then this natural person shall be the same person as the CAIR designated 
representative under the CAIR SO2 Trading Program. If the 
CAIR NOX source is also a CAIR NOX Ozone Season 
source, then this natural person shall be the same person as the CAIR 
designated representative under the CAIR NOX Ozone Season 
Trading Program. If the CAIR NOX source is also subject to 
the Acid Rain Program, then this natural person shall be the same person 
as the designated representative under the Acid Rain Program. If the 
CAIR NOX source is also subject to the Hg Budget Trading 
Program, then this natural person shall be the same person as the Hg 
designated representative under the Hg Budget Trading Program.
    CAIR NOX allowance means a limited authorization issued by a 
permitting authority or the Administrator under provisions of a State 
implementation plan that are approved under Sec. 51.123(o)(1) or (2) or 
(p) of this chapter, or under subpart EE of part 97 or Sec. 97.188 of 
this chapter, to emit one ton of nitrogen oxides during a control period 
of the specified calendar year for which the authorization is allocated 
or of any calendar year thereafter under the CAIR NOX 
Program. An authorization to emit nitrogen oxides that is not issued 
under provisions of a State implementation plan that are approved under 
Sec. 51.123(o)(1) or (2) or (p) of this chapter or subpart EE of part 
97 or Sec. 97.188 of this chapter shall not be a CAIR NOX 
allowance.
    CAIR NOX allowance deduction or deduct CAIR NOX allowances means the 
permanent withdrawal of CAIR NOX allowances by the 
Administrator from a compliance account, e.g., in order to account for a 
specified number of tons of total nitrogen oxides emissions from all 
CAIR NOX units at a CAIR NOX source for a control 
period, determined in accordance with subpart HH of this part, or to 
account for excess emissions.
    CAIR NOX Allowance Tracking System means the system by 
which the Administrator records allocations, deductions, and transfers 
of CAIR NOX allowances under the CAIR NOX Annual 
Trading Program. Such allowances will be allocated, held, deducted, or 
transferred only as whole allowances.
    CAIR NOX Allowance Tracking System account means an 
account in the CAIR NOX Allowance Tracking System established 
by the Administrator for purposes of recording the allocation, holding, 
transferring, or deducting of CAIR NOX allowances.
    CAIR NOX allowances held or hold CAIR NOX 
allowances means the CAIR NOX allowances recorded by the 
Administrator, or submitted to the Administrator for recordation, in 
accordance with subparts FF, GG, and II of this part, in a CAIR 
NOX Allowance Tracking System account.
    CAIR NOX Annual Trading Program means a multi-state 
nitrogen oxides air

[[Page 51]]

pollution control and emission reduction program approved and 
administered by the Administrator in accordance with subparts AA through 
II of this part and Sec. 51.123(o)(1) or (2) of this chapter or 
established by the Administrator in accordance with subparts AA through 
II of part 97 of this chapter and Sec. Sec. 51.123(p) and 52.35 of this 
chapter, as a means of mitigating interstate transport of fine 
particulates and nitrogen oxides.
    CAIR NOX emissions limitation means, for a CAIR 
NOX source, the tonnage equivalent, in NOX 
emissions in a control period, of the CAIR NOX allowances 
available for deduction for the source under Sec. 96.154(a) and (b) for 
the control period.
    CAIR NOX Ozone Season source means a source that is 
subject to the CAIR NOX Ozone Season Trading Program.
    CAIR NOX Ozone Season Trading Program means a multi-state 
nitrogen oxides air pollution control and emission reduction program 
approved and administered by the Administrator in accordance with 
subparts AAAA through IIII of this part and Sec. 51.123(aa)(1) or (2) 
(and (bb)(1)), (bb)(2), or (dd) of this chapter or established by the 
Administrator in accordance with subparts AAAA through IIII of part 97 
of this chapter and Sec. Sec. 51.123(ee) and 52.35 of this chapter, as 
a means of mitigating interstate transport of ozone and nitrogen oxides.
    CAIR NOX source means a source that includes one or more 
CAIR NOX units.
    CAIR NOX unit means a unit that is subject to the CAIR 
NOX Annual Trading Program under Sec. 96.104 and, except for 
purposes of Sec. 96.105 and subpart EE of this part, a CAIR 
NOX opt-in unit under subpart II of this part.
    CAIR permit means the legally binding and federally enforceable 
written document, or portion of such document, issued by the permitting 
authority under subpart CC of this part, including any permit revisions, 
specifying the CAIR NOX Annual Trading Program requirements 
applicable to a CAIR NOX source, to each CAIR NOX 
unit at the source, and to the owners and operators and the CAIR 
designated representative of the source and each such unit.
    CAIR SO2 source means a source that is subject to the 
CAIR SO2 Trading Program.
    CAIR SO2 Trading Program means a multi-state sulfur 
dioxide air pollution control and emission reduction program approved 
and administered by the Administrator in accordance with subparts AAA 
through III of this part and Sec. 51.124(o)(1) or (2) of this chapter 
or established by the Administrator in accordance with subparts AAA 
through III of part 97 of this chapter and Sec. Sec. 51.124(r) and 
52.36 of this chapter, as a means of mitigating interstate transport of 
fine particulates and sulfur dioxide.
    Clean Air Act or CAA means the Clean Air Act, 42 U.S.C. 7401, et 
seq.
    Coal means any solid fuel classified as anthracite, bituminous, 
subbituminous, or lignite.
    Coal-derived fuel means any fuel (whether in a solid, liquid, or 
gaseous state) produced by the mechanical, thermal, or chemical 
processing of coal.
    Coal-fired means:
    (1) Except for purposes of subpart EE of this part, combusting any 
amount of coal or coal-derived fuel, alone or in combination with any 
amount of any other fuel, during any year; or
    (2) For purposes of subpart EE of this part, combusting any amount 
of coal or coal-derived fuel, alone or in combination with any amount of 
any other fuel, during a specified year.
    Cogeneration unit means a stationary, fossil-fuel-fired boiler or 
stationary, fossil-fuel-fired combustion turbine:
    (1) Having equipment used to produce electricity and useful thermal 
energy for industrial, commercial, heating, or cooling purposes through 
the sequential use of energy; and
    (2) Producing during the 12-month period starting on the date the 
unit first produces electricity and during any calendar year after the 
calendar year in which the unit first produces electricity--
    (i) For a topping-cycle cogeneration unit,
    (A) Useful thermal energy not less than 5 percent of total energy 
output; and

[[Page 52]]

    (B) Useful power that, when added to one-half of useful thermal 
energy produced, is not less then 42.5 percent of total energy input, if 
useful thermal energy produced is 15 percent or more of total energy 
output, or not less than 45 percent of total energy input, if useful 
thermal energy produced is less than 15 percent of total energy output.
    (ii) For a bottoming-cycle cogeneration unit, useful power not less 
than 45 percent of total energy input;
    (3) Provided that the total energy input under paragraphs (2)(i)(B) 
and (2)(ii) of this definition shall equal the unit's total energy input 
from all fuel except biomass if the unit is a boiler.
    Combustion turbine means:
    (1) An enclosed device comprising a compressor, a combustor, and a 
turbine and in which the flue gas resulting from the combustion of fuel 
in the combustor passes through the turbine, rotating the turbine; and
    (2) If the enclosed device under paragraph (1) of this definition is 
combined cycle, any associated duct burner, heat recovery steam 
generator, and steam turbine.
    Commence commercial operation means, with regard to a unit:
    (1) To have begun to produce steam, gas, or other heated medium used 
to generate electricity for sale or use, including test generation, 
except as provided in Sec. 96.105 and Sec. 96.184(h).
    (i) For a unit that is a CAIR NOX unit under Sec. 96.104 
on the later of November 15, 1990 or the date the unit commences 
commercial operation as defined in paragraph (1) of this definition and 
that subsequently undergoes a physical change (other than replacement of 
the unit by a unit at the same source), such date shall remain the date 
of commencement of commercial operation of the unit, which shall 
continue to be treated as the same unit.
    (ii) For a unit that is a CAIR NOX unit under Sec. 
96.104 on the later of November 15, 1990 or the date the unit commences 
commercial operation as defined in paragraph (1) of this definition and 
that is subsequently replaced by a unit at the same source (e.g., 
repowered), such date shall remain the replaced unit's date of 
commencement of commercial operation, and the replacement unit shall be 
treated as a separate unit with a separate date for commencement of 
commercial operation as defined in paragraph (1) or (2) of this 
definition as appropriate.
    (2) Notwithstanding paragraph (1) of this definition and except as 
provided in Sec. 96.105, for a unit that is not a CAIR NOX 
unit under Sec. 96.104 on the later of November 15, 1990 or the date 
the unit commences commercial operation as defined in paragraph (1) of 
this definition, the unit's date for commencement of commercial 
operation shall be the date on which the unit becomes a CAIR 
NOX unit under Sec. 96.104.
    (i) For a unit with a date for commencement of commercial operation 
as defined in paragraph (2) of this definition and that subsequently 
undergoes a physical change (other than replacement of the unit by a 
unit at the same source), such date shall remain the date of 
commencement of commercial operation of the unit, which shall continue 
to be treated as the same unit.
    (ii) For a unit with a date for commencement of commercial operation 
as defined in paragraph (2) of this definition and that is subsequently 
replaced by a unit at the same source (e.g., repowered), such date shall 
remain the replaced unit's date of commencement of commercial operation, 
and the replacement unit shall be treated as a separate unit with a 
separate date for commencement of commercial operation as defined in 
paragraph (1) or (2) of this definition as appropriate.
    Commence operation means:
    (1) To have begun any mechanical, chemical, or electronic process, 
including, with regard to a unit, start-up of a unit's combustion 
chamber, except as provided in Sec. 96.184(h).
    (2) For a unit that undergoes a physical change (other than 
replacement of the unit by a unit at the same source) after the date the 
unit commences operation as defined in paragraph (1) of this definition, 
such date shall remain the date of commencement of operation of the 
unit, which shall continue to be treated as the same unit.
    (3) For a unit that is replaced by a unit at the same source (e.g., 
repowered) after the date the unit commences operation as defined in 
paragraph (1) of this definition, such date shall remain the replaced 
unit's date of

[[Page 53]]

commencement of operation, and the replacement unit shall be treated as 
a separate unit with a separate date for commencement of operation as 
defined in paragraph (1), (2), or (3) of this definition as appropriate, 
except as provided in Sec. 96.184(h).
    Compliance account means a CAIR NOX Allowance Tracking 
System account, established by the Administrator for a CAIR 
NOX source under subpart FF or II of this part, in which any 
CAIR NOX allowance allocations for the CAIR NOX 
units at the source are initially recorded and in which are held any 
CAIR NOX allowances available for use for a control period in 
order to meet the source's CAIR NOX emissions limitation in 
accordance with Sec. 96.154.
    Continuous emission monitoring system or CEMS means the equipment 
required under subpart HH of this part to sample, analyze, measure, and 
provide, by means of readings recorded at least once every 15 minutes 
(using an automated data acquisition and handling system (DAHS)), a 
permanent record of nitrogen oxides emissions, stack gas volumetric flow 
rate, stack gas moisture content, and oxygen or carbon dioxide 
concentration (as applicable), in a manner consistent with part 75 of 
this chapter. The following systems are the principal types of 
continuous emission monitoring systems required under subpart HH of this 
part:
    (1) A flow monitoring system, consisting of a stack flow rate 
monitor and an automated data acquisition and handling system and 
providing a permanent, continuous record of stack gas volumetric flow 
rate, in standard cubic feet per hour (scfh);
    (2) A nitrogen oxides concentration monitoring system, consisting of 
a NOX pollutant concentration monitor and an automated data 
acquisition and handling system and providing a permanent, continuous 
record of NOX emissions, in parts per million (ppm);
    (3) A nitrogen oxides emission rate (or NOX-diluent) 
monitoring system, consisting of a NOX pollutant 
concentration monitor, a diluent gas (CO2 or O2) 
monitor, and an automated data acquisition and handling system and 
providing a permanent, continuous record of NOX 
concentration, in parts per million (ppm), diluent gas concentration, in 
percent CO2 or O2; and NOX emission 
rate, in pounds per million British thermal units (lb/mmBtu);
    (4) A moisture monitoring system, as defined in Sec. 75.11(b)(2) of 
this chapter and providing a permanent, continuous record of the stack 
gas moisture content, in percent H2O;
    (5) A carbon dioxide monitoring system, consisting of a 
CO2 pollutant concentration monitor (or an oxygen monitor 
plus suitable mathematical equations from which the CO2 
concentration is derived) and an automated data acquisition and handling 
system and providing a permanent, continuous record of CO2 
emissions, in percent CO2; and
    (6) An oxygen monitoring system, consisting of an O2 
concentration monitor and an automated data acquisition and handling 
system and providing a permanent, continuous record of O2, in 
percent O2.
    Control period means the period beginning January 1 of a calendar 
year, except as provided in Sec. 96.106(c)(2), and ending on December 
31 of the same year, inclusive.
    Emissions means air pollutants exhausted from a unit or source into 
the atmosphere, as measured, recorded, and reported to the Administrator 
by the CAIR designated representative and as determined by the 
Administrator in accordance with subpart HH of this part.
    Excess emissions means any ton of nitrogen oxides emitted by the 
CAIR NOX units at a CAIR NOX source during a 
control period that exceeds the CAIR NOX emissions limitation 
for the source.
    Fossil fuel means natural gas, petroleum, coal, or any form of 
solid, liquid, or gaseous fuel derived from such material.
    Fossil-fuel-fired means, with regard to a unit, combusting any 
amount of fossil fuel in any calendar year.
    Fuel oil means any petroleum-based fuel (including diesel fuel or 
petroleum derivatives such as oil tar) and any recycled or blended 
petroleum products or petroleum by-products used as a fuel whether in a 
liquid, solid, or gaseous state.

[[Page 54]]

    General account means a CAIR NOX Allowance Tracking 
System account, established under subpart FF of this part, that is not a 
compliance account.
    Generator means a device that produces electricity.
    Gross electrical output means, with regard to a cogeneration unit, 
electricity made available for use, including any such electricity used 
in the power production process (which process includes, but is not 
limited to, any on-site processing or treatment of fuel combusted at the 
unit and any on-site emission controls).
    Heat input means, with regard to a specified period of time, the 
product (in mmBtu/time) of the gross calorific value of the fuel (in 
Btu/lb) divided by 1,000,000 Btu/mmBtu and multiplied by the fuel feed 
rate into a combustion device (in lb of fuel/time), as measured, 
recorded, and reported to the Administrator by the CAIR designated 
representative and determined by the Administrator in accordance with 
subpart HH of this part and excluding the heat derived from preheated 
combustion air, recirculated flue gases, or exhaust from other sources.
    Heat input rate means the amount of heat input (in mmBtu) divided by 
unit operating time (in hr) or, with regard to a specific fuel, the 
amount of heat input attributed to the fuel (in mmBtu) divided by the 
unit operating time (in hr) during which the unit combusts the fuel.
    Hg Budget Trading Program means a multi-state Hg air pollution 
control and emission reduction program approved and administered by the 
Administrator in accordance subpart HHHH of part 60 of this chapter and 
Sec. 60.24(h)(6), or established by the Administrator under section 111 
of the Clean Air Act, as a means of reducing national Hg emissions.
    Life-of-the-unit, firm power contractual arrangement means a unit 
participation power sales agreement under which a utility or industrial 
customer reserves, or is entitled to receive, a specified amount or 
percentage of nameplate capacity and associated energy generated by any 
specified unit and pays its proportional amount of such unit's total 
costs, pursuant to a contract:
    (1) For the life of the unit;
    (2) For a cumulative term of no less than 30 years, including 
contracts that permit an election for early termination; or
    (3) For a period no less than 25 years or 70 percent of the economic 
useful life of the unit determined as of the time the unit is built, 
with option rights to purchase or release some portion of the nameplate 
capacity and associated energy generated by the unit at the end of the 
period.
    Maximum design heat input means the maximum amount of fuel per hour 
(in Btu/hr) that a unit is capable of combusting on a steady state basis 
as of the initial installation of the unit as specified by the 
manufacturer of the unit.
    Monitoring system means any monitoring system that meets the 
requirements of subpart HH of this part, including a continuous 
emissions monitoring system, an alternative monitoring system, or an 
excepted monitoring system under part 75 of this chapter.
    Most stringent State or Federal NOX emissions limitation means, with 
regard to a unit, the lowest NOX emissions limitation (in 
terms of lb/mmBtu) that is applicable to the unit under State or Federal 
law, regardless of the averaging period to which the emissions 
limitation applies.
    Nameplate capacity means, starting from the initial installation of 
a generator, the maximum electrical generating output (in MWe) that the 
generator is capable of producing on a steady state basis and during 
continuous operation (when not restricted by seasonal or other 
deratings) as of such installation as specified by the manufacturer of 
the generator or, starting from the completion of any subsequent 
physical change in the generator resulting in an increase in the maximum 
electrical generating output (in MWe) that the generator is capable of 
producing on a steady state basis and during continuous operation (when 
not restricted by seasonal or other deratings), such increased maximum 
amount as of such completion as specified by the person conducting the 
physical change.
    Oil-fired means, for purposes of subpart EE of this part, combusting 
fuel

[[Page 55]]

oil for more than 15.0 percent of the annual heat input in a specified 
year and not qualifying as coal-fired.
    Operator means any person who operates, controls, or supervises a 
CAIR NOX unit or a CAIR NOX source and shall 
include, but not be limited to, any holding company, utility system, or 
plant manager of such a unit or source.
    Owner means any of the following persons:
    (1) With regard to a CAIR NOX source or a CAIR 
NOX unit at a source, respectively:
    (i) Any holder of any portion of the legal or equitable title in a 
CAIR NOX unit at the source or the CAIR NOX unit;
    (ii) Any holder of a leasehold interest in a CAIR NOX 
unit at the source or the CAIR NOX unit; or
    (iii) Any purchaser of power from a CAIR NOX unit at the 
source or the CAIR NOX unit under a life-of-the-unit, firm 
power contractual arrangement; provided that, unless expressly provided 
for in a leasehold agreement, owner shall not include a passive lessor, 
or a person who has an equitable interest through such lessor, whose 
rental payments are not based (either directly or indirectly) on the 
revenues or income from such CAIR NOX unit; or
    (2) With regard to any general account, any person who has an 
ownership interest with respect to the CAIR NOX allowances 
held in the general account and who is subject to the binding agreement 
for the CAIR authorized account representative to represent the person's 
ownership interest with respect to CAIR NOX allowances.
    Permitting authority means the State air pollution control agency, 
local agency, other State agency, or other agency authorized by the 
Administrator to issue or revise permits to meet the requirements of the 
CAIR NOX Annual Trading Program or, if no such agency has 
been so authorized, the Administrator.
    Potential electrical output capacity means 33 percent of a unit's 
maximum design heat input, divided by 3,413 Btu/kWh, divided by 1,000 
kWh/MWh, and multiplied by 8,760 hr/yr.
    Receive or receipt of means, when referring to the permitting 
authority or the Administrator, to come into possession of a document, 
information, or correspondence (whether sent in hard copy or by 
authorized electronic transmission), as indicated in an official log, or 
by a notation made on the document, information, or correspondence, by 
the permitting authority or the Administrator in the regular course of 
business.
    Recordation, record, or recorded means, with regard to CAIR 
NOX allowances, the movement of CAIR NOX 
allowances by the Administrator into or between CAIR NOX 
Allowance Tracking System accounts, for purposes of allocation, 
transfer, or deduction.
    Reference method means any direct test method of sampling and 
analyzing for an air pollutant as specified in Sec. 75.22 of this 
chapter.
    Replacement, replace, or replaced means, with regard to a unit, the 
demolishing of a unit, or the permanent shutdown and permanent disabling 
of a unit, and the construction of another unit (the replacement unit) 
to be used instead of the demolished or shutdown unit (the replaced 
unit).
    Repowered means, with regard to a unit, replacement of a coal-fired 
boiler with one of the following coal-fired technologies at the same 
source as the coal-fired boiler:
    (1) Atmospheric or pressurized fluidized bed combustion;
    (2) Integrated gasification combined cycle;
    (3) Magnetohydrodynamics;
    (4) Direct and indirect coal-fired turbines;
    (5) Integrated gasification fuel cells; or
    (6) As determined by the Administrator in consultation with the 
Secretary of Energy, a derivative of one or more of the technologies 
under paragraphs (1) through (5) of this definition and any other coal-
fired technology capable of controlling multiple combustion emissions 
simultaneously with improved boiler or generation efficiency and with 
significantly greater waste reduction relative to the performance of 
technology in widespread commercial use as of January 1, 2005.
    Serial number means, for a CAIR NOX allowance, the unique 
identification

[[Page 56]]

number assigned to each CAIR NOX allowance by the 
Administrator.
    Sequential use of energy means:
    (1) For a topping-cycle cogeneration unit, the use of reject heat 
from electricity production in a useful thermal energy application or 
process; or
    (2) For a bottoming-cycle cogeneration unit, the use of reject heat 
from useful thermal energy application or process in electricity 
production.
    Solid waste incineration unit means a stationary, fossil-fuel-fired 
boiler or stationary, fossil-fuel-fired combustion turbine that is a 
``solid waste incineration unit'' as defined in section 129(g)(1) of the 
Clean Air Act.
    Source means all buildings, structures, or installations located in 
one or more contiguous or adjacent properties under common control of 
the same person or persons. For purposes of section 502(c) of the Clean 
Air Act, a ``source,'' including a ``source'' with multiple units, shall 
be considered a single ``facility.''
    State means one of the States or the District of Columbia that 
adopts the CAIR NOX Annual Trading Program pursuant to Sec. 
51.123(o)(1) or (2) of this chapter.
    Submit or serve means to send or transmit a document, information, 
or correspondence to the person specified in accordance with the 
applicable regulation:
    (1) In person;
    (2) By United States Postal Service; or
    (3) By other means of dispatch or transmission and delivery. 
Compliance with any ``submission'' or ``service'' deadline shall be 
determined by the date of dispatch, transmission, or mailing and not the 
date of receipt.
    Title V operating permit means a permit issued under title V of the 
Clean Air Act and part 70 or part 71 of this chapter.
    Title V operating permit regulations means the regulations that the 
Administrator has approved or issued as meeting the requirements of 
title V of the Clean Air Act and part 70 or 71 of this chapter.
    Ton means 2,000 pounds. For the purpose of determining compliance 
with the CAIR NOX emissions limitation, total tons of 
nitrogen oxides emissions for a control period shall be calculated as 
the sum of all recorded hourly emissions (or the mass equivalent of the 
recorded hourly emission rates) in accordance with subpart HH of this 
part, but with any remaining fraction of a ton equal to or greater than 
0.50 tons deemed to equal one ton and any remaining fraction of a ton 
less than 0.50 tons deemed to equal zero tons.
    Topping-cycle cogeneration unit means a cogeneration unit in which 
the energy input to the unit is first used to produce useful power, 
including electricity, and at least some of the reject heat from the 
electricity production is then used to provide useful thermal energy.
    Total energy input means, with regard to a cogeneration unit, total 
energy of all forms supplied to the cogeneration unit, excluding energy 
produced by the cogeneration unit itself. Each form of energy supplied 
shall be measured by the lower heating value of that form of energy 
calculated as follows:

LHV = HHV - 10.55(W + 9H)

Where:

LHV = lower heating value of fuel in Btu/lb,
HHV = higher heating value of fuel in Btu/lb,
W = Weight % of moisture in fuel, and
H = Weight % of hydrogen in fuel.

    Total energy output means, with regard to a cogeneration unit, the 
sum of useful power and useful thermal energy produced by the 
cogeneration unit.
    Unit means a stationary, fossil-fuel-fired boiler or combustion 
turbine or other stationary, fossil-fuel-fired combustion device.
    Unit operating day means a calendar day in which a unit combusts any 
fuel.
    Unit operating hour or hour of unit operation means an hour in which 
a unit combusts any fuel.
    Useful power means, with regard to a cogeneration unit, electricity 
or mechanical energy made available for use, excluding any such energy 
used in the power production process (which process includes, but is not 
limited to, any on-site processing or treatment of fuel combusted at the 
unit and any on-site emission controls).
    Useful thermal energy means, with regard to a cogeneration unit, 
thermal energy that is:

[[Page 57]]

    (1) Made available to an industrial or commercial process (not a 
power production process), excluding any heat contained in condensate 
return or makeup water;
    (2) Used in a heating application (e.g., space heating or domestic 
hot water heating); or
    (3) Used in a space cooling application (i.e., thermal energy used 
by an absorption chiller).
    Utility power distribution system means the portion of an 
electricity grid owned or operated by a utility and dedicated to 
delivering electricity to customers.

[70 FR 25339, May 12, 2005, as amended at 71 FR 25380, Apr. 28, 2006; 71 
FR 74794, Dec. 13, 2006; 72 FR 59205, Oct. 19, 2007]



Sec. 96.103  Measurements, abbreviations, and acronyms.

    Measurements, abbreviations, and acronyms used in this subpart and 
subparts BB through II are defined as follows:
Btu--British thermal unit.
CO2--carbon dioxide
H2O--water
Hg--mercury
hr--hour
kW--kilowatt electrical
kWh--kilowatt hour
lb--pound
mmBtu--million Btu
MWe--megawatt electrical
MWh--megawatt hour
NOX--nitrogen oxides
O2--oxygen
ppm--parts per million
scfh--standard cubic feet per hour
SO2--sulfur dioxide
yr--year

[71 FR 25381, Apr. 28, 2006]



Sec. 96.104  Applicability.

    (a) Except as provided in paragraph (b) of this section:
    (1) The following units in a State shall be CAIR NOX 
units, and any source that includes one or more such units shall be a 
CAIR NOX source, subject to the requirements of this subpart 
and subparts BB through HH of this part: any stationary, fossil-fuel-
fired boiler or stationary, fossil-fuel-fired combustion turbine serving 
at any time, since the later of November 15, 1990 or the start-up of the 
unit's combustion chamber, a generator with nameplate capacity of more 
than 25 MWe producing electricity for sale.
    (2) If a stationary boiler or stationary combustion turbine that, 
under paragraph (a)(1) of this section, is not a CAIR NOX 
unit begins to combust fossil fuel or to serve a generator with 
nameplate capacity of more than 25 MWe producing electricity for sale, 
the unit shall become a CAIR NOX unit as provided in 
paragraph (a)(1) of this section on the first date on which it both 
combusts fossil fuel and serves such generator.
    (b) The units in a State that meet the requirements set forth in 
paragraph (b)(1)(i), (b)(2)(i), or (b)(2)(ii) of this section shall not 
be CAIR NOX units:
    (1)(i) Any unit that is a CAIR NOX unit under paragraph 
(a)(1) or (2) of this section:
    (A) Qualifying as a cogeneration unit during the 12-month period 
starting on the date the unit first produces electricity and continuing 
to qualify as a cogeneration unit; and
    (B) Not serving at any time, since the later of November 15, 1990 or 
the start-up of the unit's combustion chamber, a generator with 
nameplate capacity of more than 25 MWe supplying in any calendar year 
more than one-third of the unit's potential electric output capacity or 
219,000 MWh, whichever is greater, to any utility power distribution 
system for sale.
    (ii) If a unit qualifies as a cogeneration unit during the 12-month 
period starting on the date the unit first produces electricity and 
meets the requirements of paragraphs (b)(1)(i) of this section for at 
least one calendar year, but subsequently no longer meets all such 
requirements, the unit shall become a CAIR NOX unit starting 
on the earlier of January 1 after the first calendar year during which 
the unit first no longer qualifies as a cogeneration unit or January 1 
after the first calendar year during which the unit no longer meets the 
requirements of paragraph (b)(1)(i)(B) of this section.
    (2)(i) Any unit that is a CAIR NOX unit under paragraph 
(a)(1) or (2) of this section commencing operation before January 1, 
1985:
    (A) Qualifying as a solid waste incineration unit; and

[[Page 58]]

    (B) With an average annual fuel consumption of non-fossil fuel for 
1985-1987 exceeding 80 percent (on a Btu basis) and an average annual 
fuel consumption of non-fossil fuel for any 3 consecutive calendar years 
after 1990 exceeding 80 percent (on a Btu basis).
    (ii) Any unit that is a CAIR NOX unit under paragraph 
(a)(1) or (2) of this section commencing operation on or after January 
1, 1985:
    (A) Qualifying as a solid waste incineration unit; and
    (B) With an average annual fuel consumption of non-fossil fuel for 
the first 3 calendar years of operation exceeding 80 percent (on a Btu 
basis) and an average annual fuel consumption of non-fossil fuel for any 
3 consecutive calendar years after 1990 exceeding 80 percent (on a Btu 
basis).
    (iii) If a unit qualifies as a solid waste incineration unit and 
meets the requirements of paragraph (b)(2)(i) or (ii) of this section 
for at least 3 consecutive calendar years, but subsequently no longer 
meets all such requirements, the unit shall become a CAIR NOX 
unit starting on the earlier of January 1 after the first calendar year 
during which the unit first no longer qualifies as a solid waste 
incineration unit or January 1 after the first 3 consecutive calendar 
years after 1990 for which the unit has an average annual fuel 
consumption of fossil fuel of 20 percent or more.

[71 FR 25382, Apr. 28, 2006]



Sec. 96.105  Retired unit exemption.

    (a)(1) Any CAIR NOX unit that is permanently retired and 
is not a CAIR NOX opt-in unit under subpart II of this part 
shall be exempt from the CAIR NOX Annual Trading Program, 
except for the provisions of this section, Sec. 96.102, Sec. 96.103, 
Sec. 96.104, Sec. 96.106(c)(4) through (7), Sec. 96.107, Sec. 
96.108, and subparts BB and EE through GG.
    (2) The exemption under paragraph (a)(1) of this section shall 
become effective the day on which the CAIR NOX unit is 
permanently retired. Within 30 days of the unit's permanent retirement, 
the CAIR designated representative shall submit a statement to the 
permitting authority otherwise responsible for administering any CAIR 
permit for the unit and shall submit a copy of the statement to the 
Administrator. The statement shall state, in a format prescribed by the 
permitting authority, that the unit was permanently retired on a 
specific date and will comply with the requirements of paragraph (b) of 
this section.
    (3) After receipt of the statement under paragraph (a)(2) of this 
section, the permitting authority will amend any permit under subpart CC 
of this part covering the source at which the unit is located to add the 
provisions and requirements of the exemption under paragraphs (a)(1) and 
(b) of this section.
    (b) Special provisions. (1) A unit exempt under paragraph (a) of 
this section shall not emit any nitrogen oxides, starting on the date 
that the exemption takes effect.
    (2) The permitting authority will allocate CAIR NOX 
allowances under subpart EE of this part to a unit exempt under 
paragraph (a) of this section.
    (3) For a period of 5 years from the date the records are created, 
the owners and operators of a unit exempt under paragraph (a) of this 
section shall retain, at the source that includes the unit, records 
demonstrating that the unit is permanently retired. The 5-year period 
for keeping records may be extended for cause, at any time before the 
end of the period, in writing by the permitting authority or the 
Administrator. The owners and operators bear the burden of proof that 
the unit is permanently retired.
    (4) The owners and operators and, to the extent applicable, the CAIR 
designated representative of a unit exempt under paragraph (a) of this 
section shall comply with the requirements of the CAIR NOX 
Annual Trading Program concerning all periods for which the exemption is 
not in effect, even if such requirements arise, or must be complied 
with, after the exemption takes effect.
    (5) A unit exempt under paragraph (a) of this section and located at 
a source that is required, or but for this exemption would be required, 
to have a title V operating permit shall not resume operation unless the 
CAIR designated representative of the source submits a complete CAIR 
permit application under Sec. 96.122 for the unit not less than

[[Page 59]]

18 months (or such lesser time provided by the permitting authority) 
before the later of January 1, 2009 or the date on which the unit 
resumes operation.
    (6) On the earlier of the following dates, a unit exempt under 
paragraph (a) of this section shall lose its exemption:
    (i) The date on which the CAIR designated representative submits a 
CAIR permit application for the unit under paragraph (b)(5) of this 
section;
    (ii) The date on which the CAIR designated representative is 
required under paragraph (b)(5) of this section to submit a CAIR permit 
application for the unit; or
    (iii) The date on which the unit resumes operation, if the CAIR 
designated representative is not required to submit a CAIR permit 
application for the unit.
    (7) For the purpose of applying monitoring, reporting, and 
recordkeeping requirements under subpart HH of this part, a unit that 
loses its exemption under paragraph (a) of this section shall be treated 
as a unit that commences commercial operation on the first date on which 
the unit resumes operation.

[70 FR 25339, May 12, 2005, as amended at 71 FR 25382, Apr. 28, 2006; 71 
FR 74794, Dec. 13, 2006]



Sec. 96.106  Standard requirements.

    (a) Permit requirements. (1) The CAIR designated representative of 
each CAIR NOX source required to have a title V operating 
permit and each CAIR NOX unit required to have a title V 
operating permit at the source shall:
    (i) Submit to the permitting authority a complete CAIR permit 
application under Sec. 96.122 in accordance with the deadlines 
specified in Sec. 96.121; and
    (ii) Submit in a timely manner any supplemental information that the 
permitting authority determines is necessary in order to review a CAIR 
permit application and issue or deny a CAIR permit.
    (2) The owners and operators of each CAIR NOX source 
required to have a title V operating permit and each CAIR NOX 
unit required to have a title V operating permit at the source shall 
have a CAIR permit issued by the permitting authority under subpart CC 
of this part for the source and operate the source and the unit in 
compliance with such CAIR permit.
    (3) Except as provided in subpart II of this part, the owners and 
operators of a CAIR NOX source that is not otherwise required 
to have a title V operating permit and each CAIR NOX unit 
that is not otherwise required to have a title V operating permit are 
not required to submit a CAIR permit application, and to have a CAIR 
permit, under subpart CC of this part for such CAIR NOX 
source and such CAIR NOX unit.
    (b) Monitoring, reporting, and recordkeeping requirements. (1) The 
owners and operators, and the CAIR designated representative, of each 
CAIR NOX source and each CAIR NOX unit at the 
source shall comply with the monitoring, reporting, and recordkeeping 
requirements of subpart HH of this part.
    (2) The emissions measurements recorded and reported in accordance 
with subpart HH of this part shall be used to determine compliance by 
each CAIR NOX source with the CAIR NOX emissions 
limitation under paragraph (c) of this section.
    (c) Nitrogen oxides emission requirements. (1) As of the allowance 
transfer deadline for a control period, the owners and operators of each 
CAIR NOX source and each CAIR NOX unit at the 
source shall hold, in the source's compliance account, CAIR 
NOX allowances available for compliance deductions for the 
control period under Sec. 96.154(a) in an amount not less than the tons 
of total nitrogen oxides emissions for the control period from all CAIR 
NOX units at the source, as determined in accordance with 
subpart HH of this part.
    (2) A CAIR NOX unit shall be subject to the requirements 
under paragraph (c)(1) of this section for the control period starting 
on the later of January 1, 2009 or the deadline for meeting the unit's 
monitor certification requirements under Sec. 96.170(b)(1), (2), or (5) 
and for each control period thereafter.
    (3) A CAIR NOX allowance shall not be deducted, for 
compliance with the requirements under paragraph (c)(1) of this section, 
for a control period in a calendar year before the year for which the 
CAIR NOX allowance was allocated.

[[Page 60]]

    (4) CAIR NOX allowances shall be held in, deducted from, 
or transferred into or among CAIR NOX Allowance Tracking 
System accounts in accordance with subparts FF, GG, and II of this part.
    (5) A CAIR NOX allowance is a limited authorization to 
emit one ton of nitrogen oxides in accordance with the CAIR 
NOX Annual Trading Program. No provision of the CAIR 
NOX Annual Trading Program, the CAIR permit application, the 
CAIR permit, or an exemption under Sec. 96.105 and no provision of law 
shall be construed to limit the authority of the State or the United 
States to terminate or limit such authorization.
    (6) A CAIR NOX allowance does not constitute a property 
right.
    (7) Upon recordation by the Administrator under subpart EE, FF, GG, 
or II of this part, every allocation, transfer, or deduction of a CAIR 
NOX allowance to or from a CAIR NOX source's 
compliance account is incorporated automatically in any CAIR permit of 
the source.
    (d) Excess emissions requirements. If a CAIR NOX source 
emits nitrogen oxides during any control period in excess of the CAIR 
NOX emissions limitation, then:
    (1) The owners and operators of the source and each CAIR 
NOX unit at the source shall surrender the CAIR 
NOX allowances required for deduction under Sec. 
96.154(d)(1) and pay any fine, penalty, or assessment or comply with any 
other remedy imposed, for the same violations, under the Clean Air Act 
or applicable State law; and
    (2) Each ton of such excess emissions and each day of such control 
period shall constitute a separate violation of this subpart, the Clean 
Air Act, and applicable State law.
    (e) Recordkeeping and reporting requirements. (1) Unless otherwise 
provided, the owners and operators of the CAIR NOX source and 
each CAIR NOX unit at the source shall keep on site at the 
source each of the following documents for a period of 5 years from the 
date the document is created. This period may be extended for cause, at 
any time before the end of 5 years, in writing by the permitting 
authority or the Administrator.
    (i) The certificate of representation under Sec. 96.113 for the 
CAIR designated representative for the source and each CAIR 
NOX unit at the source and all documents that demonstrate the 
truth of the statements in the certificate of representation; provided 
that the certificate and documents shall be retained on site at the 
source beyond such 5-year period until such documents are superseded 
because of the submission of a new certificate of representation under 
Sec. 96.113 changing the CAIR designated representative.
    (ii) All emissions monitoring information, in accordance with 
subpart HH of this part, provided that to the extent that subpart HH of 
this part provides for a 3-year period for recordkeeping, the 3-year 
period shall apply.
    (iii) Copies of all reports, compliance certifications, and other 
submissions and all records made or required under the CAIR 
NOX Annual Trading Program.
    (iv) Copies of all documents used to complete a CAIR permit 
application and any other submission under the CAIR NOX 
Annual Trading Program or to demonstrate compliance with the 
requirements of the CAIR NOX Annual Trading Program.
    (2) The CAIR designated representative of a CAIR NOX 
source and each CAIR NOX unit at the source shall submit the 
reports required under the CAIR NOX Annual Trading Program, 
including those under subpart HH of this part.
    (f) Liability. (1) Each CAIR NOX source and each CAIR 
NOX unit shall meet the requirements of the CAIR 
NOX Annual Trading Program.
    (2) Any provision of the CAIR NOX Annual Trading Program 
that applies to a CAIR NOX source or the CAIR designated 
representative of a CAIR NOX source shall also apply to the 
owners and operators of such source and of the CAIR NOX units 
at the source.
    (3) Any provision of the CAIR NOX Annual Trading Program 
that applies to a CAIR NOX unit or the CAIR designated 
representative of a CAIR NOX unit shall also apply to the 
owners and operators of such unit.
    (g) Effect on other authorities. No provision of the CAIR 
NOX Annual Trading Program, a CAIR permit application, a

[[Page 61]]

CAIR permit, or an exemption under Sec. 96.105 shall be construed as 
exempting or excluding the owners and operators, and the CAIR designated 
representative, of a CAIR NOX source or CAIR NOX 
unit from compliance with any other provision of the applicable, 
approved State implementation plan, a federally enforceable permit, or 
the Clean Air Act.

[70 FR 25339, May 12, 2005, as amended at 71 FR 25382, Apr. 28, 2006]



Sec. 96.107  Computation of time.

    (a) Unless otherwise stated, any time period scheduled, under the 
CAIR NOX Annual Trading Program, to begin on the occurrence 
of an act or event shall begin on the day the act or event occurs.
    (b) Unless otherwise stated, any time period scheduled, under the 
CAIR NOX Annual Trading Program, to begin before the 
occurrence of an act or event shall be computed so that the period ends 
the day before the act or event occurs.
    (c) Unless otherwise stated, if the final day of any time period, 
under the CAIR NOX Annual Trading Program, falls on a weekend 
or a State or Federal holiday, the time period shall be extended to the 
next business day.



Sec. 96.108  Appeal procedures.

    The appeal procedures for decisions of the Administrator under the 
CAIR NOX Annual Trading Program are set forth in part 78 of 
this chapter.



     Subpart BB_CAIR Designated Representative for CAIR NOX Sources

    Source: 70 FR 25339, May 12, 2005, unless otherwise noted.



Sec. 96.110  Authorization and responsibilities of CAIR designated 
representative.

    (a) Except as provided under Sec. 96.111, each CAIR NOX 
source, including all CAIR NOX units at the source, shall 
have one and only one CAIR designated representative, with regard to all 
matters under the CAIR NOX Annual Trading Program concerning 
the source or any CAIR NOX unit at the source.
    (b) The CAIR designated representative of the CAIR NOX 
source shall be selected by an agreement binding on the owners and 
operators of the source and all CAIR NOX units at the source 
and shall act in accordance with the certification statement in Sec. 
96.113(a)(4)(iv).
    (c) Upon receipt by the Administrator of a complete certificate of 
representation under Sec. 96.113, the CAIR designated representative of 
the source shall represent and, by his or her representations, actions, 
inactions, or submissions, legally bind each owner and operator of the 
CAIR NOX source represented and each CAIR NOX unit 
at the source in all matters pertaining to the CAIR NOX 
Annual Trading Program, notwithstanding any agreement between the CAIR 
designated representative and such owners and operators. The owners and 
operators shall be bound by any decision or order issued to the CAIR 
designated representative by the permitting authority, the 
Administrator, or a court regarding the source or unit.
    (d) No CAIR permit will be issued, no emissions data reports will be 
accepted, and no CAIR NOX Allowance Tracking System account 
will be established for a CAIR NOX unit at a source, until 
the Administrator has received a complete certificate of representation 
under Sec. 96.113 for a CAIR designated representative of the source 
and the CAIR NOX units at the source.
    (e)(1) Each submission under the CAIR NOX Annual Trading 
Program shall be submitted, signed, and certified by the CAIR designated 
representative for each CAIR NOX source on behalf of which 
the submission is made. Each such submission shall include the following 
certification statement by the CAIR designated representative: ``I am 
authorized to make this submission on behalf of the owners and operators 
of the source or units for which the submission is made. I certify under 
penalty of law that I have personally examined, and am familiar with, 
the statements and information submitted in this document and all its 
attachments. Based on my inquiry of those individuals with primary 
responsibility for obtaining the information, I

[[Page 62]]

certify that the statements and information are to the best of my 
knowledge and belief true, accurate, and complete. I am aware that there 
are significant penalties for submitting false statements and 
information or omitting required statements and information, including 
the possibility of fine or imprisonment.''
    (2) The permitting authority and the Administrator will accept or 
act on a submission made on behalf of owner or operators of a CAIR 
NOX source or a CAIR NOX unit only if the 
submission has been made, signed, and certified in accordance with 
paragraph (e)(1) of this section.



Sec. 96.111  Alternate CAIR designated representative.

    (a) A certificate of representation under Sec. 96.113 may designate 
one and only one alternate CAIR designated representative, who may act 
on behalf of the CAIR designated representative. The agreement by which 
the alternate CAIR designated representative is selected shall include a 
procedure for authorizing the alternate CAIR designated representative 
to act in lieu of the CAIR designated representative.
    (b) Upon receipt by the Administrator of a complete certificate of 
representation under Sec. 96.113, any representation, action, inaction, 
or submission by the alternate CAIR designated representative shall be 
deemed to be a representation, action, inaction, or submission by the 
CAIR designated representative.
    (c) Except in this section and Sec. Sec. 96.102, 96.110(a) and (d), 
96.112, 96.113, 96.115, 96.151, and 96.182, whenever the term ``CAIR 
designated representative'' is used in subparts AA through II of this 
part, the term shall be construed to include the CAIR designated 
representative or any alternate CAIR designated representative.

[70 FR 25339, May 12, 2005, as amended at 71 FR 25382, Apr. 28, 2006]



Sec. 96.112  Changing CAIR designated representative and alternate
CAIR designated representative; changes in owners and operators.

    (a) Changing CAIR designated representative. The CAIR designated 
representative may be changed at any time upon receipt by the 
Administrator of a superseding complete certificate of representation 
under Sec. 96.113. Notwithstanding any such change, all 
representations, actions, inactions, and submissions by the previous 
CAIR designated representative before the time and date when the 
Administrator receives the superseding certificate of representation 
shall be binding on the new CAIR designated representative and the 
owners and operators of the CAIR NOX source and the CAIR 
NOX units at the source.
    (b) Changing alternate CAIR designated representative. The alternate 
CAIR designated representative may be changed at any time upon receipt 
by the Administrator of a superseding complete certificate of 
representation under Sec. 96.113. Notwithstanding any such change, all 
representations, actions, inactions, and submissions by the previous 
alternate CAIR designated representative before the time and date when 
the Administrator receives the superseding certificate of representation 
shall be binding on the new alternate CAIR designated representative and 
the owners and operators of the CAIR NOX source and the CAIR 
NOX units at the source.
    (c) Changes in owners and operators. (1) In the event an owner or 
operator of a CAIR NOX source or a CAIR NOX unit 
is not included in the list of owners and operators in the certificate 
of representation under Sec. 96.113, such owner or operator shall be 
deemed to be subject to and bound by the certificate of representation, 
the representations, actions, inactions, and submissions of the CAIR 
designated representative and any alternate CAIR designated 
representative of the source or unit, and the decisions and orders of 
the permitting authority, the Administrator, or a court, as if the owner 
or operator were included in such list.
    (2) Within 30 days following any change in the owners and operators 
of a CAIR NOX source or a CAIR NOX unit, including 
the addition of a new owner or operator, the CAIR designated 
representative or any alternate CAIR designated representative shall 
submit a revision to the certificate of representation under Sec. 
96.113 amending the list

[[Page 63]]

of owners and operators to include the change.

[70 FR 25339, May 12, 2005, as amended at 71 FR 25382, Apr. 28, 2006]



Sec. 96.113  Certificate of representation.

    (a) A complete certificate of representation for a CAIR designated 
representative or an alternate CAIR designated representative shall 
include the following elements in a format prescribed by the 
Administrator:
    (1) Identification of the CAIR NOX source, and each CAIR 
NOX unit at the source, for which the certificate of 
representation is submitted, including identification and nameplate 
capacity of each generator served by each such unit.
    (2) The name, address, e-mail address (if any), telephone number, 
and facsimile transmission number (if any) of the CAIR designated 
representative and any alternate CAIR designated representative.
    (3) A list of the owners and operators of the CAIR NOX 
source and of each CAIR NOX unit at the source.
    (4) The following certification statements by the CAIR designated 
representative and any alternate CAIR designated representative--
    (i) ``I certify that I was selected as the CAIR designated 
representative or alternate CAIR designated representative, as 
applicable, by an agreement binding on the owners and operators of the 
source and each CAIR NOX unit at the source.''
    (ii) ``I certify that I have all the necessary authority to carry 
out my duties and responsibilities under the CAIR NOX Annual 
Trading Program on behalf of the owners and operators of the source and 
of each CAIR NOX unit at the source and that each such owner 
and operator shall be fully bound by my representations, actions, 
inactions, or submissions.''
    (iii) ``I certify that the owners and operators of the source and of 
each CAIR NOX unit at the source shall be bound by any order 
issued to me by the Administrator, the permitting authority, or a court 
regarding the source or unit.''
    (iv) ``Where there are multiple holders of a legal or equitable 
title to, or a leasehold interest in, a CAIR NOX unit, or 
where a utility or industrial customer purchases power from a CAIR 
NOX unit under a life-of-the-unit, firm power contractual 
arrangement, I certify that: I have given a written notice of my 
selection as the `CAIR designated representative' or `alternate CAIR 
designated representative', as applicable, and of the agreement by which 
I was selected to each owner and operator of the source and of each CAIR 
NOX unit at the source; and CAIR NOX allowances 
and proceeds of transactions involving CAIR NOX allowances 
will be deemed to be held or distributed in proportion to each holder's 
legal, equitable, leasehold, or contractual reservation or entitlement, 
except that, if such multiple holders have expressly provided for a 
different distribution of CAIR NOX allowances by contract, 
CAIR NOX allowances and proceeds of transactions involving 
CAIR NOX allowances will be deemed to be held or distributed 
in accordance with the contract.''
    (5) The signature of the CAIR designated representative and any 
alternate CAIR designated representative and the dates signed.
    (b) Unless otherwise required by the permitting authority or the 
Administrator, documents of agreement referred to in the certificate of 
representation shall not be submitted to the permitting authority or the 
Administrator. Neither the permitting authority nor the Administrator 
shall be under any obligation to review or evaluate the sufficiency of 
such documents, if submitted.

[70 FR 25339, May 12, 2005, as amended at 71 FR 25382, Apr. 28, 2006]



Sec. 96.114  Objections concerning CAIR designated representative.

    (a) Once a complete certificate of representation under Sec. 96.113 
has been submitted and received, the permitting authority and the 
Administrator will rely on the certificate of representation unless and 
until a superseding complete certificate of representation under Sec. 
96.113 is received by the Administrator.

[[Page 64]]

    (b) Except as provided in Sec. 96.112(a) or (b), no objection or 
other communication submitted to the permitting authority or the 
Administrator concerning the authorization, or any representation, 
action, inaction, or submission, of the CAIR designated representative 
shall affect any representation, action, inaction, or submission of the 
CAIR designated representative or the finality of any decision or order 
by the permitting authority or the Administrator under the CAIR 
NOX Annual Trading Program.
    (c) Neither the permitting authority nor the Administrator will 
adjudicate any private legal dispute concerning the authorization or any 
representation, action, inaction, or submission of any CAIR designated 
representative, including private legal disputes concerning the proceeds 
of CAIR NOX allowance transfers.



Sec. 96.115  Delegation by CAIR designated representative and 
alternate CAIR designated representative.

    (a) A CAIR designated representative may delegate, to one or more 
natural persons, his or her authority to make an electronic submission 
to the Administrator provided for or required under this part.
    (b) An alternate CAIR designated representative may delegate, to one 
or more natural persons, his or her authority to make an electronic 
submission to the Administrator provided for or required under this 
part.
    (c) In order to delegate authority to make an electronic submission 
to the Administrator in accordance with paragraph (a) or (b) of this 
section, the CAIR designated representative or alternate CAIR designated 
representative, as appropriate, must submit to the Administrator a 
notice of delegation, in a format prescribed by the Administrator, that 
includes the following elements:
    (1) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of such CAIR designated 
representative or alternate CAIR designated representative;
    (2) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of each such natural person 
(referred to as an ``agent'');
    (3) For each such natural person, a list of the type or types of 
electronic submissions under paragraph (a) or (b) of this section for 
which authority is delegated to him or her; and
    (4) The following certification statements by such CAIR designated 
representative or alternate CAIR designated representative:
    (i) ``I agree that any electronic submission to the Administrator 
that is by an agent identified in this notice of delegation and of a 
type listed for such agent in this notice of delegation and that is made 
when I am a CAIR designated representative or alternate CAIR designated 
representative, as appropriate, and before this notice of delegation is 
superseded by another notice of delegation under 40 CFR 96.115(d) shall 
be deemed to be an electronic submission by me.''
    (ii) ``Until this notice of delegation is superseded by another 
notice of delegation under 40 CFR 96.115(d), I agree to maintain an e-
mail account and to notify the Administrator immediately of any change 
in my e-mail address unless all delegation of authority by me under 40 
CFR 96.115 is terminated.''
    (d) A notice of delegation submitted under paragraph (c) of this 
section shall be effective, with regard to the CAIR designated 
representative or alternate CAIR designated representative identified in 
such notice, upon receipt of such notice by the Administrator and until 
receipt by the Administrator of a superseding notice of delegation 
submitted by such CAIR designated representative or alternate CAIR 
designated representative, as appropriate. The superseding notice of 
delegation may replace any previously identified agent, add a new agent, 
or eliminate entirely any delegation of authority.
    (e) Any electronic submission covered by the certification in 
paragraph (c)(4)(i) of this section and made in accordance with a notice 
of delegation effective under paragraph (d) of this section shall be 
deemed to be an electronic submission by the CAIR designated 
representative or alternate

[[Page 65]]

CAIR designated representative submitting such notice of delegation.

[71 FR 25382, Apr. 28, 2006, as amended at 71 FR 74794, Dec. 13, 2006]



                           Subpart CC_Permits

    Source: 70 FR 25339, May 12, 2005, unless otherwise noted.



Sec. 96.120  General CAIR NOX Annual Trading Program permit 
requirements.

    (a) For each CAIR NOX source required to have a title V 
operating permit or required, under subpart II of this part, to have a 
title V operating permit or other federally enforceable permit, such 
permit shall include a CAIR permit administered by the permitting 
authority for the title V operating permit or the federally enforceable 
permit as applicable. The CAIR portion of the title V permit or other 
federally enforceable permit as applicable shall be administered in 
accordance with the permitting authority's title V operating permits 
regulations promulgated under part 70 or 71 of this chapter or the 
permitting authority's regulations for other federally enforceable 
permits as applicable, except as provided otherwise by Sec. 96.105, 
this subpart, and subpart II of this part.
    (b) Each CAIR permit shall contain, with regard to the CAIR 
NOX source and the CAIR NOX units at the source 
covered by the CAIR permit, all applicable CAIR NOX Annual 
Trading Program, CAIR NOX Ozone Season Trading Program, and 
CAIR SO2 Trading Program requirements and shall be a complete 
and separable portion of the title V operating permit or other federally 
enforceable permit under paragraph (a) of this section.

[70 FR 25339, May 12, 2005, as amended at 71 FR 25383, Apr. 28, 2006]



Sec. 96.121  Submission of CAIR permit applications.

    (a) Duty to apply. The CAIR designated representative of any CAIR 
NOX source required to have a title V operating permit shall 
submit to the permitting authority a complete CAIR permit application 
under Sec. 96.122 for the source covering each CAIR NOX unit 
at the source at least 18 months (or such lesser time provided by the 
permitting authority) before the later of January 1, 2009 or the date on 
which the CAIR NOX unit commences commercial operation, 
except as provided in Sec. 96.183(a).
    (b) Duty to Reapply. For a CAIR NOX source required to 
have a title V operating permit, the CAIR designated representative 
shall submit a complete CAIR permit application under Sec. 96.122 for 
the source covering each CAIR NOX unit at the source to renew 
the CAIR permit in accordance with the permitting authority's title V 
operating permits regulations addressing permit renewal, except as 
provided in Sec. 96.183(b).

[70 FR 25339, May 12, 2005, as amended at 71 FR 25383, Apr. 28, 2006]



Sec. 96.122  Information requirements for CAIR permit applications.

    A complete CAIR permit application shall include the following 
elements concerning the CAIR NOX source for which the 
application is submitted, in a format prescribed by the permitting 
authority:
    (a) Identification of the CAIR NOX source;
    (b) Identification of each CAIR NOX unit at the CAIR 
NOX source; and
    (c) The standard requirements under Sec. 96.106.



Sec. 96.123  CAIR permit contents and term.

    (a) Each CAIR permit will contain, in a format prescribed by the 
permitting authority, all elements required for a complete CAIR permit 
application under Sec. 96.122.
    (b) Each CAIR permit is deemed to incorporate automatically the 
definitions of terms under Sec. 96.102 and, upon recordation by the 
Administrator under subpart EE, FF, GG, or II of this part, every 
allocation, transfer, or deduction of a CAIR NOX allowance to 
or from the compliance account of the CAIR NOX source covered 
by the permit.
    (c) The term of the CAIR permit will be set by the permitting 
authority, as necessary to facilitate coordination of the renewal of the 
CAIR permit with issuance, revision, or renewal of the CAIR 
NOX source's title V operating

[[Page 66]]

permit or other federally enforceable permit as applicable.

[70 FR 25339, May 12, 2005, as amended at 71 FR 25383, Apr. 28, 2006]



Sec. 96.124  CAIR permit revisions.

    Except as provided in Sec. 96.123(b), the permitting authority will 
revise the CAIR permit, as necessary, in accordance with the permitting 
authority's title V operating permits regulations or the permitting 
authority's regulations for other federally enforceable permits as 
applicable addressing permit revisions.

Subpart DD [Reserved]



                Subpart EE_CAIR NOX Allowance Allocations

    Source: 70 FR 25339, May 12, 2005, unless otherwise noted.



Sec. 96.140  State trading budgets.

    The State trading budgets for annual allocations of CAIR 
NOX allowances for the control periods in 2009 through 2014 
and in 2015 and thereafter are respectively as follows:

------------------------------------------------------------------------
                                                          State trading
                                        State trading    budget for 2015
                State                 budget for 2009-   and thereafter
                                         2014 (tons)         (tons)
------------------------------------------------------------------------
Alabama.............................            69,020            57,517
Delaware............................             4,166             3,472
District of Columbia................               144               120
Florida.............................            99,445            82,871
Georgia.............................            66,321            55,268
Illinois............................            76,230            63,525
Indiana.............................           108,935            90,779
Iowa................................            32,692            27,243
Kentucky............................            83,205            69,337
Louisiana...........................            35,512            29,593
Maryland............................            27,724            23,104
Michigan............................            65,304            54,420
Minnesota...........................            31,443            26,203
Mississippi.........................            17,807            14,839
Missouri............................            59,871            49,892
New Jersey..........................            12,670            10,558
New York............................            45,617            38,014
North Carolina......................            62,183            51,819
Ohio................................           108,667            90,556
Pennsylvania........................            99,049            82,541
South Carolina......................            32,662            27,219
Tennessee...........................            50,973            42,478
Texas...............................           181,014           150,845
Virginia............................            36,074            30,062
West Virginia.......................            74,220            61,850
Wisconsin...........................            40,759            33,966
------------------------------------------------------------------------


[70 FR 25339, May 12, 2005, as amended at 71 FR 25302, Apr. 28, 2006]



Sec. 96.141  Timing requirements for CAIR NOX allowance allocations.

    (a) By October 31, 2006, the permitting authority will submit to the 
Administrator the CAIR NOX allowance allocations, in a format 
prescribed by the Administrator and in accordance with Sec. 96.142(a) 
and (b), for the control periods in 2009, 2010, 2011, 2012, 2013, and 
2014.
    (b) By October 31, 2009 and October 31 of each year thereafter, the 
permitting authority will submit to the Administrator the CAIR 
NOX allowance allocations, in a format prescribed by the 
Administrator and in accordance with Sec. 96.142(a) and (b), for the 
control period in the sixth year after the year of the applicable 
deadline for submission under this paragraph.
    (c) By October 31, 2009 and October 31 of each year thereafter, the 
permitting authority will submit to the Administrator the CAIR 
NOX allowance allocations, in a format prescribed by the 
Administrator and in accordance with Sec. 96.142(a), (c), and (d), for 
the control period in the year of the applicable deadline for submission 
under this paragraph.

[70 FR 25339, May 12, 2005, as amended at 71 FR 25383, Apr. 28, 2006]



Sec. 96.142  CAIR NOX allowance allocations.

    (a)(1) The baseline heat input (in mmBtu) used with respect to CAIR 
NOX allowance allocations under paragraph (b) of this section 
for each CAIR NOX unit will be:
    (i) For units commencing operation before January 1, 2001 the 
average of the 3 highest amounts of the unit's adjusted control period 
heat input for 2000 through 2004, with the adjusted control period heat 
input for each year calculated as follows:
    (A) If the unit is coal-fired during the year, the unit's control 
period heat input for such year is multiplied by 100 percent;
    (B) If the unit is oil-fired during the year, the unit's control 
period heat input for such year is multiplied by 60 percent; and
    (C) If the unit is not subject to paragraph (a)(1)(i)(A) or (B) of 
this section, the unit's control period heat input for such year is 
multiplied by 40 percent.

[[Page 67]]

    (ii) For units commencing operation on or after January 1, 2001 and 
operating each calendar year during a period of 5 or more consecutive 
calendar years, the average of the 3 highest amounts of the unit's total 
converted control period heat input over the first such 5 years.
    (2)(i) A unit's control period heat input, and a unit's status as 
coal-fired or oil-fired, for a calendar year under paragraph (a)(1)(i) 
of this section, and a unit's total tons of NOX emissions 
during a calendar year under paragraph (c)(3) of this section, will be 
determined in accordance with part 75 of this chapter, to the extent the 
unit was otherwise subject to the requirements of part 75 of this 
chapter for the year, or will be based on the best available data 
reported to the permitting authority for the unit, to the extent the 
unit was not otherwise subject to the requirements of part 75 of this 
chapter for the year.
    (ii) A unit's converted control period heat input for a calendar 
year specified under paragraph (a)(1)(ii) of this section equals:
    (A) Except as provided in paragraph (a)(2)(ii)(B) or (C) of this 
section, the control period gross electrical output of the generator or 
generators served by the unit multiplied by 7,900 Btu/kWh, if the unit 
is coal-fired for the year, or 6,675 Btu/kWh, if the unit is not coal-
fired for the year, and divided by 1,000,000 Btu/mmBtu, provided that if 
a generator is served by 2 or more units, then the gross electrical 
output of the generator will be attributed to each unit in proportion to 
the unit's share of the total control period heat input of such units 
for the year;
    (B) For a unit that is a boiler and has equipment used to produce 
electricity and useful thermal energy for industrial, commercial, 
heating, or cooling purposes through the sequential use of energy, the 
total heat energy (in Btu) of the steam produced by the boiler during 
the control period, divided by 0.8 and by 1,000,000 Btu/mmBtu; or
    (C) For a unit that is a combustion turbine and has equipment used 
to produce electricity and useful thermal energy for industrial, 
commercial, heating, or cooling purposes through the sequential use of 
energy, the control period gross electrical output of the enclosed 
device comprising the compressor, combustor, and turbine multiplied by 
3,413 Btu/kWh, plus the total heat energy (in Btu) of the steam produced 
by any associated heat recovery steam generator during the control 
period divided by 0.8, and with the sum divided by 1,000,000 Btu/mmBtu.
    (b)(1) For each control period in 2009 and thereafter, the 
permitting authority will allocate to all CAIR NOX units in 
the State that have a baseline heat input (as determined under paragraph 
(a) of this section) a total amount of CAIR NOX allowances 
equal to 95 percent for a control period during 2009 through 2014, and 
97 percent for a control period during 2015 and thereafter, of the tons 
of NOX emissions in the State trading budget under Sec. 
96.140 (except as provided in paragraph (d) of this section).
    (2) The permitting authority will allocate CAIR NOX 
allowances to each CAIR NOX unit under paragraph (b)(1) of 
this section in an amount determined by multiplying the total amount of 
CAIR NOX allowances allocated under paragraph (b)(1) of this 
section by the ratio of the baseline heat input of such CAIR 
NOX unit to the total amount of baseline heat input of all 
such CAIR NOX units in the State and rounding to the nearest 
whole allowance as appropriate.
    (c) For each control period in 2009 and thereafter, the permitting 
authority will allocate CAIR NOX allowances to CAIR 
NOX units in a State that are not allocated CAIR 
NOX allowances under paragraph (b) of this section because 
the units do not yet have a baseline heat input under paragraph (a) of 
this section or because the units have a baseline heat input but all 
CAIR NOX allowances available under paragraph (b) of this 
section for the control period are already allocated, in accordance with 
the following procedures:
    (1) The permitting authority will establish a separate new unit set-
aside for each control period. Each new unit set-aside will be allocated 
CAIR NOX allowances equal to 5 percent for a control period 
in 2009 through 2014, and 3 percent for a control period in 2015and 
thereafter, of the amount of tons of

[[Page 68]]

NOX emissions in the State trading budget under Sec. 96.140.
    (2) The CAIR designated representative of such a CAIR NOX 
unit may submit to the permitting authority a request, in a format 
specified by the permitting authority, to be allocated CAIR 
NOX allowances, starting with the later of the control period 
in 2009 or the first control period after the control period in which 
the CAIR NOX unit commences commercial operation and until 
the first control period for which the unit is allocated CAIR 
NOX allowances under paragraph (b) of this section. A 
separate CAIR NOX allowance allocation request for each 
control period for which CAIR NOX allowances are sought must 
be submitted on or before May 1 of such control period and after the 
date on which the CAIR NOX unit commences commercial 
operation.
    (3) In a CAIR NOX allowance allocation request under 
paragraph (c)(2) of this section, the CAIR designated representative may 
request for a control period CAIR NOX allowances in an amount 
not exceeding the CAIR NOX unit's total tons of 
NOX emissions during the calendar year immediately before 
such control period.
    (4) The permitting authority will review each CAIR NOX 
allowance allocation request under paragraph (c)(2) of this section and 
will allocate CAIR NOX allowances for each control period 
pursuant to such request as follows:
    (i) The permitting authority will accept an allowance allocation 
request only if the request meets, or is adjusted by the permitting 
authority as necessary to meet, the requirements of paragraphs (c)(2) 
and (3) of this section.
    (ii) On or after May 1 of the control period, the permitting 
authority will determine the sum of the CAIR NOX allowances 
requested (as adjusted under paragraph (c)(4)(i) of this section) in all 
allowance allocation requests accepted under paragraph (c)(4)(i) of this 
section for the control period.
    (iii) If the amount of CAIR NOX allowances in the new 
unit set-aside for the control period is greater than or equal to the 
sum under paragraph (c)(4)(ii) of this section, then the permitting 
authority will allocate the amount of CAIR NOX allowances 
requested (as adjusted under paragraph (c)(4)(i) of this section) to 
each CAIR NOX unit covered by an allowance allocation request 
accepted under paragraph (c)(4)(i) of this section.
    (iv) If the amount of CAIR NOX allowances in the new unit 
set-aside for the control period is less than the sum under paragraph 
(c)(4)(ii) of this section, then the permitting authority will allocate 
to each CAIR NOX unit covered by an allowance allocation 
request accepted under paragraph (c)(4)(i) of this section the amount of 
the CAIR NOX allowances requested (as adjusted under 
paragraph (c)(4)(i) of this section), multiplied by the amount of CAIR 
NOX allowances in the new unit set-aside for the control 
period, divided by the sum determined under paragraph (c)(4)(ii) of this 
section, and rounded to the nearest whole allowance as appropriate.
    (v) The permitting authority will notify each CAIR designated 
representative that submitted an allowance allocation request of the 
amount of CAIR NOX allowances (if any) allocated for the 
control period to the CAIR NOX unit covered by the request.
    (d) If, after completion of the procedures under paragraph (c)(4) of 
this section for a control period, any unallocated CAIR NOX 
allowances remain in the new unit set-aside for the control period, the 
permitting authority will allocate to each CAIR NOX unit that 
was allocated CAIR NOX allowances under paragraph (b) of this 
section an amount of CAIR NOX allowances equal to the total 
amount of such remaining unallocated CAIR NOX allowances, 
multiplied by the unit's allocation under paragraph (b) of this section, 
divided by 95 percent for a control period during 2009 through 2014, and 
97 percent for a control period during 2015 and thereafter, of the 
amount of tons of NOX emissions in the State trading budget 
under Sec. 96.140, and rounded to the nearest whole allowance as 
appropriate.

[70 FR 25339, May 12, 2005, as amended at 71 FR 25383, Apr. 28, 2006]



Sec. 96.143  Compliance supplement pool.

    (a) In addition to the CAIR NOX allowances allocated 
under Sec. 96.142, the permitting authority may allocate for

[[Page 69]]

the control period in 2009 up to the following amount of CAIR 
NOX allowances to CAIR NOX units in the respective 
State:

------------------------------------------------------------------------
                                                              Compliance
                           State                              supplement
                                                                 pool
------------------------------------------------------------------------
Alabama....................................................       10,166
Delaware...................................................          843
District Of Columbia.......................................            0
Florida....................................................        8,335
Georgia....................................................       12,397
Illinois...................................................       11,299
Indiana....................................................       20,155
Iowa.......................................................        6,978
Kentucky...................................................       14,935
Louisiana..................................................        2,251
Maryland...................................................        4,670
Michigan...................................................        8,347
Minnesota..................................................        6,528
Mississippi................................................        3,066
Missouri...................................................        9,044
New Jersey.................................................          660
New York...................................................            0
North Carolina.............................................            0
Ohio.......................................................       25,037
Pennsylvania...............................................       16,009
South Carolina.............................................        2,600
Tennessee..................................................        8,944
Texas......................................................          772
Virginia...................................................        5,134
West Virginia..............................................       16,929
Wisconsin..................................................        4,898
------------------------------------------------------------------------

    (b) For any CAIR NOX unit in the State that achieves 
NOX emission reductions in 2007 and 2008 that are not 
necessary to comply with any State or federal emissions limitation 
applicable during such years, the CAIR designated representative of the 
unit may request early reduction credits, and allocation of CAIR 
NOX allowances from the compliance supplement pool under 
paragraph (a) of this section for such early reduction credits, in 
accordance with the following:
    (1) The owners and operators of such CAIR NOX unit shall 
monitor and report the NOX emissions rate and the heat input 
of the unit in accordance with subpart HH of this part in each control 
period for which early reduction credit is requested.
    (2) The CAIR designated representative of such CAIR NOX 
unit shall submit to the permitting authority by May 1, 2009 a request, 
in a format specified by the permitting authority, for allocation of an 
amount of CAIR NOX allowances from the compliance supplement 
pool not exceeding the sum of the amounts (in tons) of the unit's 
NOX emission reductions in 2007 and 2008 that are not 
necessary to comply with any State or federal emissions limitation 
applicable during such years, determined in accordance with subpart HH 
of this part.
    (c) For any CAIR NOX unit in the State whose compliance 
with the CAIR NOX emissions limitation for the control period 
in 2009 would create an undue risk to the reliability of electricity 
supply during such control period, the CAIR designated representative of 
the unit may request the allocation of CAIR NOX allowances 
from the compliance supplement pool under paragraph (a) of this section, 
in accordance with the following:
    (1) The CAIR designated representative of such CAIR NOX 
unit shall submit to the permitting authority by May 1, 2009 a request, 
in a format specified by the permitting authority, for allocation of an 
amount of CAIR NOX allowances from the compliance supplement 
pool not exceeding the minimum amount of CAIR NOX allowances 
necessary to remove such undue risk to the reliability of electricity 
supply.
    (2) In the request under paragraph (c)(1) of this section, the CAIR 
designated representative of such CAIR NOX unit shall 
demonstrate that, in the absence of allocation to the unit of the amount 
of CAIR NOX allowances requested, the unit's compliance with 
the CAIR NOX emissions limitation for the control period in 
2009 would create an undue risk to the reliability of electricity supply 
during such control period. This demonstration must include a showing 
that it would not be feasible for the owners and operators of the unit 
to:
    (i) Obtain a sufficient amount of electricity from other electricity 
generation facilities, during the installation of control technology at 
the unit for compliance with the CAIR NOX emissions 
limitation, to prevent such undue risk; or
    (ii) Obtain under paragraphs (b) and (d) of this section, or 
otherwise obtain, a sufficient amount of CAIR NOX allowances 
to prevent such undue risk.
    (d) The permitting authority will review each request under 
paragraph (b) or (c) of this section submitted by May 1, 2009 and will 
allocate CAIR NOX allowances for the control period in 2009

[[Page 70]]

to CAIR NOX units in the State and covered by such request as 
follows:
    (1) Upon receipt of each such request, the permitting authority will 
make any necessary adjustments to the request to ensure that the amount 
of the CAIR NOX allowances requested meets the requirements 
of paragraph (b) or (c) of this section.
    (2) If the State's compliance supplement pool under paragraph (a) of 
this section has an amount of CAIR NOX allowances not less 
than the total amount of CAIR NOX allowances in all such 
requests (as adjusted under paragraph (d)(1) of this section), the 
permitting authority will allocate to each CAIR NOX unit 
covered by such requests the amount of CAIR NOX allowances 
requested (as adjusted under paragraph (d)(1) of this section).
    (3) If the State's compliance supplement pool under paragraph (a) of 
this section has a smaller amount of CAIR NOX allowances than 
the total amount of CAIR NOX allowances in all such requests 
(as adjusted under paragraph (d)(1) of this section), the permitting 
authority will allocate CAIR NOX allowances to each CAIR 
NOX unit covered by such requests according to the following 
formula and rounding to the nearest whole allowance as appropriate:

Unit's allocation = Unit's adjusted allocation x (State's compliance 
supplement pool / Total adjusted allocations for all units)

Where:

`Unit's allocation' is the amount of CAIR NOX allowances 
          allocated to the unit from the State's compliance supplement 
          pool. Unit's adjusted allocation'' is the amount of CAIR 
          NOX allowances requested for the unit under 
          paragraph (b) or (c) of this section, as adjusted under 
          paragraph (d)(1) of this section. ``State's compliance 
          supplement pool'' is the amount of CAIR NOX 
          allowances in the State's compliance supplement pool. ``Total 
          adjusted allocations for all units'' is the sum of the amounts 
          of allocations requested for all units under paragraph (b) or 
          (c) of this section, as adjusted under paragraph (d)(1) of 
          this section.

    (4) By November 30, 2009, the permitting authority will determine, 
and submit to the Administrator, the allocations under paragraph (d)(2) 
or (3)of this section.
    (5) By January 1, 2010, the Administrator will record the 
allocations under paragraph (d)(4) of this section.

[70 FR 25339, May 12, 2005, as amended at 71 FR 25302, 25383, Apr. 28, 
2006; 71 FR 74794, Dec. 13, 2006]



              Subpart FF_CAIR NOX Allowance Tracking System

    Source: 70 FR 25339, May 12, 2005, unless otherwise noted.



Sec. 96.150  [Reserved]



Sec. 96.151  Establishment of accounts.

    (a) Compliance accounts. Except as provided in Sec. 96.184(e), upon 
receipt of a complete certificate of representation under Sec. 96.113, 
the Administrator will establish a compliance account for the CAIR 
NOX source for which the certificate of representation was 
submitted unless the source already has a compliance account.
    (b) General accounts--(1) Application for general account. (i) Any 
person may apply to open a general account for the purpose of holding 
and transferring CAIR NOX allowances. An application for a 
general account may designate one and only one CAIR authorized account 
representative and one and only one alternate CAIR authorized account 
representative who may act on behalf of the CAIR authorized account 
representative. The agreement by which the alternate CAIR authorized 
account representative is selected shall include a procedure for 
authorizing the alternate CAIR authorized account representative to act 
in lieu of the CAIR authorized account representative.
    (ii) A complete application for a general account shall be submitted 
to the Administrator and shall include the following elements in a 
format prescribed by the Administrator:
    (A) Name, mailing address, e-mail address (if any), telephone 
number, and facsimile transmission number (if any) of the CAIR 
authorized account representative and any alternate CAIR authorized 
account representative;
    (B) Organization name and type of organization, if applicable;

[[Page 71]]

    (C) A list of all persons subject to a binding agreement for the 
CAIR authorized account representative and any alternate CAIR authorized 
account representative to represent their ownership interest with 
respect to the CAIR NOX allowances held in the general 
account;
    (D) The following certification statement by the CAIR authorized 
account representative and any alternate CAIR authorized account 
representative: ``I certify that I was selected as the CAIR authorized 
account representative or the alternate CAIR authorized account 
representative, as applicable, by an agreement that is binding on all 
persons who have an ownership interest with respect to CAIR 
NOX allowances held in the general account. I certify that I 
have all the necessary authority to carry out my duties and 
responsibilities under the CAIR NOX Annual Trading Program on 
behalf of such persons and that each such person shall be fully bound by 
my representations, actions, inactions, or submissions and by any order 
or decision issued to me by the Administrator or a court regarding the 
general account.''
    (E) The signature of the CAIR authorized account representative and 
any alternate CAIR authorized account representative and the dates 
signed.
    (iii) Unless otherwise required by the permitting authority or the 
Administrator, documents of agreement referred to in the application for 
a general account shall not be submitted to the permitting authority or 
the Administrator. Neither the permitting authority nor the 
Administrator shall be under any obligation to review or evaluate the 
sufficiency of such documents, if submitted.
    (2) Authorization of CAIR authorized account representative and 
alternate CAIR authorized account representative. (i) Upon receipt by 
the Administrator of a complete application for a general account under 
paragraph (b)(1) of this section:
    (A) The Administrator will establish a general account for the 
person or persons for whom the application is submitted.
    (B) The CAIR authorized account representative and any alternate 
CAIR authorized account representative for the general account shall 
represent and, by his or her representations, actions, inactions, or 
submissions, legally bind each person who has an ownership interest with 
respect to CAIR NOX allowances held in the general account in 
all matters pertaining to the CAIR NOX Annual Trading 
Program, notwithstanding any agreement between the CAIR authorized 
account representative or any alternate CAIR authorized account 
representative and such person. Any such person shall be bound by any 
order or decision issued to the CAIR authorized account representative 
or any alternate CAIR authorized account representative by the 
Administrator or a court regarding the general account.
    (C) Any representation, action, inaction, or submission by any 
alternate CAIR authorized account representative shall be deemed to be a 
representation, action, inaction, or submission by the CAIR authorized 
account representative.
    (ii) Each submission concerning the general account shall be 
submitted, signed, and certified by the CAIR authorized account 
representative or any alternate CAIR authorized account representative 
for the persons having an ownership interest with respect to CAIR 
NOX allowances held in the general account. Each such 
submission shall include the following certification statement by the 
CAIR authorized account representative or any alternate CAIR authorized 
account representative: ``I am authorized to make this submission on 
behalf of the persons having an ownership interest with respect to the 
CAIR NOX allowances held in the general account. I certify 
under penalty of law that I have personally examined, and am familiar 
with, the statements and information submitted in this document and all 
its attachments. Based on my inquiry of those individuals with primary 
responsibility for obtaining the information, I certify that the 
statements and information are to the best of my knowledge and belief 
true, accurate, and complete. I am aware that there are significant 
penalties for submitting false statements and information or

[[Page 72]]

omitting required statements and information, including the possibility 
of fine or imprisonment.''
    (iii) The Administrator will accept or act on a submission 
concerning the general account only if the submission has been made, 
signed, and certified in accordance with paragraph (b)(2)(ii) of this 
section.
    (3) Changing CAIR authorized account representative and alternate 
CAIR authorized account representative; changes in persons with 
ownership interest. (i) The CAIR authorized account representative for a 
general account may be changed at any time upon receipt by the 
Administrator of a superseding complete application for a general 
account under paragraph (b)(1) of this section. Notwithstanding any such 
change, all representations, actions, inactions, and submissions by the 
previous CAIR authorized account representative before the time and date 
when the Administrator receives the superseding application for a 
general account shall be binding on the new CAIR authorized account 
representative and the persons with an ownership interest with respect 
to the CAIR NOX allowances in the general account.
    (ii) The alternate CAIR authorized account representative for a 
general account may be changed at any time upon receipt by the 
Administrator of a superseding complete application for a general 
account under paragraph (b)(1) of this section. Notwithstanding any such 
change, all representations, actions, inactions, and submissions by the 
previous alternate CAIR authorized account representative before the 
time and date when the Administrator receives the superseding 
application for a general account shall be binding on the new alternate 
CAIR authorized account representative and the persons with an ownership 
interest with respect to the CAIR NOX allowances in the 
general account.
    (iii)(A) In the event a person having an ownership interest with 
respect to CAIR NOX allowances in the general account is not 
included in the list of such persons in the application for a general 
account, such person shall be deemed to be subject to and bound by the 
application for a general account, the representation, actions, 
inactions, and submissions of the CAIR authorized account representative 
and any alternate CAIR authorized account representative of the account, 
and the decisions and orders of the Administrator or a court, as if the 
person were included in such list.
    (B) Within 30 days following any change in the persons having an 
ownership interest with respect to CAIR NOX allowances in the 
general account, including the addition of a new person, the CAIR 
authorized account representative or any alternate CAIR authorized 
account representative shall submit a revision to the application for a 
general account amending the list of persons having an ownership 
interest with respect to the CAIR NOX allowances in the 
general account to include the change.
    (4) Objections concerning CAIR authorized account representative and 
alternate CAIR authorized account representative. (i) Once a complete 
application for a general account under paragraph (b)(1) of this section 
has been submitted and received, the Administrator will rely on the 
application unless and until a superseding complete application for a 
general account under paragraph (b)(1) of this section is received by 
the Administrator.
    (ii) Except as provided in paragraph (b)(3)(i) or (ii) of this 
section, no objection or other communication submitted to the 
Administrator concerning the authorization, or any representation, 
action, inaction, or submission of the CAIR authorized account 
representative or any alternate CAIR authorized account representative 
for a general account shall affect any representation, action, inaction, 
or submission of the CAIR authorized account representative or any 
alternate CAIR authorized account representative or the finality of any 
decision or order by the Administrator under the CAIR NOX 
Annual Trading Program.
    (iii) The Administrator will not adjudicate any private legal 
dispute concerning the authorization or any representation, action, 
inaction, or submission of the CAIR authorized account representative or 
any alternate CAIR authorized account representative for a general 
account, including private legal disputes concerning the

[[Page 73]]

proceeds of CAIR NOX allowance transfers.
    (5) Delegation by CAIR authorized account representative and 
alternate CAIR authorized account representative. (i) A CAIR authorized 
account representative may delegate, to one or more natural persons, his 
or her authority to make an electronic submission to the Administrator 
provided for or required under subparts FF and GG of this part.
    (ii) An alternate CAIR authorized account representative may 
delegate, to one or more natural persons, his or her authority to make 
an electronic submission to the Administrator provided for or required 
under subparts FF and GG of this part.
    (iii) In order to delegate authority to make an electronic 
submission to the Administrator in accordance with paragraph (b)(5)(i) 
or (ii) of this section, the CAIR authorized account representative or 
alternate CAIR authorized account representative, as appropriate, must 
submit to the Administrator a notice of delegation, in a format 
prescribed by the Administrator, that includes the following elements:
    (A) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of such CAIR authorized account 
representative or alternate CAIR authorized account representative;
    (B) The name, address, e-mail address, telephone number, and, 
facsimile transmission number (if any) of each such natural person 
(referred to as an ``agent'');
    (C) For each such natural person, a list of the type or types of 
electronic submissions under paragraph (b)(5)(i) or (ii) of this section 
for which authority is delegated to him or her;
    (D) The following certification statement by such CAIR authorized 
account representative or alternate CAIR authorized account 
representative: ``I agree that any electronic submission to the 
Administrator that is by an agent identified in this notice of 
delegation and of a type listed for such agent in this notice of 
delegation and that is made when I am a CAIR authorized account 
representative or alternate CAIR authorized representative, as 
appropriate, and before this notice of delegation is superseded by 
another notice of delegation under 40 CFR 96.151(b)(5)(iv) shall be 
deemed to be an electronic submission by me.''; and
    (E) The following certification statement by such CAIR authorized 
account representative or alternate CAIR authorized account 
representative: ``Until this notice of delegation is superseded by 
another notice of delegation under 40 CFR 96.151 (b)(5)(iv), I agree to 
maintain an e-mail account and to notify the Administrator immediately 
of any change in my e-mail address unless all delegation of authority by 
me under 40 CFR 96.151 (b)(5) is terminated.''
    (iv) A notice of delegation submitted under paragraph (b)(5)(iii) of 
this section shall be effective, with regard to the CAIR authorized 
account representative or alternate CAIR authorized account 
representative identified in such notice, upon receipt of such notice by 
the Administrator and until receipt by the Administrator of a 
superseding notice of delegation submitted by such CAIR authorized 
account representative or alternate CAIR authorized account 
representative, as appropriate. The superseding notice of delegation may 
replace any previously identified agent, add a new agent, or eliminate 
entirely any delegation of authority.
    (v) Any electronic submission covered by the certification in 
paragraph (b)(5)(iii)(D) of this section and made in accordance with a 
notice of delegation effective under paragraph (b)(5)(iv) of this 
section shall be deemed to be an electronic submission by the CAIR 
designated representative or alternate CAIR designated representative 
submitting such notice of delegation.
    (c) Account identification. The Administrator will assign a unique 
identifying number to each account established under paragraph (a) or 
(b) of this section.

[70 FR 25339, May 12, 2005, as amended at 71 FR 25383, Apr. 28, 2006; 71 
FR 74794, Dec. 13, 2006]



Sec. 96.152  Responsibilities of CAIR authorized account 
representative.

    Following the establishment of a CAIR NOX Allowance 
Tracking System

[[Page 74]]

account, all submissions to the Administrator pertaining to the account, 
including, but not limited to, submissions concerning the deduction or 
transfer of CAIR NOX allowances in the account, shall be made 
only by the CAIR authorized account representative for the account.



Sec. 96.153  Recordation of CAIR NOX allowance allocations.

    (a) By September 30, 2007, the Administrator will record in the CAIR 
NOX source's compliance account the CAIR NOX 
allowances allocated for the CAIR NOX units at the source, as 
submitted by the permitting authority in accordance with Sec. 
96.141(a), for the control periods in 2009, 2010, 2011, 2012, 2013, and 
2014.
    (b) By December 1, 2009, the Administrator will record in the CAIR 
NOX source's compliance account the CAIR NOX 
allowances allocated for the CAIR NOX units at the source, as 
submitted by the permitting authority in accordance with Sec. 
96.141(b), for the control period in 2015.
    (c) By December 1, 2009 and December 1 of each year thereafter, the 
Administrator will record in the CAIR NOX source's compliance 
account the CAIR NOX allowances allocated for the CAIR 
NOX units at the source, as submitted by the permitting 
authority in accordance with Sec. 96.141(b), for the control period in 
the sixth year after the year of the applicable deadline for recordation 
under this paragraph.
    (d) By December 1, 2009 and December 1 of each year thereafter, the 
Administrator will record in the CAIR NOX source's compliance 
account the CAIR NOX allowances allocated for the CAIR 
NOX units at the source, as submitted by the permitting 
authority or determined by the Administrator in accordance with Sec. 
96.141(c), for the control period in the year of the applicable deadline 
for recordation under this paragraph.
    (e) Serial numbers for allocated CAIR NOX allowances. When recording 
the allocation of CAIR NOX allowances for a CAIR 
NOX unit in a compliance account, the Administrator will 
assign each CAIR NOX allowance a unique identification number 
that will include digits identifying the year of the control period for 
which the CAIR NOX allowance is allocated.

[70 FR 25339, May 12, 2005, as amended at 71 FR 25384, Apr. 28, 2006]

    Editorial Note: At 71 FR 25384, Apr. 28, 2006, Sec. 196.153 was 
amended; however, the amendment could not be incorporated due to 
inaccurate amendatory instruction.



Sec. 96.154  Compliance with CAIR NOX emissions limitation.

    (a) Allowance transfer deadline. The CAIR NOX allowances 
are available to be deducted for compliance with a source's CAIR 
NOX emissions limitation for a control period in a given 
calendar year only if the CAIR NOX allowances:
    (1) Were allocated for the control period in the year or a prior 
year; and
    (2) Are held in the compliance account as of the allowance transfer 
deadline for the control period or are transferred into the compliance 
account by a CAIR NOX allowance transfer correctly submitted 
for recordation under Sec. Sec. 96.160 and 96.161 by the allowance 
transfer deadline for the control period.
    (b) Deductions for compliance. Following the recordation, in 
accordance with Sec. 96.161, of CAIR NOX allowance transfers 
submitted for recordation in a source's compliance account by the 
allowance transfer deadline for a control period, the Administrator will 
deduct from the compliance account CAIR NOX allowances 
available under paragraph (a) of this section in order to determine 
whether the source meets the CAIR NOX emissions limitation 
for the control period, as follows:
    (1) Until the amount of CAIR NOX allowances deducted 
equals the number of tons of total nitrogen oxides emissions, determined 
in accordance with subpart HH of this part, from all CAIR NOX 
units at the source for the control period; or
    (2) If there are insufficient CAIR NOX allowances to 
complete the deductions in paragraph (b)(1) of this section, until no 
more CAIR NOX allowances available under paragraph (a) of 
this section remain in the compliance account.
    (c)(1) Identification of CAIR NOX allowances by serial number. The 
CAIR authorized account representative for a source's

[[Page 75]]

compliance account may request that specific CAIR NOX 
allowances, identified by serial number, in the compliance account be 
deducted for emissions or excess emissions for a control period in 
accordance with paragraph (b) or (d) of this section. Such request shall 
be submitted to the Administrator by the allowance transfer deadline for 
the control period and include, in a format prescribed by the 
Administrator, the identification of the CAIR NOX source and 
the appropriate serial numbers.
    (2) First-in, first-out. The Administrator will deduct CAIR 
NOX allowances under paragraph (b) or (d) of this section 
from the source's compliance account, in the absence of an 
identification or in the case of a partial identification of CAIR 
NOX allowances by serial number under paragraph (c)(1) of 
this section, on a first-in, first-out (FIFO) accounting basis in the 
following order:
    (i) Any CAIR NOX allowances that were allocated to the 
units at the source, in the order of recordation; and then
    (ii) Any CAIR NOX allowances that were allocated to any 
entity and transferred and recorded in the compliance account pursuant 
to subpart GG of this part, in the order of recordation.
    (d) Deductions for excess emissions. (1) After making the deductions 
for compliance under paragraph (b) of this section for a control period 
in a calendar year in which the CAIR NOX source has excess 
emissions, the Administrator will deduct from the source's compliance 
account an amount of CAIR NOX allowances, allocated for the 
control period in the immediately following calendar year, equal to 3 
times the number of tons of the source's excess emissions.
    (2) Any allowance deduction required under paragraph (d)(1) of this 
section shall not affect the liability of the owners and operators of 
the CAIR NOX source or the CAIR NOX units at the 
source for any fine, penalty, or assessment, or their obligation to 
comply with any other remedy, for the same violations, as ordered under 
the Clean Air Act or applicable State law.
    (e) Recordation of deductions. The Administrator will record in the 
appropriate compliance account all deductions from such an account under 
paragraphs (b) and (d) of this section and subpart II.
    (f) Administrator's action on submissions. (1) The Administrator may 
review and conduct independent audits concerning any submission under 
the CAIR NOX Annual Trading Program and make appropriate 
adjustments of the information in the submissions.
    (2) The Administrator may deduct CAIR NOX allowances from 
or transfer CAIR NOX allowances to a source's compliance 
account based on the information in the submissions, as adjusted under 
paragraph (f)(1) of this section, and record such deductions and 
transfers.

[70 FR 25339, May 12, 2005, as amended at 71 FR 25384, Apr. 28, 2006]



Sec. 96.155  Banking.

    (a) CAIR NOX allowances may be banked for future use or 
transfer in a compliance account or a general account in accordance with 
paragraph (b) of this section.
    (b) Any CAIR NOX allowance that is held in a compliance 
account or a general account will remain in such account unless and 
until the CAIR NOX allowance is deducted or transferred under 
Sec. 96.154, Sec. 96.156, or subpart GG or II of this part.

[70 FR 25339, May 12, 2005, as amended at 71 FR 25384, Apr. 28, 2006]



Sec. 96.156  Account error.

    The Administrator may, at his or her sole discretion and on his or 
her own motion, correct any error in any CAIR NOX Allowance 
Tracking System account. Within 10 business days of making such 
correction, the Administrator will notify the CAIR authorized account 
representative for the account.



Sec. 96.157  Closing of general accounts.

    (a) The CAIR authorized account representative of a general account 
may submit to the Administrator a request to close the account, which 
shall include a correctly submitted allowance transfer under Sec. Sec. 
96.160 and 96.161 for any CAIR NOX allowances in the account 
to one or more other CAIR NOX Allowance Tracking System 
accounts.

[[Page 76]]

    (b) If a general account has no allowance transfers in or out of the 
account for a 12-month period or longer and does not contain any CAIR 
NOX allowances, the Administrator may notify the CAIR 
authorized account representative for the account that the account will 
be closed following 20 business days after the notice is sent. The 
account will be closed after the 20-day period unless, before the end of 
the 20-day period, the Administrator receives a correctly submitted 
transfer of CAIR NOX allowances into the account under 
Sec. Sec. 96.160 and 96.161 or a statement submitted by the CAIR 
authorized account representative demonstrating to the satisfaction of 
the Administrator good cause as to why the account should not be closed.

[70 FR 25339, May 12, 2005, as amended at 71 FR 25384, Apr. 28, 2006]



                 Subpart GG_CAIR NOX Allowance Transfers

    Source: 70 FR 25339, May 12, 2005, unless otherwise noted.



Sec. 96.160  Submission of CAIR NOX allowance transfers.

    A CAIR authorized account representative seeking recordation of a 
CAIR NOX allowance transfer shall submit the transfer to the 
Administrator. To be considered correctly submitted, the CAIR 
NOX allowance transfer shall include the following elements, 
in a format specified by the Administrator:
    (a) The account numbers for both the transferor and transferee 
accounts;
    (b) The serial number of each CAIR NOX allowance that is 
in the transferor account and is to be transferred; and
    (c) The name and signature of the CAIR authorized account 
representative of the transferor account and the date signed.



Sec. 96.161  EPA recordation.

    (a) Within 5 business days (except as provided in paragraph (b) of 
this section) of receiving a CAIR NOX allowance transfer, the 
Administrator will record a CAIR NOX allowance transfer by 
moving each CAIR NOX allowance from the transferor account to 
the transferee account as specified by the request, provided that:
    (1) The transfer is correctly submitted under Sec. 96.160; and
    (2) The transferor account includes each CAIR NOX 
allowance identified by serial number in the transfer.
    (b) A CAIR NOX allowance transfer that is submitted for 
recordation after the allowance transfer deadline for a control period 
and that includes any CAIR NOX allowances allocated for any 
control period before such allowance transfer deadline will not be 
recorded until after the Administrator completes the deductions under 
Sec. 96.154 for the control period immediately before such allowance 
transfer deadline.
    (c) Where a CAIR NOX allowance transfer submitted for 
recordation fails to meet the requirements of paragraph (a) of this 
section, the Administrator will not record such transfer.



Sec. 96.162  Notification.

    (a) Notification of recordation. Within 5 business days of 
recordation of a CAIR NOX allowance transfer under Sec. 
96.161, the Administrator will notify the CAIR authorized account 
representatives of both the transferor and transferee accounts.
    (b) Notification of non-recordation. Within 10 business days of 
receipt of a CAIR NOX allowance transfer that fails to meet 
the requirements of Sec. 96.161(a), the Administrator will notify the 
CAIR authorized account representatives of both accounts subject to the 
transfer of:
    (1) A decision not to record the transfer, and
    (2) The reasons for such non-recordation.
    (c) Nothing in this section shall preclude the submission of a CAIR 
NOX allowance transfer for recordation following notification 
of non-recordation.



                   Subpart HH_Monitoring and Reporting

    Source: 70 FR 25339, May 12, 2005, unless otherwise noted.



Sec. 96.170  General requirements.

    The owners and operators, and to the extent applicable, the CAIR 
designated representative, of a CAIR NOX unit,

[[Page 77]]

shall comply with the monitoring, recordkeeping, and reporting 
requirements as provided in this subpart and in subpart H of part 75 of 
this chapter. For purposes of complying with such requirements, the 
definitions in Sec. 96.102 and in Sec. 72.2 of this chapter shall 
apply, and the terms ``affected unit,'' ``designated representative,'' 
and ``continuous emission monitoring system'' (or ``CEMS'') in part 75 
of this chapter shall be deemed to refer to the terms ``CAIR 
NOX unit,'' ``CAIR designated representative,'' and 
``continuous emission monitoring system'' (or ``CEMS'') respectively, as 
defined in Sec. 96.102. The owner or operator of a unit that is not a 
CAIR NOX unit but that is monitored under Sec. 
75.72(b)(2)(ii) of this chapter shall comply with the same monitoring, 
recordkeeping, and reporting requirements as a CAIR NOX unit.
    (a) Requirements for installation, certification, and data 
accounting. The owner or operator of each CAIR NOX unit 
shall:
    (1) Install all monitoring systems required under this subpart for 
monitoring NOX mass emissions and individual unit heat input 
(including all systems required to monitor NOX emission rate, 
NOX concentration, stack gas moisture content, stack gas flow 
rate, CO2 or O2 concentration, and fuel flow rate, 
as applicable, in accordance with Sec. Sec. 75.71 and 75.72 of this 
chapter);
    (2) Successfully complete all certification tests required under 
Sec. 96.171 and meet all other requirements of this subpart and part 75 
of this chapter applicable to the monitoring systems under paragraph 
(a)(1) of this section; and
    (3) Record, report, and quality-assure the data from the monitoring 
systems under paragraph (a)(1) of this section.
    (b) Compliance deadlines. Except as provided in paragraph (e) of 
this section, the owner or operator shall meet the monitoring system 
certification and other requirements of paragraphs (a)(1) and (2) of 
this section on or before the following dates. The owner or operator 
shall record, report, and quality-assure the data from the monitoring 
systems under paragraph (a)(1) of this section on and after the 
following dates.
    (1) For the owner or operator of a CAIR NOX unit that 
commences commercial operation before July 1, 2007, by January 1, 2008.
    (2) For the owner or operator of a CAIR NOX unit that 
commences commercial operation on or after July 1, 2007, by the later of 
the following dates:
    (i) January 1, 2008; or
    (ii) 90 unit operating days or 180 calendar days, whichever occurs 
first, after the date on which the unit commences commercial operation.
    (3) For the owner or operator of a CAIR NOX unit for 
which construction of a new stack or flue or installation of add-on 
NOX emission controls is completed after the applicable 
deadline under paragraph (b)(1), (2), (4), or (5) of this section, by 90 
unit operating days or 180 calendar days, whichever occurs first, after 
the date on which emissions first exit to the atmosphere through the new 
stack or flue or add-on NOX emissions controls.
    (4) Notwithstanding the dates in paragraphs (b)(1) and (2) of this 
section, for the owner or operator of a unit for which a CAIR opt-in 
permit application is submitted and not withdrawn and a CAIR opt-in 
permit is not yet issued or denied under subpart II of this part, by the 
date specified in Sec. 96.184(b).
    (5) Notwithstanding the dates in paragraphs (b)(1) and (2) of this 
section, for the owner or operator of a CAIR NOX opt-in unit 
under subpart II of this part, by the date on which the CAIR 
NOX opt-in unit enters the CAIR NOX Annual Trading 
Program as provided in Sec. 96.184(g).
    (c) Reporting data. The owner or operator of a CAIR NOX 
unit that does not meet the applicable compliance date set forth in 
paragraph (b) of this section for any monitoring system under paragraph 
(a)(1) of this section shall, for each such monitoring system, 
determine, record, and report maximum potential (or, as appropriate, 
minimum potential) values for NOX concentration, 
NOX emission rate, stack gas flow rate, stack gas moisture 
content, fuel flow rate, and any other parameters required to determine 
NOX mass emissions and heat input in accordance with Sec. 
75.31(b)(2) or (c)(3) of this chapter, section 2.4 of appendix D to part 
75

[[Page 78]]

of this chapter, or section 2.5 of appendix E to part 75 of this 
chapter, as applicable.
    (d) Prohibitions. (1) No owner or operator of a CAIR NOX 
unit shall use any alternative monitoring system, alternative reference 
method, or any other alternative to any requirement of this subpart 
without having obtained prior written approval in accordance with Sec. 
96.175.
    (2) No owner or operator of a CAIR NOX unit shall operate 
the unit so as to discharge, or allow to be discharged, NOX 
emissions to the atmosphere without accounting for all such emissions in 
accordance with the applicable provisions of this subpart and part 75 of 
this chapter.
    (3) No owner or operator of a CAIR NOX unit shall disrupt 
the continuous emission monitoring system, any portion thereof, or any 
other approved emission monitoring method, and thereby avoid monitoring 
and recording NOX mass emissions discharged into the 
atmosphere or heat input, except for periods of recertification or 
periods when calibration, quality assurance testing, or maintenance is 
performed in accordance with the applicable provisions of this subpart 
and part 75 of this chapter.
    (4) No owner or operator of a CAIR NOX unit shall retire 
or permanently discontinue use of the continuous emission monitoring 
system, any component thereof, or any other approved monitoring system 
under this subpart, except under any one of the following circumstances:
    (i) During the period that the unit is covered by an exemption under 
Sec. 96.105 that is in effect;
    (ii) The owner or operator is monitoring emissions from the unit 
with another certified monitoring system approved, in accordance with 
the applicable provisions of this subpart and part 75 of this chapter, 
by the permitting authority for use at that unit that provides emission 
data for the same pollutant or parameter as the retired or discontinued 
monitoring system; or
    (iii) The CAIR designated representative submits notification of the 
date of certification testing of a replacement monitoring system for the 
retired or discontinued monitoring system in accordance with Sec. 
96.171(d)(3)(i).
    (e) Long-term cold storage. The owner or operator of a CAIR 
NOX unit is subject to the applicable provisions of part 75 
of this chapter concerning units in long-term cold storage.

[70 FR 25339, May 12, 2005, as amended at 71 FR 25384, Apr. 28, 2006]



Sec. 96.171  Initial certification and recertification procedures.

    (a) The owner or operator of a CAIR NOX unit shall be 
exempt from the initial certification requirements of this section for a 
monitoring system under Sec. 96.170(a)(1) if the following conditions 
are met:
    (1) The monitoring system has been previously certified in 
accordance with part 75 of this chapter; and
    (2) The applicable quality-assurance and quality-control 
requirements of Sec. 75.21 of this chapter and appendix B, appendix D, 
and appendix E to part 75 of this chapter are fully met for the 
certified monitoring system described in paragraph (a)(1) of this 
section.
    (b) The recertification provisions of this section shall apply to a 
monitoring system under Sec. 96.170(a)(1) exempt from initial 
certification requirements under paragraph (a) of this section.
    (c) If the Administrator has previously approved a petition under 
Sec. 75.17(a) or (b) of this chapter for apportioning the 
NOX emission rate measured in a common stack or a petition 
under Sec. 75.66 of this chapter for an alternative to a requirement in 
Sec. 75.12 or Sec. 75.17 of this chapter, the CAIR designated 
representative shall resubmit the petition to the Administrator under 
Sec. 96.175(a) to determine whether the approval applies under the CAIR 
NOX Annual Trading Program.
    (d) Except as provided in paragraph (a) of this section, the owner 
or operator of a CAIR NOX unit shall comply with the 
following initial certification and recertification procedures for a 
continuous monitoring system (i.e., a continuous emission monitoring 
system and an excepted monitoring system under appendices D and E to 
part 75 of this chapter) under Sec. 96.170(a)(1). The owner or operator 
of a unit that qualifies to use the low mass emissions

[[Page 79]]

excepted monitoring methodology under Sec. 75.19 of this chapter or 
that qualifies to use an alternative monitoring system under subpart E 
of part 75 of this chapter shall comply with the procedures in paragraph 
(e) or (f) of this section respectively.
    (1) Requirements for initial certification. The owner or operator 
shall ensure that each continuous monitoring system under Sec. 
96.170(a)(1)(including the automated data acquisition and handling 
system) successfully completes all of the initial certification testing 
required under Sec. 75.20 of this chapter by the applicable deadline in 
Sec. 96.170(b). In addition, whenever the owner or operator installs a 
monitoring system to meet the requirements of this subpart in a location 
where no such monitoring system was previously installed, initial 
certification in accordance with Sec. 75.20 of this chapter is 
required.
    (2) Requirements for recertification. Whenever the owner or operator 
makes a replacement, modification, or change in any certified continuous 
emission monitoring system under Sec. 96.170(a)(1) that may 
significantly affect the ability of the system to accurately measure or 
record NOX mass emissions or heat input rate or to meet the 
quality-assurance and quality-control requirements of Sec. 75.21 of 
this chapter or appendix B to part 75 of this chapter, the owner or 
operator shall recertify the monitoring system in accordance with Sec. 
75.20(b) of this chapter. Furthermore, whenever the owner or operator 
makes a replacement, modification, or change to the flue gas handling 
system or the unit's operation that may significantly change the stack 
flow or concentration profile, the owner or operator shall recertify 
each continuous emission monitoring system whose accuracy is potentially 
affected by the change, in accordance with Sec. 75.20(b) of this 
chapter. Examples of changes to a continuous emission monitoring system 
that require recertification include replacement of the analyzer, 
complete replacement of an existing continuous emission monitoring 
system, or change in location or orientation of the sampling probe or 
site. Any fuel flowmeter system, and any excepted NOX 
monitoring system under appendix E to part 75 of this chapter, under 
Sec. 96.170(a)(1) are subject to the recertification requirements in 
Sec. 75.20(g)(6) of this chapter.
    (3) Approval process for initial certification and recertification. 
Paragraphs (d)(3)(i) through (iv) of this section apply to both initial 
certification and recertification of a continuous monitoring system 
under Sec. 96.170(a)(1). For recertifications, replace the words 
``certification'' and ``initial certification'' with the word 
``recertification'', replace the word ``certified'' with the word 
``recertified,'' and follow the procedures in Sec. Sec. 75.20(b)(5) and 
(g)(7) of this chapter in lieu of the procedures in paragraph (d)(3)(v) 
of this section.
    (i) Notification of certification. The CAIR designated 
representative shall submit to the permitting authority, the appropriate 
EPA Regional Office, and the Administrator written notice of the dates 
of certification testing, in accordance with Sec. 96.173.
    (ii) Certification application. The CAIR designated representative 
shall submit to the permitting authority a certification application for 
each monitoring system. A complete certification application shall 
include the information specified in Sec. 75.63 of this chapter.
    (iii) Provisional certification date. The provisional certification 
date for a monitoring system shall be determined in accordance with 
Sec. 75.20(a)(3) of this chapter. A provisionally certified monitoring 
system may be used under the CAIR NOX Annual Trading Program 
for a period not to exceed 120 days after receipt by the permitting 
authority of the complete certification application for the monitoring 
system under paragraph (d)(3)(ii) of this section. Data measured and 
recorded by the provisionally certified monitoring system, in accordance 
with the requirements of part 75 of this chapter, will be considered 
valid quality-assured data (retroactive to the date and time of 
provisional certification), provided that the permitting authority does 
not invalidate the provisional certification by issuing a notice of 
disapproval within 120 days of the date of receipt of the complete 
certification application by the permitting authority.
    (iv) Certification application approval process. The permitting 
authority will issue a written notice of approval or

[[Page 80]]

disapproval of the certification application to the owner or operator 
within 120 days of receipt of the complete certification application 
under paragraph (d)(3)(ii) of this section. In the event the permitting 
authority does not issue such a notice within such 120-day period, each 
monitoring system that meets the applicable performance requirements of 
part 75 of this chapter and is included in the certification application 
will be deemed certified for use under the CAIR NOX Annual 
Trading Program.
    (A) Approval notice. If the certification application is complete 
and shows that each monitoring system meets the applicable performance 
requirements of part 75 of this chapter, then the permitting authority 
will issue a written notice of approval of the certification application 
within 120 days of receipt.
    (B) Incomplete application notice. If the certification application 
is not complete, then the permitting authority will issue a written 
notice of incompleteness that sets a reasonable date by which the CAIR 
designated representative must submit the additional information 
required to complete the certification application. If the CAIR 
designated representative does not comply with the notice of 
incompleteness by the specified date, then the permitting authority may 
issue a notice of disapproval under paragraph (d)(3)(iv)(C) of this 
section. The 120-day review period shall not begin before receipt of a 
complete certification application.
    (C) Disapproval notice. If the certification application shows that 
any monitoring system does not meet the performance requirements of part 
75 of this chapter or if the certification application is incomplete and 
the requirement for disapproval under paragraph (d)(3)(iv)(B) of this 
section is met, then the permitting authority will issue a written 
notice of disapproval of the certification application. Upon issuance of 
such notice of disapproval, the provisional certification is invalidated 
by the permitting authority and the data measured and recorded by each 
uncertified monitoring system shall not be considered valid quality-
assured data beginning with the date and hour of provisional 
certification (as defined under Sec. 75.20(a)(3) of this chapter). The 
owner or operator shall follow the procedures for loss of certification 
in paragraph (d)(3)(v) of this section for each monitoring system that 
is disapproved for initial certification.
    (D) Audit decertification. The permitting authority or, for a CAIR 
NOX opt-in unit or a unit for which a CAIR opt-in permit 
application is submitted and not withdrawn and a CAIR opt-in permit is 
not yet issued or denied under subpart II of this part, the 
Administrator may issue a notice of disapproval of the certification 
status of a monitor in accordance with Sec. 96.172(b).
    (v) Procedures for loss of certification. If the permitting 
authority or the Administrator issues a notice of disapproval of a 
certification application under paragraph (d)(3)(iv)(C) of this section 
or a notice of disapproval of certification status under paragraph 
(d)(3)(iv)(D) of this section, then:
    (A) The owner or operator shall substitute the following values, for 
each disapproved monitoring system, for each hour of unit operation 
during the period of invalid data specified under Sec. 
75.20(a)(4)(iii), Sec. 75.20(g)(7), or Sec. 75.21(e) of this chapter 
and continuing until the applicable date and hour specified under Sec. 
75.20(a)(5)(i) or (g)(7) of this chapter:
    (1) For a disapproved NOX emission rate (i.e., 
NOX-diluent) system, the maximum potential NOX 
emission rate, as defined in Sec. 72.2 of this chapter.
    (2) For a disapproved NOX pollutant concentration monitor 
and disapproved flow monitor, respectively, the maximum potential 
concentration of NOX and the maximum potential flow rate, as 
defined in sections 2.1.2.1 and 2.1.4.1 of appendix A to part 75 of this 
chapter.
    (3) For a disapproved moisture monitoring system and disapproved 
diluent gas monitoring system, respectively, the minimum potential 
moisture percentage and either the maximum potential CO2 
concentration or the minimum potential O2 concentration (as 
applicable), as defined in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of 
appendix A to part 75 of this chapter.
    (4) For a disapproved fuel flowmeter system, the maximum potential 
fuel

[[Page 81]]

flow rate, as defined in section 2.4.2.1 of appendix D to part 75 of 
this chapter.
    (5) For a disapproved excepted NOX monitoring system 
under appendix E to part 75 of this chapter, the fuel-specific maximum 
potential NOX emission rate, as defined in Sec. 72.2 of this 
chapter.
    (B) The CAIR designated representative shall submit a notification 
of certification retest dates and a new certification application in 
accordance with paragraphs (d)(3)(i) and (ii) of this section.
    (C) The owner or operator shall repeat all certification tests or 
other requirements that were failed by the monitoring system, as 
indicated in the permitting authority's or the Administrator's notice of 
disapproval, no later than 30 unit operating days after the date of 
issuance of the notice of disapproval.
    (e) Initial certification and recertification procedures for units 
using the low mass emission excepted methodology under Sec. 75.19 of 
this chapter. The owner or operator of a unit qualified to use the low 
mass emissions (LME) excepted methodology under Sec. 75.19 of this 
chapter shall meet the applicable certification and recertification 
requirements in Sec. Sec. 75.19(a)(2) and 75.20(h) of this chapter. If 
the owner or operator of such a unit elects to certify a fuel flowmeter 
system for heat input determination, the owner or operator shall also 
meet the certification and recertification requirements in Sec. 
75.20(g) of this chapter.
    (f) Certification/recertification procedures for alternative 
monitoring systems. The CAIR designated representative of each unit for 
which the owner or operator intends to use an alternative monitoring 
system approved by the Administrator and, if applicable, the permitting 
authority under subpart E of part 75 of this chapter shall comply with 
the applicable notification and application procedures of Sec. 75.20(f) 
of this chapter.

[70 FR 25339, May 12, 2005, as amended at 71 FR 25385, Apr. 28, 2006]



Sec. 96.172  Out of control periods.

    (a) Whenever any monitoring system fails to meet the quality-
assurance and quality-control requirements or data validation 
requirements of part 75 of this chapter, data shall be substituted using 
the applicable missing data procedures in subpart D or subpart H of, or 
appendix D or appendix E to, part 75 of this chapter.
    (b) Audit decertification. Whenever both an audit of a monitoring 
system and a review of the initial certification or recertification 
application reveal that any monitoring system should not have been 
certified or recertified because it did not meet a particular 
performance specification or other requirement under Sec. 96.171 or the 
applicable provisions of part 75 of this chapter, both at the time of 
the initial certification or recertification application submission and 
at the time of the audit, the permitting authority or, for a CAIR 
NOX opt-in unit or a unit for which a CAIR opt-in permit 
application is submitted and not withdrawn and a CAIR opt-in permit is 
not yet issued or denied under subpart II of this part, the 
Administrator will issue a notice of disapproval of the certification 
status of such monitoring system. For the purposes of this paragraph, an 
audit shall be either a field audit or an audit of any information 
submitted to the permitting authority or the Administrator. By issuing 
the notice of disapproval, the permitting authority or the Administrator 
revokes prospectively the certification status of the monitoring system. 
The data measured and recorded by the monitoring system shall not be 
considered valid quality-assured data from the date of issuance of the 
notification of the revoked certification status until the date and time 
that the owner or operator completes subsequently approved initial 
certification or recertification tests for the monitoring system. The 
owner or operator shall follow the applicable initial certification or 
recertification procedures in Sec. 96.171 for each disapproved 
monitoring system.



Sec. 96.173  Notifications.

    The CAIR designated representative for a CAIR NOX unit 
shall submit written notice to the permitting authority and the 
Administrator in accordance with Sec. 75.61 of this chapter.

[70 FR 25339, May 12, 2005, as amended at 71 FR 25385, Apr. 28, 2006]

[[Page 82]]



Sec. 96.174  Recordkeeping and reporting.

    (a) General provisions. The CAIR designated representative shall 
comply with all recordkeeping and reporting requirements in this 
section, the applicable recordkeeping and reporting requirements under 
Sec. 75.73 of this chapter, and the requirements of Sec. 96.110(e)(1).
    (b) Monitoring Plans. The owner or operator of a CAIR NOX 
unit shall comply with requirements of Sec. 75.73(c) and (e) of this 
chapter and, for a unit for which a CAIR opt-in permit application is 
submitted and not withdrawn and a CAIR opt-in permit is not yet issued 
or denied under subpart II of this part, Sec. Sec. 96.183 and 
96.184(a).
    (c) Certification Applications. The CAIR designated representative 
shall submit an application to the permitting authority within 45 days 
after completing all initial certification or recertification tests 
required under Sec. 96.171, including the information required under 
Sec. 75.63 of this chapter.
    (d) Quarterly reports. The CAIR designated representative shall 
submit quarterly reports, as follows:
    (1) The CAIR designated representative shall report the 
NOX mass emissions data and heat input data for the CAIR 
NOX unit, in an electronic quarterly report in a format 
prescribed by the Administrator, for each calendar quarter beginning 
with:
    (i) For a unit that commences commercial operation before July 1, 
2007, the calendar quarter covering January 1, 2008 through March 31, 
2008;
    (ii) For a unit that commences commercial operation on or after July 
1, 2007, the calendar quarter corresponding to the earlier of the date 
of provisional certification or the applicable deadline for initial 
certification under Sec. 96.170(b), unless that quarter is the third or 
fourth quarter of 2007, in which case reporting shall commence in the 
quarter covering January 1, 2008 through March 31, 2008;
    (iii) Notwithstanding paragraphs (d)(1)(i) and (ii) of this section, 
for a unit for which a CAIR opt-in permit application is submitted and 
not withdrawn and a CAIR opt-in permit is not yet issued or denied under 
subpart II of this part, the calendar quarter corresponding to the date 
specified in Sec. 96.184(b); and
    (iv) Notwithstanding paragraphs (d)(1)(i) and (ii) of this section, 
for a CAIR NOX opt-in unit under subpart II of this part, the 
calendar quarter corresponding to the date on which the CAIR 
NOX opt-in unit enters the CAIR NOX Annual Trading 
Program as provided in Sec. 96.184(g).
    (2) The CAIR designated representative shall submit each quarterly 
report to the Administrator within 30 days following the end of the 
calendar quarter covered by the report. Quarterly reports shall be 
submitted in the manner specified in Sec. 75.73(f) of this chapter.
    (3) For CAIR NOX units that are also subject to an Acid 
Rain emissions limitation or the CAIR NOX Ozone Season 
Trading Program, CAIR SO2 Trading Program, or Hg Budget 
Trading Program, quarterly reports shall include the applicable data and 
information required by subparts F through I of part 75 of this chapter 
as applicable, in addition to the NOX mass emission data, 
heat input data, and other information required by this subpart.
    (e) Compliance certification. The CAIR designated representative 
shall submit to the Administrator a compliance certification (in a 
format prescribed by the Administrator) in support of each quarterly 
report based on reasonable inquiry of those persons with primary 
responsibility for ensuring that all of the unit's emissions are 
correctly and fully monitored. The certification shall state that:
    (1) The monitoring data submitted were recorded in accordance with 
the applicable requirements of this subpart and part 75 of this chapter, 
including the quality assurance procedures and specifications; and
    (2) For a unit with add-on NOX emission controls and for 
all hours where NOX data are substituted in accordance with 
Sec. 75.34(a)(1) of this chapter, the add-on emission controls were 
operating within the range of parameters listed in the quality 
assurance/quality control program under appendix B to part 75 of this 
chapter and the substitute data values do not systematically 
underestimate NOX emissions.

[70 FR 25339, May 12, 2005, as amended at 71 FR 25385, Apr. 28, 2006]

[[Page 83]]



Sec. 96.175  Petitions.

    (a) Except as provided in paragraph (b)(2) of this section, the CAIR 
designated representative of a CAIR NOX unit that is subject 
to an Acid Rain emissions limitation may submit a petition under Sec. 
75.66 of this chapter to the Administrator requesting approval to apply 
an alternative to any requirement of this subpart. Application of an 
alternative to any requirement of this subpart is in accordance with 
this subpart only to the extent that the petition is approved in writing 
by the Administrator, in consultation with the permitting authority.
    (b)(1) The CAIR designated representative of a CAIR NOX 
unit that is not subject to an Acid Rain emissions limitation may submit 
a petition under Sec. 75.66 of this chapter to the permitting authority 
and the Administrator requesting approval to apply an alternative to any 
requirement of this subpart. Application of an alternative to any 
requirement of this subpart is in accordance with this subpart only to 
the extent that the petition is approved in writing by both the 
permitting authority and the Administrator.
    (2) The CAIR designated representative of a CAIR NOX unit 
that is subject to an Acid Rain emissions limitation may submit a 
petition under Sec. 75.66 of this chapter to the permitting authority 
and the Administrator requesting approval to apply an alternative to a 
requirement concerning any additional continuous emission monitoring 
system required under Sec. 75.72 of this chapter. Application of an 
alternative to any such requirement is in accordance with this subpart 
only to the extent that the petition is approved in writing by both the 
permitting authority and the Administrator.



                    Subpart II_CAIR NOX Opt-in Units

    Source: 70 FR 25339, May 12, 2005, unless otherwise noted.



Sec. 96.180  Applicability.

    A CAIR NOX opt-in unit must be a unit that:
    (a) Is located in the State;
    (b) Is not a CAIR NOX unit under Sec. 96.104 and is not 
covered by a retired unit exemption under Sec. 96.105 that is in 
effect;
    (c) Is not covered by a retired unit exemption under Sec. 72.8 of 
this chapter that is in effect;
    (d) Has or is required or qualified to have a title V operating 
permit or other federally enforceable permit; and
    (e) Vents all of its emissions to a stack and can meet the 
monitoring, recordkeeping, and reporting requirements of subpart HH of 
this part.



Sec. 96.181  General.

    (a) Except as otherwise provided in Sec. Sec. 96.101 through 
96.104, Sec. Sec. 96.106 through 96.108, and subparts BB and CC and 
subparts FF through HH of this part, a CAIR NOX opt-in unit 
shall be treated as a CAIR NOX unit for purposes of applying 
such sections and subparts of this part.
    (b) Solely for purposes of applying, as provided in this subpart, 
the requirements of subpart HH of this part to a unit for which a CAIR 
opt-in permit application is submitted and not withdrawn and a CAIR opt-
in permit is not yet issued or denied under this subpart, such unit 
shall be treated as a CAIR NOX unit before issuance of a CAIR 
opt-in permit for such unit.



Sec. 96.182  CAIR designated representative.

    Any CAIR NOX opt-in unit, and any unit for which a CAIR 
opt-in permit application is submitted and not withdrawn and a CAIR opt-
in permit is not yet issued or denied under this subpart, located at the 
same source as one or more CAIR NOX units shall have the same 
CAIR designated representative and alternate CAIR designated 
representative as such CAIR NOX units.



Sec. 96.183  Applying for CAIR opt-in permit.

    (a) Applying for initial CAIR opt-in permit. The CAIR designated 
representative of a unit meeting the requirements for a CAIR 
NOX opt-in unit in Sec. 96.180 may apply for an initial CAIR 
opt-in permit at any time, except as provided under Sec. 96.186(f) and 
(g), and, in order to apply, must submit the following:
    (1) A complete CAIR permit application under Sec. 96.122;

[[Page 84]]

    (2) A certification, in a format specified by the permitting 
authority, that the unit:
    (i) Is not a CAIR NOX unit under Sec. 96.104 and is not 
covered by a retired unit exemption under Sec. 96.105 that is in 
effect;
    (ii) Is not covered by a retired unit exemption under Sec. 72.8 of 
this chapter that is in effect;
    (iii) Vents all of its emissions to a stack, and
    (iv) Has documented heat input for more than 876 hours during the 6 
months immediately preceding submission of the CAIR permit application 
under Sec. 96.122;
    (3) A monitoring plan in accordance with subpart HH of this part;
    (4) A complete certificate of representation under Sec. 96.113 
consistent with Sec. 96.182, if no CAIR designated representative has 
been previously designated for the source that includes the unit; and
    (5) A statement, in a format specified by the permitting authority, 
whether the CAIR designated representative requests that the unit be 
allocated CAIR NOX allowances under Sec. 96.188(b) or Sec. 
96.188(c) (subject to the conditions in Sec. Sec. 96.184(h) and 
96.186(g)). If allocation under Sec. 96.188(c) is requested, this 
statement shall include a statement that the owners and operators of the 
unit intend to repower the unit before January 1, 2015 and that they 
will provide, upon request, documentation demonstrating such intent.
    (b) Duty to reapply. (1) The CAIR designated representative of a 
CAIR NOX opt-in unit shall submit a complete CAIR permit 
application under Sec. 96.122 to renew the CAIR opt-in unit permit in 
accordance with the permitting authority's regulations for title V 
operating permits, or the permitting authority's regulations for other 
federally enforceable permits if applicable, addressing permit renewal.
    (2) Unless the permitting authority issues a notification of 
acceptance of withdrawal of the CAIR NOX opt-in unit from the 
CAIR NOX Annual Trading Program in accordance with Sec. 
96.186 or the unit becomes a CAIR NOX unit under Sec. 
96.104, the CAIR NOX opt-in unit shall remain subject to the 
requirements for a CAIR NOX opt-in unit, even if the CAIR 
designated representative for the CAIR NOX opt-in unit fails 
to submit a CAIR permit application that is required for renewal of the 
CAIR opt-in permit under paragraph (b)(1) of this section.

[70 FR 25339, May 12, 2005, as amended at 71 FR 25385, Apr. 28, 2006]



Sec. 96.184  Opt-in process.

    The permitting authority will issue or deny a CAIR opt-in permit for 
a unit for which an initial application for a CAIR opt-in permit under 
Sec. 96.183 is submitted in accordance with the following:
    (a) Interim review of monitoring plan. The permitting authority and 
the Administrator will determine, on an interim basis, the sufficiency 
of the monitoring plan accompanying the initial application for a CAIR 
opt-in permit under Sec. 96.183. A monitoring plan is sufficient, for 
purposes of interim review, if the plan appears to contain information 
demonstrating that the NOX emissions rate and heat input of 
the unit and all other applicable parameters are monitored and reported 
in accordance with subpart HH of this part. A determination of 
sufficiency shall not be construed as acceptance or approval of the 
monitoring plan.
    (b) Monitoring and reporting. (1)(i) If the permitting authority and 
the Administrator determine that the monitoring plan is sufficient under 
paragraph (a) of this section, the owner or operator shall monitor and 
report the NOX emissions rate and the heat input of the unit 
and all other applicable parameters, in accordance with subpart HH of 
this part, starting on the date of certification of the appropriate 
monitoring systems under subpart HH of this part and continuing until a 
CAIR opt-in permit is denied under Sec. 96.184(f) or, if a CAIR opt-in 
permit is issued, the date and time when the unit is withdrawn from the 
CAIR NOX Annual Trading Program in accordance with Sec. 
96.186.
    (ii) The monitoring and reporting under paragraph (b)(1)(i) of this 
section shall include the entire control period immediately before the 
date on which the unit enters the CAIR NOX Annual Trading 
Program under Sec. 96.184(g), during which period monitoring system

[[Page 85]]

availability must not be less than 90 percent under subpart HH of this 
part and the unit must be in full compliance with any applicable State 
or Federal emissions or emissions-related requirements.
    (2) To the extent the NOX emissions rate and the heat 
input of the unit are monitored and reported in accordance with subpart 
HH of this part for one or more control periods, in addition to the 
control period under paragraph (b)(1)(ii) of this section, during which 
control periods monitoring system availability is not less than 90 
percent under subpart HH of this part and the unit is in full compliance 
with any applicable State or Federal emissions or emissions-related 
requirements and which control periods begin not more than 3 years 
before the unit enters the CAIR NOX Annual Trading Program 
under Sec. 96.184(g), such information shall be used as provided in 
paragraphs (c) and (d) of this section.
    (c) Baseline heat input. The unit's baseline heat input shall equal:
    (1) If the unit's NOX emissions rate and heat input are 
monitored and reported for only one control period, in accordance with 
paragraph (b)(1) of this section, the unit's total heat input (in mmBtu) 
for the control period; or
    (2) If the unit's NOX emissions rate and heat input are 
monitored and reported for more than one control period, in accordance 
with paragraphs (b)(1) and (2) of this section, the average of the 
amounts of the unit's total heat input (in mmBtu) for the control 
periods under paragraphs (b)(1)(ii) and (2) of this section.
    (d) Baseline NOX emission rate. The unit's baseline 
NOX emission rate shall equal:
    (1) If the unit's NOX emissions rate and heat input are 
monitored and reported for only one control period, in accordance with 
paragraph (b)(1) of this section, the unit's NOX emissions 
rate (in lb/mmBtu) for the control period;
    (2) If the unit's NOX emissions rate and heat input are 
monitored and reported for more than one control period, in accordance 
with paragraphs (b)(1) and (2) of this section, and the unit does not 
have add-on NOX emission controls during any such control 
periods, the average of the amounts of the unit's NOX 
emissions rate (in lb/mmBtu) for the control periods under paragraphs 
(b)(1)(ii) and (2) of this section; or
    (3) If the unit's NOX emissions rate and heat input are 
monitored and reported for more than one control period, in accordance 
with paragraphs (b)(1) and (2) of this section, and the unit has add-on 
NOX emission controls during any such control periods, the 
average of the amounts of the unit's NOX emissions rate (in 
lb/mmBtu) for such control periods during which the unit has add-on 
NOX emission controls.
    (e) Issuance of CAIR opt-in permit. After calculating the baseline 
heat input and the baseline NOX emissions rate for the unit 
under paragraphs (c) and (d) of this section and if the permitting 
authority determines that the CAIR designated representative shows that 
the unit meets the requirements for a CAIR NOX opt-in unit in 
Sec. 96.180 and meets the elements certified in Sec. 96.183(a)(2), the 
permitting authority will issue a CAIR opt-in permit. The permitting 
authority will provide a copy of the CAIR opt-in permit to the 
Administrator, who will then establish a compliance account for the 
source that includes the CAIR NOX opt-in unit unless the 
source already has a compliance account.
    (f) Issuance of denial of CAIR opt-in permit. Notwithstanding 
paragraphs (a) through (e) of this section, if at any time before 
issuance of a CAIR opt-in permit for the unit, the permitting authority 
determines that the CAIR designated representative fails to show that 
the unit meets the requirements for a CAIR NOX opt-in unit in 
Sec. 96.180 or meets the elements certified in Sec. 96.183(a)(2), the 
permitting authority will issue a denial of a CAIR opt-in permit for the 
unit.
    (g) Date of entry into CAIR NOX Annual Trading Program. A 
unit for which an initial CAIR opt-in permit is issued by the permitting 
authority shall become a CAIR NOX opt-in unit, and a CAIR 
NOX unit, as of the later of January 1, 2009 or January 1 of 
the first control period during which such CAIR opt-in permit is issued.
    (h) Repowered CAIR NOX opt-in unit. (1) If CAIR 
designated representative

[[Page 86]]

requests, and the permitting authority issues a CAIR opt-in permit 
providing for, allocation to a CAIR NOX opt-in unit of CAIR 
NOX allowances under Sec. 96.188(c) and such unit is 
repowered after its date of entry into the CAIR NOX Annual 
Trading Program under paragraph (g) of this section, the repowered unit 
shall be treated as a CAIR NOX opt-in unit replacing the 
original CAIR NOX opt-in unit, as of the date of start-up of 
the repowered unit's combustion chamber.
    (2) Notwithstanding paragraphs (c) and (d) of this section, as of 
the date of start-up under paragraph (h)(1) of this section, the 
repowered unit shall be deemed to have the same date of commencement of 
operation, date of commencement of commercial operation, baseline heat 
input, and baseline NOX emission rate as the original CAIR 
NOX opt-in unit, and the original CAIR NOX opt-in 
unit shall no longer be treated as a CAIR NOX opt-in unit or 
a CAIR NOX unit.

[70 FR 25339, May 12, 2005, as amended at 71 FR 25385, Apr. 28, 2006; 71 
FR 74794, Dec. 13, 2006]



Sec. 96.185  CAIR opt-in permit contents.

    (a) Each CAIR opt-in permit will contain:
    (1) All elements required for a complete CAIR permit application 
under Sec. 96.122;
    (2) The certification in Sec. 96.183(a)(2);
    (3) The unit's baseline heat input under Sec. 96.184(c);
    (4) The unit's baseline NOX emission rate under Sec. 
96.184(d);
    (5) A statement whether the unit is to be allocated CAIR 
NOX allowances Sec. 96.188(b) or Sec. 96.188(c) (subject to 
the conditions in Sec. Sec. 96.184(h) and 96.186(g));
    (6) A statement that the unit may withdraw from the CAIR 
NOX Annual Trading Program only in accordance with Sec. 
96.186; and
    (7) A statement that the unit is subject to, and the owners and 
operators of the unit must comply with, the requirements of Sec. 
96.187.
    (b) Each CAIR opt-in permit is deemed to incorporate automatically 
the definitions of terms under Sec. 96.102 and, upon recordation by the 
Administrator under subpart FF or GG of this part or this subpart, every 
allocation, transfer, or deduction of CAIR NOX allowances to 
or from the compliance account of the source that includes a CAIR 
NOX opt-in unit covered by the CAIR opt-in permit.
    (c) The CAIR opt-in permit shall be included, in a format specified 
by the permitting authority, in the CAIR permit for the source where the 
CAIR NOX opt-in unit is located and in a title V operating 
permit or other federally enforceable permit for the source.

[70 FR 25339, May 12, 2005, as amended at 71 FR 25385, Apr. 28, 2006]



Sec. 96.186  Withdrawal from CAIR NOX Annual Trading Program.

    Except as provided under paragraph (g) of this section, a CAIR 
NOX opt-in unit may withdraw from the CAIR NOX 
Annual Trading Program, but only if the permitting authority issues a 
notification to the CAIR designated representative of the CAIR 
NOX opt-in unit of the acceptance of the withdrawal of the 
CAIR NOX opt-in unit in accordance with paragraph (d) of this 
section.
    (a) Requesting withdrawal. In order to withdraw a CAIR CAIR 
NOX opt-in unit from the CAIR NOX Annual Trading 
Program, the CAIR designated representative of the CAIR NOX 
opt-in unit shall submit to the permitting authority a request to 
withdraw effective as of midnight of December 31 of a specified calendar 
year, which date must be at least 4 years after December 31 of the year 
of entry into the CAIR NOX Annual Trading Program under Sec. 
96.184(g). The request must be submitted no later than 90 days before 
the requested effective date of withdrawal.
    (b) Conditions for withdrawal. Before a CAIR NOX opt-in 
unit covered by a request under paragraph (a) of this section may 
withdraw from the CAIR NOX Annual Trading Program and the 
CAIR opt-in permit may be terminated under paragraph (e) of this 
section, the following conditions must be met:
    (1) For the control period ending on the date on which the 
withdrawal is to be effective, the source that includes the CAIR 
NOX opt-in unit must meet the requirement to hold CAIR 
NOX allowances under Sec. 96.106(c) and cannot have any 
excess emissions.

[[Page 87]]

    (2) After the requirement for withdrawal under paragraph (b)(1) of 
this section is met, the Administrator will deduct from the compliance 
account of the source that includes the CAIR NOX opt-in unit 
CAIR NOX allowances equal in amount to and allocated for the 
same or a prior control period as any CAIR NOX allowances 
allocated to the CAIR NOX opt-in unit under Sec. 96.188 for 
any control period for which the withdrawal is to be effective. If there 
are no remaining CAIR NOX units at the source, the 
Administrator will close the compliance account, and the owners and 
operators of the CAIR NOX opt-in unit may submit a CAIR 
NOX allowance transfer for any remaining CAIR NOX 
allowances to another CAIR NOX Allowance Tracking System in 
accordance with subpart GG of this part.
    (c) Notification. (1) After the requirements for withdrawal under 
paragraphs (a) and (b) of this section are met (including deduction of 
the full amount of CAIR NOX allowances required), the 
permitting authority will issue a notification to the CAIR designated 
representative of the CAIR NOX opt-in unit of the acceptance 
of the withdrawal of the CAIR NOX opt-in unit as of midnight 
on December 31 of the calendar year for which the withdrawal was 
requested.
    (2) If the requirements for withdrawal under paragraphs (a) and (b) 
of this section are not met, the permitting authority will issue a 
notification to the CAIR designated representative of the CAIR 
NOX opt-in unit that the CAIR NOX opt-in unit's 
request to withdraw is denied. Such CAIR NOX opt-in unit 
shall continue to be a CAIR NOX opt-in unit.
    (d) Permit amendment. After the permitting authority issues a 
notification under paragraph (c)(1) of this section that the 
requirements for withdrawal have been met, the permitting authority will 
revise the CAIR permit covering the CAIR NOX opt-in unit to 
terminate the CAIR opt-in permit for such unit as of the effective date 
specified under paragraph (c)(1) of this section. The unit shall 
continue to be a CAIR NOX opt-in unit until the effective 
date of the termination and shall comply with all requirements under the 
CAIR NOX Annual Trading Program concerning any control 
periods for which the unit is a CAIR NOX opt-in unit, even if 
such requirements arise or must be complied with after the withdrawal 
takes effect.
    (e) Reapplication upon failure to meet conditions of withdrawal. If 
the permitting authority denies the CAIR NOX opt-in unit's 
request to withdraw, the CAIR designated representative may submit 
another request to withdraw in accordance with paragraphs (a) and (b) of 
this section.
    (f) Ability to reapply to the CAIR NOX Annual Trading 
Program. Once a CAIR NOX opt-in unit withdraws from the CAIR 
NOX Annual Trading Program and its CAIR opt-in permit is 
terminated under this section, the CAIR designated representative may 
not submit another application for a CAIR opt-in permit under Sec. 
96.183 for such CAIR NOX opt-in unit before the date that is 
4 years after the date on which the withdrawal became effective. Such 
new application for a CAIR opt-in permit will be treated as an initial 
application for a CAIR opt-in permit under Sec. 96.184.
    (g) Inability to withdraw. Notwithstanding paragraphs (a) through 
(f) of this section, a CAIR NOX opt-in unit shall not be 
eligible to withdraw from the CAIR NOX Annual Trading Program 
if the CAIR designated representative of the CAIR NOX opt-in 
unit requests, and the permitting authority issues a CAIR NOX 
opt-in permit providing for, allocation to the CAIR NOX opt-
in unit of CAIR NOX allowances under Sec. 96.188(c).

[70 FR 25339, May 12, 2005, as amended at 71 FR 25385, Apr. 28, 2006]



Sec. 96.187  Change in regulatory status.

    (a) Notification. If a CAIR NOX opt-in unit becomes a 
CAIR NOX unit under Sec. 96.104, then the CAIR designated 
representative shall notify in writing the permitting authority and the 
Administrator of such change in the CAIR NOX opt-in unit's 
regulatory status, within 30 days of such change.
    (b) Permitting authority's and Administrator's actions. (1) If a 
CAIR NOX opt-in unit becomes a CAIR NOX unit under 
Sec. 96.104, the permitting authority will revise the CAIR 
NOX opt-in unit's CAIR opt-in permit to meet the requirements

[[Page 88]]

of a CAIR permit under Sec. 96.123, and remove the CAIR opt-in permit 
provisions, as of the date on which the CAIR NOX opt-in unit 
becomes a CAIR NOX unit under Sec. 96.104.
    (2)(i) The Administrator will deduct from the compliance account of 
the source that includes the CAIR NOX opt-in unit that 
becomes a CAIR NOX unit under Sec. 96.104, CAIR 
NOX allowances equal in amount to and allocated for the same 
or a prior control period as:
    (A) Any CAIR NOX allowances allocated to the CAIR 
NOX opt-in unit under Sec. 96.188 for any control period 
after the date on which the CAIR NOX opt-in unit becomes a 
CAIR NOX unit under Sec. 96.104; and
    (B) If the date on which the CAIR NOX opt-in unit becomes 
a CAIR NOX unit under Sec. 96.104 is not December 31, the 
CAIR NOX allowances allocated to the CAIR NOX opt-
in unit under Sec. 96.188 for the control period that includes the date 
on which the CAIR NOX opt-in unit becomes a CAIR 
NOX unit under Sec. 96.104, multiplied by the ratio of the 
number of days, in the control period, starting with the date on which 
the CAIR NOX opt-in unit becomes a CAIR NOX unit 
under Sec. 96.104 divided by the total number of days in the control 
period and rounded to the nearest whole allowance as appropriate.
    (ii) The CAIR designated representative shall ensure that the 
compliance account of the source that includes the CAIR NOX 
opt-in unit that becomes a CAIR NOX unit under Sec. 96.104 
contains the CAIR NOX allowances necessary for completion of 
the deduction under paragraph (b)(2)(i) of this section.
    (3)(i) For every control period after the date on which the CAIR 
NOX opt-in unit becomes a CAIR NOX unit under 
Sec. 96.104, the CAIR NOX opt-in unit will be allocated CAIR 
NOX allowances under Sec. 96.142.
    (ii) If the date on which the CAIR NOX opt-in unit 
becomes a CAIR NOX unit under Sec. 96.104 is not December 
31, the following amount of CAIR NOX allowances will be 
allocated to the CAIR NOX opt-in unit (as a CAIR 
NOX unit) under Sec. 96.142 for the control period that 
includes the date on which the CAIR NOX opt-in unit becomes a 
CAIR NOX unit under Sec. 96.104:
    (A) The amount of CAIR NOX allowances otherwise allocated 
to the CAIR NOX opt-in unit (as a CAIR NOX unit) 
under Sec. 96.142 for the control period multiplied by;
    (B) The ratio of the number of days, in the control period, starting 
with the date on which the CAIR NOX opt-in unit becomes a 
CAIR NOX unit under Sec. 96.104, divided by the total number 
of days in the control period; and
    (C) Rounded to the nearest whole allowance as appropriate.

[70 FR 25339, May 12, 2005, as amended at 71 FR 25385, Apr. 28, 2006; 71 
FR 74794, Dec. 13, 2006]



Sec. 96.188  CAIR NOX allowance allocations to CAIR NOX opt-in units.

    (a) Timing requirements. (1) When the CAIR opt-in permit is issued 
under Sec. 96.184(e), the permitting authority will allocate CAIR 
NOX allowances to the CAIR NOX opt-in unit, and 
submit to the Administrator the allocation for the control period in 
which a CAIR NOX opt-in unit enters the CAIR NOX 
Annual Trading Program under Sec. 96.184(g), in accordance with 
paragraph (b) or (c) of this section.
    (2) By no later than October 31 of the control period after the 
control period in which a CAIR NOX opt-in unit enters the 
CAIR NOX Annual Trading Program under Sec. 96.184(g) and 
October 31 of each year thereafter, the permitting authority will 
allocate CAIR NOX allowances to the CAIR NOX opt-
in unit, and submit to the Administrator the allocation for the control 
period that includes such submission deadline and in which the unit is a 
CAIR NOX opt-in unit, in accordance with paragraph (b) or (c) 
of this section.
    (b) Calculation of allocation. For each control period for which a 
CAIR NOX opt-in unit is to be allocated CAIR NOX 
allowances, the permitting authority will allocate in accordance with 
the following procedures:
    (1) The heat input (in mmBtu) used for calculating the CAIR 
NOX allowance allocation will be the lesser of:
    (i) The CAIR NOX opt-in unit's baseline heat input 
determined under Sec. 96.184(c); or
    (ii) The CAIR NOX opt-in unit's heat input, as determined 
in accordance with subpart HH of this part, for the

[[Page 89]]

immediately prior control period, except when the allocation is being 
calculated for the control period in which the CAIR NOX opt-
in unit enters the CAIR NOX Annual Trading Program under 
Sec. 96.184(g).
    (2) The NOX emission rate (in lb/mmBtu) used for 
calculating CAIR NOX allowance allocations will be the lesser 
of:
    (i) The CAIR NOX opt-in unit's baseline NOX 
emissions rate (in lb/mmBtu) determined under Sec. 96.184(d) and 
multiplied by 70 percent; or
    (ii) The most stringent State or Federal NOX emissions 
limitation applicable to the CAIR NOX opt-in unit at any time 
during the control period for which CAIR NOX allowances are 
to be allocated.
    (3) The permitting authority will allocate CAIR NOX 
allowances to the CAIR NOX opt-in unit in an amount equaling 
the heat input under paragraph (b)(1) of this section, multiplied by the 
NOX emission rate under paragraph (b)(2) of this section, 
divided by 2,000 lb/ton, and rounded to the nearest whole allowance as 
appropriate.
    (c) Notwithstanding paragraph (b) of this section and if the CAIR 
designated representative requests, and the permitting authority issues 
a CAIR opt-in permit (based on a demonstration of the intent to repower 
stated under Sec. 96.183(a)(5)) providing for, allocation to a CAIR 
NOX opt-in unit of CAIR NOX allowances under this 
paragraph (subject to the conditions in Sec. Sec. 96.184(h) and 
96.186(g)), the permitting authority will allocate to the CAIR 
NOX opt-in unit as follows:
    (1) For each control period in 2009 through 2014 for which the CAIR 
NOX opt-in unit is to be allocated CAIR NOX 
allowances,
    (i) The heat input (in mmBtu) used for calculating CAIR 
NOX allowance allocations will be determined as described in 
paragraph (b)(1) of this section.
    (ii) The NOX emission rate (in lb/mmBtu) used for 
calculating CAIR NOX allowance allocations will be the lesser 
of:
    (A) The CAIR NOX opt-in unit's baseline NOX 
emissions rate (in lb/mmBtu) determined under Sec. 96.184(d); or
    (B) The most stringent State or Federal NOX emissions 
limitation applicable to the CAIR NOX opt-in unit at any time 
during the control period in which the CAIR NOX opt-in unit 
enters the CAIR NOX Annual Trading Program under Sec. 
96.184(g).
    (iii) The permitting authority will allocate CAIR NOX 
allowances to the CAIR NOX opt-in unit in an amount equaling 
the heat input under paragraph (c)(1)(i) of this section, multiplied by 
the NOX emission rate under paragraph (c)(1)(ii) of this 
section, divided by 2,000 lb/ton, and rounded to the nearest whole 
allowance as appropriate.
    (2) For each control period in 2015 and thereafter for which the 
CAIR NOX opt-in unit is to be allocated CAIR NOX 
allowances,
    (i) The heat input (in mmBtu) used for calculating the CAIR 
NOX allowance allocations will be determined as described in 
paragraph (b)(1) of this section.
    (ii) The NOX emission rate (in lb/mmBtu) used for 
calculating the CAIR NOX allowance allocation will be the 
lesser of:
    (A) 0.15 lb/mmBtu;
    (B) The CAIR NOX opt-in unit's baseline NOX 
emissions rate (in lb/mmBtu) determined under Sec. 96.184(d); or
    (C) The most stringent State or Federal NOX emissions 
limitation applicable to the CAIR NOX opt-in unit at any time 
during the control period for which CAIR NOX allowances are 
to be allocated.
    (iii) The permitting authority will allocate CAIR NOX 
allowances to the CAIR NOX opt-in unit in an amount equaling 
the heat input under paragraph (c)(2)(i) of this section, multiplied by 
the NOX emission rate under paragraph (c)(2)(ii) of this 
section, divided by 2,000 lb/ton, and rounded to the nearest whole 
allowance as appropriate.
    (d) Recordation. (1) The Administrator will record, in the 
compliance account of the source that includes the CAIR NOX 
opt-in unit, the CAIR NOX allowances allocated by the 
permitting authority to the CAIR NOX opt-in unit under 
paragraph (a)(1) of this section.
    (2) By December 1 of the control period in which a CAIR 
NOX opt-in unit

[[Page 90]]

enters the CAIR NOX Annual Trading Program under Sec. 
96.184(g) and December 1 of each year thereafter, the Administrator will 
record, in the compliance account of the source that includes the CAIR 
NOX opt-in unit, the CAIR NOX allowances allocated 
by the permitting authority to the CAIR NOX opt-in unit under 
paragraph (a)(2) of this section.

[70 FR 25339, May 12, 2005, as amended at 71 FR 25385, Apr. 28, 2006]

Subparts JJ-ZZ [Reserved]



        Subpart AAA_CAIR SO 2 Trading Program General Provisions

    Source: 70 FR 25362, May 12, 2005, unless otherwise noted.



Sec. 96.201  Purpose.

    This subpart and subparts BBB through III establish the model rule 
comprising general provisions and the designated representative, 
permitting, allowance, monitoring, and opt-in provisions for the State 
Clean Air Interstate Rule (CAIR) SO2 Trading Program, under 
section 110 of the Clean Air Act and Sec. 51.124 of this chapter, as a 
means of mitigating interstate transport of fine particulates and sulfur 
dioxide. The owner or operator of a unit or a source shall comply with 
the requirements of this subpart and subparts BBB through III as a 
matter of federal law only if the State with jurisdiction over the unit 
and the source incorporates by reference such subparts or otherwise 
adopts the requirements of such subparts in accordance with Sec. 
51.124(o)(1) or (2) of this chapter, the State submits to the 
Administrator one or more revisions of the State implementation plan 
that include such adoption, and the Administrator approves such 
revisions. If the State adopts the requirements of such subparts in 
accordance with Sec. 51.124(o)(1) or (2) of this chapter, then the 
State authorizes the Administrator to assist the State in implementing 
the CAIR SO2 Trading Program by carrying out the functions 
set forth for the Administrator in such subparts.



Sec. 96.202  Definitions.

    The terms used in this subpart and subparts BBB through III shall 
have the meanings set forth in this section as follows:
    Account number means the identification number given by the 
Administrator to each CAIR SO2 Allowance Tracking System 
account.
    Acid Rain emissions limitation means a limitation on emissions of 
sulfur dioxide or nitrogen oxides under the Acid Rain Program.
    Acid Rain Program means a multi-state sulfur dioxide and nitrogen 
oxides air pollution control and emission reduction program established 
by the Administrator under title IV of the CAA and parts 72 through 78 
of this chapter.
    Administrator means the Administrator of the United States 
Environmental Protection Agency or the Administrator's duly authorized 
representative.
    Allocate or allocation means, with regard to CAIR SO2 
allowances issued under the Acid Rain Program, the determination by the 
Administrator of the amount of such CAIR SO2 allowances to be 
initially credited to a CAIR SO2 unit or other entity and, 
with regard to CAIR SO2 allowances issued under provisions of 
a State implementation plan that are approved under Sec. 51.124(o)(1) 
or (2) or (r) of this chapter or Sec. 97.288 of this chapter, the 
determination by a permitting authority of the amount of such CAIR 
SO2 allowances to be initially credited to a CAIR 
SO2 unit or other entity.
    Allowance transfer deadline means, for a control period, midnight of 
March 1 (if it is a business day), or midnight of the first business day 
thereafter (if March 1 is not a business day), immediately following the 
control period and is the deadline by which a CAIR SO2 
allowance transfer must be submitted for recordation in a CAIR 
SO2 source's compliance account in order to be used to meet 
the source's CAIR SO2 emissions limitation for such control 
period in accordance with Sec. 96.254.
    Alternate CAIR designated representative means, for a CAIR 
SO2 source and each CAIR SO2 unit at the source, 
the natural person who is authorized by the owners and operators of the 
source

[[Page 91]]

and all such units at the source, in accordance with subparts BBB and 
III of this part, to act on behalf of the CAIR designated representative 
in matters pertaining to the CAIR SO2 Trading Program. If the 
CAIR SO2 source is also a CAIR NOX source, then 
this natural person shall be the same person as the alternate CAIR 
designated representative under the CAIR NOX Annual Trading 
Program. If the CAIR SO2 source is also a CAIR NOX 
Ozone Season source, then this natural person shall be the same person 
as the alternate CAIR designated representative under the CAIR 
NOX Ozone Season Trading Program. If the CAIR SO2 
source is also subject to the Acid Rain Program, then this natural 
person shall be the same person as the alternate designated 
representative under the Acid Rain Program. If the CAIR SO2 
source is also subject to the Hg Budget Trading Program, then this 
natural person shall be the same person as the alternate Hg designated 
representative under the Hg Budget Trading Program.
    Automated data acquisition and handling system or DAHS means that 
component of the continuous emission monitoring system, or other 
emissions monitoring system approved for use under subpart HHH of this 
part, designed to interpret and convert individual output signals from 
pollutant concentration monitors, flow monitors, diluent gas monitors, 
and other component parts of the monitoring system to produce a 
continuous record of the measured parameters in the measurement units 
required by subpart HHH of this part.
    Biomass means--
    (1) Any organic material grown for the purpose of being converted to 
energy;
    (2) Any organic byproduct of agriculture that can be converted into 
energy; or
    (3) Any material that can be converted into energy and is 
nonmerchantable for other purposes, that is segregated from other 
nonmerchantable material, and that is;
    (i) A forest-related organic resource, including mill residues, 
precommercial thinnings, slash, brush, or byproduct from conversion of 
trees to merchantable material; or
    (ii) A wood material, including pallets, crates, dunnage, 
manufacturing and construction materials (other than pressure-treated, 
chemically-treated, or painted wood products), and landscape or right-
of-way tree trimmings.
    Boiler means an enclosed fossil- or other-fuel-fired combustion 
device used to produce heat and to transfer heat to recirculating water, 
steam, or other medium.
    Bottoming-cycle cogeneration unit means a cogeneration unit in which 
the energy input to the unit is first used to produce useful thermal 
energy and at least some of the reject heat from the useful thermal 
energy application or process is then used for electricity production.
    CAIR authorized account representative means, with regard to a 
general account, a responsible natural person who is authorized, in 
accordance with subparts BBB, FFF, and III of this part, to transfer and 
otherwise dispose of CAIR SO2 allowances held in the general 
account and, with regard to a compliance account, the CAIR designated 
representative of the source.
    CAIR designated representative means, for a CAIR SO2 
source and each CAIR SO2 unit at the source, the natural 
person who is authorized by the owners and operators of the source and 
all such units at the source, in accordance with subparts BBB and III of 
this part, to represent and legally bind each owner and operator in 
matters pertaining to the CAIR SO2 Trading Program. If the 
CAIR SO2 source is also a CAIR NOX source, then 
this natural person shall be the same person as the CAIR designated 
representative under the CAIR NOX Annual Trading Program. If 
the CAIR SO2 source is also a CAIR NOX Ozone 
Season source, then this natural person shall be the same person as the 
CAIR designated representative under the CAIR NOX Ozone 
Season Trading Program. If the CAIR SO2 source is also 
subject to the Acid Rain Program, then this natural person shall be the 
same person as the designated representative under the Acid Rain 
Program. If the CAIR SO2 source is also subject to the Hg 
Budget Trading Program, then this natural person

[[Page 92]]

shall be the same person as the Hg designated representative under the 
Hg Budget Trading Program.
    CAIR NO X Annual Trading Program means a multi-state 
nitrogen oxides air pollution control and emission reduction program 
approved and administered by the Administrator in accordance with 
subparts AA through II of this part and Sec. 51.123(o)(1) or (2) of 
this chapter or established by the Administrator in accordance with 
subparts AA through II of part 97 of this chapter and Sec. Sec. 
51.123(p) and 52.35 of this chapter, as a means of mitigating interstate 
transport of fine particulates and nitrogen oxides.
    CAIR NOX Ozone Season source means a source that includes one or 
more CAIR NOX Ozone Season units.
    CAIR NOX Ozone Season Trading Program means a multi-state nitrogen 
oxides air pollution control and emission reduction program approved and 
administered by the Administrator in accordance with subparts AAAA 
through IIII of this part and Sec. 51.123(aa)(1) or (2) (and (bb)(1)), 
(bb)(2), or (dd) of this chapter or established by the Administrator in 
accordance with subparts AA through II of part 97 of this chapter and 
Sec. Sec. 51.123(p) and 52.35 of this chapter, as a means of mitigating 
interstate transport of ozone and nitrogen oxides.
    CAIR NOX source means a source that is subject to the CAIR 
NOX Ozone Season Trading Program.
    CAIR permit means the legally binding and federally enforceable 
written document, or portion of such document, issued by the permitting 
authority under subpart CCC of this part, including any permit 
revisions, specifying the CAIR SO2 Trading Program 
requirements applicable to a CAIR SO2 source, to each CAIR 
SO2 unit at the source, and to the owners and operators and 
the CAIR designated representative of the source and each such unit.
    CAIR SO2 allowance means a limited authorization issued by the 
Administrator under the Acid Rain Program, or by a permitting authority 
under provisions of a State implementation plan that are approved under 
Sec. 51.124(o)(1) or (2) or (r) of this chapter or Sec. 97.288 of this 
chapter,'', by designating the last sentence of the definition as 
paragraph (4), and by revising in paragraph (4) the words ``(Program or 
under the provisions of a State implementation plan that is approved 
under Sec. 51.124(o)(1) or (2) of this chapter'' to read ``(Program, 
provisions of a State implementation plan that are approved under Sec. 
51.124(o)(1) or (2) or (r) of this chapter, or Sec. 97.288 of this 
chapter, to emit sulfur dioxide during the control period of the 
specified calendar year for which the authorization is allocated or of 
any calendar year thereafter under the CAIR SO2 Trading 
Program as follows:
    (1) For one CAIR SO2 allowance allocated for a control 
period in a year before 2010, one ton of sulfur dioxide, except as 
provided in Sec. 96.254(b);
    (2) For one CAIR SO2 allowance allocated for a control 
period in 2010 through 2014, 0.50 ton of sulfur dioxide, except as 
provided in Sec. 96.254(b); and
    (3) For one CAIR SO2 allowance allocated for a control 
period in 2015 or later, 0.35 ton of sulfur dioxide, except as provided 
in Sec. 96.254(b).
    An authorization to emit sulfur dioxide that is not issued under the 
Acid Rain Program or under the provisions of a State implementation plan 
that is approved under Sec. 51.124(o)(1) or (2) of this chapter shall 
not be a CAIR SO2 allowance.
    CAIR SO2 allowance deduction or deduct CAIR SO2 allowances means the 
permanent withdrawal of CAIR SO2 allowances by the 
Administrator from a compliance account, e.g., in order to account for a 
specified number of tons of total sulfur dioxide emissions from all CAIR 
SO2 units at a CAIR SO2 source for a control 
period, determined in accordance with subpart HHH of this part, or to 
account for excess emissions.
    CAIR SO2 Allowance Tracking System means the system by which the 
Administrator records allocations, deductions, and transfers of CAIR 
SO2 allowances under the CAIR SO2 Trading Program. 
This is the same system as the Allowance Tracking System under Sec. 
72.2 of this chapter by which the Administrator records allocations, 
deduction, and transfers of Acid Rain SO2 allowances under 
the Acid Rain Program.
    CAIR SO2 Allowance Tracking System account means an account in the 
CAIR

[[Page 93]]

SO2 Allowance Tracking System established by the 
Administrator for purposes of recording the allocation, holding, 
transferring, or deducting of CAIR SO2 allowances. Such 
allowances will be allocated, held, deducted, or transferred only as 
whole allowances.
    CAIR SO2 allowances held or hold CAIR SO2 allowances means the CAIR 
SO2 allowances recorded by the Administrator, or submitted to 
the Administrator for recordation, in accordance with subparts FFF, GGG, 
and III of this part or part 73 of this chapter, in a CAIR 
SO2 Allowance Tracking System account.
    CAIR SO2 emissions limitation means, for a CAIR SO2 
source, the tonnage equivalent, in SO2 emissions in a control 
period, of the CAIR SO2 allowances available for deduction 
for the source under Sec. 96.254(a) and (b) for the control period.
    CAIR SO2 source means a source that includes one or more CAIR 
SO2 units.
    CAIR SO2 Trading Program means a multi-state sulfur dioxide air 
pollution control and emission reduction program approved and 
administered by the Administrator in accordance with subparts AAA 
through III of this part and Sec. 51.124(o)(1) or (2) of this chapter 
or established by the Administrator in accordance with subparts AAA 
through III of part 97 of this chapter and Sec. Sec. 51.124(r) and 
52.36 of this chapter, as a means of mitigating interstate transport of 
fine particulates and sulfur dioxide.
    CAIR SO2 unit means a unit that is subject to the CAIR 
SO2 Trading Program under Sec. 96.204 and, except for 
purposes of Sec. 96.205, a CAIR SO2 opt-in unit under 
subpart III of this part.
    Clean Air Act or CAA means the Clean Air Act, 42 U.S.C. 7401, et 
seq.
    Coal means any solid fuel classified as anthracite, bituminous, 
subbituminous, or lignite.
    Coal-derived fuel means any fuel (whether in a solid, liquid, or 
gaseous state) produced by the mechanical, thermal, or chemical 
processing of coal.
    Coal-fired means combusting any amount of coal or coal-derived fuel, 
alone, or in combination with any amount of any other fuel.
    Cogeneration unit means a stationary, fossil-fuel-fired boiler or 
stationary, fossil-fuel-fired combustion turbine:
    (1) Having equipment used to produce electricity and useful thermal 
energy for industrial, commercial, heating, or cooling purposes through 
the sequential use of energy; and
    (2) Producing during the 12-month period starting on the date the 
unit first produces electricity and during any calendar year after the 
calendar year in which the unit first produces electricity--
    (i) For a topping-cycle cogeneration unit,
    (A) Useful thermal energy not less than 5 percent of total energy 
output; and
    (B) Useful power that, when added to one-half of useful thermal 
energy produced, is not less then 42.5 percent of total energy input, if 
useful thermal energy produced is 15 percent or more of total energy 
output, or not less than 45 percent of total energy input, if useful 
thermal energy produced is less than 15 percent of total energy output.
    (ii) For a bottoming-cycle cogeneration unit, useful power not less 
than 45 percent of total energy input;
    (3) Provided that the total energy input under paragraphs (2)(i)(B) 
and (2)(ii) of this definition shall equal the unit's total energy input 
from all fuel except biomass if the unit is a boiler.
    Combustion turbine means:
    (1) An enclosed device comprising a compressor, a combustor, and a 
turbine and in which the flue gas resulting from the combustion of fuel 
in the combustor passes through the turbine, rotating the turbine; and
    (2) If the enclosed device under paragraph (1) of this definition is 
combined cycle, any associated duct burner, heat recovery steam 
generator, and steam turbine.
    Commence commercial operation means, with regard to a unit:
    (1) To have begun to produce steam, gas, or other heated medium used 
to generate electricity for sale or use, including test generation, 
except as provided in Sec. 96.205 and Sec. 96.284(h).
    (i) For a unit that is a CAIR SO2 unit under Sec. 96.204 
on the later of November 15, 1990 or the date the unit commences 
commercial operation as defined in

[[Page 94]]

paragraph (1) of this definition and that subsequently undergoes a 
physical change (other than replacement of the unit by a unit at the 
same source), such date shall remain the date of commencement of 
commercial operation of the unit, which shall continue to be treated as 
the same unit.
    (ii) For a unit that is a CAIR SO2 unit under Sec. 
96.204 on the later of November 15, 1990 or the date the unit commences 
commercial operation as defined in paragraph (1) of this definition and 
that is subsequently replaced by a unit at the same source (e.g., 
repowered), such date shall remain the replaced unit's date of 
commencement of commercial operation, and the replacement unit shall be 
treated as a separate unit with a separate date for commencement of 
commercial operation as defined in paragraph (1) or (2) of this 
definition as appropriate.
    (2) Notwithstanding paragraph (1) of this definition and except as 
provided in Sec. 96.205, for a unit that is not a CAIR SO2 
unit under Sec. 96.204 on the later of November 15, 1990 or the date 
the unit commences commercial operation as defined in paragraph (1) of 
this definition, the unit's date for commencement of commercial 
operation shall be the date on which the unit becomes a CAIR 
SO2 unit under Sec. 96.204.
    (i) For a unit with a date for commencement of commercial operation 
as defined in paragraph (2) of this definition and that subsequently 
undergoes a physical change (other than replacement of the unit by a 
unit at the same source), such date shall remain the date of 
commencement of commercial operation of the unit, which shall continue 
to be treated as the same unit.
    (ii) For a unit with a date for commencement of commercial operation 
as defined in paragraph (2) of this definition and that is subsequently 
replaced by a unit at the same source (e.g., repowered), such date shall 
remain the replaced unit's date of commencement of commercial operation, 
and the replacement unit shall be treated as a separate unit with a 
separate date for commencement of commercial operation as defined in 
paragraph (1) or (2) of this definition as appropriate.
    Commence operation means:
    (1) To have begun any mechanical, chemical, or electronic process, 
including, with regard to a unit, start-up of a unit's combustion 
chamber, except as provided in Sec. 96.284(h).
    (2) For a unit that undergoes a physical change (other than 
replacement of the unit by a unit at the same source) after the date the 
unit commences operation as defined in paragraph (1) of this definition, 
such date shall remain the date of commencement of operation of the 
unit, which shall continue to be treated as the same unit.
    (3) For a unit that is replaced by a unit at the same source (e.g., 
repowered) after the date the unit commences operation as defined in 
paragraph (1) of this definition, such date shall remain the replaced 
unit's date of commencement of operation, and the replacement unit shall 
be treated as a separate unit with a separate date for commencement of 
operation as defined in paragraph (1), (2), or (3) of this definition as 
appropriate, except as provided in (96.284(h).
    Compliance account means a CAIR SO2 Allowance Tracking 
System account, established by the Administrator for a CAIR 
SO2 source subject to an Acid Rain emissions limitations 
under Sec. 73.31(a) or (b) of this chapter or for any other CAIR 
SO2 source under subpart FFF or III of this part, in which 
any CAIR SO2 allowance allocations for the CAIR 
SO2 units at the source are initially recorded and in which 
are held any CAIR SO2 allowances available for use for a 
control period in order to meet the source's CAIR SO2 
emissions limitation in accordance with Sec. 96.254.
    Continuous emission monitoring system or CEMS means the equipment 
required under subpart HHH of this part to sample, analyze, measure, and 
provide, by means of readings recorded at least once every 15 minutes 
(using an automated data acquisition and handling system (DAHS)), a 
permanent record of sulfur dioxide emissions, stack gas volumetric flow 
rate, stack gas moisture content, and oxygen or carbon dioxide 
concentration (as applicable), in a manner consistent with part 75 of 
this chapter. The following systems are the principal types of 
continuous emission monitoring systems required under subpart HHH of 
this part:

[[Page 95]]

    (1) A flow monitoring system, consisting of a stack flow rate 
monitor and an automated data acquisition and handling system and 
providing a permanent, continuous record of stack gas volumetric flow 
rate, in standard cubic feet per hour (scfh);
    (2) A sulfur dioxide monitoring system, consisting of a 
SO2 pollutant concentration monitor and an automated data 
acquisition handling system and providing a permanent, continuous record 
of SO2 emissions, in parts per million (ppm);
    (3) A moisture monitoring system, as defined in Sec. 75.11(b)(2) of 
this chapter and providing a permanent, continuous record of the stack 
gas moisture content, in percent H2O;
    (4) A carbon dioxide monitoring system, consisting of a 
CO2 pollutant concentration monitor (or an oxygen monitor 
plus suitable mathematical equations from which the CO2 
concentration is derived) and an automated data acquisition and handling 
system and providing a permanent, continuous record of CO2 
emissions, in percent CO2; and
    (5) An oxygen monitoring system, consisting of an O2 
concentration monitor and an automated data acquisition and handling 
system and providing a permanent, continuous record of O2 in 
percent O2.
    Control period means the period beginning January 1 of a calendar 
year, except as provided in Sec. 96.206(c)(2), and ending on December 
31 of the same year, inclusive.
    Emissions means air pollutants exhausted from a unit or source into 
the atmosphere, as measured, recorded, and reported to the Administrator 
by the CAIR designated representative and as determined by the 
Administrator in accordance with subpart HHH of this part.
    Excess emissions means any ton, or portion of a ton, of sulfur 
dioxide emitted by the CAIR SO2 units at a CAIR 
SO2 source during a control period that exceeds the CAIR 
SO2 emissions limitation for the source, provided that any 
portion of a ton of excess emissions shall be treated as one ton of 
excess emissions.
    Fossil fuel means natural gas, petroleum, coal, or any form of 
solid, liquid, or gaseous fuel derived from such material.
    Fossil-fuel-fired means, with regard to a unit, combusting any 
amount of fossil fuel in any calendar year.
    General account means a CAIR SO2 Allowance Tracking 
System account, established under subpart FFF of this part, that is not 
a compliance account.
    Generator means a device that produces electricity.
    Heat input means, with regard to a specified period of time, the 
product (in mmBtu/time) of the gross calorific value of the fuel (in 
Btu/lb) divided by 1,000,000 Btu/mmBtu and multiplied by the fuel feed 
rate into a combustion device (in lb of fuel/time), as measured, 
recorded, and reported to the Administrator by the CAIR designated 
representative and determined by the Administrator in accordance with 
subpart HHH of this part and excluding the heat derived from preheated 
combustion air, recirculated flue gases, or exhaust from other sources.
    Heat input rate means the amount of heat input (in mmBtu) divided by 
unit operating time (in hr) or, with regard to a specific fuel, the 
amount of heat input attributed to the fuel (in mmBtu) divided by the 
unit operating time (in hr) during which the unit combusts the fuel.
    Hg Budget Trading Program means a multi-state Hg air pollution 
control and emission reduction program approved and administered by the 
Administrator in accordance subpart HHHH of part 60 of this chapter and 
Sec. 60.24(h)(6), or established by the Administrator under section 111 
of the Clean Air Act, as a means of reducing national Hg emissions.
    Life-of-the-unit, firm power contractual arrangement means a unit 
participation power sales agreement under which a utility or industrial 
customer reserves, or is entitled to receive, a specified amount or 
percentage of nameplate capacity and associated energy generated by any 
specified unit and pays its proportional amount of such unit's total 
costs, pursuant to a contract:
    (1) For the life of the unit;
    (2) For a cumulative term of no less than 30 years, including 
contracts that permit an election for early termination; or

[[Page 96]]

    (3) For a period no less than 25 years or 70 percent of the economic 
useful life of the unit determined as of the time the unit is built, 
with option rights to purchase or release some portion of the nameplate 
capacity and associated energy generated by the unit at the end of the 
period.
    Maximum design heat input means the maximum amount of fuel per hour 
(in Btu/hr) that a unit is capable of combusting on a steady state basis 
as of the initial installation of the unit as specified by the 
manufacturer of the unit.
    Monitoring system means any monitoring system that meets the 
requirements of subpart HHH of this part, including a continuous 
emissions monitoring system, an alternative monitoring system, or an 
excepted monitoring system under part 75 of this chapter.
    Most stringent State or Federal SO2 emissions limitation 
means, with regard to a unit, the lowest SO2 emissions 
limitation (in terms of lb/mmBtu) that is applicable to the unit under 
State or Federal law, regardless of the averaging period to which the 
emissions limitation applies.
    Nameplate capacity means, starting from the initial installation of 
a generator, the maximum electrical generating output (in MWe) that the 
generator is capable of producing on a steady state basis and during 
continuous operation (when not restricted by seasonal or other 
deratings) as of such installation as specified by the manufacturer of 
the generator or, starting from the completion of any subsequent 
physical change in the generator resulting in an increase in the maximum 
electrical generating output (in MWe) that the generator is capable of 
producing on a steady state basis and during continuous operation (when 
not restricted by seasonal or other deratings), such increased maximum 
amount as of such completion as specified by the person conducting the 
physical change.
    Operator means any person who operates, controls, or supervises a 
CAIR SO2 unit or a CAIR SO2 source and shall 
include, but not be limited to, any holding company, utility system, or 
plant manager of such a unit or source.
    Owner means any of the following persons:
    (1) With regard to a CAIR SO2 source or a CAIR 
SO2 unit at a source, respectively:
    (i) Any holder of any portion of the legal or equitable title in a 
CAIR SO2 unit at the source or the CAIR SO2 unit;
    (ii) Any holder of a leasehold interest in a CAIR SO2 
unit at the source or the CAIR SO2 unit; or
    (iii) Any purchaser of power from a CAIR SO2 unit at the 
source or the CAIR SO2 unit under a life-of-the-unit, firm 
power contractual arrangement; provided that, unless expressly provided 
for in a leasehold agreement, owner shall not include a passive lessor, 
or a person who has an equitable interest through such lessor, whose 
rental payments are not based (either directly or indirectly) on the 
revenues or income from such CAIR SO2 unit; or
    (2) With regard to any general account, any person who has an 
ownership interest with respect to the CAIR SO2 allowances 
held in the general account and who is subject to the binding agreement 
for the CAIR authorized account representative to represent the person's 
ownership interest with respect to CAIR SO2 allowances.
    Permitting authority means the State air pollution control agency, 
local agency, other State agency, or other agency authorized by the 
Administrator to issue or revise permits to meet the requirements of the 
CAIR SO2 Trading Program or, if no such agency has been so 
authorized, the Administrator.
    Potential electrical output capacity means 33 percent of a unit's 
maximum design heat input, divided by 3,413 Btu/kWh, divided by 1,000 
kWh/MWh, and multiplied by 8,760 hr/yr.
    Receive or receipt of means, when referring to the permitting 
authority or the Administrator, to come into possession of a document, 
information, or correspondence (whether sent in hard copy or by 
authorized electronic transmission), as indicated in an official log, or 
by a notation made on the document, information, or correspondence,

[[Page 97]]

by the permitting authority or the Administrator in the regular course 
of business.
    Recordation, record, or recorded means, with regard to CAIR 
SO2 allowances, the movement of CAIR SO2 
allowances by the Administrator into or between CAIR SO2 
Allowance Tracking System accounts, for purposes of allocation, 
transfer, or deduction.
    Reference method means any direct test method of sampling and 
analyzing for an air pollutant as specified in Sec. 75.22 of this 
chapter.
    Replacement, replace, or replaced means, with regard to a unit, the 
demolishing of a unit, or the permanent shutdown and permanent disabling 
of a unit, and the construction of another unit (the replacement unit) 
to be used instead of the demolished or shutdown unit (the replaced 
unit).
    Repowered means, with regard to a unit, replacement of a coal-fired 
boiler with one of the following coal-fired technologies at the same 
source as the coal-fired boiler:
    (1) Atmospheric or pressurized fluidized bed combustion;
    (2) Integrated gasification combined cycle;
    (3) Magnetohydrodynamics;
    (4) Direct and indirect coal-fired turbines;
    (5) Integrated gasification fuel cells; or
    (6) As determined by the Administrator in consultation with the 
Secretary of Energy, a derivative of one or more of the technologies 
under paragraphs (1) through (5) of this definition and any other coal-
fired technology capable of controlling multiple combustion emissions 
simultaneously with improved boiler or generation efficiency and with 
significantly greater waste reduction relative to the performance of 
technology in widespread commercial use as of January 1, 2005.
    Serial number means, for a CAIR SO2 allowance, the unique 
identification number assigned to each CAIR SO2 allowance by 
the Administrator.
    Sequential use of energy means:
    (1) For a topping-cycle cogeneration unit, the use of reject heat 
from electricity production in a useful thermal energy application or 
process; or
    (2) For a bottoming-cycle cogeneration unit, the use of reject heat 
from useful thermal energy application or process in electricity 
production.
    Solid waste incineration unit means a stationary, fossil-fuel-fired 
boiler or stationary, fossil-fuel-fired combustion turbine that is a 
``solid waste incineration unit'' as defined in section 129(g)(1) of the 
Clean Air Act.
    Source means all buildings, structures, or installations located in 
one or more contiguous or adjacent properties under common control of 
the same person or persons. For purposes of section 502(c) of the Clean 
Air Act, a ``source,'' including a ``source'' with multiple units, shall 
be considered a single ``facility.''
    State means one of the States or the District of Columbia that 
adopts the CAIR SO2 Trading Program pursuant to Sec. 51.124 
(o)(1) or (2) of this chapter.
    Submit or serve means to send or transmit a document, information, 
or correspondence to the person specified in accordance with the 
applicable regulation:
    (1) In person;
    (2) By United States Postal Service; or
    (3) By other means of dispatch or transmission and delivery. 
Compliance with any ``submission'' or ``service'' deadline shall be 
determined by the date of dispatch, transmission, or mailing and not the 
date of receipt.
    Title V operating permit means a permit issued under title V of the 
Clean Air Act and part 70 or part 71 of this chapter.
    Title V operating permit regulations means the regulations that the 
Administrator has approved or issued as meeting the requirements of 
title V of the Clean Air Act and part 70 or 71 of this chapter.
    Ton means 2,000 pounds. For the purpose of determining compliance 
with the CAIR SO2 emissions limitation, total tons of sulfur 
dioxide emissions for a control period shall be calculated as the sum of 
all recorded hourly emissions (or the mass equivalent of the recorded 
hourly emission rates) in accordance with subpart HHH of this part, but 
with any remaining fraction of a ton equal to or greater than 0.50 tons 
deemed to equal one ton and any

[[Page 98]]

remaining fraction of a ton less than 0.50 tons deemed to equal zero 
tons.
    Topping-cycle cogeneration unit means a cogeneration unit in which 
the energy input to the unit is first used to produce useful power, 
including electricity, and at least some of the reject heat from the 
electricity production is then used to provide useful thermal energy.
    Total energy input means, with regard to a cogeneration unit, total 
energy of all forms supplied to the cogeneration unit, excluding energy 
produced by the cogeneration unit itself. Each form of energy supplied 
shall be measured by the lower heating value of that form of energy 
calculated as follows:

LHV = HHV-10.55(W + 9H)

Where:

LHV = lower heating value of fuel in Btu/lb,
HHV = higher heating value of fuel in Btu/lb,
W = Weight % of moisture in fuel, and
H = Weight % of hydrogen in fuel.

    Total energy output means, with regard to a cogeneration unit, the 
sum of useful power and useful thermal energy produced by the 
cogeneration unit.
    Unit means a stationary, fossil-fuel-fired boiler or combustion 
turbine or other stationary, fossil-fuel-fired combustion device.
    Unit operating day means a calendar day in which a unit combusts any 
fuel.
    Unit operating hour or hour of unit operation means an hour in which 
a unit combusts any fuel.
    Useful power means, with regard to a cogeneration unit, electricity 
or mechanical energy made available for use, excluding any such energy 
used in the power production process (which process includes, but is not 
limited to, any on-site processing or treatment of fuel combusted at the 
unit and any on-site emission controls).
    Useful thermal energy means, with regard to a cogeneration unit, 
thermal energy that is:
    (1) Made available to an industrial or commercial process (not a 
power production process), excluding any heat contained in condensate 
return or makeup water;
    (2) Used in a heating application (e.g., space heating or domestic 
hot water heating); or
    (3) Used in a space cooling application (i.e., thermal energy used 
by an absorption chiller).
    Utility power distribution system means the portion of an 
electricity grid owned or operated by a utility and dedicated to 
delivering electricity to customers.

[70 FR 25362, May 12, 2005, as amended at 71 FR 25385, Apr. 28, 2006; 71 
FR 74794, Dec. 13, 2006; 72 FR 59206, Oct. 19, 2007]

    Editorial Notes: 1. At 71 FR 25386, Apr. 28, 2006, Sec. 96.202 was 
amended in the definition of ``CAIR NOX Ozone Season 
source'', by revising the words ``includes one or more CAIR 
NOX Ozone Season unit'' to read ``is subject to the CAIR 
NOX Ozone Season Trading Program''; however, those words do 
not exist in this section and the amendment could not be incorporated.

    2. At 71 FR 74794, Dec. 13, 2006, Sec. 96.202 was amended in the 
definition of ``CAIR SO2 allowance'' in paragraph (4), by 
revising the words ``(Program, provisions'' to read ``Program, 
provisions''; however, paragraph (4) does not exist in this section and 
the amendment could not be incorporated.



Sec. 96.203  Measurements, abbreviations, and acronyms.

    Measurements, abbreviations, and acronyms used in this subpart and 
subparts BBB through III are defined as follows:

Btu--British thermal unit
CO2--carbon dioxide
H2O--water
Hg--mercury
hr--hour
kW--kilowatt electrical
kWh--kilowatt hour
lb--pound
mmBtu--million Btu
MWe--megawatt electrical
MWh--megawatt hour
NOX--nitrogen oxides
O2--oxygen
ppm--parts per million
scfh--standard cubic feet per hour
SO2--sulfur dioxide
yr--year

[71 FR 25387, Apr. 28, 2006]



Sec. 96.204  Applicability.

    (a) Except as provided in paragraph (b) of this section:
    (1) The following units in a State shall be CAIR SO2 
units, and any source that includes one or more such units shall be a 
CAIR SO2 source, subject to the requirements of this subpart

[[Page 99]]

and subparts BBB through HHH of this part: any stationary, fossil-fuel-
fired boiler or stationary, fossil-fuel-fired combustion turbine serving 
at any time, since the later of November 15, 1990 or the start-up of the 
unit's combustion chamber, a generator with nameplate capacity of more 
than 25 MWe producing electricity for sale.
    (2) If a stationary boiler or stationary combustion turbine that, 
under paragraph (a)(1) of this section, is not a CAIR SO2 
unit begins to combust fossil fuel or to serve a generator with 
nameplate capacity of more than 25 MWe producing electricity for sale, 
the unit shall become a CAIR SO2 unit as provided in 
paragraph (a)(1) of this section on the first date on which it both 
combusts fossil fuel and serves such generator.
    (b) The units in a State that meet the requirements set forth in 
paragraph (b)(1)(i), (b)(2)(i), or (b)(2)(ii) of this section shall not 
be CAIR SO2 units:
    (1)(i) Any unit that is a CAIR SO2 unit under paragraph 
(a)(1) or (2) of this section:
    (A) Qualifying as a cogeneration unit during the 12-month period 
starting on the date the unit first produces electricity and continuing 
to qualify as a cogeneration unit; and
    (B) Not serving at any time, since the later of November 15, 1990 or 
the start-up of the unit's combustion chamber, a generator with 
nameplate capacity of more than 25 MWe supplying in any calendar year 
more than one-third of the unit's potential electric output capacity or 
219,000 MWh, whichever is greater, to any utility power distribution 
system for sale.
    (ii) If a unit qualifies as a cogeneration unit during the 12-month 
period starting on the date the unit first produces electricity and 
meets the requirements of paragraphs (b)(1)(i) of this section for at 
least one calendar year, but subsequently no longer meets all such 
requirements, the unit shall become a CAIR SO2 unit starting 
on the earlier of January 1 after the first calendar year during which 
the unit first no longer qualifies as a cogeneration unit or January 1 
after the first calendar year during which the unit no longer meets the 
requirements of paragraph (b)(1)(i)(B) of this section.
    (2)(i) Any unit that is a CAIR SO2 unit under paragraph 
(a)(1) or (2) of this section commencing operation before January 1, 
1985:
    (A) Qualifying as a solid waste incineration unit; and
    (B) With an average annual fuel consumption of non-fossil fuel for 
1985-1987 exceeding 80 percent (on a Btu basis) and an average annual 
fuel consumption of non-fossil fuel for any 3 consecutive calendar years 
after 1990 exceeding 80 percent (on a Btu basis).
    (ii) Any unit that is a CAIR SO2 unit under paragraph 
(a)(1) or (2) of this section commencing operation on or after January 
1, 1985:
    (A) Qualifying as a solid waste incineration unit; and
    (B) With an average annual fuel consumption of non-fossil fuel for 
the first 3 calendar years of operation exceeding 80 percent (on a Btu 
basis) and an average annual fuel consumption of non-fossil fuel for any 
3 consecutive calendar years after 1990 exceeding 80 percent (on a Btu 
basis).
    (iii) If a unit qualifies as a solid waste incineration unit and 
meets the requirements of paragraph (b)(2)(i) or (ii) of this section 
for at least 3 consecutive calendar years, but subsequently no longer 
meets all such requirements, the unit shall become a CAIR SO2 
unit starting on the earlier of January 1 after the first calendar year 
during which the unit first no longer qualifies as a solid waste 
incineration unit or January 1 after the first 3 consecutive calendar 
years after 1990 for which the unit has an average annual fuel 
consumption of fossil fuel of 20 percent or more.

[71 FR 25387, Apr. 28, 2006]



Sec. 96.205  Retired unit exemption.

    (a)(1) Any CAIR SO2 unit that is permanently retired and 
is not a CAIR SO2 opt-in unit under subpart III of this part 
shall be exempt from the CAIR SO2 Trading Program, except for 
the provisions of this section, Sec. 96.202, Sec. 96.203, Sec. 
96.204, Sec. 96.206(c)(4) through (7), Sec. 96.207, Sec. 96.208, and 
subparts BBB, FFF, and GGG of this part.

[[Page 100]]

    (2) The exemption under paragraph (a)(1) of this section shall 
become effective the day on which the CAIR SO2 unit is 
permanently retired. Within 30 days of the unit's permanent retirement, 
the CAIR designated representative shall submit a statement to the 
permitting authority otherwise responsible for administering any CAIR 
permit for the unit and shall submit a copy of the statement to the 
Administrator. The statement shall state, in a format prescribed by the 
permitting authority, that the unit was permanently retired on a 
specific date and will comply with the requirements of paragraph (b) of 
this section.
    (3) After receipt of the statement under paragraph (a)(2) of this 
section, the permitting authority will amend any permit under subpart 
CCC of this part covering the source at which the unit is located to add 
the provisions and requirements of the exemption under paragraphs (a)(1) 
and (b) of this section.
    (b) Special provisions. (1) A unit exempt under paragraph (a) of 
this section shall not emit any sulfur dioxide, starting on the date 
that the exemption takes effect.
    (2) For a period of 5 years from the date the records are created, 
the owners and operators of a unit exempt under paragraph (a) of this 
section shall retain, at the source that includes the unit, records 
demonstrating that the unit is permanently retired. The 5-year period 
for keeping records may be extended for cause, at any time before the 
end of the period, in writing by the permitting authority or the 
Administrator. The owners and operators bear the burden of proof that 
the unit is permanently retired.
    (3) The owners and operators and, to the extent applicable, the CAIR 
designated representative of a unit exempt under paragraph (a) of this 
section shall comply with the requirements of the CAIR SO2 
Trading Program concerning all periods for which the exemption is not in 
effect, even if such requirements arise, or must be complied with, after 
the exemption takes effect.
    (4) A unit exempt under paragraph (a) of this section and located at 
a source that is required, or but for this exemption would be required, 
to have a title V operating permit shall not resume operation unless the 
CAIR designated representative of the source submits a complete CAIR 
permit application under Sec. 96.222 for the unit not less than 18 
months (or such lesser time provided by the permitting authority) before 
the later of January 1, 2010 or the date on which the unit resumes 
operation.
    (5) On the earlier of the following dates, a unit exempt under 
paragraph (a) of this section shall lose its exemption:
    (i) The date on which the CAIR designated representative submits a 
CAIR permit application for the unit under paragraph (b)(4) of this 
section;
    (ii) The date on which the CAIR designated representative is 
required under paragraph (b)(4) of this section to submit a CAIR permit 
application for the unit; or
    (iii) The date on which the unit resumes operation, if the CAIR 
designated representative is not required to submit a CAIR permit 
application for the unit.
    (6) For the purpose of applying monitoring, reporting, and 
recordkeeping requirements under subpart HHH of this part, a unit that 
loses its exemption under paragraph (a) of this section shall be treated 
as a unit that commences commercial operation on the first date on which 
the unit resumes operation.

[70 FR 25362, May 12, 2005, as amended at 71 FR 25388, Apr. 28, 2006]



Sec. 96.206  Standard requirements.

    (a) Permit requirements. (1) The CAIR designated representative of 
each CAIR SO2 source required to have a title V operating 
permit and each CAIR SO2 unit required to have a title V 
operating permit at the source shall:
    (i) Submit to the permitting authority a complete CAIR permit 
application under Sec. 96.222 in accordance with the deadlines 
specified in Sec. 96.221; and
    (ii) Submit in a timely manner any supplemental information that the 
permitting authority determines is necessary in order to review a CAIR 
permit application and issue or deny a CAIR permit.
    (2) The owners and operators of each CAIR SO2 source 
required to have a

[[Page 101]]

title V operating permit and each CAIR SO2 unit required to 
have a title V operating permit at the source shall have a CAIR permit 
issued by the permitting authority under subpart CCC of this part for 
the source and operate the source and the unit in compliance with such 
CAIR permit.
    (3) Except as provided in subpart III of this part, the owners and 
operators of a CAIR SO2 source that is not otherwise required 
to have a title V operating permit and each CAIR SO2 unit 
that is not otherwise required to have a title V operating permit are 
not required to submit a CAIR permit application, and to have a CAIR 
permit, under subpart CCC of this part for such CAIR SO2 
source and such CAIR SO2 unit.
    (b) Monitoring, reporting, and recordkeeping requirements. (1) The 
owners and operators, and the CAIR designated representative, of each 
CAIR SO2 source and each CAIR SO2 unit at the 
source shall comply with the monitoring, reporting, and recordkeeping 
requirements of subpart HHH of this part.
    (2) The emissions measurements recorded and reported in accordance 
with subpart HHH of this part shall be used to determine compliance by 
each CAIR SO2 source with the CAIR SO2 emissions 
limitation under paragraph (c) of this section.
    (c) Sulfur dioxide emission requirements. (1) As of the allowance 
transfer deadline for a control period, the owners and operators of each 
CAIR SO2 source and each CAIR SO2 unit at the 
source shall hold, in the source's compliance account, a tonnage 
equivalent in CAIR SO2 allowances available for compliance 
deductions for the control period, as determined in accordance with 
Sec. 96.254(a) and (b), not less than the tons of total sulfur dioxide 
emissions for the control period from all CAIR SO2 units at 
the source, as determined in accordance with subpart HHH of this part.
    (2) A CAIR SO2 unit shall be subject to the requirements 
under paragraph (c)(1) of this section for the control period starting 
on the later of January 1, 2010 or the deadline for meeting the unit's 
monitor certification requirements under Sec. 96.270(b)(1), (2), or (5) 
and for each control period thereafter.
    (3) A CAIR SO2 allowance shall not be deducted, for 
compliance with the requirements under paragraph (c)(1) of this section, 
for a control period in a calendar year before the year for which the 
CAIR SO2 allowance was allocated.
    (4) CAIR SO2 allowances shall be held in, deducted from, 
or transferred into or among CAIR SO2 Allowance Tracking 
System accounts in accordance with subparts FFF, GGG, and III of this 
part.
    (5) A CAIR SO2 allowance is a limited authorization to 
emit sulfur dioxide in accordance with the CAIR SO2 Trading 
Program. No provision of the CAIR SO2 Trading Program, the 
CAIR permit application, the CAIR permit, or an exemption under Sec. 
96.205 and no provision of law shall be construed to limit the authority 
of the State or the United States to terminate or limit such 
authorization.
    (6) A CAIR SO2 allowance does not constitute a property 
right.
    (7) Upon recordation by the Administrator under subpart FFF, GGG, or 
III of this part, every allocation, transfer, or deduction of a CAIR 
SO2 allowance to or from a CAIR SO2 source's 
compliance account is incorporated automatically in any CAIR permit of 
the source.
    (d) Excess emissions requirements-- If a CAIR SO2 source 
emits sulfur dioxide during any control period in excess of the CAIR 
SO2 emissions limitation, then:
    (1) The owners and operators of the source and each CAIR 
SO2 unit at the source shall surrender the CAIR 
SO2 allowances required for deduction under Sec. 
96.254(d)(1) and pay any fine, penalty, or assessment or comply with any 
other remedy imposed, for the same violations, under the Clean Air Act 
or applicable State law; and
    (2) Each ton of such excess emissions and each day of such control 
period shall constitute a separate violation of this subpart, the Clean 
Air Act, and applicable State law.
    (e) Recordkeeping and reporting requirements. (1) Unless otherwise 
provided, the owners and operators of the CAIR SO2 source and 
each CAIR SO2 unit at the source shall keep on site at

[[Page 102]]

the source each of the following documents for a period of 5 years from 
the date the document is created. This period may be extended for cause, 
at any time before the end of 5 years, in writing by the permitting 
authority or the Administrator.
    (i) The certificate of representation under Sec. 96.213 for the 
CAIR designated representative for the source and each CAIR 
SO2 unit at the source and all documents that demonstrate the 
truth of the statements in the certificate of representation; provided 
that the certificate and documents shall be retained on site at the 
source beyond such 5-year period until such documents are superseded 
because of the submission of a new certificate of representation under 
Sec. 96.213 changing the CAIR designated representative.
    (ii) All emissions monitoring information, in accordance with 
subpart HHH of this part, provided that to the extent that subpart HHH 
of this part provides for a 3-year period for recordkeeping, the 3-year 
period shall apply.
    (iii) Copies of all reports, compliance certifications, and other 
submissions and all records made or required under the CAIR 
SO2 Trading Program.
    (iv) Copies of all documents used to complete a CAIR permit 
application and any other submission under the CAIR SO2 
Trading Program or to demonstrate compliance with the requirements of 
the CAIR SO2 Trading Program.
    (2) The CAIR designated representative of a CAIR SO2 
source and each CAIR SO2 unit at the source shall submit the 
reports required under the CAIR SO2 Trading Program, 
including those under subpart HHH of this part.
    (f) Liability. (1) Each CAIR SO2 source and each CAIR 
SO2 unit shall meet the requirements of the CAIR 
SO2 Trading Program.
    (2) Any provision of the CAIR SO2 Trading Program that 
applies to a CAIR SO2 source or the CAIR designated 
representative of a CAIR SO2 source shall also apply to the 
owners and operators of such source and of the CAIR SO2 units 
at the source.
    (3) Any provision of the CAIR SO2 Trading Program that 
applies to a CAIR SO2 unit or the CAIR designated 
representative of a CAIR SO2 unit shall also apply to the 
owners and operators of such unit.
    (g) Effect on other authorities. No provision of the CAIR 
SO2 Trading Program, a CAIR permit application, a CAIR 
permit, or an exemption under Sec. 96.205 shall be construed as 
exempting or excluding the owners and operators, and the CAIR designated 
representative, of a CAIR SO2 source or CAIR SO2 
unit from compliance with any other provision of the applicable, 
approved State implementation plan, a federally enforceable permit, or 
the Clean Air Act.

[70 FR 25362, May 12, 2005, as amended at 71 FR 25388, Apr. 28, 2006; 71 
FR 74794, Dec. 13, 2006]



Sec. 96.207  Computation of time.

    (a) Unless otherwise stated, any time period scheduled, under the 
CAIR SO2 Trading Program, to begin on the occurrence of an 
act or event shall begin on the day the act or event occurs.
    (b) Unless otherwise stated, any time period scheduled, under the 
CAIR SO2 Trading Program, to begin before the occurrence of 
an act or event shall be computed so that the period ends the day before 
the act or event occurs.
    (c) Unless otherwise stated, if the final day of any time period, 
under the CAIR SO2 Trading Program, falls on a weekend or a 
State or Federal holiday, the time period shall be extended to the next 
business day.



Sec. 96.208  Appeal procedures.

    The appeal procedures for decisions of the Administrator under the 
CAIR SO2 Trading Program are set forth in part 78 of this 
chapter.



     Subpart BBB_CAIR Designated Representative for CAIR SO2 Sources

    Source: 70 FR 25362, May 12, 2005, unless otherwise noted.



Sec. 96.210  Authorization and responsibilities of CAIR designated
representative.

    (a) Except as provided under Sec. 96.211, each CAIR SO2 
source, including all CAIR SO2 units at the source, shall 
have one and only one CAIR designated

[[Page 103]]

representative, with regard to all matters under the CAIR SO2 
Trading Program concerning the source or any CAIR SO2 unit at 
the source.
    (b) The CAIR designated representative of the CAIR SO2 
source shall be selected by an agreement binding on the owners and 
operators of the source and all CAIR SO2 units at the source 
and shall act in accordance with the certification statement in Sec. 
96.213(a)(4)(iv).
    (c) Upon receipt by the Administrator of a complete certificate of 
representation under Sec. 96.213, the CAIR designated representative of 
the source shall represent and, by his or her representations, actions, 
inactions, or submissions, legally bind each owner and operator of the 
CAIR SO2 source represented and each CAIR SO2 unit 
at the source in all matters pertaining to the CAIR SO2 
Trading Program, notwithstanding any agreement between the CAIR 
designated representative and such owners and operators. The owners and 
operators shall be bound by any decision or order issued to the CAIR 
designated representative by the permitting authority, the 
Administrator, or a court regarding the source or unit.
    (d) No CAIR permit will be issued, no emissions data reports will be 
accepted, and no CAIR SO2 Allowance Tracking System account 
will be established for a CAIR SO2 unit at a source, until 
the Administrator has received a complete certificate of representation 
under Sec. 96.213 for a CAIR designated representative of the source 
and the CAIR SO2 units at the source.
    (e)(1) Each submission under the CAIR SO2 Trading Program 
shall be submitted, signed, and certified by the CAIR designated 
representative for each CAIR SO2 source on behalf of which 
the submission is made. Each such submission shall include the following 
certification statement by the CAIR designated representative: ``I am 
authorized to make this submission on behalf of the owners and operators 
of the source or units for which the submission is made. I certify under 
penalty of law that I have personally examined, and am familiar with, 
the statements and information submitted in this document and all its 
attachments. Based on my inquiry of those individuals with primary 
responsibility for obtaining the information, I certify that the 
statements and information are to the best of my knowledge and belief 
true, accurate, and complete. I am aware that there are significant 
penalties for submitting false statements and information or omitting 
required statements and information, including the possibility of fine 
or imprisonment.''
    (2) The permitting authority and the Administrator will accept or 
act on a submission made on behalf of owner or operators of a CAIR 
SO2 source or a CAIR SO2 unit only if the 
submission has been made, signed, and certified in accordance with 
paragraph (e)(1) of this section.



Sec. 96.211  Alternate CAIR designated representative.

    (a) A certificate of representation under Sec. 96.213 may designate 
one and only one alternate CAIR designated representative, who may act 
on behalf of the CAIR designated representative. The agreement by which 
the alternate CAIR designated representative is selected shall include a 
procedure for authorizing the alternate CAIR designated representative 
to act in lieu of the CAIR designated representative.
    (b) Upon receipt by the Administrator of a complete certificate of 
representation under Sec. 96.213, any representation, action, inaction, 
or submission by the alternate CAIR designated representative shall be 
deemed to be a representation, action, inaction, or submission by the 
CAIR designated representative.
    (c) Except in this section and Sec. Sec. 96.202, 96.210(a) and (d), 
96.212, 96.213, 96.215, 96.251, and 96.282, whenever the term ``CAIR 
designated representative'' is used in subparts AAA through III of this 
part, the term shall be construed to include the CAIR designated 
representative or any alternate CAIR designated representative.

[70 FR 25362, May 12, 2005, as amended at 71 FR 25388, Apr. 28, 2006]

[[Page 104]]



Sec. 96.212  Changing CAIR designated representative and alternate
CAIR designated representative; changes in owners and operators.

    (a) Changing CAIR designated representative. The CAIR designated 
representative may be changed at any time upon receipt by the 
Administrator of a superseding complete certificate of representation 
under Sec. 96.213. Notwithstanding any such change, all 
representations, actions, inactions, and submissions by the previous 
CAIR designated representative before the time and date when the 
Administrator receives the superseding certificate of representation 
shall be binding on the new CAIR designated representative and the 
owners and operators of the CAIR SO2 source and the CAIR 
SO2 units at the source.
    (b) Changing alternate CAIR designated representative. The alternate 
CAIR designated representative may be changed at any time upon receipt 
by the Administrator of a superseding complete certificate of 
representation under Sec. 96.213. Notwithstanding any such change, all 
representations, actions, inactions, and submissions by the previous 
alternate CAIR designated representative before the time and date when 
the Administrator receives the superseding certificate of representation 
shall be binding on the new alternate CAIR designated representative and 
the owners and operators of the CAIR SO2 source and the CAIR 
SO2 units at the source.
    (c) Changes in owners and operators. (1) In the event an owner or 
operator of a CAIR SO2 source or a CAIR SO2 unit 
is not included in the list of owners and operators in the certificate 
of representation under Sec. 96.213, such owner or operator shall be 
deemed to be subject to and bound by the certificate of representation, 
the representations, actions, inactions, and submissions of the CAIR 
designated representative and any alternate CAIR designated 
representative of the source or unit, and the decisions and orders of 
the permitting authority, the Administrator, or a court, as if the owner 
or operator were included in such list.
    (2) Within 30 days following any change in the owners and operators 
of a CAIR SO2 source or a CAIR SO2 unit, including 
the addition of a new owner or operator, the CAIR designated 
representative or any alternate CAIR designated representative shall 
submit a revision to the certificate of representation under Sec. 
96.213 amending the list of owners and operators to include the change.

[70 FR 25362, May 12, 2005, as amended at 71 FR 25388, Apr. 28, 2006]



Sec. 96.213  Certificate of representation.

    (a) A complete certificate of representation for a CAIR designated 
representative or an alternate CAIR designated representative shall 
include the following elements in a format prescribed by the 
Administrator:
    (1) Identification of the CAIR SO2 source, and each CAIR 
SO2 unit at the source, for which the certificate of 
representation is submitted, including identification and nameplate 
capacity of each generator served by each such unit.
    (2) The name, address, e-mail address (if any), telephone number, 
and facsimile transmission number (if any) of the CAIR designated 
representative and any alternate CAIR designated representative.
    (3) A list of the owners and operators of the CAIR SO2 
source and of each CAIR SO2 unit at the source.
    (4) The following certification statements by the CAIR designated 
representative and any alternate CAIR designated representative--
    (i) ``I certify that I was selected as the CAIR designated 
representative or alternate CAIR designated representative, as 
applicable, by an agreement binding on the owners and operators of the 
source and each CAIR SO2 unit at the source.''
    (ii) ``I certify that I have all the necessary authority to carry 
out my duties and responsibilities under the CAIR SO2 Trading 
Program on behalf of the owners and operators of the source and of each 
CAIR SO2 unit at the source and that each such owner and 
operator shall be fully bound by my representations, actions, inactions, 
or submissions.''
    (iii) ``I certify that the owners and operators of the source and of 
each CAIR SO2 unit at the source shall be bound by any order 
issued to me by the

[[Page 105]]

Administrator, the permitting authority, or a court regarding the source 
or unit.''
    (iv) ``Where there are multiple holders of a legal or equitable 
title to, or a leasehold interest in, a CAIR SO2 unit, or 
where a utility or industrial customer purchases power from a CAIR 
SO2 unit under a life-of-the-unit, firm power contractual 
arrangement, I certify that: I have given a written notice of my 
selection as the `CAIR designated representative' or `alternate CAIR 
designated representative', as applicable, and of the agreement by which 
I was selected to each owner and operator of the source and of each CAIR 
SO2 unit at the source; and CAIR SO2 allowances 
and proceeds of transactions involving CAIR SO2 allowances 
will be deemed to be held or distributed in proportion to each holder's 
legal, equitable, leasehold, or contractual reservation or entitlement, 
except that, if such multiple holders have expressly provided for a 
different distribution of CAIR SO2 allowances by contract, 
CAIR SO2 allowances and proceeds of transactions involving 
CAIR SO2 allowances will be deemed to be held or distributed 
in accordance with the contract.''
    (5) The signature of the CAIR designated representative and any 
alternate CAIR designated representative and the dates signed.
    (b) Unless otherwise required by the permitting authority or the 
Administrator, documents of agreement referred to in the certificate of 
representation shall not be submitted to the permitting authority or the 
Administrator. Neither the permitting authority nor the Administrator 
shall be under any obligation to review or evaluate the sufficiency of 
such documents, if submitted.

[70 FR 25362, May 12, 2005, as amended at 71 FR 25388, Apr. 28, 2006]



Sec. 96.214  Objections concerning CAIR designated representative.

    (a) Once a complete certificate of representation under Sec. 96.213 
has been submitted and received, the permitting authority and the 
Administrator will rely on the certificate of representation unless and 
until a superseding complete certificate of representation under Sec. 
96.213 is received by the Administrator.
    (b) Except as provided in Sec. 96.212(a) or (b), no objection or 
other communication submitted to the permitting authority or the 
Administrator concerning the authorization, or any representation, 
action, inaction, or submission, of the CAIR designated representative 
shall affect any representation, action, inaction, or submission of the 
CAIR designated representative or the finality of any decision or order 
by the permitting authority or the Administrator under the CAIR 
SO2 Trading Program.
    (c) Neither the permitting authority nor the Administrator will 
adjudicate any private legal dispute concerning the authorization or any 
representation, action, inaction, or submission of any CAIR designated 
representative, including private legal disputes concerning the proceeds 
of CAIR SO2 allowance transfers.



Sec. 96.215  Delegation by CAIR designated representative and 
alternate CAIR designated representative.

    (a) A CAIR designated representative may delegate, to one or more 
natural persons, his or her authority to make an electronic submission 
to the Administrator provided for or required under this part.
    (b) An alternate CAIR designated representative may delegate, to one 
or more natural persons, his or her authority to make an electronic 
submission to the Administrator provided for or required under this 
part.
    (c) In order to delegate authority to make an electronic submission 
to the Administrator in accordance with paragraph (a) or (b) of this 
section, the CAIR designated representative or alternate CAIR designated 
representative, as appropriate, must submit to the Administrator a 
notice of delegation, in a format prescribed by the Administrator, that 
includes the following elements:
    (1) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of such CAIR designated 
representative or alternate CAIR designated representative;

[[Page 106]]

    (2) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of each such natural person 
``referred to as an ``agent'');
    (3) For each such natural person, a list of the type or types of 
electronic submissions under paragraph (a) or (b) of this section for 
which authority is delegated to him or her; and
    (4) The following certification statements by such CAIR designated 
representative or alternate CAIR designated representative:
    (i) ``I agree that any electronic submission to the Administrator 
that is by an agent identified in this notice of delegation and of a 
type listed for such agent in this notice of delegation and that is made 
when I am a CAIR designated representative or alternate CAIR designated 
representative, as appropriate, and before this notice of delegation is 
superseded by another notice of delegation under 40 CFR 96.215(d) shall 
be deemed to be an electronic submission by me.''
    (ii) ``Until this notice of delegation is superseded by another 
notice of delegation under 40 CFR 96.215(d), I agree to maintain an e-
mail account and to notify the Administrator immediately of any change 
in my e-mail address unless all delegation of authority by me under 40 
CFR 96.215 is terminated.''.
    (d) A notice of delegation submitted under paragraph (c) of this 
section shall be effective, with regard to the CAIR designated 
representative or alternate CAIR designated representative identified in 
such notice, upon receipt of such notice by the Administrator and until 
receipt by the Administrator of a superseding notice of delegation 
submitted by such CAIR designated representative or alternate CAIR 
designated representative, as appropriate. The superseding notice of 
delegation may replace any previously identified agent, add a new agent, 
or eliminate entirely any delegation of authority.
    (e) Any electronic submission covered by the certification in 
paragraph (c)(4)(i) of this section and made in accordance with a notice 
of delegation effective under paragraph (d) of this section shall be 
deemed to be an electronic submission by the CAIR designated 
representative or alternate CAIR designated representative submitting 
such notice of delegation.

[71 FR 25388, Apr. 28, 2006, as amended at 71 FR 74794, Dec. 13, 2006]



                           Subpart CCC_Permits

    Source: 70 FR 25362, May 12, 2005, unless otherwise noted.



Sec. 96.220  General CAIR SO [bdi2] Trading Program permit 
requirements.

    (a) For each CAIR SO2 source required to have a title V 
operating permit or required, under subpart III of this part, to have a 
title V operating permit or other federally enforceable permit, such 
permit shall include a CAIR permit administered by the permitting 
authority for the title V operating permit or the federally enforceable 
permit as applicable. The CAIR portion of the title V permit or other 
federally enforceable permit as applicable shall be administered in 
accordance with the permitting authority's title V operating permits 
regulations promulgated under part 70 or 71 of this chapter or the 
permitting authority's regulations for other federally enforceable 
permits as applicable, except as provided otherwise by Sec. 96.205, 
this subpart, and subpart III of this part.
    (b) Each CAIR permit shall contain, with regard to the CAIR 
SO2 source and the CAIR SO2 units at the source 
covered by the CAIR permit, all applicable CAIR SO2 Trading 
Program, CAIR NOX Annual Trading Program, and CAIR 
NOX Ozone Season Trading Program requirements and shall be a 
complete and separable portion of the title V operating permit or other 
federally enforceable permit under paragraph (a) of this section.

[70 FR 25362, May 12, 2005, as amended at 71 FR 25388, Apr. 28, 2006]



Sec. 96.221  Submission of CAIR permit applications.

    (a) Duty to apply. The CAIR designated representative of any CAIR 
SO2 source required to have a title V operating permit shall 
submit to the permitting authority a complete CAIR permit application 
under Sec. 96.222 for the source covering each CAIR SO2 unit 
at

[[Page 107]]

the source at least 18 months (or such lesser time provided by the 
permitting authority) before the later of January 1, 2010 or the date on 
which the CAIR SO2 unit commences commercial operation, 
except as provided in Sec. 96.283(a).
    (b) Duty to Reapply. For a CAIR SO2 source required to 
have a title V operating permit, the CAIR designated representative 
shall submit a complete CAIR permit application under Sec. 96.222 for 
the source covering each CAIR SO2 unit at the source to renew 
the CAIR permit in accordance with the permitting authority's title V 
operating permits regulations addressing permit renewal, except as 
provided in Sec. 96.283(b).

[70 FR 25362, May 12, 2005, as amended at 71 FR 25388, Apr. 28, 2006]



Sec. 96.222  Information requirements for CAIR permit applications.

    A complete CAIR permit application shall include the following 
elements concerning the CAIR SO2 source for which the 
application is submitted, in a format prescribed by the permitting 
authority:
    (a) Identification of the CAIR SO2 source;
    (b) Identification of each CAIR SO2 unit at the CAIR 
SO2 source; and
    (c) The standard requirements under Sec. 96.206.



Sec. 96.223  CAIR permit contents and term.

    (a) Each CAIR permit will contain, in a format prescribed by the 
permitting authority, all elements required for a complete CAIR permit 
application under Sec. 96.222.
    (b) Each CAIR permit is deemed to incorporate automatically the 
definitions of terms under Sec. 96.202 and, upon recordation by the 
Administrator under subpart FFF, GGG, or III of this part, every 
allocation, transfer, or deduction of a CAIR SO2 allowance to 
or from the compliance account of the CAIR SO2 source covered 
by the permit.
    (c) The term of the CAIR permit will be set by the permitting 
authority, as necessary to facilitate coordination of the renewal of the 
CAIR permit with issuance, revision, or renewal of the CAIR 
SO2 source's title V operating permit or other federally 
enforceable permit as applicable.



Sec. 96.224  CAIR permit revisions.

    Except as provided in Sec. 96.223(b), the permitting authority will 
revise the CAIR permit, as necessary, in accordance with the permitting 
authority's title V operating permits regulations or the permitting 
authority's regulations for other federally enforceable permits as 
applicable addressing permit revisions.

Subparts DDD-EEE [Reserved]



             Subpart FFF_CAIR SO2 Allowance Tracking System

    Source: 70 FR 25362, May 12, 2005, unless otherwise noted.



Sec. 96.250  [Reserved]



Sec. 96.251  Establishment of accounts.

    (a) Compliance accounts. Except as provided in Sec. 96.284(e), upon 
receipt of a complete certificate of representation under Sec. 96.213, 
the Administrator will establish a compliance account for the CAIR 
SO2 source for which the certificate of representation was 
submitted, unless the source already has a compliance account.
    (b) General accounts--(1) Application for general account. (i) Any 
person may apply to open a general account for the purpose of holding 
and transferring CAIR SO2 allowances. An application for a 
general account may designate one and only one CAIR authorized account 
representative and one and only one alternate CAIR authorized account 
representative who may act on behalf of the CAIR authorized account 
representative. The agreement by which the alternate CAIR authorized 
account representative is selected shall include a procedure for 
authorizing the alternate CAIR authorized account representative to act 
in lieu of the CAIR authorized account representative.
    (ii) A complete application for a general account shall be submitted 
to the Administrator and shall include the following elements in a 
format prescribed by the Administrator:
    (A) Name, mailing address, e-mail address (if any), telephone 
number, and

[[Page 108]]

facsimile transmission number (if any) of the CAIR authorized account 
representative and any alternate CAIR authorized account representative;
    (B) Organization name and type of organization, if applicable;
    (C) A list of all persons subject to a binding agreement for the 
CAIR authorized account representative and any alternate CAIR authorized 
account representative to represent their ownership interest with 
respect to the CAIR SO2 allowances held in the general 
account;
    (D) The following certification statement by the CAIR authorized 
account representative and any alternate CAIR authorized account 
representative: ``I certify that I was selected as the CAIR authorized 
account representative or the alternate CAIR authorized account 
representative, as applicable, by an agreement that is binding on all 
persons who have an ownership interest with respect to CAIR 
SO2 allowances held in the general account. I certify that I 
have all the necessary authority to carry out my duties and 
responsibilities under the CAIR SO2 Trading Program on behalf 
of such persons and that each such person shall be fully bound by my 
representations, actions, inactions, or submissions and by any order or 
decision issued to me by the Administrator or a court regarding the 
general account.''
    (E) The signature of the CAIR authorized account representative and 
any alternate CAIR authorized account representative and the dates 
signed.
    (iii) Unless otherwise required by the permitting authority or the 
Administrator, documents of agreement referred to in the application for 
a general account shall not be submitted to the permitting authority or 
the Administrator. Neither the permitting authority nor the 
Administrator shall be under any obligation to review or evaluate the 
sufficiency of such documents, if submitted.
    (2) Authorization of CAIR authorized account representative and 
alternate CAIR authorized account representative. (i) Upon receipt by 
the Administrator of a complete application for a general account under 
paragraph (b)(1) of this section:
    (A) The Administrator will establish a general account for the 
person or persons for whom the application is submitted.
    (B) The CAIR authorized account representative and any alternate 
CAIR authorized account representative for the general account shall 
represent and, by his or her representations, actions, inactions, or 
submissions, legally bind each person who has an ownership interest with 
respect to CAIR SO2 allowances held in the general account in 
all matters pertaining to the CAIR SO2 Trading Program, 
notwithstanding any agreement between the CAIR authorized account 
representative or any alternate CAIR authorized account representative 
and such person. Any such person shall be bound by any order or decision 
issued to the CAIR authorized account representative or any alternate 
CAIR authorized account representative by the Administrator or a court 
regarding the general account.
    (C) Any representation, action, inaction, or submission by any 
alternate CAIR authorized account representative shall be deemed to be a 
representation, action, inaction, or submission by the CAIR authorized 
account representative.
    (ii) Each submission concerning the general account shall be 
submitted, signed, and certified by the CAIR authorized account 
representative or any alternate CAIR authorized account representative 
for the persons having an ownership interest with respect to CAIR 
SO2 allowances held in the general account. Each such 
submission shall include the following certification statement by the 
CAIR authorized account representative or any alternate CAIR authorized 
account representative: ``I am authorized to make this submission on 
behalf of the persons having an ownership interest with respect to the 
CAIR SO2 allowances held in the general account. I certify 
under penalty of law that I have personally examined, and am familiar 
with, the statements and information submitted in this document and all 
its attachments. Based on my inquiry of those individuals with primary 
responsibility for obtaining the information, I

[[Page 109]]

certify that the statements and information are to the best of my 
knowledge and belief true, accurate, and complete. I am aware that there 
are significant penalties for submitting false statements and 
information or omitting required statements and information, including 
the possibility of fine or imprisonment.''
    (iii) The Administrator will accept or act on a submission 
concerning the general account only if the submission has been made, 
signed, and certified in accordance with paragraph (b)(2)(ii) of this 
section.
    (3) Changing CAIR authorized account representative and alternate 
CAIR authorized account representative; changes in persons with 
ownership interest. (i) The CAIR authorized account representative for a 
general account may be changed at any time upon receipt by the 
Administrator of a superseding complete application for a general 
account under paragraph (b)(1) of this section. Notwithstanding any such 
change, all representations, actions, inactions, and submissions by the 
previous CAIR authorized account representative before the time and date 
when the Administrator receives the superseding application for a 
general account shall be binding on the new CAIR authorized account 
representative and the persons with an ownership interest with respect 
to the CAIR SO2 allowances in the general account.
    (ii) The alternate CAIR authorized account representative for a 
general account may be changed at any time upon receipt by the 
Administrator of a superseding complete application for a general 
account under paragraph (b)(1) of this section. Notwithstanding any such 
change, all representations, actions, inactions, and submissions by the 
previous alternate CAIR authorized account representative before the 
time and date when the Administrator receives the superseding 
application for a general account shall be binding on the new alternate 
CAIR authorized account representative and the persons with an ownership 
interest with respect to the CAIR SO2 allowances in the 
general account.
    (iii)(A) In the event a person having an ownership interest with 
respect to CAIR SO2 allowances in the general account is not 
included in the list of such persons in the application for a general 
account, such person shall be deemed to be subject to and bound by the 
application for a general account, the representation, actions, 
inactions, and submissions of the CAIR authorized account representative 
and any alternate CAIR authorized account representative of the account, 
and the decisions and orders of the Administrator or a court, as if the 
person were included in such list.
    (B) Within 30 days following any change in the persons having an 
ownership interest with respect to CAIR SO2 allowances in the 
general account, including the addition of a new person, the CAIR 
authorized account representative or any alternate CAIR authorized 
account representative shall submit a revision to the application for a 
general account amending the list of persons having an ownership 
interest with respect to the CAIR SO2 allowances in the 
general account to include the change.
    (4) Objections concerning CAIR authorized account representative and 
alternate CAIR authorized account representative. (i) Once a complete 
application for a general account under paragraph (b)(1) of this section 
has been submitted and received, the Administrator will rely on the 
application unless and until a superseding complete application for a 
general account under paragraph (b)(1) of this section is received by 
the Administrator.
    (ii) Except as provided in paragraph (b)(3)(i) or (ii) of this 
section, no objection or other communication submitted to the 
Administrator concerning the authorization, or any representation, 
action, inaction, or submission of the CAIR authorized account 
representative or any alternate CAIR authorized account representative 
for a general account shall affect any representation, action, inaction, 
or submission of the CAIR authorized account representative or any 
alternate CAIR authorized account representative or the finality of any 
decision or order by the Administrator under the CAIR SO2 
Trading Program.

[[Page 110]]

    (iii) The Administrator will not adjudicate any private legal 
dispute concerning the authorization or any representation, action, 
inaction, or submission of the CAIR authorized account representative or 
any alternate CAIR authorized account representative for a general 
account, including private legal disputes concerning the proceeds of 
CAIR SO2 allowance transfers.
    (5) Delegation by CAIR authorized account representative and 
alternate CAIR authorized account representative. (i) A CAIR authorized 
account representative may delegate, to one or more natural persons, his 
or her authority to make an electronic submission to the Administrator 
provided for or required under subparts FFF and GGG of this part.
    (ii) An alternate CAIR authorized account representative may 
delegate, to one or more natural persons, his or her authority to make 
an electronic submission to the Administrator provided for or required 
under subparts FFF and GGG of this part.
    (iii) In order to delegate authority to make an electronic 
submission to the Administrator in accordance with paragraph (b)(5)(i) 
or (ii) of this section, the CAIR authorized account representative or 
alternate CAIR authorized account representative, as appropriate, must 
submit to the Administrator a notice of delegation, in a format 
prescribed by the Administrator, that includes the following elements:
    (A) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of such CAIR authorized account 
representative or alternate CAIR authorized account representative;
    (B) The name, address, e-mail address, telephone number, and, 
facsimile transmission number (if any) of each such natural person 
(referred to as an ``agent'');
    (C) For each such natural person, a list of the type or types of 
electronic submissions under paragraph (b)(5)(i) or (ii) of this section 
for which authority is delegated to him or her;
    (D) The following certification statement by such CAIR authorized 
account representative or alternate CAIR authorized account 
representative: ``I agree that any electronic submission to the 
Administrator that is by an agent identified in this notice of 
delegation and of a type listed for such agent in this notice of 
delegation and that is made when I am a CAIR authorized account 
representative or alternate CAIR authorized representative, as 
appropriate, and before this notice of delegation is superseded by 
another notice of delegation under 40 CFR 96.251(b)(5)(iv) shall be 
deemed to be an electronic submission by me.''; and
    (E) The following certification statement by such CAIR authorized 
account representative or alternate CAIR authorized account 
representative: ``Until this notice of delegation is superseded by 
another notice of delegation under 40 CFR 96.251 (b)(5)(iv), I agree to 
maintain an e-mail account and to notify the Administrator immediately 
of any change in my e-mail address unless all delegation of authority by 
me under 40 CFR 96.251 (b)(5) is terminated.''
    (iv) A notice of delegation submitted under paragraph (b)(5)(iii) of 
this section shall be effective, with regard to the CAIR authorized 
account representative or alternate CAIR authorized account 
representative identified in such notice, upon receipt of such notice by 
the Administrator and until receipt by the Administrator of a 
superseding notice of delegation submitted by such CAIR authorized 
account representative or alternate CAIR authorized account 
representative, as appropriate. The superseding notice of delegation may 
replace any previously identified agent, add a new agent, or eliminate 
entirely any delegation of authority.
    (v) Any electronic submission covered by the certification in 
paragraph (b)(5)(iii)(D) of this section and made in accordance with a 
notice of delegation effective under paragraph (b)(5)(iv) of this 
section shall be deemed to be an electronic submission by the CAIR 
designated representative or alternate CAIR designated representative 
submitting such notice of delegation.

[[Page 111]]

    (c) Account identification. The Administrator will assign a unique 
identifying number to each account established under paragraph (a) or 
(b) of this section.

[70 FR 25362, May 12, 2005, as amended at 71 FR 25388, Apr. 28, 2006; 71 
FR 74794, Dec. 13, 2006]



Sec. 96.252  Responsibilities of CAIR authorized account representative.

    Following the establishment of a CAIR SO2 Allowance 
Tracking System account, all submissions to the Administrator pertaining 
to the account, including, but not limited to, submissions concerning 
the deduction or transfer of CAIR SO2 allowances in the 
account, shall be made only by the CAIR authorized account 
representative for the account.



Sec. 96.253  Recordation of CAIR SO [bdi2] allowances.

    (a)(1) After a compliance account is established under Sec. 
96.251(a) or Sec. 73.31(a) or (b) of this chapter, the Administrator 
will record in the compliance account any CAIR SO2 allowance 
allocated to any CAIR SO2 unit at the source for each of the 
30 years starting the later of 2010 or the year in which the compliance 
account is established and any CAIR SO2 allowance allocated 
for each of the 30 years starting the later of 2010 or the year in which 
the compliance account is established and transferred to the source in 
accordance with subpart GGG of this part or subpart D of part 73 of this 
chapter.
    (2) In 2011 and each year thereafter, after Administrator has 
completed all deductions under Sec. 96.254(b), the Administrator will 
record in the compliance account any CAIR SO2 allowance 
allocated to any CAIR SO2 unit at the source for the new 30th 
year (i.e., the year that is 30 years after the calendar year for which 
such deductions are or could be made) and any CAIR SO2 
allowance allocated for the new 30th year and transferred to the source 
in accordance with subpart GGG of this part or subpart D of part 73 of 
this chapter.
    (b)(1) After a general account is established under Sec. 96.251(b) 
or Sec. 73.31(c) of this chapter, the Administrator will record in the 
general account any CAIR SO2 allowance allocated for each of 
the 30 years starting the later of 2010 or the year in which the general 
account is established and transferred to the general account in 
accordance with subpart GGG of this part or subpart D of part 73 of this 
chapter.
    (2) In 2011 and each year thereafter, after Administrator has 
completed all deductions under Sec. 96.254(b), the Administrator will 
record in the general account any CAIR SO2 allowance 
allocated for the new 30th year (i.e., the year that is 30 years after 
the calendar year for which such deductions are or could be made) and 
transferred to the general account in accordance with subpart GGG of 
this part or subpart D of part 73 of this chapter.
    (c) Serial numbers for allocated CAIR SO2 allowances. 
When recording the allocation of CAIR SO2 allowances issued 
by a permitting authority under Sec. 96.288, the Administrator will 
assign each such CAIR SO2 allowance a unique identification 
number that will include digits identifying the year of the control 
period for which the CAIR SO2 allowance is allocated.



Sec. 96.254  Compliance with CAIR SO [bdi2] emissions limitation.

    (a) Allowance transfer deadline. The CAIR SO2 allowances 
are available to be deducted for compliance with a source's CAIR 
SO2 emissions limitation for a control period in a given 
calendar year only if the CAIR SO2 allowances:
    (1) Were allocated for the control period in the year or a prior 
year; and
    (2) Are held in the compliance account as of the allowance transfer 
deadline for the control period or are transferred into the compliance 
account by a CAIR SO2 allowance transfer correctly submitted 
for recordation under Sec. Sec. 96.260 and 96.261 by the allowance 
transfer deadline for the control period.
    (b) Deductions for compliance. Following the recordation, in 
accordance with Sec. 96.261, of CAIR SO2 allowance transfers 
submitted for recordation in a source's compliance account by the 
allowance transfer deadline for a control period, the Administrator will 
deduct from the compliance account CAIR SO2 allowances 
available under paragraph (a) of this section in order to determine 
whether the source meets

[[Page 112]]

the CAIR SO2 emissions limitation for the control period as 
follows:
    (1) For a CAIR SO2 source subject to an Acid Rain 
emissions limitation, the Administrator will, in the following order:
    (i) Deduct the amount of CAIR SO2 allowances, available 
under paragraph (a) of this section and not issued by a permitting 
authority under Sec. 96.288, that is required under Sec. Sec. 73.35(b) 
and (c) of this part. If there are sufficient CAIR SO2 
allowances to complete this deduction, the deduction will be treated as 
satisfying the requirements of Sec. Sec. 73.35(b) and (c) of this 
chapter.
    (ii) Deduct the amount of CAIR SO2 allowances, not issued 
by a permitting authority under Sec. 96.288, that is required under 
Sec. Sec. 73.35(d) and 77.5 of this part. If there are sufficient CAIR 
SO2 allowances to complete this deduction, the deduction will 
be treated as satisfying the requirements of Sec. Sec. 73.35(d) and 
77.5 of this chapter.
    (iii) Treating the CAIR SO2 allowances deducted under 
paragraph (b)(1)(i) of this section as also being deducted under this 
paragraph (b)(1)(iii), deduct CAIR SO2 allowances available 
under paragraph (a) of this section (including any issued by a 
permitting authority under Sec. 96.288) in order to determine whether 
the source meets the CAIR SO2 emissions limitation for the 
control period, as follows:
    (A) Until the tonnage equivalent of the CAIR SO2 
allowances deducted equals, or exceeds in accordance with paragraphs 
(c)(1) and (2) of this section, the number of tons of total sulfur 
dioxide emissions, determined in accordance with subpart HHH of this 
part, from all CAIR SO2 units at the source for the control 
period; or
    (B) If there are insufficient CAIR SO2 allowances to 
complete the deductions in paragraph (b)(1)(iii)(A) of this section, 
until no more CAIR SO2 allowances available under paragraph 
(a) of this section (including any issued by a permitting authority 
under Sec. 96.288) remain in the compliance account.
    (2) For a CAIR SO2 source not subject to an Acid Rain 
emissions limitation, the Administrator will deduct CAIR SO2 
allowances available under paragraph (a) of this section (including any 
issued by a permitting authority under Sec. 96.288) in order to 
determine whether the source meets the CAIR SO2 emissions 
limitation for the control period, as follows:
    (i) Until the tonnage equivalent of the CAIR SO2 
allowances deducted equals, or exceeds in accordance with paragraphs 
(c)(1) and (2) of this section, the number of tons of total sulfur 
dioxide emissions, determined in accordance with subpart HHH of this 
part, from all CAIR SO2 units at the source for the control 
period; or
    (ii) If there are insufficient CAIR SO2 allowances to 
complete the deductions in paragraph (b)(2)(i) of this section, until no 
more CAIR SO2 allowances available under paragraph (a) of 
this section (including any issued by a permitting authority under Sec. 
96.288) remain in the compliance account.
    (c)(1) Identification of CAIR SO2 allowances by serial 
number. The CAIR authorized account representative for a source's 
compliance account may request that specific CAIR SO2 
allowances, identified by serial number, in the compliance account be 
deducted for emissions or excess emissions for a control period in 
accordance with paragraph (b) or (d) of this section. Such request shall 
be submitted to the Administrator by the allowance transfer deadline for 
the control period and include, in a format prescribed by the 
Administrator, the identification of the CAIR SO2 source and 
the appropriate serial numbers.
    (2) First-in, first-out. The Administrator will deduct CAIR 
SO2 allowances under paragraph (b) or (d) of this section 
from the source's compliance account, in the absence of an 
identification or in the case of a partial identification of CAIR 
SO2 allowances by serial number under paragraph (c)(1) of 
this section, on a first-in, first-out (FIFO) accounting basis in the 
following order:
    (i) Any CAIR SO2 allowances that were allocated to the 
units at the source for a control period before 2010, in the order of 
recordation;
    (ii) Any CAIR SO2 allowances that were allocated to any 
entity for a control period before 2010 and transferred and recorded in 
the compliance account pursuant to subpart GGG of this

[[Page 113]]

part or subpart D of part 73 of this chapter, in the order of 
recordation;
    (iii) Any CAIR SO2 allowances that were allocated to the 
units at the source for a control period during 2010 through 2014, in 
the order of recordation;
    (iv) Any CAIR SO2 allowances that were allocated to any 
entity for a control period during 2010 through 2014 and transferred and 
recorded in the compliance account pursuant to subpart GGG of this part 
or subpart D of part 73 of this chapter, in the order of recordation;
    (v) Any CAIR SO2 allowances that were allocated to the 
units at the source for a control period in 2015 or later, in the order 
of recordation; and
    (vi) Any CAIR SO2 allowances that were allocated to any 
entity for a control period in 2015 or later and transferred and 
recorded in the compliance account pursuant to subpart GGG of this part 
or subpart D of part 73 of this chapter, in the order of recordation.
    (d) Deductions for excess emissions. (1) After making the deductions 
for compliance under paragraph (b) of this section for a control period 
in a calendar year in which the CAIR SO2 source has excess 
emissions, the Administrator will deduct from the source's compliance 
account the tonnage equivalent in CAIR SO2 allowances, 
allocated for the control period in the immediately following calendar 
year (including any issued by a permitting authority under Sec. 
96.288), equal to, or exceeding in accordance with paragraphs (c)(1) and 
(2) of this section, 3 times the following amount: the number of tons of 
the source's excess emissions minus, if the source is subject to an Acid 
Rain emissions limitation, the amount of the CAIR SO2 
allowances required to be deducted under paragraph (b)(1)(ii) of this 
section.
    (2) Any allowance deduction required under paragraph (d)(1) of this 
section shall not affect the liability of the owners and operators of 
the CAIR SO2 source or the CAIR SO2 units at the 
source for any fine, penalty, or assessment, or their obligation to 
comply with any other remedy, for the same violations, as ordered under 
the Clean Air Act or applicable State law.
    (e) Recordation of deductions. The Administrator will record in the 
appropriate compliance account all deductions from such an account under 
paragraphs (b) and (d) of this section and subpart III.
    (f) Administrator's action on submissions. (1) The Administrator may 
review and conduct independent audits concerning any submission under 
the CAIR SO2 Trading Program and make appropriate adjustments 
of the information in the submissions.
    (2) The Administrator may deduct CAIR SO2 allowances from 
or transfer CAIR SO2 allowances to a source's compliance 
account based on the information in the submissions, as adjusted under 
paragraph (f)(1) of this section, and record such deductions and 
transfers.

[70 FR 25362, May 12, 2005, as amended at 71 FR 25389, Apr. 28, 2006; 71 
FR 74794, Dec. 13, 2006]



Sec. 96.255  Banking.

    (a) CAIR SO2 allowances may be banked for future use or 
transfer in a compliance account or a general account in accordance with 
paragraph (b) of this section.
    (b) Any CAIR SO2 allowance that is held in a compliance 
account or a general account will remain in such account unless and 
until the CAIR SO2 allowance is deducted or transferred under 
Sec. 96.254, Sec. 96.256, or subpart GGG or III of this part.

[70 FR 25362, May 12, 2005, as amended at 71 FR 25389, Apr. 28, 2006]



Sec. 96.256  Account error.

    The Administrator may, at his or her sole discretion and on his or 
her own motion, correct any error in any CAIR SO2 Allowance 
Tracking System account. Within 10 business days of making such 
correction, the Administrator will notify the CAIR authorized account 
representative for the account.



Sec. 96.257  Closing of general accounts.

    (a) The CAIR authorized account representative of a general account 
may submit to the Administrator a request to close the account, which 
shall include a correctly submitted allowance transfer under Sec. Sec. 
96.260 and 96.261 for

[[Page 114]]

any CAIR SO2 allowances in the account to one or more other 
CAIR SO2 Allowance Tracking System accounts.
    (b) If a general account has no allowance transfers in or out of the 
account for a 12-month period or longer and does not contain any CAIR 
SO2 allowances, the Administrator may notify the CAIR 
authorized account representative for the account that the account will 
be closed following 20 business days after the notice is sent. The 
account will be closed after the 20-day period unless, before the end of 
the 20-day period, the Administrator receives a correctly submitted 
transfer of CAIR SO2 allowances into the account under 
Sec. Sec. 96.260 and 96.261 or a statement submitted by the CAIR 
authorized account representative demonstrating to the satisfaction of 
the Administrator good cause as to why the account should not be closed.

[70 FR 25362, May 12, 2005, as amended at 71 FR 25389, Apr. 28, 2006]



                Subpart GGG_CAIR SO2 Allowance Transfers

    Source: 70 FR 25362, May 12, 2005, unless otherwise noted.



Sec. 96.260  Submission of CAIR SO [bdi2] allowance transfers.

    (a) A CAIR authorized account representative seeking recordation of 
a CAIR SO2 allowance transfer shall submit the transfer to 
the Administrator. To be considered correctly submitted, the CAIR 
SO2 allowance transfer shall include the following elements, 
in a format specified by the Administrator:
    (1) The account numbers of both the transferor and transferee 
accounts;
    (2) The serial number of each CAIR SO2 allowance that is 
in the transferor account and is to be transferred; and
    (3) The name and signature of the CAIR authorized account 
representatives of the transferor and transferee accounts and the dates 
signed.
    (b)(1) The CAIR authorized account representative for the transferee 
account can meet the requirements in paragraph (a)(3) of this section by 
submitting, in a format prescribed by the Administrator, a statement 
signed by the CAIR authorized account representative and identifying 
each account into which any transfer of allowances, submitted on or 
after the date on which the Administrator receives such statement, is 
authorized. Such authorization shall be binding on any CAIR authorized 
account representative for such account and shall apply to all transfers 
into the account that are submitted on or after such date of receipt, 
unless and until the Administrator receives a statement signed by the 
CAIR authorized account representative retracting the authorization for 
the account.
    (2) The statement under paragraph (b)(1) of this section shall 
include the following: ``By this signature I authorize any transfer of 
allowances into each account listed herein, except that I do not waive 
any remedies under State or Federal law to obtain correction of any 
erroneous transfers into such accounts. This authorization shall be 
binding on any CAIR authorized account representative for such account 
unless and until a statement signed by the CAIR authorized account 
representative retracting this authorization for the account is received 
by the Administrator.''



Sec. 96.261  EPA recordation.

    (a) Within 5 business days (except as necessary to perform a 
transfer in perpetuity of CAIR SO2 allowances allocated to a 
CAIR SO2 unit or as provided in paragraph (b) of this 
section) of receiving a CAIR SO2 allowance transfer, the 
Administrator will record a CAIR SO2 allowance transfer by 
moving each CAIR SO2 allowance from the transferor account to 
the transferee account as specified by the request, provided that:
    (1) The transfer is correctly submitted under Sec. 96.260;
    (2) The transferor account includes each CAIR SO2 
allowance identified by serial number in the transfer; and
    (3) The transfer is in accordance with the limitation on transfer 
under Sec. 74.42 of this chapter and Sec. 74.47(c) of this chapter, as 
applicable.
    (b) A CAIR SO2 allowance transfer that is submitted for 
recordation after the allowance transfer deadline for a control period 
and that includes any CAIR SO2 allowances allocated for any

[[Page 115]]

control period before such allowance transfer deadline will not be 
recorded until after the Administrator completes the deductions under 
Sec. 96.254 for the control period immediately before such allowance 
transfer deadline.
    (c) Where a CAIR SO2 allowance transfer submitted for 
recordation fails to meet the requirements of paragraph (a) of this 
section, the Administrator will not record such transfer.

[70 FR 25362, May 12, 2005, as amended at 71 FR 25389, Apr. 28, 2006]



Sec. 96.262  Notification.

    (a) Notification of recordation. Within 5 business days of 
recordation of a CAIR SO2 allowance transfer under Sec. 
96.261, the Administrator will notify the CAIR authorized account 
representatives of both the transferor and transferee accounts.
    (b) Notification of non-recordation. Within 10 business days of 
receipt of a CAIR SO2 allowance transfer that fails to meet 
the requirements of Sec. 96.261(a), the Administrator will notify the 
CAIR authorized account representatives of both accounts subject to the 
transfer of:
    (1) A decision not to record the transfer, and
    (2) The reasons for such non-recordation.
    (c) Nothing in this section shall preclude the submission of a CAIR 
SO2 allowance transfer for recordation following notification 
of non-recordation.



                  Subpart HHH_Monitoring and Reporting

    Source: 70 FR 25362, May 12, 2005, unless otherwise noted.



Sec. 96.270  General requirements.

    The owners and operators, and to the extent applicable, the CAIR 
designated representative, of a CAIR SO2 unit, shall comply 
with the monitoring, recordkeeping, and reporting requirements as 
provided in this subpart and in subparts F and G of part 75 of this 
chapter. For purposes of complying with such requirements, the 
definitions in Sec. 96.202 and in Sec. 72.2 of this chapter shall 
apply, and the terms ``affected unit,'' ``designated representative,'' 
and ``continuous emission monitoring system'' (or ``CEMS'') in part 75 
of this chapter shall be deemed to refer to the terms ``CAIR 
SO2 unit,'' ``CAIR designated representative,'' and 
``continuous emission monitoring system'' (or ``CEMS'') respectively, as 
defined in Sec. 96.202. The owner or operator of a unit that is not a 
CAIR SO2 unit but that is monitored under Sec. 75.16(b)(2) 
of this chapter shall comply with the same monitoring, recordkeeping, 
and reporting requirements as a CAIR SO2 unit.
    (a) Requirements for installation, certification, and data 
accounting. The owner or operator of each CAIR SO2 unit 
shall:
    (1) Install all monitoring systems required under this subpart for 
monitoring SO2 mass emissions and individual unit heat input 
(including all systems required to monitor SO2 concentration, 
stack gas moisture content, stack gas flow rate, CO2 or 
O2 concentration, and fuel flow rate, as applicable, in 
accordance with Sec. Sec. 75.11 and 75.16 of this chapter);
    (2) Successfully complete all certification tests required under 
Sec. 96.271 and meet all other requirements of this subpart and part 75 
of this chapter applicable to the monitoring systems under paragraph 
(a)(1) of this section; and
    (3) Record, report, and quality-assure the data from the monitoring 
systems under paragraph (a)(1) of this section.
    (b) Compliance deadlines. Except as provided in paragraph (e) of 
this section, the owner or operator shall meet the monitoring system 
certification and other requirements of paragraphs (a)(1) and (2) of 
this section on or before the following dates. The owner or operator 
shall record, report, and quality-assure the data from the monitoring 
systems under paragraph (a)(1) of this section on and after the 
following dates.
    (1) For the owner or operator of a CAIR SO2 unit that 
commences commercial operation before July 1, 2008, by January 1, 2009.
    (2) For the owner or operator of a CAIR SO2 unit that 
commences commercial operation on or after July 1, 2008, by the later of 
the following dates:
    (i) January 1, 2009; or

[[Page 116]]

    (ii) 90 unit operating days or 180 calendar days, whichever occurs 
first, after the date on which the unit commences commercial operation.
    (3) For the owner or operator of a CAIR SO2 unit for 
which construction of a new stack or flue or installation of add-on 
SO2 emission controls is completed after the applicable 
deadline under paragraph (b)(1), (2), (4), or (5) of this section, by 90 
unit operating days or 180 calendar days, whichever occurs first, after 
the date on which emissions first exit to the atmosphere through the new 
stack or flue or add-on SO2 emissions controls.
    (4) Notwithstanding the dates in paragraphs (b)(1) and (2) of this 
section, for the owner or operator of a unit for which a CAIR opt-in 
permit application is submitted and not withdrawn and a CAIR opt-in 
permit is not yet issued or denied under subpart III of this part, by 
the date specified in Sec. 96.284(b).
    (5) Notwithstanding the dates in paragraphs (b)(1) and (2) of this 
section, for the owner or operator of a CAIR SO2 opt-in unit 
under subpart III of this part, by the date on which the CAIR 
SO2 opt-in unit enters the CAIR SO2 Trading 
Program as provided in Sec. 96.284(g).
    (c) Reporting data. The owner or operator of a CAIR SO2 
unit that does not meet the applicable compliance date set forth in 
paragraph (b) of this section for any monitoring system under paragraph 
(a)(1) of this section shall, for each such monitoring system, 
determine, record, and report maximum potential (or, as appropriate, 
minimum potential) values for SO2 concentration, stack gas 
flow rate, stack gas moisture content, fuel flow rate, and any other 
parameters required to determine SO2 mass emissions and heat 
input in accordance with Sec. 75.31(b)(2) or (c)(3) of this chapter or 
section 2.4 of appendix D to part 75 of this chapter, as applicable.
    (d) Prohibitions. (1) No owner or operator of a CAIR SO2 
unit shall use any alternative monitoring system, alternative reference 
method, or any other alternative to any requirement of this subpart 
without having obtained prior written approval in accordance with Sec. 
96.275.
    (2) No owner or operator of a CAIR SO2 unit shall operate 
the unit so as to discharge, or allow to be discharged, SO2 
emissions to the atmosphere without accounting for all such emissions in 
accordance with the applicable provisions of this subpart and part 75 of 
this chapter.
    (3) No owner or operator of a CAIR SO2 unit shall disrupt 
the continuous emission monitoring system, any portion thereof, or any 
other approved emission monitoring method, and thereby avoid monitoring 
and recording SO2 mass emissions discharged into the 
atmosphere or heat input, except for periods of recertification or 
periods when calibration, quality assurance testing, or maintenance is 
performed in accordance with the applicable provisions of this subpart 
and part 75 of this chapter.
    (4) No owner or operator of a CAIR SO2 unit shall retire 
or permanently discontinue use of the continuous emission monitoring 
system, any component thereof, or any other approved monitoring system 
under this subpart, except under any one of the following circumstances:
    (i) During the period that the unit is covered by an exemption under 
Sec. 96.205 that is in effect;
    (ii) The owner or operator is monitoring emissions from the unit 
with another certified monitoring system approved, in accordance with 
the applicable provisions of this subpart and part 75 of this chapter, 
by the permitting authority for use at that unit that provides emission 
data for the same pollutant or parameter as the retired or discontinued 
monitoring system; or
    (iii) The CAIR designated representative submits notification of the 
date of certification testing of a replacement monitoring system for the 
retired or discontinued monitoring system in accordance with Sec. 
96.271(d)(3)(i).
    (e) Long-term cold storage. The owner or operator of a CAIR 
SO2 unit is subject to the applicable provisions of part 75 
of this chapter concerning units in long-term cold storage.

[70 FR 25362, May 12, 2005, as amended at 71 FR 25389, Apr. 28, 2006]

[[Page 117]]



Sec. 96.271  Initial certification and recertification procedures.

    (a) The owner or operator of a CAIR SO2 unit shall be 
exempt from the initial certification requirements of this section for a 
monitoring system under Sec. 96.270(a)(1) if the following conditions 
are met:
    (1) The monitoring system has been previously certified in 
accordance with part 75 of this chapter; and
    (2) The applicable quality-assurance and quality-control 
requirements of Sec. 75.21 of this chapter and appendix B and appendix 
D to part 75 of this chapter are fully met for the certified monitoring 
system described in paragraph (a)(1) of this section.
    (b) The recertification provisions of this section shall apply to a 
monitoring system under Sec. 96.270(a)(1) exempt from initial 
certification requirements under paragraph (a) of this section.
    (c) [Reserved]
    (d) Except as provided in paragraph (a) of this section, the owner 
or operator of a CAIR SO2 unit shall comply with the 
following initial certification and recertification procedures, for a 
continuous monitoring system (i.e., a continuous emission monitoring 
system and an excepted monitoring system under appendix D to part 75 of 
this chapter) under Sec. 96.270(a)(1). The owner or operator of a unit 
that qualifies to use the low mass emissions excepted monitoring 
methodology under Sec. 75.19 of this chapter or that qualifies to use 
an alternative monitoring system under subpart E of part 75 of this 
chapter shall comply with the procedures in paragraph (e) or (f) of this 
section respectively.
    (1) Requirements for initial certification. The owner or operator 
shall ensure that each continuous monitoring system under Sec. 
96.270(a)(1) (including the automated data acquisition and handling 
system) successfully completes all of the initial certification testing 
required under Sec. 75.20 of this chapter by the applicable deadline in 
Sec. 96.270(b). In addition, whenever the owner or operator installs a 
monitoring system to meet the requirements of this subpart in a location 
where no such monitoring system was previously installed, initial 
certification in accordance with Sec. 75.20 of this chapter is 
required.
    (2) Requirements for recertification. Whenever the owner or operator 
makes a replacement, modification, or change in any certified continuous 
emission monitoring system under Sec. 96.270(a)(1) that may 
significantly affect the ability of the system to accurately measure or 
record SO2 mass emissions or heat input rate or to meet the 
quality-assurance and quality-control requirements of Sec. 75.21 of 
this chapter or appendix B to part 75 of this chapter, the owner or 
operator shall recertify the monitoring system in accordance with Sec. 
75.20(b) of this chapter. Furthermore, whenever the owner or operator 
makes a replacement, modification, or change to the flue gas handling 
system or the unit's operation that may significantly change the stack 
flow or concentration profile, the owner or operator shall recertify 
each continuous emission monitoring system whose accuracy is potentially 
affected by the change, in accordance with Sec. 75.20(b) of this 
chapter. Examples of changes to a continuous emission monitoring system 
that require recertification include: replacement of the analyzer, 
complete replacement of an existing continuous emission monitoring 
system, or change in location or orientation of the sampling probe or 
site. Any fuel flowmeter system under Sec. 96.270(a)(1) is subject to 
the recertification requirements in Sec. 75.20(g)(6) of this chapter.
    (3) Approval process for initial certification and recertification. 
Paragraphs (d)(3)(i) through (iv) of this section apply to both initial 
certification and recertification of a continuous monitoring system 
under Sec. 96.270(a)(1). For recertifications, replace the words 
``certification'' and ``initial certification'' with the word 
``recertification'', replace the word ``certified'' with the word 
``recertified,'' and follow the procedures in Sec. Sec. 75.20(b)(5) and 
(g)(7) of this chapter in lieu of the procedures in paragraph (d)(3)(v) 
of this section.
    (i) Notification of certification. The CAIR designated 
representative shall submit to the permitting authority, the appropriate 
EPA Regional Office, and the Administrator written notice of the dates 
of certification testing, in accordance with Sec. 96.273.

[[Page 118]]

    (ii) Certification application. The CAIR designated representative 
shall submit to the permitting authority a certification application for 
each monitoring system. A complete certification application shall 
include the information specified in Sec. 75.63 of this chapter.
    (iii) Provisional certification date. The provisional certification 
date for a monitoring system shall be determined in accordance with 
Sec. 75.20(a)(3) of this chapter. A provisionally certified monitoring 
system may be used under the CAIR SO2 Trading Program for a 
period not to exceed 120 days after receipt by the permitting authority 
of the complete certification application for the monitoring system 
under paragraph (d)(3)(ii) of this section. Data measured and recorded 
by the provisionally certified monitoring system, in accordance with the 
requirements of part 75 of this chapter, will be considered valid 
quality-assured data (retroactive to the date and time of provisional 
certification), provided that the permitting authority does not 
invalidate the provisional certification by issuing a notice of 
disapproval within 120 days of the date of receipt of the complete 
certification application by the permitting authority.
    (iv) Certification application approval process. The permitting 
authority will issue a written notice of approval or disapproval of the 
certification application to the owner or operator within 120 days of 
receipt of the complete certification application under paragraph 
(d)(3)(ii) of this section. In the event the permitting authority does 
not issue such a notice within such 120-day period, each monitoring 
system that meets the applicable performance requirements of part 75 of 
this chapter and is included in the certification application will be 
deemed certified for use under the CAIR SO2 Trading Program.
    (A) Approval notice. If the certification application is complete 
and shows that each monitoring system meets the applicable performance 
requirements of part 75 of this chapter, then the permitting authority 
will issue a written notice of approval of the certification application 
within 120 days of receipt.
    (B) Incomplete application notice. If the certification application 
is not complete, then the permitting authority will issue a written 
notice of incompleteness that sets a reasonable date by which the CAIR 
designated representative must submit the additional information 
required to complete the certification application. If the CAIR 
designated representative does not comply with the notice of 
incompleteness by the specified date, then the permitting authority may 
issue a notice of disapproval under paragraph (d)(3)(iv)(C) of this 
section. The 120-day review period shall not begin before receipt of a 
complete certification application.
    (C) Disapproval notice. If the certification application shows that 
any monitoring system does not meet the performance requirements of part 
75 of this chapter or if the certification application is incomplete and 
the requirement for disapproval under paragraph (d)(3)(iv)(B) of this 
section is met, then the permitting authority will issue a written 
notice of disapproval of the certification application. Upon issuance of 
such notice of disapproval, the provisional certification is invalidated 
by the permitting authority and the data measured and recorded by each 
uncertified monitoring system shall not be considered valid quality-
assured data beginning with the date and hour of provisional 
certification (as defined under Sec. 75.20(a)(3) of this chapter). The 
owner or operator shall follow the procedures for loss of certification 
in paragraph (d)(3)(v) of this section for each monitoring system that 
is disapproved for initial certification.
    (D) Audit decertification. The permitting authority or, for a CAIR 
SO2 opt-in unit or a unit for which a CAIR opt-in permit 
application is submitted and not withdrawn and a CAIR opt-in permit is 
not yet issued or denied under subpart III of this part, the 
Administrator may issue a notice of disapproval of the certification 
status of a monitor in accordance with Sec. 96.272(b).
    (v) Procedures for loss of certification. If the permitting 
authority or the Administrator issues a notice of disapproval of a 
certification application under paragraph (d)(3)(iv)(C) of this

[[Page 119]]

section or a notice of disapproval of certification status under 
paragraph (d)(3)(iv)(D) of this section, then:
    (A) The owner or operator shall substitute the following values, for 
each disapproved monitoring system, for each hour of unit operation 
during the period of invalid data specified under Sec. 
75.20(a)(4)(iii), Sec. 75.20(g)(7), or Sec. 75.21(e) of this chapter 
and continuing until the applicable date and hour specified under Sec. 
75.20(a)(5)(i) or (g)(7) of this chapter:
    (1) For a disapproved SO2 pollutant concentration monitor 
and disapproved flow monitor, respectively, the maximum potential 
concentration of SO2 and the maximum potential flow rate, as 
defined in sections 2.1.1.1 and 2.1.4.1 of appendix A to part 75 of this 
chapter.
    (2) For a disapproved moisture monitoring system and disapproved 
diluent gas monitoring system, respectively, the minimum potential 
moisture percentage and either the maximum potential CO2 
concentration or the minimum potential O2 concentration (as 
applicable), as defined in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of 
appendix A to part 75 of this chapter.
    (3) For a disapproved fuel flowmeter system, the maximum potential 
fuel flow rate, as defined in section 2.4.2.1 of appendix D to part 75 
of this chapter.
    (B) The CAIR designated representative shall submit a notification 
of certification retest dates and a new certification application in 
accordance with paragraphs (d)(3)(i) and (ii) of this section.
    (C) The owner or operator shall repeat all certification tests or 
other requirements that were failed by the monitoring system, as 
indicated in the permitting authority's or the Administrator's notice of 
disapproval, no later than 30 unit operating days after the date of 
issuance of the notice of disapproval.
    (e) Initial certification and recertification procedures for units 
using the low mass emission excepted methodology under Sec. 75.19 of 
this chapter. The owner or operator of a unit qualified to use the low 
mass emissions (LME) excepted methodology under Sec. 75.19 of this 
chapter shall meet the applicable certification and recertification 
requirements in Sec. Sec. 75.19(a)(2) and 75.20(h) of this chapter. If 
the owner or operator of such a unit elects to certify a fuel flowmeter 
system for heat input determination, the owner or operator shall also 
meet the certification and recertification requirements in Sec. 
75.20(g) of this chapter.
    (f) Certification/recertification procedures for alternative 
monitoring systems. The CAIR designated representative of each unit for 
which the owner or operator intends to use an alternative monitoring 
system approved by the Administrator and, if applicable, the permitting 
authority under subpart E of part 75 of this chapter shall comply with 
the applicable notification and application procedures of Sec. 75.20(f) 
of this chapter.

[70 FR 25362, May 12, 2005, as amended at 71 FR 25390, Apr. 28, 2006; 71 
FR 74794, Dec. 13, 2006]



Sec. 96.272  Out of control periods.

    (a) Whenever any monitoring system fails to meet the quality-
assurance and quality-control requirements or data validation 
requirements of part 75 of this chapter, data shall be substituted using 
the applicable missing data procedures in subpart D of or appendix D to 
part 75 of this chapter.
    (b) Audit decertification. Whenever both an audit of a monitoring 
system and a review of the initial certification or recertification 
application reveal that any monitoring system should not have been 
certified or recertified because it did not meet a particular 
performance specification or other requirement under Sec. 96.271 or the 
applicable provisions of part 75 of this chapter, both at the time of 
the initial certification or recertification application submission and 
at the time of the audit, the permitting authority or, for a CAIR 
SO2 opt-in unit or a unit for which a CAIR opt-in permit 
application is submitted and not withdrawn and a CAIR opt-in permit is 
not yet issued or denied under subpart III of this part, the 
Administrator will issue a notice of disapproval of the certification 
status of such monitoring system. For the purposes of this paragraph, an 
audit shall be either a field audit or an audit of any information 
submitted to the permitting authority or the Administrator. By issuing 
the notice of disapproval, the permitting authority or

[[Page 120]]

the Administrator revokes prospectively the certification status of the 
monitoring system. The data measured and recorded by the monitoring 
system shall not be considered valid quality-assured data from the date 
of issuance of the notification of the revoked certification status 
until the date and time that the owner or operator completes 
subsequently approved initial certification or recertification tests for 
the monitoring system. The owner or operator shall follow the applicable 
initial certification or recertification procedures in Sec. 96.271 for 
each disapproved monitoring system.



Sec. 96.273  Notifications.

    The CAIR designated representative for a CAIR SO2 unit 
shall submit written notice to the permitting authority and the 
Administrator in accordance with Sec. 75.61 of this chapter.

[70 FR 25362, May 12, 2005, as amended at 71 FR 25390, Apr. 28, 2006]



Sec. 96.274  Recordkeeping and reporting.

    (a) General provisions. The CAIR designated representative shall 
comply with all recordkeeping and reporting requirements in this 
section, the applicable recordkeeping and reporting requirements in 
subparts F and G of part 75 of this chapter, and the requirements of 
Sec. 96.210(e)(1).
    (b) Monitoring plans. The owner or operator of a CAIR SO2 
unit shall comply with requirements of Sec. 75.62 of this chapter and, 
for a unit for which a CAIR opt-in permit application is submitted and 
not withdrawn and a CAIR opt-in permit is not yet issued or denied under 
subpart III of this part, Sec. Sec. 96.283 and 96.284(a).
    (c) Certification applications. The CAIR designated representative 
shall submit an application to the permitting authority within 45 days 
after completing all initial certification or recertification tests 
required under Sec. 96.271, including the information required under 
Sec. 75.63 of this chapter.
    (d) Quarterly reports. The CAIR designated representative shall 
submit quarterly reports, as follows:
    (1) The CAIR designated representative shall report the 
SO2 mass emissions data and heat input data for the CAIR 
SO2 unit, in an electronic quarterly report in a format 
prescribed by the Administrator, for each calendar quarter beginning 
with:
    (i) For a unit that commences commercial operation before July 1, 
2008, the calendar quarter covering January 1, 2009 through March 31, 
2009;
    (ii) For a unit that commences commercial operation on or after July 
1, 2008, the calendar quarter corresponding to the earlier of the date 
of provisional certification or the applicable deadline for initial 
certification under Sec. 96.270(b), unless that quarter is the third or 
fourth quarter of 2008, in which case reporting shall commence in the 
quarter covering January 1, 2009 through March 31, 2009;
    (iii) Notwithstanding paragraphs (d)(1)(i) and (ii) of this section, 
for a unit for which a CAIR opt-in permit application is submitted and 
not withdrawn and a CAIR opt-in permit is not yet issued or denied under 
subpart III of this part, the calendar quarter corresponding to the date 
specified in Sec. 96.284(b); and
    (iv) Notwithstanding paragraphs (d)(1)(i) and (ii) of this section, 
for a CAIR SO2 opt-in unit under subpart III of this part, 
the calendar quarter corresponding to the date on which the CAIR 
SO2 opt-in unit enters the CAIR SO2 Trading 
Program as provided in Sec. 96.284(g).
    (2) The CAIR designated representative shall submit each quarterly 
report to the Administrator within 30 days following the end of the 
calendar quarter covered by the report. Quarterly reports shall be 
submitted in the manner specified in Sec. 75.64 of this chapter.
    (3) For CAIR SO2 units that are also subject to an Acid 
Rain emissions limitation or the CAIR NOX Annual Trading 
Program CAIR NOX Ozone Season Trading Program, or Hg Budget 
Trading Program, quarterly reports shall include the applicable data and 
information required by subparts F through I of part 75 of this chapter 
as applicable, in addition to the SO2 mass emission data, 
heat input data, and other information required by this subpart.
    (e) Compliance certification. The CAIR designated representative 
shall submit to the Administrator a compliance certification (in a 
format prescribed by the Administrator) in support of each

[[Page 121]]

quarterly report based on reasonable inquiry of those persons with 
primary responsibility for ensuring that all of the unit's emissions are 
correctly and fully monitored. The certification shall state that:
    (1) The monitoring data submitted were recorded in accordance with 
the applicable requirements of this subpart and part 75 of this chapter, 
including the quality assurance procedures and specifications; and
    (2) For a unit with add-on SO2 emission controls and for 
all hours where SO2 data are substituted in accordance with 
Sec. 75.34(a)(1) of this chapter, the add-on emission controls were 
operating within the range of parameters listed in the quality 
assurance/quality control program under appendix B to part 75 of this 
chapter and the substitute data values do not systematically 
underestimate SO2 emissions.

[70 FR 25362, May 12, 2005, as amended at 71 FR 25390, Apr. 28, 2006]



Sec. 96.275  Petitions.

    (a) The CAIR designated representative of a CAIR SO2 unit 
that is subject to an Acid Rain emissions limitation may submit a 
petition under Sec. 75.66 of this chapter to the Administrator 
requesting approval to apply an alternative to any requirement of this 
subpart. Application of an alternative to any requirement of this 
subpart is in accordance with this subpart only to the extent that the 
petition is approved in writing by the Administrator, in consultation 
with the permitting authority.
    (b) The CAIR designated representative of a CAIR SO2 unit 
that is not subject to an Acid Rain emissions limitation may submit a 
petition under Sec. 75.66 of this chapter to the permitting authority 
and the Administrator requesting approval to apply an alternative to any 
requirement of this subpart. Application of an alternative to any 
requirement of this subpart is in accordance with this subpart only to 
the extent that the petition is approved in writing by both the 
permitting authority and the Administrator.



                   Subpart III_CAIR SO 2 Opt-in Units

    Source: 70 FR 25362, May 12, 2005, unless otherwise noted.



Sec. 96.280  Applicability.

    A CAIR SO2 opt-in unit must be a unit that:
    (a) Is located in the State;
    (b) Is not a CAIR SO2 unit under Sec. 96.204 and is not 
covered by a retired unit exemption under Sec. 96.205 that is in 
effect;
    (c) Is not covered by a retired unit exemption under Sec. 72.8 of 
this chapter that is in effect and is not an opt-in source under part 74 
of this chapter;
    (d) Has or is required or qualified to have a title V operating 
permit or other federally enforceable permit; and
    (e) Vents all of its emissions to a stack and can meet the 
monitoring, recordkeeping, and reporting requirements of subpart HHH of 
this part.



Sec. 96.281  General.

    (a) Except as otherwise provided in Sec. Sec. 96.201 through 
96.204, Sec. Sec. 96.206 through 96.208, and subparts BBB and CCC and 
subparts FFF through HHH of this part, a CAIR SO2 opt-in unit 
shall be treated as a CAIR SO2 unit for purposes of applying 
such sections and subparts of this part.
    (b) Solely for purposes of applying, as provided in this subpart, 
the requirements of subpart HHH of this part to a unit for which a CAIR 
opt-in permit application is submitted and not withdrawn and a CAIR opt-
in permit is not yet issued or denied under this subpart, such unit 
shall be treated as a CAIR SO2 unit before issuance of a CAIR 
opt-in permit for such unit.



Sec. 96.282  CAIR designated representative.

    Any CAIR SO2 opt-in unit, and any unit for which a CAIR 
opt-in permit application is submitted and not withdrawn and a CAIR opt-
in permit is not yet issued or denied under this subpart, located at the 
same source as one or more CAIR SO2 units shall have the same 
CAIR designated representative and alternate CAIR designated 
representative as such CAIR SO2 units.

[[Page 122]]



Sec. 96.283  Applying for CAIR opt-in permit.

    (a) Applying for initial CAIR opt-in permit. The CAIR designated 
representative of a unit meeting the requirements for a CAIR 
SO2 opt-in unit in Sec. 96.280 may apply for an initial CAIR 
opt-in permit at any time, except as provided under Sec. 96.286(f) and 
(g), and, in order to apply, must submit the following:
    (1) A complete CAIR permit application under Sec. 96.222;
    (2) A certification, in a format specified by the permitting 
authority, that the unit:
    (i) Is not a CAIR SO2 unit under Sec. 96.204 and is not 
covered by a retired unit exemption under Sec. 96.205 that is in 
effect;
    (ii) Is not covered by a retired unit exemption under Sec. 72.8 of 
this chapter that is in effect;
    (iii) Is not and, so long as the unit is a CAIR SO2 opt-
in unit, will not become, an opt-in source under part 74 of this 
chapter;
    (iv) Vents all of its emissions to a stack; and
    (v) Has documented heat input for more than 876 hours during the 6 
months immediately preceding submission of the CAIR permit application 
under Sec. 96.222;
    (3) A monitoring plan in accordance with subpart HHH of this part;
    (4) A complete certificate of representation under Sec. 96.213 
consistent with Sec. 96.282, if no CAIR designated representative has 
been previously designated for the source that includes the unit; and
    (5) A statement, in a format specified by the permitting authority, 
whether the CAIR designated representative requests that the unit be 
allocated CAIR SO2 allowances under Sec. 96.288(b) or Sec. 
96.288(c) (subject to the conditions in Sec. Sec. 96.284(h) and 
96.286(g)). If allocation under Sec. 96.288(c) is requested, this 
statement shall include a statement that the owners and operators of the 
unit intend to repower the unit before January 1, 2015 and that they 
will provide, upon request, documentation demonstrating such intent.
    (b) Duty to reapply. (1) The CAIR designated representative of a 
CAIR SO2 opt-in unit shall submit a complete CAIR permit 
application under Sec. 96.222 to renew the CAIR opt-in unit permit in 
accordance with the permitting authority's regulations for title V 
operating permits, or the permitting authority's regulations for other 
federally enforceable permits if applicable, addressing permit renewal.
    (2) Unless the permitting authority issues a notification of 
acceptance of withdrawal of the CAIR SO2 opt-in unit from the 
CAIR SO2 Trading Program in accordance with Sec. 96.286 or 
the unit becomes a CAIR SO2 unit under Sec. 96.204, the CAIR 
SO2 opt-in unit shall remain subject to the requirements for 
a CAIR SO2 opt-in unit, even if the CAIR designated 
representative for the CAIR SO2 opt-in unit fails to submit a 
CAIR permit application that is required for renewal of the CAIR opt-in 
permit under paragraph (b)(1) of this section.

[70 FR 25362, May 12, 2005, as amended at 71 FR 25390, Apr. 28, 2006]



Sec. 96.284  Opt-in process.

    The permitting authority will issue or deny a CAIR opt-in permit for 
a unit for which an initial application for a CAIR opt-in permit under 
Sec. 96.283 is submitted in accordance with the following:
    (a) Interim review of monitoring plan. The permitting authority and 
the Administrator will determine, on an interim basis, the sufficiency 
of the monitoring plan accompanying the initial application for a CAIR 
opt-in permit under Sec. 96.283. A monitoring plan is sufficient, for 
purposes of interim review, if the plan appears to contain information 
demonstrating that the SO2 emissions rate and heat input of 
the unit and all other applicable parameters are monitored and reported 
in accordance with subpart HHH of this part. A determination of 
sufficiency shall not be construed as acceptance or approval of the 
monitoring plan.
    (b) Monitoring and reporting. (1)(i) If the permitting authority and 
the Administrator determine that the monitoring plan is sufficient under 
paragraph (a) of this section, the owner or operator shall monitor and 
report the SO2 emissions rate and the heat input of the unit 
and all other applicable parameters, in accordance with subpart HHH of 
this part, starting on the date

[[Page 123]]

of certification of the appropriate monitoring systems under subpart HHH 
of this part and continuing until a CAIR opt-in permit is denied under 
Sec. 96.284(f) or, if a CAIR opt-in permit is issued, the date and time 
when the unit is withdrawn from the CAIR SO2 Trading Program 
in accordance with Sec. 96.286.
    (ii) The monitoring and reporting under paragraph (b)(1)(i) of this 
section shall include the entire control period immediately before the 
date on which the unit enters the CAIR SO2 Trading Program 
under Sec. 96.284(g), during which period monitoring system 
availability must not be less than 90 percent under subpart HHH of this 
part and the unit must be in full compliance with any applicable State 
or Federal emissions or emissions-related requirements.
    (2) To the extent the SO2 emissions rate and the heat 
input of the unit are monitored and reported in accordance with subpart 
HHH of this part for one or more control periods, in addition to the 
control period under paragraph (b)(1)(ii) of this section, during which 
control periods monitoring system availability is not less than 90 
percent under subpart HHH of this part and the unit is in full 
compliance with any applicable State or Federal emissions or emissions-
related requirements and which control periods begin not more than 3 
years before the unit enters the CAIR SO2 Trading Program 
under Sec. 96.284(g), such information shall be used as provided in 
paragraphs (c) and (d) of this section.
    (c) Baseline heat input. The unit's baseline heat input shall equal:
    (1) If the unit's SO2 emissions rate and heat input are 
monitored and reported for only one control period, in accordance with 
paragraph (b)(1) of this section, the unit's total heat input (in mmBtu) 
for the control period; or
    (2) If the unit's SO2 emissions rate and heat input are 
monitored and reported for more than one control period, in accordance 
with paragraphs (b)(1) and (2) of this section, the average of the 
amounts of the unit's total heat input (in mmBtu) for the control 
periods under paragraphs (b)(1)(ii) and (2) of this section and the 
control periods under paragraph (b)(2) of this section.
    (d) Baseline SO2 emission rate. The unit's baseline 
SO2 emission rate shall equal:
    (1) If the unit's SO2 emissions rate and heat input are 
monitored and reported for only one control period, in accordance with 
paragraph (b)(1) of this section, the unit's SO2 emissions 
rate (in lb/mmBtu) for the control period;
    (2) If the unit's SO2 emissions rate and heat input are 
monitored and reported for more than one control period, in accordance 
with paragraphs (b)(1) and (2) of this section, and the unit does not 
have add-on SO2 emission controls during any such control 
periods, the average of the amounts of the unit's SO2 
emissions rate (in lb/mmBtu) for the control periods under paragraphs 
(b)(1)(ii) and (2) of this section; or
    (3) If the unit's SO2 emissions rate and heat input are 
monitored and reported for more than one control period, in accordance 
with paragraphs (b)(1) and (2) of this section, and the unit has add-on 
SO2 emission controls during any such control periods, the 
average of the amounts of the unit's SO2 emissions rate (in 
lb/mmBtu) for such control periods during which the unit has add-on 
SO2 emission controls.
    (e) Issuance of CAIR opt-in permit. After calculating the baseline 
heat input and the baseline SO2 emissions rate for the unit 
under paragraphs (c) and (d) of this section and if the permitting 
authority determines that the CAIR designated representative shows that 
the unit meets the requirements for a CAIR SO2 opt-in unit in 
Sec. 96.280 and meets the elements certified in Sec. 96.283(a)(2), the 
permitting authority will issue a CAIR opt-in permit. The permitting 
authority will provide a copy of the CAIR opt-in permit to the 
Administrator, who will then establish a compliance account for the 
source that includes the CAIR SO2 opt-in unit unless the 
source already has a compliance account.
    (f) Issuance of denial of CAIR opt-in permit. Notwithstanding 
paragraphs (a) through (e) of this section, if at any time before 
issuance of a CAIR opt-in permit for the unit, the permitting authority 
determines that the CAIR designated representative fails to show

[[Page 124]]

that the unit meets the requirements for a CAIR SO2 opt-in 
unit in Sec. 96.280 or meets the elements certified in Sec. 
96.283(a)(2), the permitting authority will issue a denial of a CAIR 
opt-in permit for the unit.
    (g) Date of entry into CAIR SO2 Trading Program. A unit 
for which an initial CAIR opt-in permit is issued by the permitting 
authority shall become a CAIR SO2 opt-in unit, and a CAIR 
SO2 unit, as of the later of January 1, 2010 or January 1 of 
the first control period during which such CAIR opt-in permit is issued.
    (h) Repowered CAIR SO2 opt-in unit. (1) If CAIR 
designated representative requests, and the permitting authority issues 
a CAIR opt-in permit providing for, allocation to a CAIR SO2 
opt-in unit of CAIR SO2 allowances under Sec. 96.288(c) and 
such unit is repowered after its date of entry into the CAIR 
SO2 Trading Program under paragraph (g) of this section, the 
repowered unit shall be treated as a CAIR SO2 opt-in unit 
replacing the original CAIR SO2 opt-in unit, as of the date 
of start-up of the repowered unit's combustion chamber.
    (2) Notwithstanding paragraphs (c) and (d) of this section, as of 
the date of start-up under paragraph (h)(1) of this section, the 
repowered unit shall be deemed to have the same date of commencement of 
operation, date of commencement of commercial operation, baseline heat 
input, and baseline SO2 emission rate as the original CAIR 
SO2 opt-in unit, and the original CAIR SO2 opt-in 
unit shall no longer be treated as a CAIR SO2 opt-in unit or 
a CAIR SO2 unit.

[70 FR 25362, May 12, 2005, as amended at 71 FR 25390, Apr. 28, 2006; 71 
FR 74794, Dec. 13, 2006]



Sec. 96.285  CAIR opt-in permit contents.

    (a) Each CAIR opt-in permit will contain:
    (1) All elements required for a complete CAIR permit application 
under Sec. 96.222;
    (2) The certification in Sec. 96.283(a)(2);
    (3) The unit's baseline heat input under Sec. 96.284(c);
    (4) The unit's baseline SO2 emission rate under Sec. 
96.284(d);
    (5) A statement whether the unit is to be allocated CAIR 
SO2 allowances Sec. 96.288(b) or Sec. 96.288(c) (subject to 
the conditions in Sec. Sec. 96.284(h) and 96.286(g));
    (6) A statement that the unit may withdraw from the CAIR 
SO2 Trading Program only in accordance with Sec. 96.286; and
    (7) A statement that the unit is subject to, and the owners and 
operators of the unit must comply with, the requirements of Sec. 
96.287.
    (b) Each CAIR opt-in permit is deemed to incorporate automatically 
the definitions of terms under Sec. 96.202 and, upon recordation by the 
Administrator under subpart FFF or GGG of this part or this subpart, 
every allocation, transfer, or deduction of CAIR SO2 
allowances to or from the compliance account of the source that includes 
a CAIR SO2 opt-in unit covered by the CAIR opt-in permit.
    (c) The CAIR opt-in permit shall be included, in a format specified 
by the permitting authority, in the CAIR permit for the source where the 
CAIR SO2 opt-in unit is located and in a title V operating 
permit or other federally enforceable permit for the source.

[70 FR 25362, May 12, 2005, as amended at 71 FR 25390, Apr. 28, 2006]



Sec. 96.286  Withdrawal from CAIR SO [bdi2] Trading Program.

    Except as provided under paragraph (g) of this section, a CAIR 
SO2 opt-in unit may withdraw from the CAIR SO2 
Trading Program, but only if the permitting authority issues a 
notification to the CAIR designated representative of the CAIR 
SO2 opt-in unit of the acceptance of the withdrawal of the 
CAIR SO2 opt-in unit in accordance with paragraph (d) of this 
section.
    (a) Requesting withdrawal. In order to withdraw a CAIR 
SO2 opt-in unit from the CAIR SO2 Trading Program, 
the CAIR designated representative of the CAIR SO2 opt-in 
unit shall submit to the permitting authority a request to withdraw 
effective as of midnight of December 31 of a specified calendar year, 
which date must be at least 4 years after December 31 of the year of 
entry into the CAIR SO2 Trading Program under Sec. 
96.284(g). The request must be submitted no later than 90

[[Page 125]]

days before the requested effective date of withdrawal.
    (b) Conditions for withdrawal. Before a CAIR SO2 opt-in 
unit covered by a request under paragraph (a) of this section may 
withdraw from the CAIR SO2 Trading Program and the CAIR opt-
in permit may be terminated under paragraph (e) of this section, the 
following conditions must be met:
    (1) For the control period ending on the date on which the 
withdrawal is to be effective, the source that includes the CAIR 
SO2 opt-in unit must meet the requirement to hold CAIR 
SO2 allowances under Sec. 96.206(c) and cannot have any 
excess emissions.
    (2) After the requirement for withdrawal under paragraph (b)(1) of 
this section is met, the Administrator will deduct from the compliance 
account of the source that includes the CAIR SO2 opt-in unit 
CAIR SO2 allowances equal in amount to and allocated for the 
same or a prior control period as any CAIR SO2 allowances 
allocated to the CAIR SO2 opt-in unit under Sec. 96.288 for 
any control period for which the withdrawal is to be effective. If there 
are no remaining CAIR SO2 units at the source, the 
Administrator will close the compliance account, and the owners and 
operators of the CAIR SO2 opt-in unit may submit a CAIR 
SO2 allowance transfer for any remaining CAIR SO2 
allowances to another CAIR SO2 Allowance Tracking System in 
accordance with subpart GGG of this part.
    (c) Notification. (1) After the requirements for withdrawal under 
paragraphs (a) and (b) of this section are met (including deduction of 
the full amount of CAIR SO2 allowances required), the 
permitting authority will issue a notification to the CAIR designated 
representative of the CAIR SO2 opt-in unit of the acceptance 
of the withdrawal of the CAIR SO2 opt-in unit as of midnight 
on December 31 of the calendar year for which the withdrawal was 
requested.
    (2) If the requirements for withdrawal under paragraphs (a) and (b) 
of this section are not met, the permitting authority will issue a 
notification to the CAIR designated representative of the CAIR 
SO2 opt-in unit that the CAIR SO2 opt-in unit's 
request to withdraw is denied. Such CAIR SO2 opt-in unit 
shall continue to be a CAIR SO2 opt-in unit.
    (d) Permit amendment. After the permitting authority issues a 
notification under paragraph (c)(1) of this section that the 
requirements for withdrawal have been met, the permitting authority will 
revise the CAIR permit covering the CAIR SO2 opt-in unit to 
terminate the CAIR opt-in permit for such unit as of the effective date 
specified under paragraph (c)(1) of this section. The unit shall 
continue to be a CAIR SO2 opt-in unit until the effective 
date of the termination and shall comply with all requirements under the 
CAIR SO2 Trading Program concerning any control periods for 
which the unit is a CAIR SO2 opt-in unit, even if such 
requirements arise or must be complied with after the withdrawal takes 
effect.
    (e) Reapplication upon failure to meet conditions of withdrawal. If 
the permitting authority denies the CAIR SO2 opt-in unit's 
request to withdraw, the CAIR designated representative may submit 
another request to withdraw in accordance with paragraphs (a) and (b) of 
this section.
    (f) Ability to reapply to the CAIR SO2 Trading Program. 
Once a CAIR SO2 opt-in unit withdraws from the CAIR 
SO2 Trading Program and its CAIR opt-in permit is terminated 
under this section, the CAIR designated representative may not submit 
another application for a CAIR opt-in permit under Sec. 96.283 for such 
CAIR SO2 opt-in unit before the date that is 4 years after 
the date on which the withdrawal became effective. Such new application 
for a CAIR opt-in permit will be treated as an initial application for a 
CAIR opt-in permit under Sec. 96.284.
    (g) Inability to withdraw. Notwithstanding paragraphs (a) through 
(f) of this section, a CAIR SO2 opt-in unit shall not be 
eligible to withdraw from the CAIR SO2 Trading Program if the 
CAIR designated representative of the CAIR SO2 opt-in unit 
requests, and the permitting authority issues a CAIR opt-in permit 
providing for, allocation to the CAIR SO2 opt-in unit of CAIR 
SO2 allowances under Sec. 96.288(c).

[70 FR 25362, May 12, 2005, as amended at 71 FR 25390, Apr. 28, 2006]

[[Page 126]]



Sec. 96.287  Change in regulatory status.

    (a) Notification. If a CAIR SO2 opt-in unit becomes a 
CAIR SO2 unit under Sec. 96.204, then the CAIR designated 
representative shall notify in writing the permitting authority and the 
Administrator of such change in the CAIR SO2 opt-in unit's 
regulatory status, within 30 days of such change.
    (b) Permitting authority's and Administrator's actions. (1) If a 
CAIR SO2 opt-in unit becomes a CAIR SO2 unit under 
Sec. 96.204, the permitting authority will revise the CAIR 
SO2 opt-in unit's CAIR opt-in permit to meet the requirements 
of a CAIR permit under Sec. 96.223, and remove the CAIR opt-in permit 
provisions, as of the date on which the CAIR SO2 opt-in unit 
becomes a CAIR SO2 unit under Sec. 96.204.
    (2)(i) The Administrator will deduct from the compliance account of 
the source that includes a CAIR SO2 opt-in unit that becomes 
a CAIR SO2 unit under Sec. 96.204, CAIR SO2 
allowances equal in amount to and allocated for the same or a prior 
control period as:
    (A) Any CAIR SO2 allowances allocated to the CAIR 
SO2 opt-in unit under Sec. 96.288 for any control period 
after the date on which the CAIR SO2 opt-in unit becomes a 
CAIR SO2 unit under Sec. 96.204; and
    (B) If the date on which the CAIR SO2 opt-in unit becomes 
a CAIR SO2 unit under Sec. 96.204 is not December 31, the 
CAIR SO2 allowances allocated to the CAIR SO2 opt-
in unit under Sec. 96.288 for the control period that includes the date 
on which the CAIR SO2 opt-in unit becomes a CAIR 
SO2 unit under Sec. 96.204, multiplied by the ratio of the 
number of days, in the control period, starting with the date on which 
the CAIR SO2 opt-in unit becomes a CAIR SO2 unit 
under Sec. 96.204 divided by the total number of days in the control 
period and rounded to the nearest whole allowance as appropriate.
    (ii) The CAIR designated representative shall ensure that the 
compliance account of the source that includes the CAIR SO2 
opt-in unit that becomes a CAIR SO2 unit under Sec. 96.204 
contains the CAIR SO2 allowances necessary for completion of 
the deduction under paragraph (b)(2)(i) of this section.

[70 FR 25362, May 12, 2005, as amended at 71 FR 25390, Apr. 28, 2006; 71 
FR 74794, Dec. 13, 2006]



Sec. 96.288  CAIR SO [bdi2] allowance allocations to CAIR SO [bdi2]
opt-in units.

    (a) Timing requirements. (1) When the CAIR opt-in permit is issued 
under Sec. 96.284(e), the permitting authority will allocate CAIR 
SO2 allowances to the CAIR SO2 opt-in unit, and 
submit to the Administrator the allocation for the control period in 
which a CAIR SO2 opt-in unit enters the CAIR SO2 
Trading Program under Sec. 96.284(g), in accordance with paragraph (b) 
or (c) of this section.
    (2) By no later than October 31 of the control period after the 
control period in which a CAIR SO2 opt-in unit enters the 
CAIR SO2 Trading Program under Sec. 96.284(g) and October 31 
of each year thereafter, the permitting authority will allocate CAIR 
SO2 allowances to the CAIR SO2 opt-in unit, and 
submit to the Administrator the allocation for the control period that 
includes such submission deadline and in which the unit is a CAIR 
SO2 opt-in unit, in accordance with paragraph (b) or (c) of 
this section.
    (b) Calculation of allocation. For each control period for which a 
CAIR SO2 opt-in unit is to be allocated CAIR SO2 
allowances, the permitting authority will allocate in accordance with 
the following procedures:
    (1) The heat input (in mmBtu) used for calculating the CAIR 
SO2 allowance allocation will be the lesser of:
    (i) The CAIR SO2 opt-in unit's baseline heat input 
determined under Sec. 96.284(c); or
    (ii) The CAIR SO2 opt-in unit's heat input, as determined 
in accordance with subpart HHH of this part, for the immediately prior 
control period, except when the allocation is being calculated for the 
control period in which the CAIR SO2 opt-in unit enters the 
CAIR SO2 Trading Program under Sec. 96.284(g).
    (2) The SO2 emission rate (in lb/mmBtu) used for 
calculating CAIR SO2 allowance allocations will be the lesser 
of:

[[Page 127]]

    (i) The CAIR SO2 opt-in unit's baseline SO2 
emissions rate (in lb/mmBtu) determined under Sec. 96.284(d) and 
multiplied by 70 percent; or
    (ii) The most stringent State or Federal SO2 emissions 
limitation applicable to the CAIR SO2 opt-in unit at any time 
during the control period for which CAIR SO2 allowances are 
to be allocated.
    (3) The permitting authority will allocate CAIR SO2 
allowances to the CAIR SO2 opt-in unit with a tonnage 
equivalent equal to, or less than by the smallest possible amount, the 
heat input under paragraph (b)(1) of this section, multiplied by the 
SO2 emission rate under paragraph (b)(2) of this section, and 
divided by 2,000 lb/ton.
    (c) Notwithstanding paragraph (b) of this section and if the CAIR 
designated representative requests, and the permitting authority issues 
a CAIR opt-in permit (based on a demonstration of the intent to repower 
stated under Sec. 96.283(a)(5)) providing for, allocation to a CAIR 
SO2 opt-in unit of CAIR SO2 allowances under this 
paragraph (subject to the conditions in Sec. Sec. 96.284(h) and 
96.286(g)), the permitting authority will allocate to the CAIR 
SO2 opt-in unit as follows:
    (1) For each control period in 2010 through 2014 for which the CAIR 
SO2 opt-in unit is to be allocated CAIR SO2 
allowances,
    (i) The heat input (in mmBtu) used for calculating CAIR 
SO2 allowance allocations will be determined as described in 
paragraph (b)(1) of this section.
    (ii) The SO2 emission rate (in lb/mmBtu) used for 
calculating CAIR SO2 allowance allocations will be the lesser 
of:
    (A) The CAIR SO2 opt-in unit's baseline SO2 
emissions rate (in lb/mmBtu) determined under Sec. 96.284(d); or
    (B) The most stringent State or Federal SO2 emissions 
limitation applicable to the CAIR SO2 opt-in unit at any time 
during the control period in which the CAIR SO2 opt-in unit 
enters the CAIR SO2 Trading Program under Sec. 96.284(g).
    (iii) The permitting authority will allocate CAIR SO2 
allowances to the CAIR SO2 opt-in unit with a tonnage 
equivalent equal to, or less than by the smallest possible amount, the 
heat input under paragraph (c)(1)(i) of this section, multiplied by the 
SO2 emission rate under paragraph (c)(1)(ii) of this section, 
and divided by 2,000 lb/ton.
    (2) For each control period in 2015 and thereafter for which the 
CAIR SO2 opt-in unit is to be allocated CAIR SO2 
allowances,
    (i) The heat input (in mmBtu) used for calculating the CAIR 
SO2 allowance allocations will be determined as described in 
paragraph (b)(1) of this section.
    (ii) The SO2 emission rate (in lb/mmBtu) used for 
calculating the CAIR SO2 allowance allocation will be the 
lesser of:
    (A) The CAIR SO2 opt-in unit's baseline SO2 
emissions rate (in lb/mmBtu) determined under Sec. 96.284(d) multiplied 
by 10 percent; or
    (B) The most stringent State or Federal SO2 emissions 
limitation applicable to the CAIR SO2 opt-in unit at any time 
during the control period for which CAIR SO2 allowances are 
to be allocated.
    (iii) The permitting authority will allocate CAIR SO2 
allowances to the CAIR SO2 opt-in unit with a tonnage 
equivalent equal to, or less than by the smallest possible amount, the 
heat input under paragraph (c)(2)(i) of this section, multiplied by the 
SO2 emission rate under paragraph (c)(2)(ii) of this section, 
and divided by 2,000 lb/ton.
    (d) Recordation. (1) The Administrator will record, in the 
compliance account of the source that includes the CAIR SO2 
opt-in unit, the CAIR SO2 allowances allocated by the 
permitting authority to the CAIR SO2 opt-in unit under 
paragraph (a)(1) of this section.
    (2) By December 1 of the control period in which a CAIR 
SO2 opt-in unit enters the CAIR SO2 Trading 
Program under Sec. 96.284(g), and December 1 of each year thereafter, 
the Administrator will record, in the compliance account of the source 
that includes the CAIR SO2 opt-in unit, the CAIR 
SO2 allowances allocated by the permitting authority to the 
CAIR SO2 opt-in unit under paragraph (a)(2) of this section.

[70 FR 25362, May 12, 2005, as amended at 71 FR 25390, Apr. 28, 2006]

Subparts JJJ-ZZZ [Reserved]

[[Page 128]]



  Subpart AAAA_CAIR NOX Ozone Season Trading Program General Provisions

    Source: 70 FR 25382, May 12, 2005, unless otherwise noted.



Sec. 96.301  Purpose.

    This subpart and subparts BBBB through IIII establish the model rule 
comprising general provisions and the designated representative, 
permitting, allowance, monitoring, and opt-in provisions for the State 
Clean Air Interstate Rule (CAIR) NOX Ozone Season Trading 
Program, under section 110 of the Clean Air Act and Sec. 51.123 of this 
chapter, as a means of mitigating interstate transport of ozone and 
nitrogen oxides. The owner or operator of a unit or a source shall 
comply with the requirements of this subpart and subparts BBBB through 
IIII as a matter of federal law only if the State with jurisdiction over 
the unit and the source incorporates by reference such subparts or 
otherwise adopts the requirements of such subparts in accordance with 
Sec. 51.123(aa)(1) or (2), of this chapter, the State submits to the 
Administrator one or more revisions of the State implementation plan 
that include such adoption, and the Administrator approves such 
revisions. If the State adopts the requirements of such subparts in 
accordance with Sec. 51.123(aa)(1) or (2), (bb), or (dd) of this 
chapter, then the State authorizes the Administrator to assist the State 
in implementing the CAIR NOX Ozone Season Trading Program by 
carrying out the functions set forth for the Administrator in such 
subparts.



Sec. 96.302  Definitions.

    The terms used in this subpart and subparts BBBB through IIII shall 
have the meanings set forth in this section as follows:
    Account number means the identification number given by the 
Administrator to each CAIR NOX Ozone Season Allowance 
Tracking System account.
    Acid Rain emissions limitation means a limitation on emissions of 
sulfur dioxide or nitrogen oxides under the Acid Rain Program.
    Acid Rain Program means a multi-state sulfur dioxide and nitrogen 
oxides air pollution control and emission reduction program established 
by the Administrator under title IV of the CAA and parts 72 through 78 
of this chapter.
    Administrator means the Administrator of the United States 
Environmental Protection Agency or the Administrator's duly authorized 
representative.
    Allocate or allocation means, with regard to CAIR NOX 
Ozone Season allowances, the determination by a permitting authority or 
the Administrator of the amount of such CAIR NOX Ozone Season 
allowances to be initially credited to a CAIR NOX Ozone 
Season unit, a new unit set-aside, or other entity.
    Allowance transfer deadline means, for a control period, midnight of 
November 30 (if it is a business day), or midnight of the first business 
day thereafter (if November 30 is not a business day), immediately 
following the control period and is the deadline by which a CAIR 
NOX Ozone Season allowance transfer must be submitted for 
recordation in a CAIR NOX Ozone Season source's compliance 
account in order to be used to meet the source's CAIR NOX 
Ozone Season emissions limitation for such control period in accordance 
with Sec. 96.354.
    Alternate CAIR designated representative means, for a CAIR 
NOX Ozone Season source and each CAIR NOX Ozone 
Season unit at the source, the natural person who is authorized by the 
owners and operators of the source and all such units at the source, in 
accordance with subparts BBBB and IIII of this part, to act on behalf of 
the CAIR designated representative in matters pertaining to the CAIR 
NOX Ozone Season Trading Program. If the CAIR NOX 
Ozone Season source is also a CAIR NOX source, then this 
natural person shall be the same person as the alternate CAIR designated 
representative under the CAIR NOX Annual Trading Program. If 
the CAIR NOX Ozone Season source is also a CAIR 
SO2 source, then this natural person shall be the same person 
as the alternate CAIR designated representative under the CAIR 
SO2 Trading Program. If the CAIR NOX Ozone Season 
source is also subject to

[[Page 129]]

the Acid Rain Program, then this natural person shall be the same person 
as the alternate designated representative under the Acid Rain Program. 
If the CAIR NOX Ozone Season source is also subject to the Hg 
Budget Trading Program, then this natural person shall be the same 
person as the alternate Hg designated representative under the Hg Budget 
Trading Program.
    Automated data acquisition and handling system or DAHS means that 
component of the continuous emission monitoring system, or other 
emissions monitoring system approved for use under subpart HHHH of this 
part, designed to interpret and convert individual output signals from 
pollutant concentration monitors, flow monitors, diluent gas monitors, 
and other component parts of the monitoring system to produce a 
continuous record of the measured parameters in the measurement units 
required by subpart HHHH of this part.
    Biomass means--
    (1) Any organic material grown for the purpose of being converted to 
energy;
    (2) Any organic byproduct of agriculture that can be converted into 
energy; or
    (3) Any material that can be converted into energy and is 
nonmerchantable for other purposes, that is segregated from other 
nonmerchantable material, and that is;
    (i) A forest-related organic resource, including mill residues, 
precommercial thinnings, slash, brush, or byproduct from conversion of 
trees to merchantable material; or
    (ii) A wood material, including pallets, crates, dunnage, 
manufacturing and construction materials (other than pressure-treated, 
chemically-treated, or painted wood products), and landscape or right-
of-way tree trimmings.
    Boiler means an enclosed fossil- or other-fuel-fired combustion 
device used to produce heat and to transfer heat to recirculating water, 
steam, or other medium.
    Bottoming-cycle cogeneration unit means a cogeneration unit in which 
the energy input to the unit is first used to produce useful thermal 
energy and at least some of the reject heat from the useful thermal 
energy application or process is then used for electricity production.
    CAIR authorized account representative means, with regard to a 
general account, a responsible natural person who is authorized, in 
accordance with subparts BBBB, FFFF, and IIII of this part, to transfer 
and otherwise dispose of CAIR NOX Ozone Season allowances 
held in the general account and, with regard to a compliance account, 
the CAIR designated representative of the source.
    CAIR designated representative means, for a CAIR NOX 
Ozone Season source and each CAIR NOX Ozone Season unit at 
the source, the natural person who is authorized by the owners and 
operators of the source and all such units at the source, in accordance 
with subparts BBBB and IIII of this part, to represent and legally bind 
each owner and operator in matters pertaining to the CAIR NOX 
Ozone Season Trading Program. If the CAIR NOX Ozone Season 
source is also a CAIR NOX source, then this natural person 
shall be the same person as the CAIR designated representative under the 
CAIR NOX Annual Trading Program. If the CAIR NOX 
Ozone Season source is also a CAIR SO2 source, then this 
natural person shall be the same person as the CAIR designated 
representative under the CAIR SO2 Trading Program. If the 
CAIR NOX Ozone Season source is also subject to the Acid Rain 
Program, then this natural person shall be the same person as the 
designated representative under the Acid Rain Program. If the CAIR 
NOX Ozone Season source is also subject to the Hg Budget 
Trading Program, then this natural person shall be the same person as 
the Hg designated representative under the Hg Budget Trading Program.
    CAIR NOX Annual Trading Program means a multi-state nitrogen oxides 
air pollution control and emission reduction program approved and 
administered by the Administrator in accordance with subparts AA through 
II of this part and Sec. 51.123(o)(1) or (2) of this chapter or 
established by the Administrator in accordance with subparts AA through 
II of part 97 of this chapter and Sec. Sec. 51.123(p) and 52.35 of this 
chapter, as

[[Page 130]]

a means of mitigating interstate transport of fine particulates and 
nitrogen oxides.
    CAIR NOX Ozone Season allowance means a limited authorization issued 
by a permitting authority or the Administrator under provisions of a 
State implementation plan that are approved under Sec. 51.123(aa)(1) or 
(2) (and (bb)(1)), (bb)(2), (dd), or (ee) of this chapter, or under 
subpart EEEE of part 97 or Sec. 97.388 of this chapter, to emit one ton 
of nitrogen oxides during a control period of the specified calendar 
year for which the authorization is allocated or of any calendar year 
thereafter under the CAIR NOX Ozone Season Trading Program or 
a limited authorization issued by a permitting authority for a control 
period during 2003 through 2008 under the NOX Budget Trading 
Program in accordance with Sec. 51.121(p) of this chapter to emit one 
ton of nitrogen oxides during a control period, provided that the 
provision in Sec. 51.121(b)(2)(ii)(E) of this chapter shall not be used 
in applying this definition and the limited authorization shall not have 
been used to meet the allowance-holding requirement under the 
NOX Budget Trading Program. An authorization to emit nitrogen 
oxides that is not issued under provisions of a State implementation 
plan approved under Sec. 51.123(aa)(1) or (2) (and (bb)(1)), (bb)(2), 
(dd), or (ee) of this chapter or subpart EEEE of part 97 or Sec. 97.388 
of this chapter or under the NOX Budget Trading Program as 
described in the prior sentence shall not be a CAIR NOX Ozone 
Season allowance.
    CAIR NOX Ozone Season allowance deduction or deduct CAIR NOX Ozone 
Season allowances means the permanent withdrawal of CAIR NOX 
Ozone Season allowances by the Administrator from a compliance account, 
e.g., in order to account for a specified number of tons of total 
nitrogen oxides emissions from all CAIR NOX Ozone Season 
units at a CAIR NOX Ozone Season source for a control period, 
determined in accordance with subpart HHHH of this part, or to account 
for excess emissions.
    CAIR NOX Ozone Season Allowance Tracking System means the system by 
which the Administrator records allocations, deductions, and transfers 
of CAIR NOX Ozone Season allowances under the CAIR 
NOX Ozone Season Trading Program. Such allowances will be 
allocated, held, deducted, or transferred only as whole allowances.
    CAIR NOX Ozone Season Allowance Tracking System account means an 
account in the CAIR NOX Ozone Season Allowance Tracking 
System established by the Administrator for purposes of recording the 
allocation, holding, transferring, or deducting of CAIR NOX 
Ozone Season allowances.
    CAIR NOX Ozone Season allowances held or hold CAIR NOX Ozone Season 
allowances means the CAIR NOX Ozone Season allowances 
recorded by the Administrator, or submitted to the Administrator for 
recordation, in accordance with subparts FFFF, GGGG, and IIII of this 
part, in a CAIR NOX Ozone Season Allowance Tracking System 
account.
    CAIR NOX Ozone Season emissions limitation means, for a CAIR 
NOX Ozone Season source, the tonnage equivalent, in 
NOX emissions in a control period, of the CAIR NOX 
Ozone Season allowances available for deduction for the source under 
Sec. 96.354(a) and (b) for the control period.
    CAIR NOX Ozone Season Trading Program means a multi-state nitrogen 
oxides air pollution control and emission reduction program approved and 
administered by the Administrator in accordance with subparts AAAA 
through IIII of this part and Sec. 51.123(aa)(1) or (2) (and (bb)(1)), 
(bb)(2), or (dd) of this chapter or established by the Administrator in 
accordance with subparts AAAA through IIII of part 97 of this chapter 
and Sec. Sec. 51.123(ee) and 52.35 of this chapter, as a means of 
mitigating interstate transport of ozone and nitrogen oxides.
    CAIR NOX Ozone Season source means a source that includes one or 
more CAIR NOX Ozone Season units.
    CAIR NOX Ozone Season unit means a unit that is subject to the CAIR 
NOX Ozone Season Trading Program under Sec. 96.304 and, 
except for purposes of Sec. 96.305 and subpart EEEE of this part, a 
CAIR NOX Ozone Season opt-in unit under subpart IIII of this 
part.
    CAIR NOX source means a source that is subject to the CAIR 
NOX Annual Trading Program.

[[Page 131]]

    CAIR permit means the legally binding and federally enforceable 
written document, or portion of such document, issued by the permitting 
authority under subpart CCCC of this part, including any permit 
revisions, specifying the CAIR NOX Ozone Season Trading 
Program requirements applicable to a CAIR NOX Ozone Season 
source, to each CAIR NOX Ozone Season unit at the source, and 
to the owners and operators and the CAIR designated representative of 
the source and each such unit.
    CAIR SO2 source means a source that is subject to the CAIR 
SO2 Trading Program.
    CAIR SO2 Trading Program means a multi-state sulfur dioxide air 
pollution control and emission reduction program approved and 
administered by the Administrator in accordance with subparts AAA 
through III of this part and Sec. 51.124(o)(1) or (2) of this chapter 
or established by the Administrator in accordance with subparts AAA 
through III of part 97 of this chapter and Sec. Sec. 51.124(r) and 
52.36 of this chapter, as a means of mitigating interstate transport of 
fine particulates and sulfur dioxide.
    Clean Air Act or CAA means the Clean Air Act, 42 U.S.C. 7401, et 
seq.
    Coal means any solid fuel classified as anthracite, bituminous, 
subbituminous, or lignite.
    Coal-derived fuel means any fuel (whether in a solid, liquid, or 
gaseous state) produced by the mechanical, thermal, or chemical 
processing of coal.
    Coal-fired means:
    (1) Except for purposes of subpart EEEE of this part, combusting any 
amount of coal or coal-derived fuel, alone or in combination with any 
amount of any other fuel, during any year; or
    (2) For purposes of subpart EEEE of this part, combusting any amount 
of coal or coal-derived fuel, alone or in combination with any amount of 
any other fuel, during a specified year.
    Cogeneration unit means a stationary, fossil-fuel-fired boiler or 
stationary, fossil-fuel-fired combustion turbine:
    (1) Having equipment used to produce electricity and useful thermal 
energy for industrial, commercial, heating, or cooling purposes through 
the sequential use of energy; and
    (2) Producing during the 12-month period starting on the date the 
unit first produces electricity and during any calendar year after the 
calendar year in which the unit first produces electricity--
    (i) For a topping-cycle cogeneration unit,
    (A) Useful thermal energy not less than 5 percent of total energy 
output; and
    (B) Useful power that, when added to one-half of useful thermal 
energy produced, is not less then 42.5 percent of total energy input, if 
useful thermal energy produced is 15 percent or more of total energy 
output, or not less than 45 percent of total energy input, if useful 
thermal energy produced is less than 15 percent of total energy output.
    (ii) For a bottoming-cycle cogeneration unit, useful power not less 
than 45 percent of total energy input;
    (3) Provided that the total energy input under paragraphs (2)(i)(B) 
and (2)(ii) of this definition shall equal the unit's total energy input 
from all fuel except biomass if the unit is a boiler.
    Combustion turbine means:
    (1) An enclosed device comprising a compressor, a combustor, and a 
turbine and in which the flue gas resulting from the combustion of fuel 
in the combustor passes through the turbine, rotating the turbine; and
    (2) If the enclosed device under paragraph (1) of this definition is 
combined cycle, any associated duct burner, heat recovery steam 
generator, and steam turbine.
    Commence commercial operation means, with regard to a unit:
    (1) To have begun to produce steam, gas, or other heated medium used 
to generate electricity for sale or use, including test generation, 
except as provided in Sec. 96.305 and Sec. 96.384(h).
    (i) For a unit that is a CAIR NOX Ozone Season unit under 
Sec. 96.304 on the later of November 15, 1990 or the date the unit 
commences commercial operation as defined in paragraph (1) of this 
definition and that subsequently undergoes a physical change (other than 
replacement of the unit by a unit at the same source), such date shall 
remain the date of commencement of

[[Page 132]]

commercial operation of the unit, which shall continue to be treated as 
the same unit.
    (ii) For a unit that is a CAIR NOX Ozone Season unit 
under Sec. 96.304 on the later of November 15, 1990 or the date the 
unit commences commercial operation as defined in paragraph (1) of this 
definition and that is subsequently replaced by a unit at the same 
source (e.g., repowered), such date shall remain the replaced unit's 
date of commencement of commercial operation, and the replacement unit 
shall be treated as a separate unit with a separate date for 
commencement of commercial operation as defined in paragraph (1) or (2) 
of this definition as appropriate.
    (2) Notwithstanding paragraph (1) of this definition and except as 
provided in Sec. 96.305, for a unit that is not a CAIR NOX 
Ozone Season unit under Sec. 96.304 on the later of November 15, 1990 
or the date the unit commences commercial operation as defined in 
paragraph (1) of this definition, the unit's date for commencement of 
commercial operation shall be the date on which the unit becomes a CAIR 
NOX Ozone Season unit under Sec. 96.304.
    (i) For a unit with a date for commencement of commercial operation 
as defined in paragraph (2) of this definition and that subsequently 
undergoes a physical change (other than replacement of the unit by a 
unit at the same source), such date shall remain the date of 
commencement of commercial operation of the unit, which shall continue 
to be treated as the same unit.
    (ii) For a unit with a date for commencement of commercial operation 
as defined in paragraph (2) of this definition and that is subsequently 
replaced by a unit at the same source (e.g., repowered), such date shall 
remain the replaced unit's date of commencement of commercial operation, 
and the replacement unit shall be treated as a separate unit with a 
separate date for commencement of commercial operation as defined in 
paragraph (1) or (2) of this definition as appropriate.
    Commence operation means:
    (1) To have begun any mechanical, chemical, or electronic process, 
including, with regard to a unit, start-up of a unit's combustion 
chamber, except as provided in Sec. 96.384(h).
    (2) For a unit that undergoes a physical change (other than 
replacement of the unit by a unit at the same source) after the date the 
unit commences operation as defined in paragraph (1) of this definition, 
such date shall remain the date of commencement of operation of the 
unit, which shall continue to be treated as the same unit.
    (3) For a unit that is replaced by a unit at the same source (e.g., 
repowered) after the date the unit commences operation as defined in 
paragraph (1) of this definition, such date shall remain the replaced 
unit's date of commencement of operation, and the replacement unit shall 
be treated as a separate unit with a separate date for commencement of 
operation as defined in paragraph (1), (2), or (3) of this definition as 
appropriate, except as provided in Sec. 96.384(h).
    Common stack means a single flue through which emissions from 2 or 
more units are exhausted.
    Compliance account means a CAIR NOX Ozone Season 
Allowance Tracking System account, established by the Administrator for 
a CAIR NOX Ozone Season source under subpart FFFF or IIII of 
this part, in which any CAIR NOX Ozone Season allowance 
allocations for the CAIR NOX Ozone Season units at the source 
are initially recorded and in which are held any CAIR NOX 
Ozone Season allowances available for use for a control period in order 
to meet the source's CAIR NOX Ozone Season emissions 
limitation in accordance with Sec. 96.354.
    Continuous emission monitoring system or CEMS means the equipment 
required under subpart HHHH of this part to sample, analyze, measure, 
and provide, by means of readings recorded at least once every 15 
minutes (using an automated data acquisition and handling system 
(DAHS)), a permanent record of nitrogen oxides emissions, stack gas 
volumetric flow rate, stack gas moisture content, and oxygen or carbon 
dioxide concentration (as applicable), in a manner consistent with part 
75 of this chapter. The following systems are the principal types of 
continuous emission monitoring systems required under subpart HHHH of 
this part:

[[Page 133]]

    (1) A flow monitoring system, consisting of a stack flow rate 
monitor and an automated data acquisition and handling system and 
providing a permanent, continuous record of stack gas volumetric flow 
rate, in standard cubic feet per hour (scfh);
    (2) A nitrogen oxides concentration monitoring system, consisting of 
a NOX pollutant concentration monitor and an automated data 
acquisition and handling system and providing a permanent, continuous 
record of NOX emissions, in parts per million (ppm);
    (3) A nitrogen oxides emission rate (or NOX-diluent) 
monitoring system, consisting of a NOX pollutant 
concentration monitor, a diluent gas (CO2 or O2) 
monitor, and an automated data acquisition and handling system and 
providing a permanent, continuous record of NOX 
concentration, in parts per million (ppm), diluent gas concentration, in 
percent CO2 or O2, and NOX emission 
rate, in pounds per million British thermal units (lb/mmBtu);
    (4) A moisture monitoring system, as defined in Sec. 75.11(b)(2) of 
this chapter and providing a permanent, continuous record of the stack 
gas moisture content, in percent H2O;
    (5) A carbon dioxide monitoring system, consisting of a 
CO2 pollutant concentration monitor (or an oxygen monitor 
plus suitable mathematical equations from which the CO2 
concentration is derived) and an automated data acquisition and handling 
system and providing a permanent, continuous record of CO2 
emissions, in percent CO2; and
    (6) An oxygen monitoring system, consisting of an O2 
concentration monitor and an automated data acquisition and handling 
system and providing a permanent, continuous record of O2 in 
percent O2.
    Control period or ozone season means the period beginning May 1 of a 
calendar year, except as provided in Sec. 96.306(c)(2), and ending on 
September 30 of the same year, inclusive.
    Emissions means air pollutants exhausted from a unit or source into 
the atmosphere, as measured, recorded, and reported to the Administrator 
by the CAIR designated representative and as determined by the 
Administrator in accordance with subpart HHHH of this part.
    Excess emissions means any ton of nitrogen oxides emitted by the 
CAIR NOX Ozone Season units at a CAIR NOX Ozone 
Season source during a control period that exceeds the CAIR 
NOX Ozone Season emissions limitation for the source.
    Fossil fuel means natural gas, petroleum, coal, or any form of 
solid, liquid, or gaseous fuel derived from such material.
    Fossil-fuel-fired means, with regard to a unit, combusting any 
amount of fossil fuel in any calendar year.
    Fuel oil means any petroleum-based fuel (including diesel fuel or 
petroleum derivatives such as oil tar) and any recycled or blended 
petroleum products or petroleum by-products used as a fuel whether in a 
liquid, solid, or gaseous state.
    General account means a CAIR NOX Ozone Season Allowance 
Tracking System account, established under subpart FFFF of this part, 
that is not a compliance account.
    Generator means a device that produces electricity.
    Gross electrical output means, with regard to a cogeneration unit, 
electricity made available for use, including any such electricity used 
in the power production process (which process includes, but is not 
limited to, any on-site processing or treatment of fuel combusted at the 
unit and any on-site emission controls).
    Heat input means, with regard to a specified period of time, the 
product (in mmBtu/time) of the gross calorific value of the fuel (in 
Btu/lb) divided by 1,000,000 Btu/mmBtu and multiplied by the fuel feed 
rate into a combustion device (in lb of fuel/time), as measured, 
recorded, and reported to the Administrator by the CAIR designated 
representative and determined by the Administrator in accordance with 
subpart HHHH of this part and excluding the heat derived from preheated 
combustion air, recirculated flue gases, or exhaust from other sources.
    Heat input rate means the amount of heat input (in mmBtu) divided by 
unit operating time (in hr) or, with regard to a specific fuel, the 
amount of heat input attributed to the fuel (in mmBtu)

[[Page 134]]

divided by the unit operating time (in hr) during which the unit 
combusts the fuel.
    Life-of-the-unit, firm power contractual arrangement means a unit 
participation power sales agreement under which a utility or industrial 
customer reserves, or is entitled to receive, a specified amount or 
percentage of nameplate capacity and associated energy generated by any 
specified unit and pays its proportional amount of such unit's total 
costs, pursuant to a contract:
    (1) For the life of the unit;
    (2) For a cumulative term of no less than 30 years, including 
contracts that permit an election for early termination; or
    (3) For a period no less than 25 years or 70 percent of the economic 
useful life of the unit determined as of the time the unit is built, 
with option rights to purchase or release some portion of the nameplate 
capacity and associated energy generated by the unit at the end of the 
period.
    Maximum design heat input means the maximum amount of fuel per hour 
(in Btu/hr) that a unit is capable of combusting on a steady state basis 
as of the initial installation of the unit as specified by the 
manufacturer of the unit.
    Monitoring system means any monitoring system that meets the 
requirements of subpart HHHH of this part, including a continuous 
emissions monitoring system, an alternative monitoring system, or an 
excepted monitoring system under part 75 of this chapter.
    Most stringent State or Federal NOX emissions limitation 
means, with regard to a unit, the lowest NOX emissions 
limitation (in terms of lb/mmBtu) that is applicable to the unit under 
State or Federal law, regardless of the averaging period to which the 
emissions limitation applies.
    Nameplate capacity means, starting from the initial installation of 
a generator, the maximum electrical generating output (in MWe) that the 
generator is capable of producing on a steady state basis and during 
continuous operation (when not restricted by seasonal or other 
deratings) as of such installation as specified by the manufacturer of 
the generator or, starting from the completion of any subsequent 
physical change in the generator resulting in an increase in the maximum 
electrical generating output (in MWe) that the generator is capable of 
producing on a steady state basis and during continuous operation (when 
not restricted by seasonal or other deratings), such increased maximum 
amount as of such completion as specified by the person conducting the 
physical change.
    Oil-fired means, for purposes of subpart EEEE of this part, 
combusting fuel oil for more than 15.0 percent of the annual heat input 
in a specified year and not qualifying as coal-fired.
    Operator means any person who operates, controls, or supervises a 
CAIR NOX Ozone Season unit or a CAIR NOX Ozone 
Season source and shall include, but not be limited to, any holding 
company, utility system, or plant manager of such a unit or source.
    Owner means any of the following persons:
    (1) With regard to a CAIR NOX Ozone Season source or a 
CAIR NOX Ozone Season unit at a source, respectively:
    (i) Any holder of any portion of the legal or equitable title in a 
CAIR NOX Ozone Season unit at the source or the CAIR 
NOX Ozone Season unit;
    (ii) Any holder of a leasehold interest in a CAIR NOX 
Ozone Season unit at the source or the CAIR NOX Ozone Season 
unit; or
    (iii) Any purchaser of power from a CAIR NOX Ozone Season 
unit at the source or the CAIR NOX Ozone Season unit under a 
life-of-the-unit, firm power contractual arrangement; provided that, 
unless expressly provided for in a leasehold agreement, owner shall not 
include a passive lessor, or a person who has an equitable interest 
through such lessor, whose rental payments are not based (either 
directly or indirectly) on the revenues or income from such CAIR 
NOX Ozone Season unit; or
    (2) With regard to any general account, any person who has an 
ownership interest with respect to the CAIR NOX Ozone Season 
allowances held in the general account and who is subject to the binding 
agreement for the CAIR authorized account representative to

[[Page 135]]

represent the person's ownership interest with respect to CAIR 
NOX Ozone Season allowances.
    Permitting authority means the State air pollution control agency, 
local agency, other State agency, or other agency authorized by the 
Administrator to issue or revise permits to meet the requirements of the 
CAIR NOX Ozone Season Trading Program or, if no such agency 
has been so authorized, the Administrator.
    Potential electrical output capacity means 33 percent of a unit's 
maximum design heat input, divided by 3,413 Btu/kWh, divided by 1,000 
kWh/MWh, and multiplied by 8,760 hr/yr.
    Receive or receipt of means, when referring to the permitting 
authority or the Administrator, to come into possession of a document, 
information, or correspondence (whether sent in hard copy or by 
authorized electronic transmission), as indicated in an official log, or 
by a notation made on the document, information, or correspondence, by 
the permitting authority or the Administrator in the regular course of 
business.
    Recordation, record, or recorded means, with regard to CAIR 
NOX Ozone Season allowances, the movement of CAIR 
NOX Ozone Season allowances by the Administrator into or 
between CAIR NOX Ozone Season Allowance Tracking System 
accounts, for purposes of allocation, transfer, or deduction.
    Reference method means any direct test method of sampling and 
analyzing for an air pollutant as specified in Sec. 75.22 of this 
chapter.
    Replacement, replace, or replaced means, with regard to a unit, the 
demolishing of a unit, or the permanent shutdown and permanent disabling 
of a unit, and the construction of another unit (the replacement unit) 
to be used instead of the demolished or shutdown unit (the replaced 
unit).
    Repowered means, with regard to a unit, replacement of a coal-fired 
boiler with one of the following coal-fired technologies at the same 
source as the coal-fired boiler:
    (1) Atmospheric or pressurized fluidized bed combustion;
    (2) Integrated gasification combined cycle;
    (3) Magnetohydrodynamics;
    (4) Direct and indirect coal-fired turbines;
    (5) Integrated gasification fuel cells; or
    (6) As determined by the Administrator in consultation with the 
Secretary of Energy, a derivative of one or more of the technologies 
under paragraphs (1) through (5) of this definition and any other coal-
fired technology capable of controlling multiple combustion emissions 
simultaneously with improved boiler or generation efficiency and with 
significantly greater waste reduction relative to the performance of 
technology in widespread commercial use as of January 1, 2005.
    Serial number means, for a CAIR NOX Ozone Season 
allowance, the unique identification number assigned to each CAIR 
NOX Ozone Season allowance by the Administrator.
    Sequential use of energy means:
    (1) For a topping-cycle cogeneration unit, the use of reject heat 
from electricity production in a useful thermal energy application or 
process; or
    (2) For a bottoming-cycle cogeneration unit, the use of reject heat 
from useful thermal energy application or process in electricity 
production.
    Solid waste incineration unit means a stationary, fossil-fuel-fired 
boiler or stationary, fossil-fuel-fired combustion turbine that is a 
``solid waste incineration unit'' as defined in section 129(g)(1) of the 
Clean Air Act.
    Source means all buildings, structures, or installations located in 
one or more contiguous or adjacent properties under common control of 
the same person or persons. For purposes of section 502(c) of the Clean 
Air Act, a ``source,'' including a ``source'' with multiple units, shall 
be considered a single ``facility.''
    State means one of the States or the District of Columbia that 
adopts the CAIR NOX Ozone Season Trading Program pursuant to 
Sec. 51.123(aa)(1) or (2), (bb), or (dd) of this chapter.
    Submit or serve means to send or transmit a document, information, 
or correspondence to the person specified in accordance with the 
applicable regulation:
    (1) In person;

[[Page 136]]

    (2) By United States Postal Service; or
    (3) By other means of dispatch or transmission and delivery. 
Compliance with any ``submission'' or ``service'' deadline shall be 
determined by the date of dispatch, transmission, or mailing and not the 
date of receipt.
    Title V operating permit means a permit issued under title V of the 
Clean Air Act and part 70 or part 71 of this chapter.
    Title V operating permit regulations means the regulations that the 
Administrator has approved or issued as meeting the requirements of 
title V of the Clean Air Act and part 70 or 71 of this chapter.
    Ton means 2,000 pounds. For the purpose of determining compliance 
with the CAIR NOX Ozone Season emissions limitation, total 
tons of nitrogen oxides emissions for a control period shall be 
calculated as the sum of all recorded hourly emissions (or the mass 
equivalent of the recorded hourly emission rates) in accordance with 
subpart HHHH of this part, but with any remaining fraction of a ton 
equal to or greater than 0.50 tons deemed to equal one ton and any 
remaining fraction of a ton less than 0.50 tons deemed to equal zero 
tons.
    Topping-cycle cogeneration unit means a cogeneration unit in which 
the energy input to the unit is first used to produce useful power, 
including electricity, and at least some of the reject heat from the 
electricity production is then used to provide useful thermal energy.
    Total energy input means, with regard to a cogeneration unit, total 
energy of all forms supplied to the cogeneration unit, excluding energy 
produced by the cogeneration unit itself. Each form of energy supplied 
shall be measured by the lower heating value of that form of energy 
calculated as follows:

LHV = HHV-10.55(W + 9H)

Where:

LHV = lower heating value of fuel in Btu/lb,
HHV = higher heating value of fuel in Btu/lb,
W = Weight % of moisture in fuel, and
H = Weight % of hydrogen in fuel.

    Total energy output means, with regard to a cogeneration unit, the 
sum of useful power and useful thermal energy produced by the 
cogeneration unit.
    Unit means a stationary, fossil-fuel-fired boiler or combustion 
turbine or other stationary, fossil-fuel-fired combustion device.
    Unit operating day means a calendar day in which a unit combusts any 
fuel.
    Unit operating hour or hour of unit operation means an hour in which 
a unit combusts any fuel.
    Useful power means, with regard to a cogeneration unit, electricity 
or mechanical energy made available for use, excluding any such energy 
used in the power production process (which process includes, but is not 
limited to, any on-site processing or treatment of fuel combusted at the 
unit and any on-site emission controls).
    Useful thermal energy means, with regard to a cogeneration unit, 
thermal energy that is:
    (1) Made available to an industrial or commercial process (not a 
power production process), excluding any heat contained in condensate 
return or makeup water;
    (2) Used in a heating application (e.g., space heating or domestic 
hot water heating); or
    (3) Used in a space cooling application (i.e., thermal energy used 
by an absorption chiller).
    Utility power distribution system means the portion of an 
electricity grid owned or operated by a utility and dedicated to 
delivering electricity to customers.

[70 FR 25382, May 12, 2005, as amended at 71 FR 25390, Apr. 28, 2006; 71 
FR 74794, Dec. 13, 2006; 72 FR 59206, Oct. 19, 2007]



Sec. 96.303  Measurements, abbreviations, and acronyms.

    Measurements, abbreviations, and acronyms used in this subpart and 
subparts BBBB through IIII are defined as follows:

Btu--British thermal unit
CO2--carbon dioxide
H2O--water
Hg--mercury
hr--hour
kW--kilowatt electrical
kWh--kilowatt hour
lb--pound
mmBtu--million Btu
MWe--megawatt electrical
MWh--megawatt hour

[[Page 137]]

NOX--nitrogen oxides
O2--oxygen
ppm--parts per million
scfh--standard cubic feet per hour
SO2--sulfur dioxide
yr--year

[71 FR 25392, Apr. 28, 2006]



Sec. 96.304  Applicability.

    (a) Except as provided in paragraph (b) of this section:
    (1) The following units in a State shall be CAIR NOX 
Ozone Season units, and any source that includes one or more such units 
shall be a CAIR NOX Ozone Season source, subject to the 
requirements of this subpart and subparts BBBB through HHHH of this 
part: any stationary, fossil-fuel-fired boiler or stationary, fossil-
fuel-fired combustion turbine serving at any time, since the later of 
November 15, 1990 or the start-up of the unit's combustion chamber, a 
generator with nameplate capacity of more than 25 MWe producing 
electricity for sale.
    (2) If a stationary boiler or stationary combustion turbine that, 
under paragraph (a)(1) of this section, is not a CAIR NOX 
Ozone Season unit begins to combust fossil fuel or to serve a generator 
with nameplate capacity of more than 25 MWe producing electricity for 
sale, the unit shall become a CAIR NOX Ozone Season unit as 
provided in paragraph (a)(1) of this section on the first date on which 
it both combusts fossil fuel and serves such generator.
    (b) The units in a State that meet the requirements set forth in 
paragraph (b)(1)(i), (b)(2)(i), or (b)(2)(ii) of this section shall not 
be CAIR NOX Ozone Season units:
    (1)(i) Any unit that is a CAIR NOX Ozone Season unit 
under paragraph (a)(1) or (2) of this section:
    (A) Qualifying as a cogeneration unit during the 12-month period 
starting on the date the unit first produces electricity and continuing 
to qualify as a cogeneration unit; and
    (B) Not serving at any time, since the later of November 15, 1990 or 
the start-up of the unit's combustion chamber, a generator with 
nameplate capacity of more than 25 MWe supplying in any calendar year 
more than one-third of the unit's potential electric output capacity or 
219,000 MWh, whichever is greater, to any utility power distribution 
system for sale.
    (ii) If a unit qualifies as a cogeneration unit during the 12-month 
period starting on the date the unit first produces electricity and 
meets the requirements of paragraphs (b)(1)(i) of this section for at 
least one calendar year, but subsequently no longer meets all such 
requirements, the unit shall become a CAIR NOX Ozone Season 
unit starting on the earlier of January 1 after the first calendar year 
during which the unit first no longer qualifies as a cogeneration unit 
or January 1 after the first calendar year during which the unit no 
longer meets the requirements of paragraph (b)(1)(i)(B) of this section.
    (2)(i) Any unit that is a CAIR NOX Ozone Season unit 
under paragraph (a)(1) or (2) of this section commencing operation 
before January 1, 1985:
    (A) Qualifying as a solid waste incineration unit; and
    (B) With an average annual fuel consumption of non-fossil fuel for 
1985-1987 exceeding 80 percent (on a Btu basis) and an average annual 
fuel consumption of non-fossil fuel for any 3 consecutive calendar years 
after 1990 exceeding 80 percent (on a Btu basis).
    (ii) Any unit that is a CAIR NOX Ozone Season unit under 
paragraph (a)(1) or (2) of this section commencing operation on or after 
January 1, 1985:
    (A) Qualifying as a solid waste incineration unit; and
    (B) With an average annual fuel consumption of non-fossil fuel for 
the first 3 calendar years of operation exceeding 80 percent (on a Btu 
basis) and an average annual fuel consumption of non-fossil fuel for any 
3 consecutive calendar years after 1990 exceeding 80 percent (on a Btu 
basis).
    (iii) If a unit qualifies as a solid waste incineration unit and 
meets the requirements of paragraph (b)(2)(i) or (ii) of this section 
for at least 3 consecutive calendar years, but subsequently no longer 
meets all such requirements, the unit shall become a CAIR NOX 
Ozone Season unit starting on the earlier of January 1 after the first 
calendar year during which the unit first no longer qualifies as a solid 
waste incineration unit or January 1 after the first 3 consecutive 
calendar

[[Page 138]]

years after 1990 for which the unit has an average annual fuel 
consumption of fossil fuel of 20 percent or more.

[71 FR 25392, Apr. 28, 2006, as amended at 71 FR 74794, Dec. 13, 2006]



Sec. 96.305  Retired unit exemption.

    (a)(1) Any CAIR NOX Ozone Season unit that is permanently 
retired and is not a CAIR NOX Ozone Season opt-in unit under 
subpart IIII of this part shall be exempt from the CAIR NOX 
Ozone Season Trading Program, except for the provisions of this section, 
Sec. 96.302, Sec. 96.303, Sec. 96.304, Sec. 96.306(c)(4) through 
(7), Sec. 96.307, Sec. 96.308, and subparts BBBB and EEEE through GGGG 
of this part.
    (2) The exemption under paragraph (a)(1) of this section shall 
become effective the day on which the CAIR NOX Ozone Season 
unit is permanently retired. Within 30 days of the unit's permanent 
retirement, the CAIR designated representative shall submit a statement 
to the permitting authority otherwise responsible for administering any 
CAIR permit for the unit and shall submit a copy of the statement to the 
Administrator. The statement shall state, in a format prescribed by the 
permitting authority, that the unit was permanently retired on a 
specific date and will comply with the requirements of paragraph (b) of 
this section.
    (3) After receipt of the statement under paragraph (a)(2) of this 
section, the permitting authority will amend any permit under subpart 
CCCC of this part covering the source at which the unit is located to 
add the provisions and requirements of the exemption under paragraphs 
(a)(1) and (b) of this section.
    (b) Special provisions. (1) A unit exempt under paragraph (a) of 
this section shall not emit any nitrogen oxides, starting on the date 
that the exemption takes effect.
    (2) The permitting authority will allocate CAIR NOX Ozone 
Season allowances under subpart EEEE of this part to a unit exempt under 
paragraph (a) of this section.
    (3) For a period of 5 years from the date the records are created, 
the owners and operators of a unit exempt under paragraph (a) of this 
section shall retain, at the source that includes the unit, records 
demonstrating that the unit is permanently retired. The 5-year period 
for keeping records may be extended for cause, at any time before the 
end of the period, in writing by the permitting authority or the 
Administrator. The owners and operators bear the burden of proof that 
the unit is permanently retired.
    (4) The owners and operators and, to the extent applicable, the CAIR 
designated representative of a unit exempt under paragraph (a) of this 
section shall comply with the requirements of the CAIR NOX 
Ozone Season Trading Program concerning all periods for which the 
exemption is not in effect, even if such requirements arise, or must be 
complied with, after the exemption takes effect.
    (5) A unit exempt under paragraph (a) of this section and located at 
a source that is required, or but for this exemption would be required, 
to have a title V operating permit shall not resume operation unless the 
CAIR designated representative of the source submits a complete CAIR 
permit application under Sec. 96.322 for the unit not less than 18 
months (or such lesser time provided by the permitting authority) before 
the later of January 1, 2009 or the date on which the unit resumes 
operation.
    (6) On the earlier of the following dates, a unit exempt under 
paragraph (a) of this section shall lose its exemption:
    (i) The date on which the CAIR designated representative submits a 
CAIR permit application for the unit under paragraph (b)(5) of this 
section;
    (ii) The date on which the CAIR designated representative is 
required under paragraph (b)(5) of this section to submit a CAIR permit 
application for the unit; or
    (iii) The date on which the unit resumes operation, if the CAIR 
designated representative is not required to submit a CAIR permit 
application for the unit.
    (7) For the purpose of applying monitoring, reporting, and 
recordkeeping requirements under subpart HHHH of this part, a unit that 
loses its exemption under paragraph (a) of this section shall be treated 
as a unit that commences commercial operation on the

[[Page 139]]

first date on which the unit resumes operation.

[70 FR 25382, May 12, 2005, as amended at 71 FR 25393, Apr. 28, 2006]



Sec. 96.306  Standard requirements.

    (a) Permit requirements. (1) The CAIR designated representative of 
each CAIR NOX Ozone Season source required to have a title V 
operating permit and each CAIR NOX Ozone Season unit required 
to have a title V operating permit at the source shall:
    (i) Submit to the permitting authority a complete CAIR permit 
application under Sec. 96.322 in accordance with the deadlines 
specified in Sec. 96.321; and
    (ii) Submit in a timely manner any supplemental information that the 
permitting authority determines is necessary in order to review a CAIR 
permit application and issue or deny a CAIR permit.
    (2) The owners and operators of each CAIR NOX Ozone 
Season source required to have a title V operating permit and each CAIR 
NOX Ozone Season unit required to have a title V operating 
permit at the source shall have a CAIR permit issued by the permitting 
authority under subpart CCCC of this part for the source and operate the 
source and the unit in compliance with such CAIR permit.
    (3) Except as provided in subpart IIII of this part, the owners and 
operators of a CAIR NOX Ozone Season source that is not 
otherwise required to have a title V operating permit and each CAIR 
NOX Ozone Season unit that is not otherwise required to have 
a title V operating permit are not required to submit a CAIR permit 
application, and to have a CAIR permit, under subpart CCCC of this part 
for such CAIR NOX Ozone Season source and such CAIR 
NOX Ozone Season unit.
    (b) Monitoring, reporting, and recordkeeping requirements. (1) The 
owners and operators, and the CAIR designated representative, of each 
CAIR NOX Ozone Season source and each CAIR NOX 
Ozone Season unit at the source shall comply with the monitoring, 
reporting, and recordkeeping requirements of subpart HHHH of this part.
    (2) The emissions measurements recorded and reported in accordance 
with subpart HHHH of this part shall be used to determine compliance by 
each CAIR NOX Ozone Season source with the CAIR 
NOX Ozone Season emissions limitation under paragraph (c) of 
this section.
    (c) Nitrogen oxides ozone season emission requirements. (1) As of 
the allowance transfer deadline for a control period, the owners and 
operators of each CAIR NOX Ozone Season source and each CAIR 
NOX Ozone Season unit at the source shall hold, in the 
source's compliance account, CAIR NOX Ozone Season allowances 
available for compliance deductions for the control period under Sec. 
96.354(a) in an amount not less than the tons of total nitrogen oxides 
emissions for the control period from all CAIR NOX Ozone 
Season units at the source, as determined in accordance with subpart 
HHHH of this part.
    (2) A CAIR NOX Ozone Season unit shall be subject to the 
requirements under paragraph (c)(1) of this section for the control 
period starting on the later of May 1, 2009 or the deadline for meeting 
the unit's monitor certification requirements under Sec. 96.370(b)(1), 
(2), (3), or (7) and for each control period thereafter.
    (3) A CAIR NOX Ozone Season allowance shall not be 
deducted, for compliance with the requirements under paragraph (c)(1) of 
this section, for a control period in a calendar year before the year 
for which the CAIR NOX Ozone Season allowance was allocated.
    (4) CAIR NOX Ozone Season allowances shall be held in, 
deducted from, or transferred into or among CAIR NOX Ozone 
Season Allowance Tracking System accounts in accordance with subparts 
FFFF, GGGG, and IIII of this part.
    (5) A CAIR NOX Ozone Season allowance is a limited 
authorization to emit one ton of nitrogen oxides in accordance with the 
CAIR NOX Ozone Season Trading Program. No provision of the 
CAIR NOX Ozone Season Trading Program, the CAIR permit 
application, the CAIR permit, or an exemption under Sec. 96.305 and no 
provision of law shall be construed to limit the authority of the State 
or the United States to terminate or limit such authorization.
    (6) A CAIR NOX Ozone Season allowance does not constitute 
a property right.

[[Page 140]]

    (7) Upon recordation by the Administrator under subpart FFFF, GGGG, 
or IIII of this part, every allocation, transfer, or deduction of a CAIR 
NOX Ozone Season allowance to or from a CAIR NOX 
Ozone Season source's compliance account is incorporated automatically 
in any CAIR permit of the source.
    (d) Excess emissions requirements. If a CAIR NOX Ozone 
Season source emits nitrogen oxides during any control period in excess 
of the CAIR NOX Ozone Season emissions limitation, then:
    (1) The owners and operators of the source and each CAIR 
NOX Ozone Season unit at the source shall surrender the CAIR 
NOX Ozone Season allowances required for deduction under 
Sec. 96.354(d)(1) and pay any fine, penalty, or assessment or comply 
with any other remedy imposed, for the same violations, under the Clean 
Air Act or applicable State law; and
    (2) Each ton of such excess emissions and each day of such control 
period shall constitute a separate violation of this subpart, the Clean 
Air Act, and applicable State law.
    (e) Recordkeeping and reporting requirements. (1) Unless otherwise 
provided, the owners and operators of the CAIR NOX Ozone 
Season source and each CAIR NOX Ozone Season unit at the 
source shall keep on site at the source each of the following documents 
for a period of 5 years from the date the document is created. This 
period may be extended for cause, at any time before the end of 5 years, 
in writing by the permitting authority or the Administrator.
    (i) The certificate of representation under Sec. 96.313 for the 
CAIR designated representative for the source and each CAIR 
NOX Ozone Season unit at the source and all documents that 
demonstrate the truth of the statements in the certificate of 
representation; provided that the certificate and documents shall be 
retained on site at the source beyond such 5-year period until such 
documents are superseded because of the submission of a new certificate 
of representation under Sec. 96.313 changing the CAIR designated 
representative.
    (ii) All emissions monitoring information, in accordance with 
subpart HHHH of this part, provided that to the extent that subpart HHHH 
of this part provides for a 3-year period for recordkeeping, the 3-year 
period shall apply.
    (iii) Copies of all reports, compliance certifications, and other 
submissions and all records made or required under the CAIR 
NOX Ozone Season Trading Program.
    (iv) Copies of all documents used to complete a CAIR permit 
application and any other submission under the CAIR NOX Ozone 
Season Trading Program or to demonstrate compliance with the 
requirements of the CAIR NOX Ozone Season Trading Program.
    (2) The CAIR designated representative of a CAIR NOX 
Ozone Season source and each CAIR NOX Ozone Season unit at 
the source shall submit the reports required under the CAIR 
NOX Ozone Season Trading Program, including those under 
subpart HHHH of this part.
    (f) Liability. (1) Each CAIR NOX Ozone Season source and 
each CAIR NOX Ozone Season unit shall meet the requirements 
of the CAIR NOX Ozone Season Trading Program.
    (2) Any provision of the CAIR NOX Ozone Season Trading 
Program that applies to a CAIR NOX Ozone Season source or the 
CAIR designated representative of a CAIR NOX Ozone Season 
source shall also apply to the owners and operators of such source and 
of the CAIR NOX Ozone Season units at the source.
    (3) Any provision of the CAIR NOX Ozone Season Trading 
Program that applies to a CAIR NOX Ozone Season unit or the 
CAIR designated representative of a CAIR NOX Ozone Season 
unit shall also apply to the owners and operators of such unit.
    (g) Effect on other authorities. No provision of the CAIR 
NOX Ozone Season Trading Program, a CAIR permit application, 
a CAIR permit, or an exemption under Sec. 96.305 shall be construed as 
exempting or excluding the owners and operators, and the CAIR designated 
representative, of a CAIR NOX Ozone Season source or CAIR 
NOX Ozone Season unit from compliance with any other 
provision of the applicable, approved State implementation plan, a

[[Page 141]]

federally enforceable permit, or the Clean Air Act.

[70 FR 25382, May 12, 2005, as amended at 71 FR 25393, Apr. 28, 2006]



Sec. 96.307  Computation of time.

    (a) Unless otherwise stated, any time period scheduled, under the 
CAIR NOX Ozone Season Trading Program, to begin on the 
occurrence of an act or event shall begin on the day the act or event 
occurs.
    (b) Unless otherwise stated, any time period scheduled, under the 
CAIR NOX Ozone Season Trading Program, to begin before the 
occurrence of an act or event shall be computed so that the period ends 
the day before the act or event occurs.
    (c) Unless otherwise stated, if the final day of any time period, 
under the CAIR NOX Ozone Season Trading Program, falls on a 
weekend or a State or Federal holiday, the time period shall be extended 
to the next business day.



Sec. 96.308  Appeal procedures.

    The appeal procedures for decisions of the Administrator under the 
CAIR NOX Ozone Season Trading Program are set forth in part 
78 of this chapter.



 Subpart BBBB_CAIR Designated Representative for CAIR NOX Ozone Season 
                                 Sources

    Source: 70 FR 25382, May 12, 2005, unless otherwise noted.



Sec. 96.310  Authorization and responsibilities of CAIR designated
representative.

    (a) Except as provided under Sec. 96.311, each CAIR NOX 
Ozone Season source, including all CAIR NOX Ozone Season 
units at the source, shall have one and only one CAIR designated 
representative, with regard to all matters under the CAIR NOX 
Ozone Season Trading Program concerning the source or any CAIR 
NOX Ozone Season unit at the source.
    (b) The CAIR designated representative of the CAIR NOX 
Ozone Season source shall be selected by an agreement binding on the 
owners and operators of the source and all CAIR NOX Ozone 
Season units at the source and shall act in accordance with the 
certification statement in Sec. 96.313(a)(4)(iv).
    (c) Upon receipt by the Administrator of a complete certificate of 
representation under Sec. 96.313, the CAIR designated representative of 
the source shall represent and, by his or her representations, actions, 
inactions, or submissions, legally bind each owner and operator of the 
CAIR NOX Ozone Season source represented and each CAIR 
NOX Ozone Season unit at the source in all matters pertaining 
to the CAIR NOX Ozone Season Trading Program, notwithstanding 
any agreement between the CAIR designated representative and such owners 
and operators. The owners and operators shall be bound by any decision 
or order issued to the CAIR designated representative by the permitting 
authority, the Administrator, or a court regarding the source or unit.
    (d) No CAIR permit will be issued, no emissions data reports will be 
accepted, and no CAIR NOX Ozone Season Allowance Tracking 
System account will be established for a CAIR NOX Ozone 
Season unit at a source, until the Administrator has received a complete 
certificate of representation under Sec. 96.313 for a CAIR designated 
representative of the source and the CAIR NOX Ozone Season 
units at the source.
    (e)(1) Each submission under the CAIR NOX Ozone Season 
Trading Program shall be submitted, signed, and certified by the CAIR 
designated representative for each CAIR NOX Ozone Season 
source on behalf of which the submission is made. Each such submission 
shall include the following certification statement by the CAIR 
designated representative: ``I am authorized to make this submission on 
behalf of the owners and operators of the source or units for which the 
submission is made. I certify under penalty of law that I have 
personally examined, and am familiar with, the statements and 
information submitted in this document and all its attachments. Based on 
my inquiry of those individuals with primary responsibility for 
obtaining the information, I certify that the statements and information 
are to the best of my knowledge and belief true, accurate, and complete. 
I am aware that there are significant penalties for

[[Page 142]]

submitting false statements and information or omitting required 
statements and information, including the possibility of fine or 
imprisonment.''
    (2) The permitting authority and the Administrator will accept or 
act on a submission made on behalf of owner or operators of a CAIR 
NOX Ozone Season source or a CAIR NOX Ozone Season 
unit only if the submission has been made, signed, and certified in 
accordance with paragraph (e)(1) of this section.



Sec. 96.311  Alternate CAIR designated representative.

    (a) A certificate of representation under Sec. 96.313 may designate 
one and only one alternate CAIR designated representative, who may act 
on behalf of the CAIR designated representative. The agreement by which 
the alternate CAIR designated representative is selected shall include a 
procedure for authorizing the alternate CAIR designated representative 
to act in lieu of the CAIR designated representative.
    (b) Upon receipt by the Administrator of a complete certificate of 
representation under Sec. 96.313, any representation, action, inaction, 
or submission by the alternate CAIR designated representative shall be 
deemed to be a representation, action, inaction, or submission by the 
CAIR designated representative.
    (c) Except in this section and Sec. Sec. 96.302, 96.310(a) and (d), 
96.312, 96.313, 96.315, 96.351, and 96.382 whenever the term ``CAIR 
designated representative'' is used in subparts AAAA through IIII of 
this part, the term shall be construed to include the CAIR designated 
representative or any alternate CAIR designated representative.

[70 FR 25382, May 12, 2005, as amended at 71 FR 25393, Apr. 28, 2006]



Sec. 96.312  Changing CAIR designated representative and alternate 
CAIR designated representative; changes in owners and operators.

    (a) Changing CAIR designated representative. The CAIR designated 
representative may be changed at any time upon receipt by the 
Administrator of a superseding complete certificate of representation 
under Sec. 96.313. Notwithstanding any such change, all 
representations, actions, inactions, and submissions by the previous 
CAIR designated representative before the time and date when the 
Administrator receives the superseding certificate of representation 
shall be binding on the new CAIR designated representative and the 
owners and operators of the CAIR NOX Ozone Season source and 
the CAIR NOX Ozone Season units at the source.
    (b) Changing alternate CAIR designated representative. The alternate 
CAIR designated representative may be changed at any time upon receipt 
by the Administrator of a superseding complete certificate of 
representation under Sec. 96.313. Notwithstanding any such change, all 
representations, actions, inactions, and submissions by the previous 
alternate CAIR designated representative before the time and date when 
the Administrator receives the superseding certificate of representation 
shall be binding on the new alternate CAIR designated representative and 
the owners and operators of the CAIR NOX Ozone Season source 
and the CAIR NOX Ozone Season units at the source.
    (c) Changes in owners and operators. (1) In the event an owner or 
operator of a CAIR NOX Ozone Season source or a CAIR 
NOX Ozone Season unit is not included in the list of owners 
and operators in the certificate of representation under Sec. 96.313, 
such owner or operator shall be deemed to be subject to and bound by the 
certificate of representation, the representations, actions, inactions, 
and submissions of the CAIR designated representative and any alternate 
CAIR designated representative of the source or unit, and the decisions 
and orders of the permitting authority, the Administrator, or a court, 
as if the owner or operator were included in such list.
    (2) Within 30 days following any change in the owners and operators 
of a CAIR NOX Ozone Season source or a CAIR NOX 
Ozone Season unit, including the addition of a new owner or operator, 
the CAIR designated representative or any alternate CAIR designated 
representative shall submit a revision to the certificate of 
representation

[[Page 143]]

under Sec. 96.313 amending the list of owners and operators to include 
the change.

[70 FR 25382, May 12, 2005, as amended at 71 FR 25393, Apr. 28, 2006]



Sec. 96.313  Certificate of representation.

    (a) A complete certificate of representation for a CAIR designated 
representative or an alternate CAIR designated representative shall 
include the following elements in a format prescribed by the 
Administrator:
    (1) Identification of the CAIR NOX Ozone Season source, 
and each CAIR NOX Ozone Season unit at the source, for which 
the certificate of representation is submitted, including identification 
and nameplate capacity of each generator served by each such unit.
    (2) The name, address, e-mail address (if any), telephone number, 
and facsimile transmission number (if any) of the CAIR designated 
representative and any alternate CAIR designated representative.
    (3) A list of the owners and operators of the CAIR NOX 
Ozone Season source and of each CAIR NOX Ozone Season unit at 
the source.
    (4) The following certification statements by the CAIR designated 
representative and any alternate CAIR designated representative--
    (i) ``I certify that I was selected as the CAIR designated 
representative or alternate CAIR designated representative, as 
applicable, by an agreement binding on the owners and operators of the 
source and each CAIR NOX Ozone Season unit at the source.''
    (ii) ``I certify that I have all the necessary authority to carry 
out my duties and responsibilities under the CAIR NOX Ozone 
Season Trading Program on behalf of the owners and operators of the 
source and of each CAIR NOX Ozone Season unit at the source 
and that each such owner and operator shall be fully bound by my 
representations, actions, inactions, or submissions.''
    (iii) ``I certify that the owners and operators of the source and of 
each CAIR NOX Ozone Season unit at the source shall be bound 
by any order issued to me by the Administrator, the permitting 
authority, or a court regarding the source or unit.''
    (iv) ``Where there are multiple holders of a legal or equitable 
title to, or a leasehold interest in, a CAIR NOX Ozone Season 
unit, or where a utility or industrial customer purchases power from a 
CAIR NOX Ozone Season unit under a life-of-the-unit, firm 
power contractual arrangement, I certify that: I have given a written 
notice of my selection as the `CAIR designated representative' or 
`alternate CAIR designated representative', as applicable, and of the 
agreement by which I was selected to each owner and operator of the 
source and of each CAIR NOX Ozone Season unit at the source; 
and CAIR NOX Ozone Season allowances and proceeds of 
transactions involving CAIR NOX Ozone Season allowances will 
be deemed to be held or distributed in proportion to each holder's 
legal, equitable, leasehold, or contractual reservation or entitlement, 
except that, if such multiple holders have expressly provided for a 
different distribution of CAIR NOX Ozone Season allowances by 
contract, CAIR NOX Ozone Season allowances and proceeds of 
transactions involving CAIR NOX Ozone Season allowances will 
be deemed to be held or distributed in accordance with the contract.''
    (5) The signature of the CAIR designated representative and any 
alternate CAIR designated representative and the dates signed.
    (b) Unless otherwise required by the permitting authority or the 
Administrator, documents of agreement referred to in the certificate of 
representation shall not be submitted to the permitting authority or the 
Administrator. Neither the permitting authority nor the Administrator 
shall be under any obligation to review or evaluate the sufficiency of 
such documents, if submitted.

[70 FR 25382, May 12, 2005, as amended at 71 FR 25393, Apr. 28, 2006]



Sec. 96.314  Objections concerning CAIR designated representative.

    (a) Once a complete certificate of representation under Sec. 96.313 
has been submitted and received, the permitting authority and the 
Administrator will rely on the certificate of representation unless and 
until a superseding complete certificate of representation

[[Page 144]]

under Sec. 96.313 is received by the Administrator.
    (b) Except as provided in Sec. 96.312(a) or (b), no objection or 
other communication submitted to the permitting authority or the 
Administrator concerning the authorization, or any representation, 
action, inaction, or submission, of the CAIR designated representative 
shall affect any representation, action, inaction, or submission of the 
CAIR designated representative or the finality of any decision or order 
by the permitting authority or the Administrator under the CAIR 
NOX Ozone Season Trading Program.
    (c) Neither the permitting authority nor the Administrator will 
adjudicate any private legal dispute concerning the authorization or any 
representation, action, inaction, or submission of any CAIR designated 
representative, including private legal disputes concerning the proceeds 
of CAIR NOX Ozone Season allowance transfers.



Sec. 96.315  Delegation by CAIR designated representative and alternate
CAIR designated representative.

    (a) A CAIR designated representative may delegate, to one or more 
natural persons, his or her authority to make an electronic submission 
to the Administrator provided for or required under this part.
    (b) An alternate CAIR designated representative may delegate, to one 
or more natural persons, his or her authority to make an electronic 
submission to the Administrator provided for or required under this 
part.
    (c) In order to delegate authority to make an electronic submission 
to the Administrator in accordance with paragraph (a) or (b) of this 
section, the CAIR designated representative or alternate CAIR designated 
representative, as appropriate, must submit to the Administrator a 
notice of delegation, in a format prescribed by the Administrator, that 
includes the following elements:
    (1) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of such CAIR designated 
representative or alternate CAIR designated representative;
    (2) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of each such natural person 
(referred to as an ``agent'');
    (3) For each such natural person, a list of the type or types of 
electronic submissions under paragraph (a) or (b) of this section for 
which authority is delegated to him or her; and
    (4) The following certification statements by such CAIR designated 
representative or alternate CAIR designated representative:
    (i) ``I agree that any electronic submission to the Administrator 
that is by an agent identified in this notice of delegation and of a 
type listed for such agent in this notice of delegation and that is made 
when I am a CAIR designated representative or alternate CAIR designated 
representative, as appropriate, and before this notice of delegation is 
superseded by another notice of delegation under 40 CFR 96.315(d) shall 
be deemed to be an electronic submission by me.''
    (ii) ``Until this notice of delegation is superseded by another 
notice of delegation under 40 CFR 96.315(d), I agree to maintain an e-
mail account and to notify the Administrator immediately of any change 
in my e-mail address unless all delegation of authority by me under 40 
CFR 96.315 is terminated.''.
    (d) A notice of delegation submitted under paragraph (c) of this 
section shall be effective, with regard to the CAIR designated 
representative or alternate CAIR designated representative identified in 
such notice, upon receipt of such notice by the Administrator and until 
receipt by the Administrator of a superseding notice of delegation 
submitted by such CAIR designated representative or alternate CAIR 
designated representative, as appropriate. The superseding notice of 
delegation may replace any previously identified agent, add a new agent, 
or eliminate entirely any delegation of authority.
    (e) Any electronic submission covered by the certification in 
paragraph

[[Page 145]]

(c)(4)(i) of this section and made in accordance with a notice of 
delegation effective under paragraph (d) of this section shall be deemed 
to be an electronic submission by the CAIR designated representative or 
alternate CAIR designated representative submitting such notice of 
delegation.

[71 FR 25393, Apr. 28, 2006]



                          Subpart CCCC_Permits

    Source: 70 FR 25382, May 12, 2005, unless otherwise noted.



Sec. 96.320  General CAIR NOX Ozone Season Trading Program permit 
requirements.

    (a) For each CAIR NOX Ozone Season source required to 
have a title V operating permit or required, under subpart IIII of this 
part, to have a title V operating permit or other federally enforceable 
permit, such permit shall include a CAIR permit administered by the 
permitting authority for the title V operating permit or the federally 
enforceable permit as applicable. The CAIR portion of the title V permit 
or other federally enforceable permit as applicable shall be 
administered in accordance with the permitting authority's title V 
operating permits regulations promulgated under part 70 or 71 of this 
chapter or the permitting authority's regulations for other federally 
enforceable permits as applicable, except as provided otherwise by Sec. 
96.305, this subpart and subpart IIII of this part.
    (b) Each CAIR permit shall contain, with regard to the CAIR 
NOX Ozone Season source and the CAIR NOX Ozone 
Season units at the source covered by the CAIR permit, all applicable 
CAIR NOX Ozone Season Trading Program, CAIR NOX 
Annual Trading Program, and CAIR SO2 Trading Program 
requirements and shall be a complete and separable portion of the title 
V operating permit or other federally enforceable permit under paragraph 
(a) of this section.

[70 FR 25382, May 12, 2005, as amended at 71 FR 25394, Apr. 28, 2006]



Sec. 96.321  Submission of CAIR permit applications.

    (a) Duty to apply. The CAIR designated representative of any CAIR 
NOX Ozone Season source required to have a title V operating 
permit shall submit to the permitting authority a complete CAIR permit 
application under Sec. 96.322 for the source covering each CAIR 
NOX Ozone Season unit at the source at least 18 months (or 
such lesser time provided by the permitting authority) before the later 
of January 1, 2009 or the date on which the CAIR NOX Ozone 
Season unit commences commercial operation, except as provided in Sec. 
96.383(a).
    (b) Duty to Reapply. For a CAIR NOX Ozone Season source 
required to have a title V operating permit, the CAIR designated 
representative shall submit a complete CAIR permit application under 
Sec. 96.322 for the source covering each CAIR NOX Ozone 
Season unit at the source to renew the CAIR permit in accordance with 
the permitting authority's title V operating permits regulations 
addressing permit renewal, except as provided in Sec. 96.383(b).

[70 FR 25382, May 12, 2005, as amended at 71 FR 25394, Apr. 28, 2006]



Sec. 96.322  Information requirements for CAIR permit applications.

    A complete CAIR permit application shall include the following 
elements concerning the CAIR NOX Ozone Season source for 
which the application is submitted, in a format prescribed by the 
permitting authority:
    (a) Identification of the CAIR NOX Ozone Season source;
    (b) Identification of each CAIR NOX Ozone Season unit at 
the CAIR NOX Ozone Season source; and
    (c) The standard requirements under Sec. 96.306.



Sec. 96.323  CAIR permit contents and term.

    (a) Each CAIR permit will contain, in a format prescribed by the 
permitting authority, all elements required for a complete CAIR permit 
application under Sec. 96.322.
    (b) Each CAIR permit is deemed to incorporate automatically the 
definitions of terms under Sec. 96.302 and, upon recordation by the 
Administrator

[[Page 146]]

under subpart FFFF, GGGG, or IIII of this part, every allocation, 
transfer, or deduction of a CAIR NOX Ozone Season allowance 
to or from the compliance account of the CAIR NOX Ozone 
Season source covered by the permit.
    (c) The term of the CAIR permit will be set by the permitting 
authority, as necessary to facilitate coordination of the renewal of the 
CAIR permit with issuance, revision, or renewal of the CAIR 
NOX Ozone Season source's title V operating permit or other 
federally enforceable permit as applicable.



Sec. 96.324  CAIR permit revisions.

    Except as provided in Sec. 96.323(b), the permitting authority will 
revise the CAIR permit, as necessary, in accordance with the permitting 
authority's title V operating permits regulations or the permitting 
authority's regulations for other federally enforceable permits as 
applicable addressing permit revisions.

Subpart DDDD [Reserved]



        Subpart EEEE_CAIR NOX Ozone Season Allowance Allocations

    Source: 70 FR 25382, May 12, 2005, unless otherwise noted.



Sec. 96.340  State trading budgets.

    (a) Except as provided in paragraph (b) of this section, the State 
trading budgets for annual allocations of CAIR NOX Ozone 
Season allowances for the control periods in 2009 through 2014 and in 
2015 and thereafter are respectively as follows:

------------------------------------------------------------------------
                                                          State trading
                                        State trading    budget for 2015
                State                 budget for 2009-   and thereafter
                                         2014 (tons)         (tons)
------------------------------------------------------------------------
Alabama.............................            32,182            26,818
Arkansas............................            11,515             9,596
Connecticut.........................             2,559             2,559
Delaware............................             2,226             1,855
District of Columbia................               112                94
Florida.............................            47,912            39,926
Illinois............................            30,701            28,981
Indiana.............................            45,952            39,273
Iowa................................            14,263            11,886
Kentucky............................            36,045            30,587
Louisiana...........................            17,085            14,238
Maryland............................            12,834            10,695
Massachusetts.......................             7,551             6,293
Michigan............................            28,971            24,142
Mississippi.........................             8,714             7,262
Missouri............................            26,678            22,231
New Jersey..........................             6,654             5,545
New York............................            20,632            17,193
North Carolina......................            28,392            23,660
Ohio................................            45,664            39,945
Pennsylvania........................            42,171            35,143
South Carolina......................            15,249            12,707
Tennessee...........................            22,842            19,035
Virginia............................            15,994            13,328
West Virginia.......................            26,859            26,525
Wisconsin...........................            17,987            14,989
------------------------------------------------------------------------

    (b) If a permitting authority issues additional CAIR NOX 
Ozone Season allowance allocations under Sec. 51.123(aa)(2)(iii)(A) of 
this chapter, the amount in the State trading budget for a control 
period in a calendar year will be the sum of the amount set forth for 
the State and for the year in paragraph (a) of this section and the 
amount of additional CAIR NOX Ozone Season allowance 
allocations issued under Sec. 51.123(aa)(2)(iii)(A) of this chapter for 
the year.



Sec. 96.341  Timing requirements for CAIR NOX Ozone Season allowance
allocations.

    (a) By October 31, 2006, the permitting authority will submit to the 
Administrator the CAIR NOX Ozone Season allowance 
allocations, in a format prescribed by the Administrator and in 
accordance with Sec. 96.342(a) and (b), for the control periods in 
2009, 2010, 2011, 2012, 2013, and 2014.
    (b) By October 31, 2009 and October 31 of each year thereafter, the 
permitting authority will submit to the Administrator the CAIR 
NOX Ozone Season allowance allocations, in a format 
prescribed by the Administrator and in accordance with Sec. 96.342(a) 
and (b), for the control period in the sixth year after the year of the 
applicable deadline for submission under this paragraph.
    (c) By July 31, 2009 and July 31 of each year thereafter, the 
permitting authority will submit to the Administrator the CAIR 
NOX Ozone Season allowance allocations, in a format 
prescribed by the Administrator and in accordance with Sec. 96.342(c), 
(a), and (d), for the control period in the year of the applicable 
deadline for submission under this paragraph.

[70 FR 25382, May 12, 2005, as amended at 71 FR 25394, Apr. 28, 2006]

[[Page 147]]



Sec. 96.342  CAIR NOX Ozone Season allowance allocations.

    (a)(1) The baseline heat input (in mmBtu) used with respect to CAIR 
NOX Ozone Season allowance allocations under paragraph (b) of 
this section for each CAIR NOX Ozone Season unit will be:
    (i) For units commencing operation before January 1, 2001 the 
average of the 3 highest amounts of the unit's adjusted control period 
heat input for 2000 through 2004, with the adjusted control period heat 
input for each year calculated as follows:
    (A) If the unit is coal-fired during the year, the unit's control 
period heat input for such year is multiplied by 100 percent;
    (B) If the unit is oil-fired during the year, the unit's control 
period heat input for such year is multiplied by 60 percent; and
    (C) If the unit is not subject to paragraph (a)(1)(i)(A) or (B) of 
this section, the unit's control period heat input for such year is 
multiplied by 40 percent.
    (ii) For units commencing operation on or after January 1, 2001 and 
operating each calendar year during a period of 5 or more consecutive 
calendar years, the average of the 3 highest amounts of the unit's total 
converted control period heat input over the first such 5 years.
    (2)(i) A unit's control period heat input, and a unit's status as 
coal-fired or oil-fired, for a calendar year under paragraph (a)(1)(i) 
of this section, and a unit's total tons of NOX emissions 
during a control period in a calendar year under paragraph (c)(3) of 
this section, will be determined in accordance with part 75 of this 
chapter, to the extent the unit was otherwise subject to the 
requirements of part 75 of this chapter for the year, or will be based 
on the best available data reported to the permitting authority for the 
unit, to the extent the unit was not otherwise subject to the 
requirements of part 75 of this chapter for the year.
    (ii) A unit's converted control period heat input for a calendar 
year specified under paragraph (a)(1)(ii) of this section equals:
    (A) Except as provided in paragraph (a)(2)(ii)(B) or (C) of this 
section, the control period gross electrical output of the generator or 
generators served by the unit multiplied by 7,900 Btu/kWh, if the unit 
is coal-fired for the year, or 6,675 Btu/kWh, if the unit is not coal-
fired for the year, and divided by 1,000,000 Btu/mmBtu, provided that if 
a generator is served by 2 or more units, then the gross electrical 
output of the generator will be attributed to each unit in proportion to 
the unit's share of the total control period heat input of such units 
for the year;
    (B) For a unit that is a boiler and has equipment used to produce 
electricity and useful thermal energy for industrial, commercial, 
heating, or cooling purposes through the sequential use of energy, the 
total heat energy (in Btu) of the steam produced by the boiler during 
the control period, divided by 0.8 and by 1,000,000 Btu/mmBtu; or
    (C) For a unit that is a combustion turbine and has equipment used 
to produce electricity and useful thermal energy for industrial, 
commercial, heating, or cooling purposes through the sequential use of 
energy, the control period gross electrical output of the enclosed 
device comprising the compressor, combustor, and turbine multiplied by 
3,413 Btu/kWh, plus the total heat energy (in Btu) of the steam produced 
by any associated heat recovery steam generator during the control 
period divided by 0.8, and with the sum divided by 1,000,000 Btu/mmBtu.
    (b)(1) For each control period in 2009 and thereafter, the 
permitting authority will allocate to all CAIR NOX Ozone 
Season units in the State that have a baseline heat input (as determined 
under paragraph (a) of this section) a total amount of CAIR 
NOX Ozone Season allowances equal to 95 percent for a control 
period during 2009 through 2014, and 97 percent for a control period 
during 2015 and thereafter, of the tons of NOX emissions in 
the State trading budget under Sec. 96.340 (except as provided in 
paragraph (d) of this section).
    (2) The permitting authority will allocate CAIR NOX Ozone 
Season allowances to each CAIR NOX Ozone Season unit under 
paragraph (b)(1) of this section in an amount determined by multiplying 
the total amount of CAIR NOX Ozone Season allowances 
allocated under paragraph (b)(1) of this section by the ratio of the 
baseline heat input

[[Page 148]]

of such CAIR NOX Ozone Season unit to the total amount of 
baseline heat input of all such CAIR NOX Ozone Season units 
in the State and rounding to the nearest whole allowance as appropriate.
    (c) For each control period in 2009 and thereafter, the permitting 
authority will allocate CAIR NOX Ozone Season allowances to 
CAIR NOX Ozone Season units in a State that are not allocated 
CAIR NOX Ozone Season allowances under paragraph (b) of this 
section because the units do not yet have a baseline heat input under 
paragraph (a) of this section or because the units have a baseline heat 
input but all CAIR NOX Ozone Season allowances available 
under paragraph (b) of this section for the control period are already 
allocated, in accordance with the following procedures:
    (1) The permitting authority will establish a separate new unit set-
aside for each control period. Each new unit set-aside will be allocated 
CAIR NOX Ozone Season allowances equal to 5 percent for a 
control period in2009 through 2014, and 3 percent for a control period 
in 2015 and thereafter, of the amount of tons of NOX 
emissions in the State trading budget under Sec. 96.340.
    (2) The CAIR designated representative of such a CAIR NOX 
Ozone Season unit may submit to the permitting authority a request, in a 
format specified by the permitting authority, to be allocated CAIR 
NOX Ozone Season allowances, starting with the later of the 
control period in 2009 or the first control period after the control 
period in which the CAIR NOX Ozone Season unit commences 
commercial operation and until the first control period for which the 
unit is allocated CAIR NOX Ozone Season allowances under 
paragraph (b) of this section. A separate CAIR NOX Ozone 
Season allowance allocation request for each control period for which 
CAIR NOX Ozone Season allowances are sought must be submitted 
on or before February 1 before such control period and after the date on 
which the CAIR NOX Ozone Season unit commences commercial 
operation.
    (3) In a CAIR NOX Ozone Season allowance allocation 
request under paragraph (c)(2) of this section, the CAIR designated 
representative may request for a control period CAIR NOX 
Ozone Season allowances in an amount not exceeding the CAIR 
NOX Ozone Season unit's total tons of NOX 
emissions during the control period immediately before such control 
period.
    (4) The permitting authority will review each CAIR NOX 
Ozone Season allowance allocation request under paragraph (c)(2) of this 
section and will allocate CAIR NOX Ozone Season allowances 
for each control period pursuant to such request as follows:
    (i) The permitting authority will accept an allowance allocation 
request only if the request meets, or is adjusted by the permitting 
authority as necessary to meet, the requirements of paragraphs (c)(2) 
and (3) of this section.
    (ii) On or after February 1 before the control period, the 
permitting authority will determine the sum of the CAIR NOX 
Ozone Season allowances requested (as adjusted under paragraph (c)(4)(i) 
of this section) in all allowance allocation requests accepted under 
paragraph (c)(4)(i) of this section for the control period.
    (iii) If the amount of CAIR NOX Ozone Season allowances 
in the new unit set-aside for the control period is greater than or 
equal to the sum under paragraph (c)(4)(ii) of this section, then the 
permitting authority will allocate the amount of CAIR NOX 
Ozone Season allowances requested (as adjusted under paragraph (c)(4)(i) 
of this section) to each CAIR NOX Ozone Season unit covered 
by an allowance allocation request accepted under paragraph (c)(4)(i) of 
this section.
    (iv) If the amount of CAIR NOX Ozone Season allowances in 
the new unit set-aside for the control period is less than the sum under 
paragraph (c)(4)(ii) of this section, then the permitting authority will 
allocate to each CAIR NOX Ozone Season unit covered by an 
allowance allocation request accepted under paragraph (c)(4)(i) of this 
section the amount of the CAIR NOX Ozone Season allowances 
requested (as adjusted under paragraph (c)(4)(i) of this section), 
multiplied by the amount of CAIR NOX Ozone Season allowances 
in the new unit set-aside for the control period, divided by the sum 
determined

[[Page 149]]

under paragraph (c)(4)(ii) of this section, and rounded to the nearest 
whole allowance as appropriate.
    (v) The permitting authority will notify each CAIR designated 
representative that submitted an allowance allocation request of the 
amount of CAIR NOX Ozone Season allowances (if any) allocated 
for the control period to the CAIR NOX Ozone Season unit 
covered by the request.
    (d) If, after completion of the procedures under paragraph (c)(4) of 
this section for a control period, any unallocated CAIR NOX 
Ozone Season allowances remain in the new unit set-aside for the control 
period, the permitting authority will allocate to each CAIR 
NOX Ozone Season unit that was allocated CAIR NOX 
Ozone Season allowances under paragraph (b) of this section an amount of 
CAIR NOX Ozone Season allowances equal to the total amount of 
such remaining unallocated CAIR NOX Ozone Season allowances, 
multiplied by the unit's allocation under paragraph (b) of this section, 
divided by 95 percent for a control period during 2009 through 2014, and 
97 percent for a control period during 2015 and thereafter, of the 
amount of tons of NOX emissions in the State trading budget 
under Sec. 96.340, and rounded to the nearest whole allowance as 
appropriate.

[70 FR 25382, May 12, 2005, as amended at 71 FR 25394, Apr. 28, 2006; 71 
FR 74794, Dec. 13, 2006]



      Subpart FFFF_CAIR NOX Ozone Season Allowance Tracking System

    Source: 70 FR 25382, May 12, 2005, unless otherwise noted.



Sec. 96.350  [Reserved]



Sec. 96.351  Establishment of accounts.

    (a) Compliance accounts. Except as provided in Sec. 96.384(e), upon 
receipt of a complete certificate of representation under Sec. 96.313, 
the Administrator will establish a compliance account for the CAIR 
NOX Ozone Season source for which the certificate of 
representation was submitted, unless the source already has a compliance 
account.
    (b) General accounts--(1) Application for general account. (i) Any 
person may apply to open a general account for the purpose of holding 
and transferring CAIR NOX Ozone Season allowances. An 
application for a general account may designate one and only one CAIR 
authorized account representative and one and only one alternate CAIR 
authorized account representative who may act on behalf of the CAIR 
authorized account representative. The agreement by which the alternate 
CAIR authorized account representative is selected shall include a 
procedure for authorizing the alternate CAIR authorized account 
representative to act in lieu of the CAIR authorized account 
representative.
    (ii) A complete application for a general account shall be submitted 
to the Administrator and shall include the following elements in a 
format prescribed by the Administrator:
    (A) Name, mailing address, e-mail address (if any), telephone 
number, and facsimile transmission number (if any) of the CAIR 
authorized account representative and any alternate CAIR authorized 
account representative;
    (B) Organization name and type of organization, if applicable;
    (C) A list of all persons subject to a binding agreement for the 
CAIR authorized account representative and any alternate CAIR authorized 
account representative to represent their ownership interest with 
respect to the CAIR NOX Ozone Season allowances held in the 
general account;
    (D) The following certification statement by the CAIR authorized 
account representative and any alternate CAIR authorized account 
representative: ``I certify that I was selected as the CAIR authorized 
account representative or the alternate CAIR authorized account 
representative, as applicable, by an agreement that is binding on all 
persons who have an ownership interest with respect to CAIR 
NOX Ozone Season allowances held in the general account. I 
certify that I have all the necessary authority to carry out my duties 
and responsibilities under the CAIR NOX Ozone Season Trading 
Program on behalf of such persons and that each such person shall be 
fully bound by my representations, actions,

[[Page 150]]

inactions, or submissions and by any order or decision issued to me by 
the Administrator or a court regarding the general account.''
    (E) The signature of the CAIR authorized account representative and 
any alternate CAIR authorized account representative and the dates 
signed.
    (iii) Unless otherwise required by the permitting authority or the 
Administrator, documents of agreement referred to in the application for 
a general account shall not be submitted to the permitting authority or 
the Administrator. Neither the permitting authority nor the 
Administrator shall be under any obligation to review or evaluate the 
sufficiency of such documents, if submitted.
    (2) Authorization of CAIR authorized account representative 
andalternate CAIR authorized account representative. (i) Upon receipt by 
the Administrator of a complete application for a general account under 
paragraph (b)(1) of this section:
    (A) The Administrator will establish a general account for the 
person or persons for whom the application is submitted.
    (B) The CAIR authorized account representative and any alternate 
CAIR authorized account representative for the general account shall 
represent and, by his or her representations, actions, inactions, or 
submissions, legally bind each person who has an ownership interest with 
respect to CAIR NOX Ozone Season allowances held in the 
general account in all matters pertaining to the CAIR NOX 
Ozone Season Trading Program, notwithstanding any agreement between the 
CAIR authorized account representative or any alternate CAIR authorized 
account representative and such person. Any such person shall be bound 
by any order or decision issued to the CAIR authorized account 
representative or any alternate CAIR authorized account representative 
by the Administrator or a court regarding the general account.
    (C) Any representation, action, inaction, or submission by any 
alternate CAIR authorized account representative shall be deemed to be a 
representation, action, inaction, or submission by the CAIR authorized 
account representative.
    (ii) Each submission concerning the general account shall be 
submitted, signed, and certified by the CAIR authorized account 
representative or any alternate CAIR authorized account representative 
for the persons having an ownership interest with respect to CAIR 
NOX Ozone Season allowances held in the general account. Each 
such submission shall include the following certification statement by 
the CAIR authorized account representative or any alternate CAIR 
authorized account representative: ``I am authorized to make this 
submission on behalf of the persons having an ownership interest with 
respect to the CAIR NOX Ozone Season allowances held in the 
general account. I certify under penalty of law that I have personally 
examined, and am familiar with, the statements and information submitted 
in this document and all its attachments. Based on my inquiry of those 
individuals with primary responsibility for obtaining the information, I 
certify that the statements and information are to the best of my 
knowledge and belief true, accurate, and complete. I am aware that there 
are significant penalties for submitting false statements and 
information or omitting required statements and information, including 
the possibility of fine or imprisonment.''
    (iii) The Administrator will accept or act on a submission 
concerning the general account only if the submission has been made, 
signed, and certified in accordance with paragraph (b)(2)(ii) of this 
section.
    (3) Changing CAIR authorized account representative and alternate 
CAIR authorized account representative; changes in persons with 
ownership interest. (i) The CAIR authorized account representative for a 
general account may be changed at any time upon receipt by the 
Administrator of a superseding complete application for a general 
account under paragraph (b)(1) of this section. Notwithstanding any such 
change, all representations, actions, inactions, and submissions by the 
previous CAIR authorized account representative before the time and date 
when the Administrator receives the superseding application for a 
general account shall be binding on the new

[[Page 151]]

CAIR authorized account representative and the persons with an ownership 
interest with respect to the CAIR NOX Ozone Season allowances 
in the general account.
    (ii) The alternate CAIR authorized account representative for a 
general account may be changed at any time upon receipt by the 
Administrator of a superseding complete application for a general 
account under paragraph (b)(1) of this section. Notwithstanding any such 
change, all representations, actions, inactions, and submissions by the 
previous alternate CAIR authorized account representative before the 
time and date when the Administrator receives the superseding 
application for a general account shall be binding on the new alternate 
CAIR authorized account representative and the persons with an ownership 
interest with respect to the CAIR NOX Ozone Season allowances 
in the general account.
    (iii)(A) In the event a person having an ownership interest with 
respect to CAIR NOX Ozone Season allowances in the general 
account is not included in the list of such persons in the application 
for a general account, such person shall be deemed to be subject to and 
bound by the application for a general account, the representation, 
actions, inactions, and submissions of the CAIR authorized account 
representative and any alternate CAIR authorized account representative 
of the account, and the decisions and orders of the Administrator or a 
court, as if the person were included in such list.
    (B) Within 30 days following any change in the persons having an 
ownership interest with respect to CAIR NOX Ozone Season 
allowances in the general account, including the addition of a new 
person, the CAIR authorized account representative or any alternate CAIR 
authorized account representative shall submit a revision to the 
application for a general account amending the list of persons having an 
ownership interest with respect to the CAIR NOX Ozone Season 
allowances in the general account to include the change.
    (4) Objections concerning CAIR authorized account representative and 
alternate CAIR authorized account representative. (i) Once a complete 
application for a general account under paragraph (b)(1) of this section 
has been submitted and received, the Administrator will rely on the 
application unless and until a superseding complete application for a 
general account under paragraph (b)(1) of this section is received by 
the Administrator.
    (ii) Except as provided in paragraph (b)(3)(i) or (ii) of this 
section, no objection or other communication submitted to the 
Administrator concerning the authorization, or any representation, 
action, inaction, or submission of the CAIR authorized account 
representative or any alternate CAIR authorized account representative 
for a general account shall affect any representation, action, inaction, 
or submission of the CAIR authorized account representative or any 
alternative CAIR authorized account representative or the finality of 
any decision or order by the Administrator under the CAIR NOX 
Ozone Season Trading Program.
    (iii) The Administrator will not adjudicate any private legal 
dispute concerning the authorization or any representation, action, 
inaction, or submission of the CAIR authorized account representative or 
any alternate CAIR authorized account representative for a general 
account, including private legal disputes concerning the proceeds of 
CAIR NOX Ozone Season allowance transfers.
    (5) Delegation by CAIR authorized account representative and 
alternate CAIR authorized account representative. (i) A CAIR authorized 
account representative may delegate, to one or more natural persons, his 
or her authority to make an electronic submission to the Administrator 
provided for or required under subparts FFFF and GGGG of this part.
    (ii) An alternate CAIR authorized account representative may 
delegate, to one or more natural persons, his or her authority to make 
an electronic submission to the Administrator provided for or required 
under subparts FFFF and GGGG of this part.
    (iii) In order to delegate authority to make an electronic 
submission to the Administrator in accordance with

[[Page 152]]

paragraph (b)(5)(i) or (ii) of this section, the CAIR authorized account 
representative or alternate CAIR authorized account representative, as 
appropriate, must submit to the Administrator a notice of delegation, in 
a format prescribed by the Administrator, that includes the following 
elements:
    (A) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of such CAIR authorized account 
representative or alternate CAIR authorized account representative;
    (B) The name, address, e-mail address, telephone number, and, 
facsimile transmission number (if any) of each such natural person 
(referred to as an ``agent'');
    (C) For each such natural person, a list of the type or types of 
electronic submissions under paragraph (b)(5)(i) or (ii) of this section 
for which authority is delegated to him or her;
    (D) The following certification statement by such CAIR authorized 
account representative or alternate CAIR authorized account 
representative: ``I agree that any electronic submission to the 
Administrator that is by an agent identified in this notice of 
delegation and of a type listed for such agent in this notice of 
delegation and that is made when I am a CAIR authorized account 
representative or alternate CAIR authorized representative, as 
appropriate, and before this notice of delegation is superseded by 
another notice of delegation under 40 CFR 96.351(b)(5)(iv) shall be 
deemed to be an electronic submission by me.''; and
    (E) The following certification statement by such CAIR authorized 
account representative or alternate CAIR authorized account 
representative: ``Until this notice of delegation is superseded by 
another notice of delegation under 40 CFR 96.351(b)(5)(iv), I agree to 
maintain an e-mail account and to notify the Administrator immediately 
of any change in my e-mail address unless all delegation of authority by 
me under 40 CFR 96.351(b)(5) is terminated.''.
    (iv) A notice of delegation submitted under paragraph (b)(5)(iii) of 
this section shall be effective, with regard to the CAIR authorized 
account representative or alternate CAIR authorized account 
representative identified in such notice, upon receipt of such notice by 
the Administrator and until receipt by the Administrator of a 
superseding notice of delegation submitted by such CAIR authorized 
account representative or alternate CAIR authorized account 
representative, as appropriate. The superseding notice of delegation may 
replace any previously identified agent, add a new agent, or eliminate 
entirely any delegation of authority.
    (v) Any electronic submission covered by the certification in 
paragraph (b)(5)(iii)(D) of this section and made in accordance with a 
notice of delegation effective under paragraph (b)(5)(iv) of this 
section shall be deemed to be an electronic submission by the CAIR 
designated representative or alternate CAIR designated representative 
submitting such notice of delegation.
    (c) Account identification. The Administrator will assign a unique 
identifying number to each account established under paragraph (a) or 
(b) of this section.

[70 FR 25382, May 12, 2005, as amended at 71 FR 25394, Apr. 28, 2006; 71 
FR 74794, Dec. 13, 2006]



Sec. 96.352  Responsibilities of CAIR authorized account representative.

    Following the establishment of a CAIR NOX Ozone Season 
Allowance Tracking System account, all submissions to the Administrator 
pertaining to the account, including, but not limited to, submissions 
concerning the deduction or transfer of CAIR NOX Ozone Season 
allowances in the account, shall be made only by the CAIR authorized 
account representative for the account.



Sec. 96.353  Recordation of CAIR NOX Ozone Season allowance allocations.

    (a) By September 30, 2007, the Administrator will record in the CAIR 
NOX Ozone Season source's compliance account the CAIR 
NOX Ozone Season allowances allocated for the CAIR 
NOX Ozone Season units at the source, as submitted by the 
permitting authority in accordance with Sec. 96.341(a), for the control 
periods in 2009, 2010, 2011, 2012, 2013, and 2014.
    (b) By December 1, 2009, the Administrator will record in the CAIR 
NOX

[[Page 153]]

Ozone Season source's compliance account the CAIR NOX Ozone 
Season allowances allocated for the CAIR NOX Ozone Season 
units at the source, as submitted by the permitting authority in 
accordance with Sec. 96.341(b), for the control period in 2015.
    (c) By December 1, 2010 and December 1 of each year thereafter, the 
Administrator will record in the CAIR NOX Ozone Season 
source's compliance account the CAIR NOX Ozone Season 
allowances allocated for the CAIR NOX Ozone Season units at 
the source, as submitted by the permitting authority in accordance with 
Sec. 96.341(b), for the control period in the sixth year after the year 
of the applicable deadline for recordation under this paragraph.
    (d) By September 1, 2009 and September 1 of each year thereafter, 
the Administrator will record in the CAIR NOX Ozone Season 
source's compliance account the CAIR NOX Ozone Season 
allowances allocated for the CAIR NOX Ozone Season units at 
the source, as submitted by the permitting authority or determined by 
the Administrator in accordance with Sec. 96.341(c), for the control 
period in the year of the applicable deadline for recordation under this 
paragraph.
    (e) Serial numbers for allocated CAIR NOX Ozone Season 
allowances. When recording the allocation of CAIR NOX Ozone 
Season allowances for a CAIR NOX Ozone Season unit in a 
compliance account, the Administrator will assign each CAIR 
NOX Ozone Season allowance a unique identification number 
that will include digits identifying the year of the control period for 
which the CAIR NOX Ozone Season allowance is allocated.

[70 FR 25382, May 12, 2005, as amended at 71 FR 25394, Apr. 28, 2006]

    Editorial Note: At 71 FR 25395, Apr. 28, 2006, Sec. 96.353(d) was 
amended; however, the amendment could not be incorporated due to 
inaccurate amendatory instruction.



Sec. 96.354  Compliance with CAIR NOX emissions limitation.

    (a) Allowance transfer deadline. The CAIR NOX Ozone 
Season allowances are available to be deducted for compliance with a 
source's CAIR NOX Ozone Season emissions limitation for a 
control period in a given calendar year only if the CAIR NOX 
Ozone Season allowances:
    (1) Were allocated for the control period in the year or a prior 
year; and
    (2) Are held in the compliance account as of the allowance transfer 
deadline for the control period or are transferred into the compliance 
account by a CAIR NOX Ozone Season allowance transfer 
correctly submitted for recordation under Sec. Sec. 96.360 and 96.361 
by the allowance transfer deadline for the control period.
    (c)(1) Identification of CAIR NO X Ozone Season 
allowances by serial number. The CAIR authorized account representative 
for a source's compliance account may request that specific CAIR 
NOX Ozone Season allowances, identified by serial number, in 
the compliance account be deducted for emissions or excess emissions for 
a control period in accordance with paragraph (b) or (d) of this 
section. Such request shall be submitted to the Administrator by the 
allowance transfer deadline for the control period and include, in a 
format prescribed by the Administrator, the identification of the CAIR 
NOX Ozone Season source and the appropriate serial numbers.
    (2) First-in, first-out. The Administrator will deduct CAIR 
NOX Ozone Season allowances under paragraph (b) or (d) of 
this section from the source's compliance account, in the absence of an 
identification or in the case of a partial identification of CAIR 
NOX Ozone Season allowances by serial number under paragraph 
(c)(1) of this section, on a first-in, first-out (FIFO) accounting basis 
in the following order:
    (i) Any CAIR NOX Ozone Season allowances that were 
allocated to the units at the source, in the order of recordation; and 
then
    (ii) Any CAIR NOX Ozone Season allowances that were 
allocated to any entity and transferred and recorded in the compliance 
account pursuant to subpart GGGG of this part, in the order of 
recordation.
    (d) Deductions for excess emissions. (1) After making the deductions 
for compliance under paragraph (b) of this section for a control period 
in a calendar year in which the CAIR NOX Ozone Season source 
has excess emissions, the Administrator will deduct from the

[[Page 154]]

source's compliance account an amount of CAIR NOX Ozone 
Season allowances, allocated for the control period in the immediately 
following calendar year, equal to 3 times the number of tons of the 
source's excess emissions.
    (2) Any allowance deduction required under paragraph (d)(1) of this 
section shall not affect the liability of the owners and operators of 
the CAIR NOX Ozone Season source or the CAIR NOX 
Ozone Season units at the source for any fine, penalty, or assessment, 
or their obligation to comply with any other remedy, for the same 
violations, as ordered under the Clean Air Act or applicable State law.
    (e) Recordation of deductions. The Administrator will record in the 
appropriate compliance account all deductions from such an account under 
paragraphs (b) and (d) of this section and subpart IIII.
    (f) Administrator's action on submissions. (1) The Administrator may 
review and conduct independent audits concerning any submission under 
the CAIR NOX Ozone Season Trading Program and make 
appropriate adjustments of the information in the submissions.
    (2) The Administrator may deduct CAIR NOX Ozone Season 
allowances from or transfer CAIR NOX Ozone Season allowances 
to a source's compliance account based on the information in the 
submissions, as adjusted under paragraph (f)(1) of this section, and 
record such deductions and transfers.

[70 FR 25382, May 12, 2005, as amended at 71 FR 25395, Apr. 28, 2006]



Sec. 96.355  Banking.

    (a) CAIR NOX Ozone Season allowances may be banked for 
future use or transfer in a compliance account or a general account in 
accordance with paragraph (b) of this section.
    (b) Any CAIR NOX Ozone Season allowance that is held in a 
compliance account or a general account will remain in such account 
unless and until the CAIR NOX Ozone Season allowance is 
deducted or transferred under Sec. 96.354, Sec. 96.356, or subpart GG 
of this part.

[70 FR 25382, May 12, 2005, as amended at 71 FR 25395, Apr. 28, 2006]

    Editorial Note: At 71 FR 25395, Apr. 28, 2006, Sec. 96.355 was 
amended; however, the amendment could not be incorporated due to 
inaccurate amendatory instruction.



Sec. 96.356  Account error.

    The Administrator may, at his or her sole discretion and on his or 
her own motion, correct any error in any CAIR NOX Ozone 
Season Allowance Tracking System account. Within 10 business days of 
making such correction, the Administrator will notify the CAIR 
authorized account representative for the account.



Sec. 96.357  Closing of general accounts.

    (a) The CAIR authorized account representative of a general account 
may submit to the Administrator a request to close the account, which 
shall include a correctly submitted allowance transfer under Sec. Sec. 
96.360 and 96.361 for any CAIR NOX Ozone Season allowances in 
the account to one or more other CAIR NOX Ozone Season 
Allowance Tracking System accounts.
    (b) If a general account has no allowance transfers in or out of the 
account for a 12-month period or longer and does not contain any CAIR 
NOX Ozone Season allowances, the Administrator may notify the 
CAIR authorized account representative for the account that the account 
will be closed following 20 business days after the notice is sent. The 
account will be closed after the 20-day period unless, before the end of 
the 20-day period, the Administrator receives a correctly submitted 
transfer of CAIR NOX Ozone Season allowances into the account 
under Sec. Sec. 96.360 and 96.361 or a statement submitted by the CAIR 
authorized account representative demonstrating to the satisfaction of 
the Administrator good cause as to why the account should not be closed.

[70 FR 25382, May 12, 2005, as amended at 71 FR 25395, Apr. 28, 2006]

[[Page 155]]



         Subpart GGGG_CAIR NOX Ozone Season Allowance Transfers

    Source: 70 FR 25382, May 12, 2005, unless otherwise noted.



Sec. 96.360  Submission of CAIR NOX Ozone Season allowance transfers.

    A CAIR authorized account representative seeking recordation of a 
CAIR NOX Ozone Season allowance transfer shall submit the 
transfer to the Administrator. To be considered correctly submitted, the 
CAIR NOX Ozone Season allowance transfer shall include the 
following elements, in a format specified by the Administrator:
    (a) The account numbers for both the transferor and transferee 
accounts;
    (b) The serial number of each CAIR NOX Ozone Season 
allowance that is in the transferor account and is to be transferred; 
and
    (c) The name and signature of the CAIR authorized account 
representative of the transferor account and the date signed.



Sec. 96.361  EPA recordation.

    (a) Within 5 business days (except as provided in paragraph (b) of 
this section) of receiving a CAIR NOX Ozone Season allowance 
transfer, the Administrator will record a CAIR NOX Ozone 
Season allowance transfer by moving each CAIR NOX Ozone 
Season allowance from the transferor account to the transferee account 
as specified by the request, provided that:
    (1) The transfer is correctly submitted under Sec. 96.360; and
    (2) The transferor account includes each CAIR NOX Ozone 
Season allowance identified by serial number in the transfer.
    (b) A CAIR NOX Ozone Season allowance transfer that is 
submitted for recordation after the allowance transfer deadline for a 
control period and that includes any CAIR NOX Ozone Season 
allowances allocated for any control period before such allowance 
transfer deadline will not be recorded until after the Administrator 
completes the deductions under Sec. 96.354 for the control period 
immediately before such allowance transfer deadline.
    (c) Where a CAIR NOX Ozone Season allowance transfer 
submitted for recordation fails to meet the requirements of paragraph 
(a) of this section, the Administrator will not record such transfer.



Sec. 96.362  Notification.

    (a) Notification of recordation. Within 5 business days of 
recordation of a CAIR NOX Ozone Season allowance transfer 
under Sec. 96.361, the Administrator will notify the CAIR authorized 
account representatives of both the transferor and transferee accounts.
    (b) Notification of non-recordation. Within 10 business days of 
receipt of a CAIR NOX Ozone Season allowance transfer that 
fails to meet the requirements of Sec. 96.361(a), the Administrator 
will notify the CAIR authorized account representatives of both accounts 
subject to the transfer of:
    (1) A decision not to record the transfer, and
    (2) The reasons for such non-recordation.
    (c) Nothing in this section shall preclude the submission of a CAIR 
NOX Ozone Season allowance transfer for recordation following 
notification of non-recordation.



                  Subpart HHHH_Monitoring and Reporting

    Source: 70 FR 25382, May 12, 2005, unless otherwise noted.



Sec. 96.370  General requirements.

    The owners and operators, and to the extent applicable, the CAIR 
designated representative, of a CAIR NOX Ozone Season unit, 
shall comply with the monitoring, recordkeeping, and reporting 
requirements as provided in this subpart and in subpart H of part 75 of 
this chapter. For purposes of complying with such requirements, the 
definitions in Sec. 96.302 and in Sec. 72.2 of this chapter shall 
apply, and the terms ``affected unit,'' ``designated representative,'' 
and ``continuous emission monitoring system'' (or ``CEMS'') in part 75 
of this chapter shall be deemed to refer to the terms ``CAIR 
NOX Ozone Season unit,'' ``CAIR designated representative,'' 
and ``continuous emission monitoring system'' (or ``CEMS'') 
respectively, as defined in Sec. 96.302. The owner or operator of a 
unit that is not a CAIR

[[Page 156]]

NOX Ozone Season unit but that is monitored under Sec. 
75.72(b)(2)(ii) of this chapter shall comply with the same monitoring, 
recordkeeping, and reporting requirements as a CAIR NOX Ozone 
Season unit.
    (a) Requirements for installation, certification, and data 
accounting. The owner or operator of each CAIR NOX Ozone 
Season unit shall:
    (1) Install all monitoring systems required under this subpart for 
monitoring NOX mass emissions and individual unit heat input 
(including all systems required to monitor NOX emission rate, 
NOX concentration, stack gas moisture content, stack gas flow 
rate, CO2 or O2 concentration, and fuel flow rate, 
as applicable, in accordance with Sec. Sec. 75.71 and 75.72 of this 
chapter);
    (2) Successfully complete all certification tests required under 
Sec. 96.371 and meet all other requirements of this subpart and part 75 
of this chapter applicable to the monitoring systems under paragraph 
(a)(1) of this section; and
    (3) Record, report, and quality-assure the data from the monitoring 
systems under paragraph (a)(1) of this section.
    (b) Compliance deadlines. Except as provided in paragraph (e) of 
this section, the owner or operator shall meet the monitoring system 
certification and other requirements of paragraphs (a)(1) and (2) of 
this section on or before the following dates. The owner or operator 
shall record, report, and quality-assure the data from the monitoring 
systems under paragraph (a)(1) of this section on and after the 
following dates.
    (1) For the owner or operator of a CAIR NOX Ozone Season 
unit that commences commercial operation before July 1, 2007, by May 1, 
2008.
    (2) For the owner or operator of a CAIR NOX Ozone Season 
unit that commences commercial operation on or after July 1, 2007 and 
that reports on an annual basis under Sec. 96.374(d), by the later of 
the following dates:
    (i) 90 unit operating days or 180 calendar days, whichever occurs 
first, after the date on which the unit commences commercial operation; 
or
    (ii) May 1, 2008.
    (3) For the owner or operator of a CAIR NOX Ozone Season 
unit that commences commercial operation on or after July 1, 2007 and 
that reports on a control period basis under Sec. 96.374(d)(2)(ii), by 
the later of the following dates:
    (i) 90 unit operating days or 180 calendar days, whichever occurs 
first, after the date on which the unit commences commercial operation; 
or
    (ii) If the compliance date under paragraph (b)(3)(i) of this 
section is not during a control period, May 1 immediately following the 
compliance date under paragraph (b)(3)(i) of this section.
    (4) For the owner or operator of a CAIR NOX Ozone Season 
unit for which construction of a new stack or flue or installation of 
add-on NOX emission controls is completed after the 
applicable deadline under paragraph (b)(1), (2), (6), or (7) of this 
section and that reports on an annual basis under Sec. 96.374(d), by 90 
unit operating days or 180 calendar days, whichever occurs first, after 
the date on which emissions first exit to the atmosphere through the new 
stack or flue or add-on NOX emissions controls.
    (5) For the owner or operator of a CAIR NOX Ozone Season 
unit for which construction of a new stack or flue or installation of 
add-on NOX emission controls is completed after the 
applicable deadline under paragraph (b)(1), (3), (6), or (7) of this 
section and that reports on a control period basis under Sec. 
96.374(d)(2)(ii), by the later of the following dates:
    (i) 90 unit operating days or 180 calendar days, whichever occurs 
first, after the date on which emissions first exit to the atmosphere 
through the new stack or flue or add-on NOX emissions 
controls; or
    (ii) If the compliance date under paragraph (b)(5)(i) of this 
section is not during a control period, May 1 immediately following the 
compliance date under paragraph (b)(5)(i) of this section.
    (6) Notwithstanding the dates in paragraphs (b)(1), (2), and (3) of 
this section, for the owner or operator of a unit for which a CAIR 
NOX Ozone Season opt-in permit application is submitted and 
not withdrawn and a CAIR

[[Page 157]]

opt-in permit is not yet issued or denied under subpart IIII of this 
part, by the date specified in Sec. 96.384(b).
    (7) Notwithstanding the dates in paragraphs (b)(1), (2), and (3) of 
this section, for the owner or operator of a CAIR NOX Ozone 
Season opt-in unit, by the date on which the CAIR NOX Ozone 
Season opt-in unit under subpart IIII of this part enters the CAIR 
NOX Ozone Season Trading Program as provided in Sec. 
96.384(g).
    (c) Reporting data. The owner or operator of a CAIR NOX 
Ozone Season unit that does not meet the applicable compliance date set 
forth in paragraph (b) of this section for any monitoring system under 
paragraph (a)(1) of this section shall, for each such monitoring system, 
determine, record, and report maximum potential (or, as appropriate, 
minimum potential) values for NOX concentration, 
NOX emission rate, stack gas flow rate, stack gas moisture 
content, fuel flow rate, and any other parameters required to determine 
NOX mass emissions and heat input in accordance with Sec. 
75.31(b)(2) or (c)(3) of this chapter, section 2.4 of appendix D to part 
75 of this chapter, or section 2.5 of appendix E to part 75 of this 
chapter, as applicable.
    (d) Prohibitions. (1) No owner or operator of a CAIR NOX 
Ozone Season unit shall use any alternative monitoring system, 
alternative reference method, or any other alternative to any 
requirement of this subpart without having obtained prior written 
approval in accordance with Sec. 96.375.
    (2) No owner or operator of a CAIR NOX Ozone Season unit 
shall operate the unit so as to discharge, or allow to be discharged, 
NOX emissions to the atmosphere without accounting for all 
such emissions in accordance with the applicable provisions of this 
subpart and part 75 of this chapter.
    (3) No owner or operator of a CAIR NOX Ozone Season unit 
shall disrupt the continuous emission monitoring system, any portion 
thereof, or any other approved emission monitoring method, and thereby 
avoid monitoring and recording NOX mass emissions discharged 
into the atmosphere or heat input, except for periods of recertification 
or periods when calibration, quality assurance testing, or maintenance 
is performed in accordance with the applicable provisions of this 
subpart and part 75 of this chapter.
    (4) No owner or operator of a CAIR NOX Ozone Season unit 
shall retire or permanently discontinue use of the continuous emission 
monitoring system, any component thereof, or any other approved 
monitoring system under this subpart, except under any one of the 
following circumstances:
    (i) During the period that the unit is covered by an exemption under 
Sec. 96.305 that is in effect;
    (ii) The owner or operator is monitoring emissions from the unit 
with another certified monitoring system approved, in accordance with 
the applicable provisions of this subpart and part 75 of this chapter, 
by the permitting authority for use at that unit that provides emission 
data for the same pollutant or parameter as the retired or discontinued 
monitoring system; or
    (iii) The CAIR designated representative submits notification of the 
date of certification testing of a replacement monitoring system for the 
retired or discontinued monitoring system in accordance with Sec. 
96.371(d)(3)(i).
    (e) Long-term cold storage. The owner or operator of a CAIR 
NOX Ozone Season unit is subject to the applicable provisions 
of part 75 of this chapter concerning units in long-term cold storage.

[70 FR 25382, May 12, 2005, as amended at 71 FR 25395, Apr. 28, 2006]



Sec. 96.371  Initial certification and recertification procedures.

    (a) The owner or operator of a CAIR NOX Ozone Season unit 
shall be exempt from the initial certification requirements of this 
section for a monitoring system under Sec. 96.370(a)(1) if the 
following conditions are met:
    (1) The monitoring system has been previously certified in 
accordance with part 75 of this chapter; and
    (2) The applicable quality-assurance and quality-control 
requirements of Sec. 75.21 of this chapter and appendix B, appendix D, 
and appendix E to part 75 of this chapter are fully met for the 
certified monitoring system described in paragraph (a)(1) of this 
section.

[[Page 158]]

    (b) The recertification provisions of this section shall apply to a 
monitoring system under Sec. 96.370(a)(1) exempt from initial 
certification requirements under paragraph (a) of this section.
    (c) If the Administrator has previously approved a petition under 
Sec. 75.17(a) or (b) of this chapter for apportioning the 
NOX emission rate measured in a common stack or a petition 
under Sec. 75.66 of this chapter for an alternative to a requirement in 
Sec. 75.12 or Sec. 75.17 of this chapter, the CAIR designated 
representative shall resubmit the petition to the Administrator under 
Sec. 96.375(a) to determine whether the approval applies under the CAIR 
NOX Ozone Season Trading Program.
    (d) Except as provided in paragraph (a) of this section, the owner 
or operator of a CAIR NOX Ozone Season unit shall comply with 
the following initial certification and recertification procedures for a 
continuous monitoring system (i.e., a continuous emission monitoring 
system and an excepted monitoring system under appendices D and E to 
part 75 of this chapter) under Sec. 96.370(a)(1). The owner or operator 
of a unit that qualifies to use the low mass emissions excepted 
monitoring methodology under Sec. 75.19 of this chapter or that 
qualifies to use an alternative monitoring system under subpart E of 
part 75 of this chapter shall comply with the procedures in paragraph 
(e) or (f) of this section respectively.
    (1) Requirements for initial certification. The owner or operator 
shall ensure that each continuous monitoring system under Sec. 
96.370(a)(1)(including the automated data acquisition and handling 
system) successfully completes all of the initial certification testing 
required under Sec. 75.20 of this chapter by the applicable deadline in 
Sec. 96.370(b). In addition, whenever the owner or operator installs a 
monitoring system to meet the requirements of this subpart in a location 
where no such monitoring system was previously installed, initial 
certification in accordance with Sec. 75.20 of this chapter is 
required.
    (2) Requirements for recertification. Whenever the owner or operator 
makes a replacement, modification, or change in any certified continuous 
emission monitoring system under Sec. 96.370(a)(1) that may 
significantly affect the ability of the system to accurately measure or 
record NOX mass emissions or heat input rate or to meet the 
quality-assurance and quality-control requirements of Sec. 75.21 of 
this chapter or appendix B to part 75 of this chapter, the owner or 
operator shall recertify the monitoring system in accordance with Sec. 
75.20(b) of this chapter. Furthermore, whenever the owner or operator 
makes a replacement, modification, or change to the flue gas handling 
system or the unit's operation that may significantly change the stack 
flow or concentration profile, the owner or operator shall recertify 
each continuous emission monitoring system whose accuracy is potentially 
affected by the change, in accordance with Sec. 75.20(b) of this 
chapter. Examples of changes to a continuous emission monitoring system 
that require recertification include: replacement of the analyzer, 
complete replacement of an existing continuous emission monitoring 
system, or change in location or orientation of the sampling probe or 
site. Any fuel flowmeter systems, and any excepted NOX 
monitoring system under appendix E to part 75 of this chapter, under 
Sec. 96.370(a)(1) are subject to the recertification requirements in 
Sec. 75.20(g)(6) of this chapter.
    (3) Approval process for initial certification and recertification. 
Paragraphs (d)(3)(i) through (iv) of this section apply to both initial 
certification and recertification of a continuous monitoring system 
under Sec. 96.370(a)(1). For recertifications, replace the words 
``certification'' and ``initial certification'' with the word 
``recertification'', replace the word ``certified'' with the word 
``recertified,'' and follow the procedures in Sec. Sec. 75.20(b)(5) and 
(g)(7) of this chapter in lieu of the procedures in paragraph (d)(3)(v) 
of this section.
    (i) Notification of certification. The CAIR designated 
representative shall submit to the permitting authority, the appropriate 
EPA Regional Office, and the Administrator written notice of the dates 
of certification testing, in accordance with Sec. 96.373.
    (ii) Certification application. The CAIR designated representative 
shall submit to the permitting authority a certification application for 
each monitoring

[[Page 159]]

system. A complete certification application shall include the 
information specified in Sec. 75.63 of this chapter.
    (iii) Provisional certification date. The provisional certification 
date for a monitoring system shall be determined in accordance with 
Sec. 75.20(a)(3) of this chapter. A provisionally certified monitoring 
system may be used under the CAIR NOX Ozone Season Trading 
Program for a period not to exceed 120 days after receipt by the 
permitting authority of the complete certification application for the 
monitoring system under paragraph (d)(3)(ii) of this section. Data 
measured and recorded by the provisionally certified monitoring system, 
in accordance with the requirements of part 75 of this chapter, will be 
considered valid quality-assured data (retroactive to the date and time 
of provisional certification), provided that the permitting authority 
does not invalidate the provisional certification by issuing a notice of 
disapproval within 120 days of the date of receipt of the complete 
certification application by the permitting authority.
    (iv) Certification application approval process. The permitting 
authority will issue a written notice of approval or disapproval of the 
certification application to the owner or operator within 120 days of 
receipt of the complete certification application under paragraph 
(d)(3)(ii) of this section. In the event the permitting authority does 
not issue such a notice within such 120-day period, each monitoring 
system that meets the applicable performance requirements of part 75 of 
this chapter and is included in the certification application will be 
deemed certified for use under the CAIR NOX Ozone Season 
Trading Program.
    (A) Approval notice. If the certification application is complete 
and shows that each monitoring system meets the applicable performance 
requirements of part 75 of this chapter, then the permitting authority 
will issue a written notice of approval of the certification application 
within 120 days of receipt.
    (B) Incomplete application notice. If the certification application 
is not complete, then the permitting authority will issue a written 
notice of incompleteness that sets a reasonable date by which the CAIR 
designated representative must submit the additional information 
required to complete the certification application. If the CAIR 
designated representative does not comply with the notice of 
incompleteness by the specified date, then the permitting authority may 
issue a notice of disapproval under paragraph (d)(3)(iv)(C) of this 
section. The 120-day review period shall not begin before receipt of a 
complete certification application.
    (C) Disapproval notice. If the certification application shows that 
any monitoring system does not meet the performance requirements of part 
75 of this chapter or if the certification application is incomplete and 
the requirement for disapproval under paragraph (d)(3)(iv)(B) of this 
section is met, then the permitting authority will issue a written 
notice of disapproval of the certification application. Upon issuance of 
such notice of disapproval, the provisional certification is invalidated 
by the permitting authority and the data measured and recorded by each 
uncertified monitoring system shall not be considered valid quality-
assured data beginning with the date and hour of provisional 
certification (as defined under Sec. 75.20(a)(3) of this chapter). The 
owner or operator shall follow the procedures for loss of certification 
in paragraph (d)(3)(v) of this section for each monitoring system that 
is disapproved for initial certification.
    (D) Audit decertification. The permitting authority or, for a CAIR 
NOX Ozone Season opt-in unit or a unit for which a CAIR opt-
in permit application is submitted and not withdrawn and a CAIR opt-in 
permit is not yet issued or denied under subpart IIII of this part, the 
Administrator may issue a notice of disapproval of the certification 
status of a monitor in accordance with Sec. 96.372(b).
    (v) Procedures for loss of certification. If the permitting 
authority or the Administrator issues a notice of disapproval of a 
certification application under paragraph (d)(3)(iv)(C) of this section 
or a notice of disapproval of certification status under paragraph 
(d)(3)(iv)(D) of this section, then:

[[Page 160]]

    (A) The owner or operator shall substitute the following values, for 
each disapproved monitoring system, for each hour of unit operation 
during the period of invalid data specified under Sec. 
75.20(a)(4)(iii), Sec. 75.20(g)(7), or Sec. 75.21(e) of this chapter 
and continuing until the applicable date and hour specified under Sec. 
75.20(a)(5)(i) or (g)(7) of this chapter:
    (1) For a disapproved NOX emission rate (i.e., 
NOX-diluent) system, the maximum potential NOX 
emission rate, as defined in Sec. 72.2 of this chapter.
    (2) For a disapproved NOX pollutant concentration monitor 
and disapproved flow monitor, respectively, the maximum potential 
concentration of NOX and the maximum potential flow rate, as 
defined in sections 2.1.2.1 and 2.1.4.1 of appendix A to part 75 of this 
chapter.
    (3) For a disapproved moisture monitoring system and disapproved 
diluent gas monitoring system, respectively, the minimum potential 
moisture percentage and either the maximum potential CO2 
concentration or the minimum potential O2 concentration (as 
applicable), as defined in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of 
appendix A to part 75 of this chapter.
    (4) For a disapproved fuel flowmeter system, the maximum potential 
fuel flow rate, as defined in section 2.4.2.1 of appendix D to part 75 
of this chapter.
    (5) For a disapproved excepted NOX monitoring system 
under appendix E to part 75 of this chapter, the fuel-specific maximum 
potential NOX emission rate, as defined in Sec. 72.2 of this 
chapter.
    (B) The CAIR designated representative shall submit a notification 
of certification retest dates and a new certification application in 
accordance with paragraphs (d)(3)(i) and (ii) of this section.
    (C) The owner or operator shall repeat all certification tests or 
other requirements that were failed by the monitoring system, as 
indicated in the permitting authority's or the Administrator's notice of 
disapproval, no later than 30 unit operating days after the date of 
issuance of the notice of disapproval.
    (e) Initial certification and recertification procedures for units 
using the low mass emission excepted methodology under Sec. 75.19 of 
this chapter. The owner or operator of a unit qualified to use the low 
mass emissions (LME) excepted methodology under Sec. 75.19 of this 
chapter shall meet the applicable certification and recertification 
requirements in Sec. Sec. 75.19(a)(2) and 75.20(h) of this chapter. If 
the owner or operator of such a unit elects to certify a fuel flowmeter 
system for heat input determination, the owner or operator shall also 
meet the certification and recertification requirements in Sec. 
75.20(g) of this chapter.
    (f) Certification/recertification procedures for alternative 
monitoring systems. The CAIR designated representative of each unit for 
which the owner or operator intends to use an alternative monitoring 
system approved by the Administrator and, if applicable, the permitting 
authority under subpart E of part 75 of this chapter shall comply with 
the applicable notification and application procedures of Sec. 75.20(f) 
of this chapter.

[70 FR 25382, May 12, 2005, as amended at 71 FR 25395, Apr. 28, 2006; 71 
FR 74794, Dec. 13, 2006]



Sec. 96.372  Out of control periods.

    (a) Whenever any monitoring system fails to meet the quality-
assurance and quality-control requirements or data validation 
requirements of part 75 of this chapter, data shall be substituted using 
the applicable missing data procedures in subpart D or subpart H of, or 
appendix D or appendix E to, part 75 of this chapter.
    (b) Audit decertification. Whenever both an audit of a monitoring 
system and a review of the initial certification or recertification 
application reveal that any monitoring system should not have been 
certified or recertified because it did not meet a particular 
performance specification or other requirement under Sec. 96.371 or the 
applicable provisions of part 75 of this chapter, both at the time of 
the initial certification or recertification application submission and 
at the time of the audit, the permitting authority or, for a CAIR 
NOX Ozone Season opt-in unit or a unit for which a CAIR opt-
in permit application is submitted and not withdrawn and a CAIR opt-in 
permit is not yet issued or denied under subpart IIII of this part, the 
Administrator will

[[Page 161]]

issue a notice of disapproval of the certification status of such 
monitoring system. For the purposes of this paragraph, an audit shall be 
either a field audit or an audit of any information submitted to the 
permitting authority or the Administrator. By issuing the notice of 
disapproval, the permitting authority or the Administrator revokes 
prospectively the certification status of the monitoring system. The 
data measured and recorded by the monitoring system shall not be 
considered valid quality-assured data from the date of issuance of the 
notification of the revoked certification status until the date and time 
that the owner or operator completes subsequently approved initial 
certification or recertification tests for the monitoring system. The 
owner or operator shall follow the applicable initial certification or 
recertification procedures in Sec. 96.371 for each disapproved 
monitoring system.



Sec. 96.373  Notifications.

    The CAIR designated representative for a CAIR NOX Ozone 
Season unit shall submit written notice to the permitting authority and 
the Administrator in accordance with Sec. 75.61 of this chapter.

[70 FR 25382, May 12, 2005, as amended at 71 FR 25395, Apr. 28, 2006]



Sec. 96.374  Recordkeeping and reporting.

    (a) General provisions. The CAIR designated representative shall 
comply with all recordkeeping and reporting requirements in this 
section, the applicable recordkeeping and reporting requirements under 
Sec. 75.73 of this chapter, and the requirements of Sec. 96.310(e)(1).
    (b) Monitoring plans. The owner or operator of a CAIR NOX 
Ozone Season unit shall comply with requirements of Sec. 75.73(c) and 
(e) of this chapter and, for a unit for which a CAIR opt-in permit 
application is submitted and not withdrawn and a CAIR opt-in permit is 
not yet issued or denied under subpart IIII of this part, Sec. Sec. 
96.383 and 96.384(a).
    (c) Certification applications. The CAIR designated representative 
shall submit an application to the permitting authority within 45 days 
after completing all initial certification or recertification tests 
required under Sec. 96.371, including the information required under 
Sec. 75.63 of this chapter.
    (d) Quarterly reports. The CAIR designated representative shall 
submit quarterly reports, as follows:
    (1) If the CAIR NOX Ozone Season unit is subject to an 
Acid Rain emissions limitation or a CAIR NOX emissions 
limitation or if the owner or operator of such unit chooses to report on 
an annual basis under this subpart, the CAIR designated representative 
shall meet the requirements of subpart H of part 75 of this chapter 
(concerning monitoring of NOX mass emissions) for such unit 
for the entire year and shall report the NOX mass emissions 
data and heat input data for such unit, in an electronic quarterly 
report in a format prescribed by the Administrator, for each calendar 
quarter beginning with:
    (i) For a unit that commences commercial operation before July 1, 
2007, the calendar quarter covering May 1, 2008 through June 30, 2008;
    (ii) For a unit that commences commercial operation on or after July 
1, 2007, the calendar quarter corresponding to the earlier of the date 
of provisional certification or the applicable deadline for initial 
certification under Sec. 96.370(b), unless that quarter is the third or 
fourth quarter of 2007 or the first quarter of 2008, in which case 
reporting shall commence in the quarter covering May 1, 2008 through 
June 30, 2008;
    (iii) Notwithstanding paragraphs (d)(1)(i) and (ii) of this section, 
for a unit for which a CAIR opt-in permit application is submitted and 
not withdrawn and a CAIR opt-in permit is not yet issued or denied under 
subpart IIII of this part, the calendar quarter corresponding to the 
date specified in Sec. 96.384(b); and
    (iv) Notwithstanding paragraphs (d)(1)(i) and (ii) of this section, 
for a CAIR NOX Ozone Season opt-in unit under subpart IIII of 
this part, the calendar quarter corresponding to the date on which the 
CAIR NOX Ozone Season opt-in unit enters the CAIR 
NOX Ozone Season Trading Program as provided in Sec. 
96.384(g).
    (2) If the CAIR NOX Ozone Season unit is not subject to 
an Acid Rain emissions limitation or a CAIR NOX

[[Page 162]]

emissions limitation, then the CAIR designated representative shall 
either:
    (i) Meet the requirements of subpart H of part 75 (concerning 
monitoring of NOX mass emissions) for such unit for the 
entire year and report the NOX mass emissions data and heat 
input data for such unit in accordance with paragraph (d)(1) of this 
section; or
    (ii) Meet the requirements of subpart H of part 75 for the control 
period (including the requirements in Sec. 75.74(c) of this chapter) 
and report NOX mass emissions data and heat input data 
(including the data described in Sec. 75.74(c)(6) of this chapter) for 
such unit only for the control period of each year and report, in an 
electronic quarterly report in a format prescribed by the Administrator, 
for each calendar quarter beginning with:
    (A) For a unit that commences commercial operation before July 1, 
2007, the calendar quarter covering May 1, 2008 through June 30, 2008;
    (B) For a unit that commences commercial operation on or after July 
1, 2007, the calendar quarter corresponding to the earlier of the date 
of provisional certification or the applicable deadline for initial 
certification under Sec. 96.370(b), unless that date is not during a 
control period, in which case reporting shall commence in the quarter 
that includes May 1 through June 30 of the first control period after 
such date;.
    (C) Notwithstanding paragraphs (d)(2)(ii)(A) and (2)(ii)(B) of this 
section, for a unit for which a CAIR opt-in permit application is 
submitted and not withdrawn and a CAIR opt-in permit is not yet issued 
or denied under subpart IIII of this part, the calendar quarter 
corresponding to the date specified in Sec. 96.384(b); and
    (D) Notwithstanding paragraphs (d)(2)(ii)(A) and (2)(ii)(B) of this 
section, for a CAIR NOX Ozone Season opt-in unit under 
subpart IIII of this part, the calendar quarter corresponding to the 
date on which the CAIR NOX Ozone Season opt-in unit enters 
the CAIR NOX Ozone Season Trading Program as provided in 
Sec. 96.384(g).
    (2) The CAIR designated representative shall submit each quarterly 
report to the Administrator within 30 days following the end of the 
calendar quarter covered by the report. Quarterly reports shall be 
submitted in the manner specified in Sec. 75.73(f) of this chapter.
    (3) For CAIR NOX Ozone Season units that are also subject 
to an Acid Rain emissions limitation or the CAIR NOX Annual 
Trading Program or CAIR SO2 Trading Program, quarterly 
reports shall include the applicable data and information required by 
subparts F through H of part 75 of this chapter as applicable, in 
addition to the NOX mass emission data, heat input data, and 
other information required by this subpart.
    (e) Compliance certification. The CAIR designated representative 
shall submit to the Administrator a compliance certification (in a 
format prescribed by the Administrator) in support of each quarterly 
report based on reasonable inquiry of those persons with primary 
responsibility for ensuring that all of the unit's emissions are 
correctly and fully monitored. The certification shall state that:
    (1) The monitoring data submitted were recorded in accordance with 
the applicable requirements of this subpart and part 75 of this chapter, 
including the quality assurance procedures and specifications;
    (2) For a unit with add-on NOX emission controls and for 
all hours where NOX data are substituted in accordance with 
Sec. 75.34(a)(1) of this chapter, the add-on emission controls were 
operating within the range of parameters listed in the quality 
assurance/quality control program under appendix B to part 75 of this 
chapter and the substitute data values do not systematically 
underestimate NOX emissions; and
    (3) For a unit that is reporting on a control period basis under 
paragraph (d)(2)(ii) of this section, the NOX emission rate 
and NOX concentration values substituted for missing data 
under subpart D of part 75 of this chapter are calculated using only 
values from a control period and do not systematically underestimate 
NOX emissions.

[70 FR 25382, May 12, 2005, as amended at 71 FR 25395, Apr. 28, 2006]

[[Page 163]]



Sec. 96.375  Petitions.

    (a) Except as provided in paragraph (b)(2) of this section, the CAIR 
designated representative of a CAIR NOX Ozone Season unit 
that is subject to an Acid Rain emissions limitation may submit a 
petition under Sec. 75.66 of this chapter to the Administrator 
requesting approval to apply an alternative to any requirement of this 
subpart. Application of an alternative to any requirement of this 
subpart is in accordance with this subpart only to the extent that the 
petition is approved in writing by the Administrator, in consultation 
with the permitting authority.
    (b)(1) The CAIR designated representative of a CAIR NOX 
Ozone Season unit that is not subject to an Acid Rain emissions 
limitation may submit a petition under Sec. 75.66 of this chapter to 
the permitting authority and the Administrator requesting approval to 
apply an alternative to any requirement of this subpart. Application of 
an alternative to any requirement of this subpart is in accordance with 
this subpart only to the extent that the petition is approved in writing 
by both the permitting authority and the Administrator.
    (2) The CAIR designated representative of a CAIR NOX 
Ozone Season unit that is subject to an Acid Rain emissions limitation 
may submit a petition under Sec. 75.66 of this chapter to the 
permitting authority and the Administrator requesting approval to apply 
an alternative to a requirement concerning any additional continuous 
emission monitoring system required under Sec. 75.72 of this chapter. 
Application of an alternative to any such requirement is in accordance 
with this subpart only to the extent that the petition is approved in 
writing by both the permitting authority and the Administrator.



             Subpart IIII_CAIR NOX Ozone Season Opt-in Units

    Source: 70 FR 25382, May 12, 2005, unless otherwise noted.



Sec. 96.380  Applicability.

    A CAIR NOX Ozone Season opt-in unit must be a unit that:
    (a) Is located in the State;
    (b) Is not a CAIR NOX Ozone Season unit under Sec. 
96.304 and is not covered by a retired unit exemption under Sec. 96.305 
that is in effect;
    (c) Is not covered by a retired unit exemption under Sec. 72.8 of 
this chapter that is in effect;
    (d) Has or is required or qualified to have a title V operating 
permit or other federally enforceable permit; and
    (e) Vents all of its emissions to a stack and can meet the 
monitoring, recordkeeping, and reporting requirements of subpart HHHH of 
this part.



Sec. 96.381  General.

    (a) Except as otherwise provided in Sec. Sec. 96.301 through 
96.304, Sec. Sec. 96.306 through 96.308, and subparts BBBB and CCCC and 
subparts FFFF through HHHH of this part, a CAIR NOX Ozone 
Season opt-in unit shall be treated as a CAIR NOX Ozone 
Season unit for purposes of applying such sections and subparts of this 
part.
    (b) Solely for purposes of applying, as provided in this subpart, 
the requirements of subpart HHHH of this part to a unit for which a CAIR 
opt-in permit application is submitted and not withdrawn and a CAIR opt-
in permit is not yet issued or denied under this subpart, such unit 
shall be treated as a CAIR NOX Ozone Season unit before 
issuance of a CAIR opt-in permit for such unit.



Sec. 96.382  CAIR designated representative.

    Any CAIR NOX Ozone Season opt-in unit, and any unit for 
which a CAIR opt-in permit application is submitted and not withdrawn 
and a CAIR opt-in permit is not yet issued or denied under this subpart, 
located at the same source as one or more CAIR NOX Ozone 
Season units shall have the same CAIR designated representative and 
alternate CAIR designated representative as such CAIR NOX 
Ozone Season units.



Sec. 96.383  Applying for CAIR opt-in permit.

    (a) Applying for initial CAIR opt-in permit. The CAIR designated 
representative of a unit meeting the requirements for a CAIR 
NOX Ozone Season opt-in unit in Sec. 96.380 may apply for an 
initial CAIR opt-in permit at any time, except

[[Page 164]]

as provided under Sec. 96.386 (f) and (g), and, in order to apply, must 
submit the following:
    (1) A complete CAIR permit application under Sec. 96.322;
    (2) A certification, in a format specified by the permitting 
authority, that the unit:
    (i) Is not a CAIR NOX Ozone Season unit under Sec. 
96.304 and is not covered by a retired unit exemption under Sec. 96.305 
that is in effect;
    (ii) Is not covered by a retired unit exemption under Sec. 72.8 of 
this chapter that is in effect;
    (iii) Vents all of its emissions to a stack; and
    (iv) Has documented heat input for more than 876 hours during the 6 
months immediately preceding submission of the CAIR permit application 
under Sec. 96.322;
    (3) A monitoring plan in accordance with subpart HHHH of this part;
    (4) A complete certificate of representation under Sec. 96.313 
consistent with Sec. 96.382, if no CAIR designated representative has 
been previously designated for the source that includes the unit; and
    (5) A statement, in a format specified by the permitting authority, 
whether the CAIR designated representative requests that the unit be 
allocated CAIR NOX Ozone Season allowances under Sec. 
96.388(b) or Sec. 96.388(c) (subject to the conditions in Sec. Sec. 
96.384(h) and 96.386(g)). If allocation under Sec. 96.388(c) is 
requested, this statement shall include a statement that the owners and 
operators of the unit intend to repower the unit before January 1, 2015 
and that they will provide, upon request, documentation demonstrating 
such intent.
    (b) Duty to reapply. (1) The CAIR designated representative of a 
CAIR NOX Ozone Season opt-in unit shall submit a complete 
CAIR permit application under Sec. 96.322 to renew the CAIR opt-in unit 
permit in accordance with the permitting authority's regulations for 
title V operating permits, or the permitting authority's regulations for 
other federally enforceable permits if applicable, addressing permit 
renewal.
    (2) Unless the permitting authority issues a notification of 
acceptance of withdrawal of the CAIR NOX Ozone Season opt-in 
unit from the CAIR NOX Ozone Season Trading Program in 
accordance with Sec. 96.186 or the unit becomes a CAIR NOX 
Ozone Season unit under Sec. 96.304, the CAIR NOX opt-in 
unit shall remain subject to the requirements for a CAIR NOX 
Ozone Season opt-in unit, even if the CAIR designated representative for 
the CAIR NOX Ozone Season opt-in unit fails to submit a CAIR 
permit application that is required for renewal of the CAIR opt-in 
permit under paragraph (b)(1) of this section.

[70 FR 25382, May 12, 2005, as amended at 71 FR 25396, Apr. 28, 2006]



Sec. 96.384  Opt-in process.

    The permitting authority will issue or deny a CAIR opt-in permit for 
a unit for which an initial application for a CAIR opt-in permit under 
Sec. 96.383 is submitted in accordance with the following:
    (a) Interim review of monitoring plan. The permitting authority and 
the Administrator will determine, on an interim basis, the sufficiency 
of the monitoring plan accompanying the initial application for a CAIR 
opt-in permit under Sec. 96.383. A monitoring plan is sufficient, for 
purposes of interim review, if the plan appears to contain information 
demonstrating that the NOX emissions rate and heat input of 
the unit and all other applicable parameters are monitored and reported 
in accordance with subpart HHHH of this part. A determination of 
sufficiency shall not be construed as acceptance or approval of the 
monitoring plan.
    (b) Monitoring and reporting. (1)(i) If the permitting authority and 
the Administrator determine that the monitoring plan is sufficient under 
paragraph (a) of this section, the owner or operator shall monitor and 
report the NOX emissions rate and the heat input of the unit 
and all other applicable parameters, in accordance with subpart HHHH of 
this part, starting on the date of certification of the appropriate 
monitoring systems under subpart HHHH of this part and continuing until 
a CAIR opt-in permit is denied under Sec. 96.384(f) or, if a CAIR opt-
in permit is issued, the date and time when the unit is withdrawn from 
the CAIR NOX Ozone Season Trading Program in accordance with 
Sec. 96.386.

[[Page 165]]

    (ii) The monitoring and reporting under paragraph (b)(1)(i) of this 
section shall include the entire control period immediately before the 
date on which the unit enters the CAIR NOX Ozone Season 
Trading Program under Sec. 96.384(g), during which period monitoring 
system availability must not be less than 90 percent under subpart HHHH 
of this part and the unit must be in full compliance with any applicable 
State or Federal emissions or emissions-related requirements.
    (2) To the extent the NOX emissions rate and the heat 
input of the unit are monitored and reported in accordance with subpart 
HHHH of this part for one or more control periods, in addition to the 
control period under paragraph (b)(1)(ii) of this section, during which 
control periods monitoring system availability is not less than 90 
percent under subpart HHHH of this part and the unit is in full 
compliance with any applicable State or Federal emissions or emissions-
related requirements and which control periods begin not more than 3 
years before the unit enters the CAIR NOX Ozone Season 
Trading Program under Sec. 96.384(g), such information shall be used as 
provided in paragraphs (c) and (d) of this section.
    (c) Baseline heat input. The unit's baseline heat input shall equal:
    (1) If the unit's NOX emissions rate and heat input are 
monitored and reported for only one control period, in accordance with 
paragraph (b)(1) of this section, the unit's total heat input (in mmBtu) 
for the control period; or
    (2) If the unit's NOX emissions rate and heat input are 
monitored and reported for more than one control period, in accordance 
with paragraphs (b)(1) and (2) of this section, the average of the 
amounts of the unit's total heat input (in mmBtu) for the control 
periods under paragraphs (b)(1)(ii) and (2) of this section.
    (d) Baseline NOX emission rate. The unit's baseline 
NOX emission rate shall equal:
    (1) If the unit's NOX emissions rate and heat input are 
monitored and reported for only one control period, in accordance with 
paragraph (b)(1) of this section, the unit's NOX emissions 
rate (in lb/mmBtu) for the control period;
    (2) If the unit's NOX emissions rate and heat input are 
monitored and reported for more than one control period, in accordance 
with paragraphs (b)(1) and (2) of this section, and the unit does not 
have add-on NOX emission controls during any such control 
periods, the average of the amounts of the unit's NOX 
emissions rate (in lb/mmBtu) for the control periods under paragraphs 
(b)(1)(ii) and (2) of this section; or
    (3) If the unit's NOX emissions rate and heat input are 
monitored and reported for more than one control period, in accordance 
with paragraphs (b)(1) and (2) of this section, and the unit has add-on 
NOX emission controls during any such control periods, the 
average of the amounts of the unit's NOX emissions rate (in 
lb/mmBtu) for such control periods during which the unit has add-on 
NOX emission controls.
    (e) Issuance of CAIR opt-in permit. After calculating the baseline 
heat input and the baseline NOX emissions rate for the unit 
under paragraphs (c) and (d) of this section and if the permitting 
authority determines that the CAIR designated representative shows that 
the unit meets the requirements for a CAIR NOX Ozone Season 
opt-in unit in Sec. 96.380 and meets the elements certified in Sec. 
96.383(a)(2), the permitting authority will issue a CAIR opt-in permit. 
The permitting authority will provide a copy of the CAIR opt-in permit 
to the Administrator, who will then establish a compliance account for 
the source that includes the CAIR NOX Ozone Season opt-in 
unit unless the source already has a compliance account.
    (f) Issuance of denial of CAIR opt-in permit. Notwithstanding 
paragraphs (a) through (e) of this section, if at any time before 
issuance of a CAIR opt-in permit for the unit, the permitting authority 
determines that the CAIR designated representative fails to show that 
the unit meets the requirements for a CAIR NOX Ozone Season 
opt-in unit in Sec. 96.380 or meets the elements certified in Sec. 
96.383(a)(2), the permitting authority will issue a denial of a CAIR 
opt-in permit for the unit.
    (g) Date of entry into CAIR NOX Ozone Season Trading 
Program. A unit for which an initial CAIR opt-in permit is

[[Page 166]]

issued by the permitting authority shall become a CAIR NOX 
Ozone Season opt-in unit, and a CAIR NOX Ozone Season unit, 
as of the later of May 1, 2009 or May 1 of the first control period 
during which such CAIR opt-in permit is issued.
    (h) Repowered CAIR NOX Ozone Season opt-in unit. (1) If 
CAIR designated representative requests, and the permitting authority 
issues a CAIR opt-in permit providing for, allocation to a CAIR 
NOX Ozone Season opt-in unit of CAIR NOX Ozone 
Season allowances under Sec. 96.388(c) and such unit is repowered after 
its date of entry into the CAIR NOX Ozone Season Trading 
Program under paragraph (g) of this section, the repowered unit shall be 
treated as a CAIR NOX Ozone Season opt-in unit replacing the 
original CAIR NOX Ozone Season opt-in unit, as of the date of 
start-up of the repowered unit's combustion chamber.
    (2) Notwithstanding paragraphs (c) and (d) of this section, as of 
the date of start-up under paragraph (h)(1) of this section, the 
repowered unit shall be deemed to have the same date of commencement of 
operation, date of commencement of commercial operation, baseline heat 
input, and baseline NOX emission rate as the original CAIR 
NOX Ozone Season opt-in unit, and the original CAIR 
NOX Ozone Season opt-in unit shall no longer be treated as a 
CAIR NOX Ozone Season opt-in unit or a CAIR NOX 
Ozone Season unit.

[70 FR 25382, May 12, 2005, as amended at 71 FR 25396, Apr. 28, 2006; 71 
FR 74794, Dec. 13, 2006]



Sec. 96.385  CAIR opt-in permit contents.

    (a) Each CAIR opt-in permit will contain:
    (1) All elements required for a complete CAIR permit application 
under Sec. 96.322;
    (2) The certification in Sec. 96.383(a)(2);
    (3) The unit's baseline heat input under Sec. 96.384(c);
    (4) The unit's baseline NOX emission rate under Sec. 
96.384(d);
    (5) A statement whether the unit is to be allocated CAIR 
NOX Ozone Season allowances under Sec. 96.388(b) or Sec. 
96.388(c) (subject to the conditions in Sec. Sec. 96.384(h) and 
96.386(g));
    (6) A statement that the unit may withdraw from the CAIR 
NOX Ozone Season Trading Program only in accordance with 
Sec. 96.386; and
    (7) A statement that the unit is subject to, and the owners and 
operators of the unit must comply with, the requirements of Sec. 
96.387.
    (b) Each CAIR opt-in permit is deemed to incorporate automatically 
the definitions of terms under Sec. 96.302 and, upon recordation by the 
Administrator under subpart FFFF or GGGG of this part or this subpart, 
every allocation, transfer, or deduction of CAIR NOX Ozone 
Season allowances to or from the compliance account of the source that 
includes a CAIR NOX Ozone Season opt-in unit covered by the 
CAIR opt-in permit.
    (c) The CAIR opt-in permit shall be included, in a format specified 
by the permitting authority, in the CAIR permit for the source where the 
CAIR NOX Ozone Season opt-in unit is located and in a title V 
operating permit or other federally enforceable permit for the source.

[70 FR 25382, May 12, 2005, as amended at 71 FR 25396, Apr. 28, 2006]



Sec. 96.386  Withdrawal from CAIR NOX Ozone Season Trading Program.

    Except as provided under paragraph (g) of this section, a CAIR 
NOX Ozone Season opt-in unit may withdraw from the CAIR 
NOX Ozone Season Trading Program, but only if the permitting 
authority issues a notification to the CAIR designated representative of 
the CAIR NOX Ozone Season opt-in unit of the acceptance of 
the withdrawal of the CAIR NOX Ozone Season opt-in unit in 
accordance with paragraph (d) of this section.
    (a) Requesting withdrawal. In order to withdraw a CAIR 
NOX Ozone Season opt-on unit from the CAIR NOX 
Ozone Season Trading Program, the CAIR designated representative of the 
CAIR NOX Ozone Season opt-in unit shall submit to the 
permitting authority a request to withdraw effective as of midnight of 
September 30 of a specified calendar year, which date must be at least 4 
years after September 30 of the year of entry into the CAIR 
NOX Ozone Season Trading Program under

[[Page 167]]

Sec. 96.384(g). The request must be submitted no later than 90 days 
before the requested effective date of withdrawal.
    (b) Conditions for withdrawal. Before a CAIR NOX Ozone 
Season opt-in unit covered by a request under paragraph (a) of this 
section may withdraw from the CAIR NOX Ozone Season Trading 
Program and the CAIR opt-in permit may be terminated under paragraph (e) 
of this section, the following conditions must be met:
    (1) For the control period ending on the date on which the 
withdrawal is to be effective, the source that includes the CAIR 
NOX Ozone Season opt-in unit must meet the requirement to 
hold CAIR NOX Ozone Season allowances under Sec. 96.306(c) 
and cannot have any excess emissions.
    (2) After the requirement for withdrawal under paragraph (b)(1) of 
this section is met, the Administrator will deduct from the compliance 
account of the source that includes the CAIR NOX Ozone Season 
opt-in unit CAIR NOX Ozone Season allowances equal in amount 
to and allocated for the same or a prior control period as any CAIR 
NOX Ozone Season allowances allocated to the CAIR 
NOX Ozone Season opt-in unit under Sec. 96.388 for any 
control period for which the withdrawal is to be effective. If there are 
no remaining CAIR NOX Ozone Season units at the source, the 
Administrator will close the compliance account, and the owners and 
operators of the CAIR NOX Ozone Season opt-in unit may submit 
a CAIR NOX Ozone Season allowance transfer for any remaining 
CAIR NOX Ozone Season allowances to another CAIR 
NOX Ozone Season Allowance Tracking System in accordance with 
subpart GGGG of this part.
    (c) Notification. (1) After the requirements for withdrawal under 
paragraphs (a) and (b) of this section are met (including deduction of 
the full amount of CAIR NOX Ozone Season allowances 
required), the permitting authority will issue a notification to the 
CAIR designated representative of the CAIR NOX Ozone Season 
opt-in unit of the acceptance of the withdrawal of the CAIR 
NOX Ozone Season opt-in unit as of midnight on September 30 
of the calendar year for which the withdrawal was requested.
    (2) If the requirements for withdrawal under paragraphs (a) and (b) 
of this section are not met, the permitting authority will issue a 
notification to the CAIR designated representative of the CAIR 
NOX Ozone Season opt-in unit that the CAIR NOX 
Ozone Season opt-in unit's request to withdraw is denied. Such CAIR 
NOX Ozone Season opt-in unit shall continue to be a CAIR 
NOX Ozone Season opt-in unit.
    (d) Permit amendment. After the permitting authority issues a 
notification under paragraph (c)(1) of this section that the 
requirements for withdrawal have been met, the permitting authority will 
revise the CAIR permit covering the CAIR NOX Ozone Season 
opt-in unit to terminate the CAIR opt-in permit for such unit as of the 
effective date specified under paragraph (c)(1) of this section. The 
unit shall continue to be a CAIR NOX Ozone Season opt-in unit 
until the effective date of the termination and shall comply with all 
requirements under the CAIR NOX Ozone Season Trading Program 
concerning any control periods for which the unit is a CAIR 
NOX Ozone Season opt-in unit, even if such requirements arise 
or must be complied with after the withdrawal takes effect.
    (e) Reapplication upon failure to meet conditions of withdrawal. If 
the permitting authority denies the CAIR NOX Ozone Season 
opt-in unit's request to withdraw, the CAIR designated representative 
may submit another request to withdraw in accordance with paragraphs (a) 
and (b) of this section.
    (f) Ability to reapply to the CAIR NOX Ozone Season 
Trading Program. Once a CAIR NOX Ozone Season opt-in unit 
withdraws from the CAIR NOX Ozone Season Trading Program and 
its CAIR opt-in permit is terminated under this section, the CAIR 
designated representative may not submit another application for a CAIR 
opt-in permit under Sec. 96.383 for such CAIR NOX Ozone 
Season opt-in unit before the date that is 4 years after the date on 
which the withdrawal became effective. Such new application for a CAIR 
opt-in permit will be treated as an initial application for a CAIR opt-
in permit under Sec. 96.384.
    (g) Inability to withdraw. Notwithstanding paragraphs (a) through 
(f) of this section, a CAIR NOX Ozone Season

[[Page 168]]

opt-in unit shall not be eligible to withdraw from the CAIR 
NOX Ozone Season Trading Program if the CAIR designated 
representative of the CAIR NOX Ozone Season opt-in unit 
requests, and the permitting authority issues a CAIR opt-in permit 
providing for, allocation to the CAIR NOX Ozone Season opt-in 
unit of CAIR NOX Ozone Season allowances under Sec. 
96.388(c).

[70 FR 25382, May 12, 2005, as amended at 71 FR 25396, Apr. 28, 2006]



Sec. 96.387  Change in regulatory status.

    (a) Notification. If a CAIR NOX Ozone Season opt-in unit 
becomes a CAIR NOX Ozone Season unit under Sec. 96.304, then 
the CAIR designated representative shall notify in writing the 
permitting authority and the Administrator of such change in the CAIR 
NOX Ozone Season opt-in unit's regulatory status, within 30 
days of such change.
    (b) Permitting authority's and Administrator's actions. (1) If a 
CAIR NOX Ozone Season opt-in unit becomes a CAIR 
NOX Ozone Season unit under Sec. 96.304, the permitting 
authority will revise the CAIR NOX Ozone Season opt-in unit's 
CAIR opt-in permit to meet the requirements of a CAIR permit under Sec. 
96.323, and remove the CAIR opt-in permit provisions, as of the date on 
which the CAIR NOX Ozone Season opt-in unit becomes a CAIR 
NOX Ozone Season unit under Sec. 96.304.
    (2)(i) The Administrator will deduct from the compliance account of 
the source that includes the CAIR NOX Ozone Season opt-in 
unit that becomes a CAIR NOX Ozone Season unit under Sec. 
96.304, CAIR NOX Ozone Season allowances equal in amount to 
and allocated for the same or a prior control period as:
    (A) Any CAIR NOX Ozone Season allowances allocated to the 
CAIR NOX Ozone Season opt-in unit under Sec. 96.388 for any 
control period after the date on which the CAIR NOX Ozone 
Season opt-in unit becomes a CAIR NOX Ozone Season unit under 
Sec. 96.304; and
    (B) If the date on which the CAIR NOX Ozone Season opt-in 
unit becomes a CAIR NOX Ozone Season unit under Sec. 96.304 
is not September 30, the CAIR NOX Ozone Season allowances 
allocated to the CAIR NOX Ozone Season opt-in unit under 
Sec. 96.388 for the control period that includes the date on which the 
CAIR NOX Ozone Season opt-in unit becomes a CAIR 
NOX Ozone Season unit under Sec. 96.304, multiplied by the 
ratio of the number of days, in the control period, starting with the 
date on which the CAIR NOX Ozone Season opt-in unit becomes a 
CAIR NOX Ozone Season unit under Sec. 96.304 divided by the 
total number of days in the control period and rounded to the nearest 
whole allowance as appropriate.
    (ii) The CAIR designated representative shall ensure that the 
compliance account of the source that includes the CAIR NOX 
Ozone Season opt-in unit that becomes a CAIR NOX Ozone Season 
unit under Sec. 96.304 contains the CAIR NOX Ozone Season 
allowances necessary for completion of the deduction under paragraph 
(b)(2)(i) of this section.
    (3)(i) For every control period after the date on which the CAIR 
NOX Ozone Season opt-in unit becomes a CAIR NOX 
Ozone Season unit under Sec. 96.304, the CAIR NOX Ozone 
Season opt-in unit will be allocated CAIR NOX Ozone Season 
allowances under Sec. 96.342.
    (ii) If the date on which the CAIR NOX Ozone Season opt-
in unit becomes a CAIR NOX Ozone Season unit under Sec. 
96.304 is not September 30, the following amount of CAIR NOX 
Ozone Season allowances will be allocated to the CAIR NOX 
Ozone Season opt-in unit (as a CAIR NOX Ozone Season unit) 
under Sec. 96.342 for the control period that includes the date on 
which the CAIR NOX Ozone Season opt-in unit becomes a CAIR 
NOX Ozone Season unit under Sec. 96.304:
    (A) The amount of CAIR NOX Ozone Season allowances 
otherwise allocated to the CAIR NOX Ozone Season opt-in unit 
(as a CAIR NOX Ozone Season unit) under Sec. 96.342 for the 
control period multiplied by;
    (B) The ratio of the number of days, in the control period, starting 
with the date on which the CAIR NOX Ozone Season opt-in unit 
becomes a CAIR NOX Ozone Season unit under Sec. 96.304, 
divided by the total number of days in the control period; and

[[Page 169]]

    (C) Rounded to the nearest whole allowance as appropriate.

[70 FR 25382, May 12, 2005, as amended at 71 FR 25396, Apr. 28, 2006; 71 
FR 74794, Dec. 13, 2006]



Sec. 96.388  CAIR NOX Ozone Season allowance allocations to CAIR NOX
Ozone Season opt-in units.

    (a) Timing requirements. (1) When the CAIR opt-in permit is issued 
under Sec. 96.384(e), the permitting authority will allocate CAIR 
NOX Ozone Season allowances to the CAIR NOX Ozone 
Season opt-in unit, and submit to the Administrator the allocation for 
the control period in which a CAIR NOX Ozone Season opt-in 
unit enters the CAIR NOX Ozone Season Trading Program under 
Sec. 96.384(g), in accordance with paragraph (b) or (c) of this 
section.
    (2) By no later than July 31 of the control period after the control 
period in which a CAIR NOX Ozone Season opt-in unit enters 
the CAIR NOX Ozone Season Trading Program under Sec. 
96.384(g) and July 31 of each year thereafter, the permitting authority 
will allocate CAIR NOX Ozone Season allowances to the CAIR 
NOX Ozone Season opt-in unit, and submit to the Administrator 
the allocation for the control period that includes such submission 
deadline and in which the unit is a CAIR NOX Ozone Season 
opt-in unit, in accordance with paragraph (b)or (c) of this section.
    (b) Calculation of allocation. For each control period for which a 
CAIR NOX Ozone Season opt-in unit is to be allocated CAIR 
NOX Ozone Season allowances, the permitting authority will 
allocate in accordance with the following procedures:
    (1) The heat input (in mmBtu) used for calculating the CAIR 
NOX Ozone Season allowance allocation will be the lesser of:
    (i) The CAIR NOX Ozone Season opt-in unit's baseline heat 
input determined under Sec. 96.384(c); or
    (ii) The CAIR NOX Ozone Season opt-in unit's heat input, 
as determined in accordance with subpart HHHH of this part, for the 
immediately prior control period, except when the allocation is being 
calculated for the control period in which the CAIR NOX Ozone 
Season opt-in unit enters the CAIR NOX Ozone Season Trading 
Program under Sec. 96.384(g).
    (2) The NOX emission rate (in lb/mmBtu) used for 
calculating CAIR NOX Ozone Season allowance allocations will 
be the lesser of:
    (i) The CAIR NOX Ozone Season opt-in unit's baseline 
NOX emissions rate (in lb/mmBtu) determined under Sec. 
96.384(d) and multiplied by 70 percent; or
    (ii) The most stringent State or Federal NOX emissions 
limitation applicable to the CAIR NOX Ozone Season opt-in 
unit at any time during the control period for which CAIR NOX 
Ozone Season allowances are to be allocated.
    (3) The permitting authority will allocate CAIR NOX Ozone 
Season allowances to the CAIR NOX Ozone Season opt-in unit in 
an amount equaling the heat input under paragraph (b)(1) of this 
section, multiplied by the NOX emission rate under paragraph 
(b)(2) of this section, divided by 2,000 lb/ton, and rounded to the 
nearest whole allowance as appropriate.
    (c) Notwithstanding paragraph (b) of this section and if the CAIR 
designated representative requests, and the permitting authority issues 
a CAIR opt-in permit'' (based on a demonstration of the intent to 
repower stated under Sec. 96.383(a)(5)) providing for, allocation to a 
CAIR NOX Ozone Season opt-in unit of CAIR NOX 
Ozone Season allowances under this paragraph (subject to the conditions 
in Sec. Sec. 96.384(h) and 96.386(g)), the permitting authority will 
allocate to the CAIR NOX Ozone Season opt-in unit as follows:
    (1) For each control period in 2009 through 2014 for which the CAIR 
NOX Ozone Season opt-in unit is to be allocated CAIR 
NOX Ozone Season allowances,
    (i) The heat input (in mmBtu) used for calculating CAIR 
NOX Ozone Season allowance allocations will be determined as 
described in paragraph (b)(1) of this section.
    (ii) The NOX emission rate (in lb/mmBtu) used for 
calculating CAIR NOX Ozone Season allowance allocations will 
be the lesser of:
    (A) The CAIR NOX Ozone Season opt-in unit's baseline 
NOX emissions rate

[[Page 170]]

(in lb/mmBtu) determined under Sec. 96.384(d); or
    (B) The most stringent State or Federal NOX emissions 
limitation applicable to the CAIR NOX Ozone Season opt-in 
unit at any time during the control period in which the CAIR 
NOX Ozone Season opt-in unit enters the CAIR NOX 
Ozone Season Trading Program under Sec. 96.384(g).
    (iii) The permitting authority will allocate CAIR NOX 
Ozone Season allowances to the CAIR NOX Ozone Season opt-in 
unit in an amount equaling the heat input under paragraph (c)(1)(i) of 
this section, multiplied by the NOX emission rate under 
paragraph (c)(1)(ii) of this section, divided by 2,000 lb/ton, and 
rounded to the nearest whole allowance as appropriate.
    (2) For each control period in 2015 and thereafter for which the 
CAIR NOX Ozone Season opt-in unit is to be allocated CAIR 
NOX Ozone Season allowances,
    (i) The heat input (in mmBtu) used for calculating the CAIR 
NOX Ozone Season allowance allocations will be determined as 
described in paragraph (b)(1) of this section.
    (ii) The NOX emission rate (in lb/mmBtu) used for 
calculating the CAIR NOX Ozone Season allowance allocation 
will be the lesser of:
    (A) 0.15 lb/mmBtu;
    (B) The CAIR NOX Ozone Season opt-in unit's baseline 
NOX emissions rate (in lb/mmBtu) determined under Sec. 
96.384(d); or
    (C) The most stringent State or Federal NOX emissions 
limitation applicable to the CAIR NOX Ozone Season opt-in 
unit at any time during the control period for which CAIR NOX 
Ozone Season allowances are to be allocated.
    (iii) The permitting authority will allocate CAIR NOX 
Ozone Season allowances to the CAIR NOX Ozone Season opt-in 
unit in an amount equaling the heat input under paragraph (c)(2)(i) of 
this section, multiplied by the NOX emission rate under 
paragraph (c)(2)(ii) of this section, divided by 2,000 lb/ton, and 
rounded to the nearest whole allowance as appropriate.
    (d) Recordation. (1) The Administrator will record, in the 
compliance account of the source that includes the CAIR NOX 
Ozone Season opt-in unit, the CAIR NOX Ozone Season 
allowances allocated by the permitting authority to the CAIR 
NOX Ozone Season opt-in unit under paragraph (a)(1) of this 
section.
    (2) By September 1, of the control period in which a CAIR 
NOX Ozone Season opt-in unit enters the CAIR NOX 
Ozone Season Trading Program under Sec. 96.384(g), and September 1 of 
each year thereafter, the Administrator will record, in the compliance 
account of the source that includes the CAIR NOX Ozone Season 
opt-in unit, the CAIR NOX Ozone Season allowances allocated 
by the permitting authority to the CAIR NOX Ozone Season opt-
in unit under paragraph (a)(2) of this section.

[70 FR 25382, May 12, 2005, as amended at 71 FR 25396, Apr. 28, 2006]



PART 97_FEDERAL NOX BUDGET TRADING PROGRAM AND CAIR NOX AND SO2
TRADING PROGRAMS--Table of Contents



         Subpart A_NOX Budget Trading Program General Provisions

Sec.
97.1 Purpose.
97.2 Definitions.
97.3 Measurements, abbreviations, and acronyms.
97.4 Applicability.
97.5 Retired unit exemption.
97.6 Standard requirements.
97.7 Computation of time.

 Subpart B_NOX Authorized Account Representative for NOX Budget Sources

97.10 Authorization and responsibilities of NOX authorized 
          account representative.
97.11 Alternate NOX authorized account representative.
97.12 Changing NOX authorized account representative and 
          alternate NOX authorized account representative; 
          changes in owners and operators.
97.13 Account certificate of representation.
97.14 Objections concerning NOX authorized account 
          representative.

                            Subpart C_Permits

97.20 General NOX Budget Trading Program permit requirements.
97.21 Submission of NOX Budget permit applications.
97.22 Information requirements for NOX Budget permit 
          applications.
97.23 NOX Budget permit contents.
97.24 NOX Budget permit revisions.

[[Page 171]]

                   Subpart D_Compliance Certification

97.30 Compliance certification report.
97.31 Administrator's action on compliance certifications.

                   Subpart E_NOX Allowance Allocations

97.40 Trading program budget.
97.41 Timing requirements for NOX allowance allocations.
97.42 NOX allowance allocations.
97.43 Compliance supplement pool.

                 Subpart F_NOX Allowance Tracking System

97.50 NOX Allowance Tracking System accounts.
97.51 Establishment of accounts.
97.52 NOX Allowance Tracking System responsibilities of 
          NOX authorized account representative.
97.53 Recordation of NOX allowance allocations.
97.54 Compliance.
97.55 Banking.
97.56 Account error.
97.57 Closing of general accounts.

                    Subpart G_NOX Allowance Transfers

97.60 Submission of NOX allowance transfers.
97.61 EPA recordation.
97.62 Notification.

                   Subpart H_Monitoring and Reporting

97.70 General requirements.
97.71 Initial certification and recertification procedures.
97.72 Out of control periods.
97.73 Notifications.
97.74 Recordkeeping and reporting.
97.75 Petitions.
97.76 Additional requirements to provide heat input data.

                    Subpart I_Individual Unit Opt-ins

97.80 Applicability.
97.81 General.
97.82 NOX authorized account representative.
97.83 Applying for NOX Budget opt-in permit.
97.84 Opt-in process.
97.85 NOX Budget opt-in permit contents.
97.86 Withdrawal from NOX Budget Trading Program.
97.87 Change in regulatory status.
97.88 NOX allowance allocations to opt-in units.

                       Subpart J_Appeal Procedures

97.90 Appeal procedures.

      Subpart AA_CAIR NOX Annual Trading Program General Provisions

97.101 Purpose.
97.102 Definitions.
97.103 Measurements, abbreviations, and acronyms.
97.104 Applicability.
97.105 Retired unit exemption.
97.106 Standard requirements.
97.107 Computation of time.
97.108 Appeal procedures.

     Subpart BB_CAIR Designated Representative for CAIR NOX Sources

97.110 Authorization and responsibilities of CAIR designated 
          representative.
97.111 Alternate CAIR designated representative.
97.112 Changing CAIR designated representative and alternate CAIR 
          designated representative; changes in owners and operators.
97.113 Certificate of representation.
97.114 Objections concerning CAIR designated representative.
97.115 Delegation by CAIR designated representative and alternate CAIR 
          designated representative.

                           Subpart CC_Permits

97.120 General CAIR NOX Annual Trading Program permit 
          requirements.
97.121 Submission of CAIR permit applications.
97.122 Information requirements for CAIR permit applications.
97.123 CAIR permit contents and term.
97.124 CAIR permit revisions.

Subpart DD [Reserved]

                Subpart EE_CAIR NOX Allowance Allocations

97.140 State trading budgets.
97.141 Timing requirements for CAIR NOX allowance 
          allocations.
97.142 CAIR NOX allowance allocations.
97.143 Compliance supplement pool.
97.144 Alternative of allocation of CAIR NOX allowances and 
          compliance supplement pool by permitting authority.

Appendix A to Subpart EE of Part 97--States With Approved State 
          Implementation Plan Revisions Concerning Allocations

             Subpart FF_ CAIR NOX Allowance Tracking System

97.150 [Reserved]
97.151 Establishment of accounts.
97.152 Responsibilities of CAIR authorized account representative.

[[Page 172]]

97.153 Recordation of CAIR NOX allowance allocations.
97.154 Compliance with CAIR NOX emissions limitation.
97.155 Banking.
97.156 Account error.
97.157 Closing of general accounts.

                 Subpart GG_CAIR NOX Allowance Transfers

97.160 Submission of CAIR NOX allowance transfers.
97.161 EPA recordation.
97.162 Notification.

                   Subpart HH_Monitoring and Reporting

97.170 General requirements.
97.171 Initial certification and recertification procedures.
97.172 Out of control periods.
97.173 Notifications.
97.174 Recordkeeping and reporting.
97.175 Petitions.

                    Subpart II_CAIR NOX Opt-in Units

97.180 Applicability.
97.181 General.
97.182 CAIR designated representative.
97.183 Applying for CAIR opt-in permit.
97.184 Opt-in process.
97.185 CAIR opt-in permit contents.
97.186 Withdrawal from CAIR NOX Annual Trading Program.
97.187 Change in regulatory status.
97.188 CAIR NOX allowance allocations to CAIR NOX 
          opt-in units.

Appendix A to Subpart II of Part 97--States With Approved State 
          Implementation Plan Revisions Concerning CAIR NOX 
          Opt-in Units

         Subpart AAA_CAIR SO2 Trading Program General Provisions

97.201 Purpose.
97.202 Definitions.
97.203 Measurements, abbreviations, and acronyms.
97.204 Applicability.
97.205 Retired unit exemption.
97.206 Standard requirements.
97.207 Computation of time.
97.208 Appeal procedures.

     Subpart BBB_CAIR Designated Representative for CAIR SO2 Sources

97.210 Authorization and responsibilities of CAIR designated 
          representative.
97.211 Alternate CAIR designated representative.
97.212 Changing CAIR designated representative and alternate CAIR 
          designated representative; changes in owners and operators.
97.213 Certificate of representation.
97.214 Objections concerning CAIR designated representative.
97.215 Delegation by CAIR designated representative and alternate CAIR 
          designated representative.

                           Subpart CCC_Permits

97.220 General CAIR SO2 Trading Program permit requirements.
97.221 Submission of CAIR permit applications.
97.222 Information requirements for CAIR permit applications.
97.223 CAIR permit contents and term.
97.224 CAIR permit revisions.

Subparts DDD-EEE [Reserved]

             Subpart FFF_CAIR SO2 Allowance Tracking System

97.250 [Reserved]
97.251 Establishment of accounts.
97.252 Responsibilities of CAIR authorized account representative.
97.253 Recordation of CAIR SO2 allowances.
97.254 Compliance with CAIR SO2 emissions limitation.
97.255 Banking.
97.256 Account error.
97.257 Closing of general accounts.

                Subpart GGG_CAIR SO2 Allowance Transfers

97.260 Submission of CAIR SO2 allowance transfers.
97.261 EPA recordation.
97.262 Notification.

                  Subpart HHH_Monitoring and Reporting

97.270 General requirements.
97.271 Initial certification and recertification procedures.
97.272 Out of control periods.
97.273 Notifications.
97.274 Recordkeeping and reporting.
97.275 Petitions.

                    Subpart III_CAIR SO2 Opt-in Units

97.280 Applicability.
97.281 General.
97.282 CAIR designated representative.
97.283 Applying for CAIR opt-in permit.
97.284 Opt-in process.
97.285 CAIR opt-in permit contents.
97.286 Withdrawal from CAIR SO2 Trading Program.
97.287 Change in regulatory status.
97.288 CAIR SO2 allowance allocations to CAIR SO2 
          opt-in units.

[[Page 173]]


Appendix A to Subpart III of Part 97--States With Approved State 
          Implementation Plan Revisions Concerning CAIR SO2 
          Opt-In Units

  Subpart AAAA_CAIR NOX Ozone Season Trading Program General Provisions

97.301 Purpose.
97.302 Definitions.
97.303 Measurements, abbreviations, and acronyms.
97.304 Applicability.
97.305 Retired unit exemption.
97.306 Standard requirements.
97.307 Computation of time.
97.308 Appeal procedures.

Appendix A to Subpart AAAA of Part 97--States With Approved State 
          Implementation Plan Revisions Concerning Applicability

 Subpart BBBB_CAIR Designated Representative for CAIR NOX Ozone Season 
                                 Sources

97.310 Authorization and responsibilities of CAIR designated 
          representative.
97.311 Alternate CAIR designated representative.
97.312 Changing CAIR designated representative and alternate CAIR 
          designated representative; changes in owners and operators.
97.313 Certificate of representation.
97.314 Objections concerning CAIR designated representative.
97.315 Delegation by CAIR designated representative and alternate CAIR 
          designated representative.

                          Subpart CCCC_Permits

97.320 General CAIR NOX Ozone Season Trading Program permit 
          requirements.
97.321 Submission of CAIR permit applications.
97.322 Information requirements for CAIR permit applications.
97.323 CAIR permit contents and term.
97.324 CAIR permit revisions.

Subpart DDDD [Reserved]

        Subpart EEEE_CAIR NOX Ozone Season Allowance Allocations

97.340 State trading budgets.
97.341 Timing requirements for CAIR NOX Ozone Season 
          allowance allocations.
97.342 CAIR NOX Ozone Season allowance allocations.
97.343 Alternative of allocation of CAIR NOX Ozone Season 
          allowances by permitting authority.

Appendix A to Subpart EEEE of Part 97--States With Approved State 
          Implementation Plan Revisions Concerning Allocations

      Subpart FFFF_CAIR NOX Ozone Season Allowance Tracking System

97.350 [Reserved]
97.351 Establishment of accounts.
97.352 Responsibilities of CAIR authorized account representative.
97.353 Recordation of CAIR NOX Ozone Season allowance 
          allocations.
97.354 Compliance with CAIR NOX emissions limitation.
97.355 Banking.
97.356 Account error.
97.357 Closing of general accounts.

         Subpart GGGG_CAIR NOX Ozone Season Allowance Transfers

97.360 Submission of CAIR NOX Ozone Season allowance 
          transfers.
97.361 EPA recordation.
97.362 Notification.

                  Subpart HHHH_Monitoring and Reporting

97.370 General requirements.
97.371 Initial certification and recertification procedures.
97.372 Out of control periods.
97.373 Notifications.
97.374 Recordkeeping and reporting.
97.375 Petitions.

             Subpart IIII_CAIR NOX Ozone Season Opt-in Units

97.380 Applicability.
97.381 General.
97.382 CAIR designated representative.
97.383 Applying for CAIR opt-in permit.
97.384 Opt-in process.
97.385 CAIR opt-in permit contents.
97.386 Withdrawal from CAIR NOX Ozone Season Trading Program.
97.387 Change in regulatory status.
97.388 CAIR NOX Ozone Season allowance allocations to CAIR 
          NOX Ozone Season opt-in units.

Appendix A to Subpart IIII of Part 97--States With Approved State 
          Implementation Plan Revisions Concerning CAIR NOX 
          Ozone Season Opt-In Units

               Subpart AAAAA_TR NOX Annual Trading Program

97.401 Purpose.
97.402 Definitions.
97.403 Measurements, abbreviations, and acronyms.
97.404 Applicability.
97.405 Retired unit exemption.
97.406 Standard requirements.
97.407 Computation of time.

[[Page 174]]

97.408 Administrative appeal procedures.
97.409 [Reserved]
97.410 State NOX annual trading budgets, new unit set-asides, 
          Indian country new unit set-aside, and variability limits.
97.411 Timing requirements for TR NOX Annual allowance 
          allocations.
97.412 TR NOX Annual allowance allocations to new units.
97.413 Authorization of designated representative and alternate 
          designated representative.
97.414 Responsibilities of designated representative and alternate 
          designated representative.
97.415 Changing designated representative and alternate designated 
          representative; changes in owners and operators.
97.416 Certificate of representation.
97.417 Objections concerning designated representative and alternate 
          designated representative.
97.418 Delegation by designated representative and alternate designated 
          representative.
97.419 [Reserved]
97.420 Establishment of compliance accounts and general accounts.
97.421 Recordation of TR NOX Annual allowance allocations.
97.422 Submission of TR NOX Annual allowance transfers.
97.423 Recordation of TR NOX Annual allowance transfers.
97.424 Compliance with TR NOX Annual emissions limitation.
97.425 Compliance with TR NOX Annual assurance provisions.
97.426 Banking.
97.427 Account error.
97.428 Administrator's action on submissions.
97.429 [Reserved]
97.430 General monitoring, recordkeeping, and reporting requirements.
97.431 Initial monitoring system certification and recertification 
          procedures.
97.432 Monitoring system out-of-control periods.
97.433 Notifications concerning monitoring.
97.434 Recordkeeping and reporting.
97.435 Petitions for alternatives to monitoring, recordkeeping, or 
          reporting requirements.

            Subpart BBBBB_TR NOX Ozone Season Trading Program

97.501 Purpose.
97.502 Definitions.
97.503 Measurements, abbreviations, and acronyms.
97.504 Applicability.
97.505 Retired unit exemption.
97.506 Standard requirements.
97.507 Computation of time.
97.508 Administrative appeal procedures.
97.509 [Reserved]
97.510 State NOX ozone season trading budgets, new unit set-
          asides, Indian country new unit set-aside, and variability 
          limits.
97.511 Timing requirements for TR NOX Ozone Season allowance 
          allocations.
97.512 TR NOX Ozone Season allowance allocations to new 
          units.
97.513 Authorization of designated representative and alternate 
          designated representative.
97.514 Responsibilities of designated representative and alternate 
          designated representative.
97.515 Changing designated representative and alternate designated 
          representative; changes in owners and operators.
97.516 Certificate of representation.
97.517 Objections concerning designated representative and alternate 
          designated representative.
97.518 Delegation by designated representative and alternate designated 
          representative.
97.519 [Reserved]
97.520 Establishment of compliance accounts and general accounts.
97.521 Recordation of TR NOX Ozone Season allowance 
          allocations.
97.522 Submission of TR NOX Ozone Season allowance transfers.
97.523 Recordation of TR NOX Ozone Season allowance 
          transfers.
97.524 Compliance with TR NOX Ozone Season emissions 
          limitation.
97.525 Compliance with TR NOX Ozone Season assurance 
          provisions.
97.526 Banking.
97.527 Account error.
97.528 Administrator's action on submissions.
97.529 [Reserved]
97.530 General monitoring, recordkeeping, and reporting requirements.
97.531 Initial monitoring system certification and recertification 
          procedures.
97.532 Monitoring system out-of-control periods.
97.533 Notifications concerning monitoring.
97.534 Recordkeeping and reporting.
97.535 Petitions for alternatives to monitoring, recordkeeping, or 
          reporting requirements.

              Subpart CCCCC_TR SO2 Group 1 Trading Program

97.601 Purpose.
97.602 Definitions.
97.603 Measurements, abbreviations, and acronyms.
97.604 Applicability.
97.605 Retired unit exemption.
97.606 Standard requirements.
97.607 Computation of time.
97.608 Administrative appeal procedures.

[[Page 175]]

97.609 [Reserved]
97.610 State SO2 Group 1 trading budgets, new unit set-
          asides, Indian country new unit set-aside, and variability 
          limits.
97.611 Timing requirements for TR SO2 Group 1 allowance 
          allocations.
97.612 TR SO2 Group 1 allowance allocations to new units.
97.613 Authorization of designated representative and alternate 
          designated representative.
97.614 Responsibilities of designated representative and alternate 
          designated representative.
97.615 Changing designated representative and alternate designated 
          representative; changes in owners and operators.
97.616 Certificate of representation.
97.617 Objections concerning designated representative and alternate 
          designated representative.
97.618 Delegation by designated representative and alternate designated 
          representative.
97.619 [Reserved]
97.620 Establishment of compliance accounts and general accounts.
97.621 Recordation of TR SO2 Group 1 allowance allocations.
97.622 Submission of TR SO2 Group 1 allowance transfers.
97.623 Recordation of TR SO2 Group 1 allowance transfers.
97.624 Compliance with TR SO2 Group 1 emissions limitation.
97.625 Compliance with TR SO2 Group 1 assurance provisions.
97.626 Banking.
97.627 Account error.
97.628 Administrator's action on submissions.
97.629 [Reserved]
97.630 General monitoring, recordkeeping, and reporting requirements.
97.631 Initial monitoring system certification and recertification 
          procedures.
97.632 Monitoring system out-of-control periods.
97.633 Notifications concerning monitoring.
97.634 Recordkeeping and reporting.
97.635 Petitions for alternatives to monitoring, recordkeeping, or 
          reporting requirements.

              Subpart DDDDD_TR SO2 Group 2 Trading Program

97.701 Purpose.
97.702 Definitions.
97.703 Measurements, abbreviations, and acronyms.
97.704 Applicability.
97.705 Retired unit exemption.
97.706 Standard requirements.
97.707 Computation of time.
97.708 Administrative appeal procedures.
97.709 [Reserved]
97.710 State SO2 Group 2 trading budgets, new unit set-
          asides, Indian country new unit set-aside, and variability 
          limits.
97.711 Timing requirements for TR SO2 Group 2 allowance 
          allocations.
97.712 TR SO2 Group 2 allowance allocations to new units.
97.713 Authorization of designated representative and alternate 
          designated representative.
97.714 Responsibilities of designated representative and alternate 
          designated representative.
97.715 Changing designated representative and alternate designated 
          representative; changes in owners and operators.
97.716 Certificate of representation.
97.717 Objections concerning designated representative and alternate 
          designated representative.
97.718 Delegation by designated representative and alternate designated 
          representative.
97.719 [Reserved]
97.720 Establishment of compliance accounts and general accounts.
97.721 Recordation of TR SO2 Group 2 allowance allocations.
97.722 Submission of TR SO2 Group 2 allowance transfers.
97.723 Recordation of TR SO2 Group 2 allowance transfers.
97.724 Compliance with TR SO2 Group 2 emissions limitation.
97.725 Compliance with TR SO2 Group 2 assurance provisions.
97.726 Banking.
97.727 Account error.
97.728 Administrator's action on submissions.
97.729 [Reserved]
97.730 General monitoring, recordkeeping, and reporting requirements.
97.731 Initial monitoring system certification and recertification 
          procedures.
97.732 Monitoring system out-of-control periods.
97.733 Notifications concerning monitoring.
97.734 Recordkeeping and reporting.
97.735 Petitions for alternatives to monitoring, recordkeeping, or 
          reporting requirements.

Appendix A to Part 97--Final Section 126 Rule: EGU Allocations, 2003-
          2007
Appendix B to Part 97--Final Section 126 Rule: Non-EGU Allocations, 
          2003-2007
Appendix C to Part 97--Final Section 126 Rule: Trading Budget, 2003-2007
Appendix D to Part 97--Final Section 126 Rule: State Compliance 
          Supplement Pools for the Section 126 Final Rule (Tons)

    Authority: 42 U.S.C. 7401, 7403, 7410, 7426, 7601, and 7651, et seq.

[[Page 176]]


    Source: 65 FR 2727, Jan. 18, 2000, unless otherwise noted. 71 FR 
25396, 25422, and 25443, Apr. 28, 2006



         Subpart A_NOX Budget Trading Program General Provisions



Sec. 97.1  Purpose.

    This part establishes general provisions and the applicability, 
permitting, allowance, excess emissions, monitoring, and opt-in 
provisions for the federal NOX Budget Trading Program, under 
section 126 of the CAA and Sec. 52.34 of this chapter, as a means of 
mitigating the interstate transport of ozone and nitrogen oxides, an 
ozone precursor.



Sec. 97.2  Definitions.

    The terms used in this part shall have the meanings set forth in 
this section as follows:
    Account number means the identification number given by the 
Administrator to each NOX Allowance Tracking System account.
    Acid Rain emissions limitation means, as defined in Sec. 72.2 of 
this chapter, a limitation on emissions of sulfur dioxide or nitrogen 
oxides under the Acid Rain Program under title IV of the Clean Air Act.
    Administrator means the Administrator of the United States 
Environmental Protection Agency or the Administrator's duly authorized 
representative.
    Allocate or allocation means, with regard to NOX 
allowances, the determination by the Administrator of the number of 
NOX allowances to be initially credited to a NOX 
Budget unit or an allocation set-aside.
    Automated data acquisition and handling system or DAHS means that 
component of the CEMS, or other emissions monitoring system approved for 
use under subpart H of this part, designed to interpret and convert 
individual output signals from pollutant concentration monitors, flow 
monitors, diluent gas monitors, and other component parts of the 
monitoring system to produce a continuous record of the measured 
parameters in the measurement units required by subpart H of this part.
    Boiler means an enclosed fossil or other fuel-fired combustion 
device used to produce heat and to transfer heat to recirculating water, 
steam, or other medium.
    Clean Air Act means the Clean Air Act, 42 U.S.C. 7401 et seq.
    Combined cycle system means a system comprised of one or more 
combustion turbines, heat recovery steam generators, and steam turbines 
configured to improve overall efficiency of electricity generation or 
steam production.
    Combustion turbine means an enclosed fossil or other fuel-fired 
device that is comprised of a compressor, a combustor, and a turbine, 
and in which the flue gas resulting from the combustion of fuel in the 
combustor passes through the turbine, rotating the turbine.
    Commence commercial operation means, with regard to a unit that 
serves a generator, to have begun to produce steam, gas, or other heated 
medium used to generate electricity for sale or use, including test 
generation. Except as provided in Sec. 97.4(b), Sec. 97.5, or subpart 
I of this part, for a unit that is a NOX Budget unit under 
Sec. 97.4(a) on the date the unit commences commercial operation, such 
date shall remain the unit's date of commencement of commercial 
operation even if the unit is subsequently modified, reconstructed, or 
repowered. Except as provided in Sec. 97.4(b), Sec. 97.5, or subpart I 
of this part, for a unit that is not a NOX Budget unit under 
Sec. 97.4(a) on the date the unit commences commercial operation, the 
date the unit becomes a NOX Budget unit under Sec. 97.4(a) 
shall be the unit's date of commencement of commercial operation.
    Commence operation means to have begun any mechanical, chemical, or 
electronic process, including, with regard to a unit, start-up of a 
unit's combustion chamber. Except as provided in Sec. 97.4(b), Sec. 
97.5, or subpart I of this part for a unit that is a NOX 
Budget unit under Sec. 97.4(a) on the date of commencement of 
operation, such date shall remain the unit's date of commencement of 
operation even if the unit is subsequently modified, reconstructed, or 
repowered. Except as provided in Sec. 97.4(b), Sec. 97.5, or subpart I 
of this part, for a unit that is not a NOX Budget unit under 
Sec. 97.4(a) on the date

[[Page 177]]

of commencement of operation, the date the unit becomes a NOX 
Budget unit under Sec. 97.4(a) shall be the unit's date of commencement 
of operation.
    Common stack means a single flue through which emissions from two or 
more units are exhausted.
    Compliance account means a NOX Allowance Tracking System 
account, established by the Administrator for a NOX Budget 
unit under subpart F of this part, in which the NOX allowance 
allocations for the unit are initially recorded and in which are held 
NOX allowances available for use by the unit for a control 
period for the purpose of meeting the unit's NOX Budget 
emissions limitation.
    Continuous emission monitoring system or CEMS means the equipment 
required under subpart H of this part to sample, analyze, measure, and 
provide, by means of readings taken at least once every 15 minutes 
(using an automated data acquisition and handling system (DAHS)), a 
permanent record of nitrogen oxides (NOX) emissions, stack 
gas volumetric flow rate or stack gas moisture content (as applicable), 
in a manner consistent with part 75 of this chapter. The following are 
the principal types of continuous emission monitoring systems required 
under subpart H of this part:
    (1) A flow monitoring system, consisting of a stack flow rate 
monitor and an automated DAHS. A flow monitoring system provides a 
permanent, continuous record of stack gas volumetric flow rate, in units 
of standard cubic feet per hour (scfh);
    (2) A nitrogen oxides concentration monitoring system, consisting of 
a NOX pollutant concentration monitor and an automated DAHS. 
A NOX concentration monitoring system provides a permanent, 
continuous record of NOX emissions in units of parts per 
million (ppm);
    (3) A nitrogen oxides emission rate (or NOX-diluent) 
monitoring system, consisting of a NOX pollutant 
concentration monitor, a diluent gas (CO2 or O2) 
monitor, and an automated DAHS. A NOX concentration 
monitoring system provides a permanent, continuous record of: 
NOX concentration in units of parts per million (ppm), 
diluent gas concentration in units of percent O2 or 
CO2 (percent O2 or CO2), and 
NOX emission rate in units of pounds per million British 
thermal units (lb/mmBtu); and
    (4) A moisture monitoring system, as defined in Sec. 75.11(b)(2) of 
this chapter. A moisture monitoring system provides a permanent, 
continuous record of the stack gas moisture content, in units of percent 
H2O (percent H2O).
    Control period means the period beginning May 1 of a year and ending 
on September 30 of the same year, inclusive.
    Electricity for sale under firm contract to the grid means 
electricity for sale where the capacity involved is intended to be 
available at all times during the period covered by a guaranteed 
commitment to deliver, even under adverse conditions.
    Emissions means air pollutants exhausted from a unit or source into 
the atmosphere, as measured, recorded, and reported to the Administrator 
by the NOX authorized account representative and as 
determined by the Administrator in accordance with subpart H of this 
part.
    Energy Information Administration means the Energy Information 
Administration of the United States Department of Energy.
    Excess emissions means any tonnage of nitrogen oxides emitted by a 
NOX Budget unit during a control period that exceeds the 
NOX Budget emissions limitation for the unit.
    Fossil fuel means natural gas, petroleum, coal, or any form of 
solid, liquid, or gaseous fuel derived from such material.
    Fossil fuel fired means, with regard to a unit:
    (1) For units that commenced operation before January 1, 1996, the 
combustion of fossil fuel, alone or in combination with any other fuel, 
where fossil fuel actually combusted comprises more than 50 percent of 
the annual heat input on a Btu basis during 1995, or, if a unit had no 
heat input in 1995, during the last year of operation of the unit prior 
to 1995;
    (2) For units that commenced operation on or after January 1, 1996 
and before January 1, 1997, the combustion of fossil fuel, alone or in 
combination with any other fuel, where fossil fuel

[[Page 178]]

actually combusted comprises more than 50 percent of the annual heat 
input on a Btu basis during 1996; or
    (3) For units that commence operation on or after January 1, 1997:
    (i) The combination of fossil fuel, alone or in combustion with any 
other fuel, where fossil fuel actually combusted comprises more than 50 
percent of the annual heat input on a Btu basis during any year; or
    (ii) The combination of fossil fuel, alone or in combination with 
any other fuel, where fossil fuel is projected to comprise more than 50 
percent of the annual heat input on a Btu basis during any year, 
provided that the unit shall be ``fossil fuel-fired'' as of the date, 
during such year, on which the unit begins combusting fossil fuel.
    General account means a NOX Allowance Tracking System 
account, established under subpart F of this part, that is not a 
compliance account or an overdraft account.
    Generator means a device that produces electricity.
    Heat input means, with regard to a specified period to time, the 
product (in mmBtu/time) of the gross calorific value of the fuel (in 
Btu/lb) divided by 1,000,000 Btu/mmBtu and multiplied by the fuel feed 
rate into a combustion device (in lb of fuel/time), as measured, 
recorded, and reported to the Administrator by the NOX 
authorized account representative and as determined by the Administrator 
in accordance with subpart H of this part. Heat input does not include 
the heat derived from preheated combustion air, recirculated flue gases, 
or exhaust from other sources.
    Heat input rate means the amount of heat input (in mmBtu) divided by 
unit operating time (in hr) or, with regard to a specific fuel, the 
amount of heat input attributed to the fuel (in mmBtu) divided by the 
unit operating time (in hr) during which the unit combusts the fuel.
    Life-of-the-unit, firm power contractual arrangement means a unit 
participation power sales agreement under which a utility or industrial 
customer reserves, or is entitled to receive, a specified amount or 
percentage of nameplate capacity and associated energy from any 
specified unit and pays its proportional amount of such unit's total 
costs, pursuant to a contract:
    (1) For the life of the unit;
    (2) For a cumulative term of no less than 30 years, including 
contracts that permit an election for early termination; or
    (3) For a period equal to or greater than 25 years or 70 percent of 
the economic useful life of the unit determined as of the time the unit 
is built, with option rights to purchase or release some portion of the 
nameplate capacity and associated energy generated by the unit at the 
end of the period.
    Maximum design heat input means the ability of a unit to combust a 
stated maximum amount of fuel per hour (in mmBtu/hr) on a steady state 
basis, as determined by the physical design and physical characteristics 
of the unit.
    Maximum potential hourly heat input means an hourly heat input (in 
mmBtu/hr) used for reporting purposes when a unit lacks certified 
monitors to report heat input. If the unit intends to use appendix D of 
part 75 of this chapter to report heat input, this value should be 
calculated, in accordance with part 75 of this chapter, using the 
maximum fuel flow rate and the maximum gross calorific value. If the 
unit intends to use a flow monitor and a diluent gas monitor, this value 
should be reported, in accordance with part 75 of this chapter, using 
the maximum potential flowrate and either the maximum carbon dioxide 
concentration (in percent CO2) or the minimum oxygen 
concentration (in percent O2).
    Maximum potential NOX emission rate means the emission rate of 
nitrogen oxides (in lb/mmBtu) calculated in accordance with section 3 of 
appendix F of part 75 of this chapter, using the maximum potential 
concentration of NOX under section 2 of appendix A of part 75 
of this chapter, and either the maximum oxygen concentration (in percent 
O2) or the minimum carbon dioxide concentration (in percent 
CO2), under all operating conditions of the unit except for 
unit start up, shutdown, and upsets.
    Maximum rated hourly heat input means a unit specific maximum hourly 
heat input (in mmBtu/hr) which is the higher of the manufacturer's 
maximum

[[Page 179]]

rated hourly heat input or the highest observed hourly heat input.
    Monitoring system means any monitoring system that meets the 
requirements of subpart H of this part, including a continuous emissions 
monitoring system, an excepted monitoring system, or an alternative 
monitoring system.
    Most stringent State or Federal NOX emissions limitation means the 
lowest NOX emissions limitation (in lb/mmBtu) that is 
applicable to the unit under State or Federal law, regardless of the 
averaging period to which the emissions limitation applies.
    Nameplate capacity means the maximum electrical generating output 
(in MWe) that a generator can sustain over a specified period of time 
when not restricted by seasonal or other deratings as measured in 
accordance with the United States Department of Energy standards.
    Non-title V permit means a federally enforceable permit administered 
by the permitting authority pursuant to the Clean Air Act and regulatory 
authority under the Clean Air Act, other than title V of the Clean Air 
Act and part 70 or 71 of this chapter.
    NOX allowance means a limited authorization by the Administrator 
under the NOX Budget Trading Program to emit up to one ton of 
nitrogen oxides during the control period of the specified year or of 
any year thereafter, except as provided under Sec. 97.54(f). No 
provision of the NOX Budget Trading Program, the 
NOX Budget permit application, the NOX Budget 
permit, or an exemption under Sec. 97.4(b) or Sec. 97.5 and no 
provision of law shall be construed to limit the authority of the United 
States to terminate or limit such authorization, which does not 
constitute a property right. For purposes of all sections of this part 
except Sec. 97.40, Sec. 97.41, Sec. 97.42, Sec. 97.43, or Sec. 
97.88, ``NOX allowance'' also includes an authorization to 
emit up to one ton of nitrogen oxides during the control period of the 
specified year or of any year thereafter by the permitting authority or 
the Administrator in accordance with a State NOX Budget 
Trading Program established, and approved and administered by the 
Administrator, pursuant to Sec. 51.121 of this chapter.
    NOX allowance deduction or deduct NOX allowances means the permanent 
withdrawal of NOX allowances by the Administrator from a 
NOX Allowance Tracking System compliance account or overdraft 
account to account for the number of tons of NOX emissions 
from a NOX Budget unit for a control period, determined in 
accordance with subparts H and F of this part, or for any other 
NOX allowance withdrawal requirement under this part.
    NOX Allowance Tracking System means the system by which the 
Administrator records allocations, deductions, and transfers of 
NOX allowances under the NOX Budget Trading 
Program.
    NOX Allowance Tracking System account means an account in the 
NOX Allowance Tracking System established by the 
Administrator for purposes of recording the allocation, holding, 
transferring, or deducting of NOX allowances.
    NOX allowance transfer deadline means midnight of November 30 or, if 
November 30 is not a business day, midnight of the first business day 
thereafter and is the deadline by which NOX allowances must 
be submitted for recordation in a NOX Budget unit's 
compliance account, or the overdraft account of the source where the 
unit is located, in order to meet the unit's NOX Budget 
emissions limitation for the control period immediately preceding such 
deadline.
    NOX allowances held or hold NOX allowances means the NOX 
allowances recorded by the Administrator, or submitted to the 
Administrator for recordation, in accordance with subparts F and G of 
this part, in a NOX Allowance Tracking System account.
    NOX authorized account representative means, for a NOX 
Budget source or NOX Budget unit at the source, the natural 
person who is authorized by the owners and operators of the source and 
all NOX Budget units at the source, in accordance with 
subpart B of this part, to represent and legally bind each owner and 
operator in matters pertaining to the NOX Budget Trading 
Program or, for a general account, the natural person who is authorized, 
in accordance with subpart F of this part, to transfer or otherwise 
dispose of NOX allowances held in the general account.

[[Page 180]]

    NOX Budget emissions limitation means, for a NOX Budget 
unit, the tonnage equivalent of the NOX allowances available 
for compliance deduction for the unit under Sec. 97.54(a), (b), (e), 
and (f) in a control period adjusted by deductions of such 
NOX allowances to account for actual heat input under Sec. 
97.42(e) for the control period or to account for excess emissions for a 
prior control period under Sec. 97.54(d) or to account for withdrawal 
from the NOX Budget Trading Program, or for a change in 
regulatory status, of a NOX Budget opt-in unit under Sec. 
97.86 or Sec. 97.87.
    NOX Budget opt-in permit means a NOX Budget permit 
covering a NOX Budget opt-in unit.
    NOX Budget opt-in unit means a unit that has been elected to become 
a NOX Budget unit under the NOX Budget Trading 
Program and whose NOX Budget opt-in permit has been issued 
and is in effect under subpart I of this part.
    NOX Budget permit means the legally binding and federally 
enforceable written document, or portion of such document, issued by the 
permitting authority under this part, including any permit revisions, 
specifying the NOX Budget Trading Program requirements 
applicable to a NOX Budget source, to each NOX 
Budget unit at the NOX Budget source, and to the owners and 
operators and the NOX authorized account representative of 
the NOX Budget source and each NOX Budget unit.
    NOX Budget source means a source that includes one or more 
NOX Budget units.
    NOX Budget Trading Program means a multistate nitrogen oxides air 
pollution control and emission reduction program established by the 
Administrator in accordance with this part and pursuant to Sec. 52.34 
of this chapter, as a means of mitigating the interstate transport of 
ozone and nitrogen oxides, an ozone precursor.
    NOX Budget unit means a unit that is subject to the NOX 
Budget emissions limitation under Sec. 97.4(a) or Sec. 97.80.
    Operating means, with regard to a unit under Sec. Sec. 97.22(d)(2) 
and 97.80, having documented heat input for more than 876 hours in the 6 
months immediately preceding the submission of an application for an 
initial NOX Budget permit under Sec. 97.83(a). The unit's 
documented heat input will be determined in accordance with part 75 of 
this chapter if the unit was otherwise subject to the requirements of 
part 75 of this chapter during that 6-month period or will be based on 
the best available data reported to the Administrator for the unit if 
the unit was not otherwise subject to the requirements of part 75 of 
this chapter during that 6-month period.
    Operator means any person who operates, controls, or supervises a 
NOX Budget unit, a NOX Budget source, or a unit 
for which an application for a NOX Budget opt-in permit under 
Sec. 97.83 is submitted and not denied or withdrawn and shall include, 
but not be limited to, any holding company, utility system, or plant 
manager of such a unit or source.
    Opt-in means to be elected to become a NOX Budget unit 
under the NOX Budget Trading Program through a final, 
effective NOX Budget opt-in permit under subpart I of this 
part.
    Overdraft account means the NOX Allowance Tracking System 
account, established by the Administrator under subpart F of this part, 
for each NOX Budget source where there are two or more 
NOX Budget units.
    Owner means any of the following persons:
    (1) Any holder of any portion of the legal or equitable title in a 
NOX Budget unit or in a unit for which an application for a 
NOX Budget opt-in permit under Sec. 97.83 is submitted and 
not denied or withdrawn; or
    (2) Any holder of a leasehold interest in a NOX Budget 
unit or in a unit for which an application for a NOX Budget 
opt-in permit under Sec. 97.83 is submitted and not denied or 
withdrawn; or
    (3) Any purchaser of power from a NOX Budget unit or from 
a unit for which an application for a NOX Budget opt-in 
permit under Sec. 97.83 is submitted and not denied or withdrawn under 
a life-of-the-unit, firm power contractual arrangement. However, unless 
expressly provided for in a leasehold agreement, owner shall not include 
a passive lessor, or a person who has an equitable interest through such 
lessor, whose rental payments are not based, either directly or 
indirectly, upon the revenues or income from the NOX

[[Page 181]]

Budget unit or the unit for which an application for a NOX 
Budget opt-in permit under Sec. 97.83 is submitted and not denied or 
withdrawn; or
    (4) With respect to any general account, any person who has an 
ownership interest with respect to the NOX allowances held in 
the general account and who is subject to the binding agreement for the 
NOX authorized account representative to represent that 
person's ownership interest with respect to the NOX 
allowances.
    Percent monitor data availability means, for purposes of Sec. 97.43 
(a)(1) and Sec. 97.84(b), total unit operating hours for which quality-
assured data were recorded under subpart H of this part in a control 
period, divided by the total number of unit operating hours in the 
control period, and multiplied by 100 percent.
    Permitting authority means the State air pollution control agency, 
local agency, other State agency, or other agency authorized by the 
Administrator to issue or revise permits to meet the requirements of the 
NOX Budget Trading Program in accordance with subpart C of 
this part.
    Potential electrical output capacity means 33 percent of a unit's 
maximum design heat input.
    Receive or receipt of means, when referring to the permitting 
authority or the Administrator, to come into possession of a document, 
information, or correspondence (whether sent in writing or by authorized 
electronic transmission), as indicated in an official correspondence 
log, or by a notation made on the document, information, or 
correspondence, by the permitting authority or the Administrator in the 
regular course of business.
    Recordation, record, or recorded means, with regard to 
NOX allowances, the movement of NOX allowances by 
the Administrator from one NOX Allowance Tracking System 
account to another, for purposes of allocation, transfer, or deduction.
    Reference method means any direct test method of sampling and 
analyzing for an air pollutant as specified in appendix A of part 60 of 
this chapter.
    Serial number means, when referring to NOX allowances, 
the unique identification number assigned to each NOX 
allowance by the Administrator, under Sec. 97.53(c).
    Source means any governmental, institutional, commercial, or 
industrial structure, installation, plant, building, or facility that 
emits or has the potential to emit any regulated air pollutant under the 
Clean Air Act. For purposes of section 502(c) of the Clean Air Act, a 
``source,'' including a ``source'' with multiple units, shall be 
considered a single ``facility.''
    State means one of the 48 contiguous States or a portion thereof or 
the District of Columbia that is specified in Sec. 52.34 of this 
chapter and in which are located units for which the Administrator makes 
an effective finding under Sec. 52.34 of this chapter.
    Submit or serve means to send or transmit a document, information, 
or correspondence to the person specified in accordance with the 
applicable regulation:
    (1) In person;
    (2) By United States Postal Service; or
    (3) By other means of dispatch or transmission and delivery. 
Compliance with any ``submission,'' ``service,'' or ``mailing'' deadline 
shall be determined by the date of dispatch, transmission, or mailing 
and not the date of receipt.
    Title V operating permit means a permit issued under title V of the 
Clean Air Act and part 70 or part 71 of this chapter.
    Title V operating permit regulations means the regulations that the 
Administrator has approved or issued as meeting the requirements of 
title V of the Clean Air Act and part 70 or 71 of this chapter.
    Ton or tonnage means any ``short ton'' (i.e., 2,000 pounds). For the 
purpose of determining compliance with the NOX Budget 
emissions limitation, total tons for a control period shall be 
calculated as the sum of all recorded hourly emissions (or the tonnage 
equivalent of the recorded hourly emissions rates) in accordance with 
subpart H of this part, with any remaining fraction of a ton equal to or 
greater than 0.50 ton deemed to equal one ton and any fraction of a ton 
less than 0.50 ton deemed to equal zero tons.

[[Page 182]]

    Unit means a fossil fuel-fired stationary boiler, combustion 
turbine, or combined cycle system.
    Unit operating day means a calendar day in which a unit combusts any 
fuel.
    Unit operating hour or hour of unit operation means any hour (or 
fraction of an hour) during which a unit combusts any fuel.

[65 FR 2727, Jan. 18, 2000, as amended at 69 FR 21645, Apr. 21, 2004]



Sec. 97.3  Measurements, abbreviations, and acronyms.

    Measurements, abbreviations, and acronyms used in this part are 
defined as follows:

Btu-British thermal unit.
CO2-carbon dioxide.
hr-hour.
kW-kilowatt electrical.
kWh-kilowatt hour.
lb-pounds.
mmBtu-million Btu.
MWe-megawatt electrical.
NOX-nitrogen oxides.
O2-oxygen.
ton-2000 pounds.



Sec. 97.4  Applicability.

    (a) The following units in a State shall be a NOX Budget 
unit, and any source that includes one or more such units shall be a 
NOX Budget source, subject to the requirements of this part:
    (1)(i) For units other than cogeneration units--
    (A) For units commencing operation before January 1, 1997, a unit 
serving during 1995 or 1996 a generator--
    (1) With a nameplate capacity greater than 25 MWe and
    (2) Producing electricity for sale under a firm contract to the 
electric grid.
    (B) For units commencing operation in 1997 or 1998, a unit serving 
during 1997 or 1998 a generator--
    (1) With a nameplate capacity greater than 25 MWe and
    (2) Producing electricity for sale under a firm contract to the 
electric grid.
    (C) For units commencing operation on or after January 1, 1999, a 
unit serving at any time a generator--
    (1) With a nameplate capacity greater than 25 MWe and
    (2) Producing electricity for sale.
    (ii) For cogeneration units--
    (A) For units commencing operation before January 1, 1997, a unit 
serving during 1995 or 1996 a generator with a nameplate capacity 
greater than 25 MWe and failing to qualify as an unaffected unit under 
Sec. 72.6(b)(4) of this chapter for 1995 or 1996 under the Acid Rain 
Program.
    (B) For units commencing operation in 1997 or 1998, a unit serving 
during 1997 or 1998 a generator with a nameplate capacity grater than 25 
MWe and failing to qualify as an unaffected unit under Sec. 72.6(b)(4) 
of this chapter for 1997 or 1998 under the Acid Rain Program.
    (C) For units commencing operation on or after January 1, 1999, a 
unit serving at any time a generator with a nameplate capacity greater 
than 25 MWe and failing to qualify as an unaffected unit under Sec. 
72.6(b)(4) of this chapter under the Acid Rain Program for any year.
    (2)(i) For units other than cogeneration units--
    (A) For units commencing operation before January 1, 1997, a unit--
    (1) With a maximum design heat input greater than 250 mmBtu/hr and
    (2) Not serving during 1995 or 1996 a generator producing 
electricity for sale under a firm contract to the electric grid.
    (B) For units commencing operation in 1997 or 1998, a unit--
    (1) With a maximum design heat input greater than 250 mmBtu/hr and
    (2) Not serving during 1997 or 1998 a generator producing 
electricity for sale under a firm contract to the electric grid.
    (C) For units commencing on or after January 1, 1999, a unit with a 
maximum design heat input greater than 250 mmBtu/hr:
    (1) At no time serving a generator producing electricity for sale; 
or
    (2) At any time serving a generator with a nameplate capacity of 25 
MWe or less producing electricity for sale and with the potential to use 
no more than 50 percent of the potential electrical output capacity of 
the unit.
    (ii) For cogeneration units--
    (A) For units commencing operation before January 1, 1997, a unit 
with a maximum design heat input greater than 250 mmBtu/hr and 
qualifying as

[[Page 183]]

an unaffected unit under Sec. 72.6(b)(4) of this chapter under the Acid 
Rain Program for 1995 and 1996.
    (B) For units commencing operation in 1997 or 1998, a unit with a 
maximum design heat input greater than 250 mmBtu/hr and qualifying as an 
unaffected unit under Sec. 72.6(b)(4) under the Acid Rain Program for 
1997 and 1998.
    (C) For units commencing on or after January 1, 1999, a unit with a 
maximum design heat input greater than 250 mmBtu/hr and qualifying as an 
unaffected unit under Sec. 72.6(b)(4) of this chapter under the Acid 
Rain Program for each year.
    (b)(1) Notwithstanding paragraph (a) of this section, a unit under 
paragraph (a)(1) or (a)(2) of this section that has a federally 
enforceable permit that restricts the unit to combusting only natural 
gas or fuel oil (as defined in Sec. 75.2 of this chapter) during a 
control period includes a NOX emission limitation restricting 
NOX emissions during a control period to 25 tons or less, and 
includes the special provisions in paragraph (b)(4) of this section 
shall be exempt from the requirements of the NOX Budget 
Trading Program, except for the provisions of this paragraph (b), Sec. 
97.2, Sec. 97.3, Sec. 97.4(a), Sec. 97.7, and subparts E, F, and G of 
this part. The NOX emission limitation under this paragraph 
(b)(1) shall restrict NOX emissions during the control period 
by limiting unit operating hours. The restriction on unit operating 
hours shall be calculated by dividing 25 tons by the unit's maximum 
potential hourly NOX mass emissions, which shall equal the 
unit's maximum rated hourly heat input multiplied by the highest default 
NOX emission rate otherwise applicable to the unit under 
Sec. 75.19 of this chapter.
    (2) The exemption under paragraph (b)(1) of this section shall 
become effective as follows:
    (i) The exemption shall become effective on the date on which the 
NOX emission limitation and the special provisions in the 
permit under paragraph (b)(1) of this section become final; or
    (ii) If the NOX emission limitation and the special 
provisions in the permit under paragraph (b)(1) of this section become 
final during a control period and after the first date on which the unit 
operates during such control period, then the exemption shall become 
effective on May 1 of such control period, provided that such 
NOX emission limitation and the special provisions apply to 
the unit as of such first date of operation. If such NOX 
emission limitation and special provisions do not apply to the unit as 
of such first date of operation, then the exemption under paragraph 
(b)(1) of this section shall become effective on October 1 of the year 
during which such NOX emission limitation and the special 
provisions become final.
    (3) The permitting authority that issues a federally enforceable 
permit under paragraph (b)(1) of this section for a unit under paragraph 
(a)(1) or (a)(2) of this section will provide the Administrator written 
notice of the issuance of such permit and, upon request, a copy of the 
permit.
    (4) Special provisions. (i) A unit exempt under paragraph (b)(1) of 
this section shall comply with the restriction on fuel use and unit 
operating hours described in paragraph (b)(1) of this section during the 
control period in each year.
    (ii) The Administrator will allocate NOX allowances to 
the unit under Sec. Sec. 97.41(a) through (c) and 97.42(a) through (c). 
For each control period for which the unit is allocated NOX 
allowances under Sec. Sec. 97.41(a) through (c) and 97.42(a) through 
(c):
    (A) The owners and operators of the unit must specify a general 
account, in which the Administrator will record the NOX 
allowances; and
    (B) After the Administrator records a NOX allowance 
allocations under Sec. Sec. 97.41(a) through (c) and 97.42(a) through 
(c), the Administrator will deduct, from the general account under 
paragraph (b)(4)(ii)(A) of this section, NOX allowances that 
are allocated for the same or a prior control period as the 
NOX allowances allocated to the unit under Sec. Sec. 
97.41(a) through (c) and 97.42(a) through (c) and that equal the 
NOX emission limitation (in tons of NOX) on which 
the unit's exemption under paragraph (b)(1) of this section is

[[Page 184]]

based. The NOX authorized account representative shall ensure 
that such general account contains the NOX allowances 
necessary for completion of such deduction.
    (iii) A unit exempt under this paragraph (b) shall report hours of 
unit operation during the control period in each year to the permitting 
authority by November 1 of that year.
    (iv) For a period of 5 years from the date the records are created, 
the owners and operators of a unit exempt under paragraph (b)(1) of this 
section shall retain, at the source that includes the unit, records 
demonstrating that the conditions of the federally enforceable permit 
under paragraph (b)(1) of this section were met, including the 
restriction on fuel use or unit operating hours. The 5-year period for 
keeping records may be extended for cause, at any time prior to the end 
of the period, in writing by the permitting authority or the 
Administrator. The owners and operators bear the burden of proof that 
the unit met the restriction on fuel use or unit operating hours.
    (v) The owners and operators and, to the extent applicable, the 
NOX authorized account representative of a unit exempt under 
paragraph (b)(1) of this section shall comply with the requirements of 
the NOX Budget Trading Program concerning all periods for 
which the exemption is not in effect, even if such requirements arise, 
or must be complied with, after the exemption takes effect.
    (vi) On the earlier of the following dates, a unit exempt under 
paragraph (b)(1) of this section shall lose its exemption:
    (A) The date on which the restriction on fuel use or unit operating 
hours described in paragraph (b)(1) of this section is removed from the 
unit's federally enforceable permit or otherwise becomes no longer 
applicable to any control period starting in 2004; or
    (B) The first date on which the unit fails to comply, or with regard 
to which the owners and operators fail to meet their burden of proving 
that the unit is complying, with the restriction on fuel use or unit 
operating hours described in paragraph (b)(1) of this section during any 
control period starting in 2004.
    (vii) A unit that loses its exemption in accordance with paragraph 
(b)(4)(vi) of this section shall be subject to the requirements of this 
part. For the purpose of applying permitting requirements under subpart 
C of this part, allocating allowances under subpart E of this part, and 
applying monitoring requirements under subpart H of this part, the unit 
shall be treated as commencing operation and, if the unit is covered by 
paragraph (a)(1) of this section, commencing commercial operation on the 
date the unit loses its exemption.
    (viii) A unit that is exempt under paragraph (b)(1) of this section 
is not eligible to be a NOX Budget opt-in unit under subpart 
I of this part.

[65 FR 2727, Jan. 18, 2000, as amended at 67 FR 21529, Apr. 30, 2002; 69 
FR 21645, Apr. 21, 2004]



Sec. 97.5  Retired unit exemption.

    (a) This section applies to any NOX Budget unit, other 
than a NOX Budget opt-in unit, that is permanently retired.
    (b)(1) Any NOX Budget unit, other than a NOX 
Budget opt-in unit, that is permanently retired shall be exempt from the 
NOX Budget Trading Program, except for the provisions of this 
section, Sec. 97.2, Sec. 97.3, Sec. 97.4, Sec. 97.7, and subparts E, 
F, and G of this part.
    (2) The exemption under paragraph (b)(1) of this section shall 
become effective the day on which the unit is permanently retired. 
Within 30 days of permanent retirement, the NOX authorized 
account representative (authorized in accordance with subpart B of this 
part) shall submit a statement to the permitting authority otherwise 
responsible for administering any NOX Budget permit for the 
unit. The NOX authorized account representative shall submit 
a copy of the statement to the Administrator. The statement shall state, 
in a format prescribed by the permitting authority, that the unit is 
permanently retired and will comply with the requirements of paragraph 
(c) of this section.
    (3) After receipt of the notice under paragraph (b)(2) of this 
section, the permitting authority will amend any permit covering the 
source at which

[[Page 185]]

the unit is located to add the provisions and requirements of the 
exemption under paragraphs (b)(1) and (c) of this section.
    (c) Special provisions. (1) A unit exempt under this section shall 
not emit any nitrogen oxides, starting on the date that the exemption 
takes effect.
    (2) The Administrator will allocate NOX allowances under 
subpart E of this part to a unit exempt under this section. For each 
control period for which the unit is allocated one or more 
NOX allowances, the owners and operators of the unit shall 
specify a general account, in which the Administrator will record such 
NOX allowances.
    (3) For a period of 5 years from the date the records are created, 
the owners and operators of a unit exempt under this section shall 
retain at the source that includes the unit, records demonstrating that 
the unit is permanently retired. The 5-year period for keeping records 
may be extended for cause, at any time prior to the end of the period, 
in writing by the permitting authority or the Administrator. The owners 
and operators bear the burden of proof that the unit is permanently 
retired.
    (4) The owners and operators and, to the extent applicable, the 
NOX authorized account representative of a unit exempt under 
this section shall comply with the requirements of the NOX 
Budget Trading Program concerning all periods for which the exemption is 
not in effect, even if such requirements arise, or must be complied 
with, after the exemption takes effect.
    (5)(i) A unit exempt under this section and located at a source that 
is required, or but for this exemption would be required, to have a 
title V operating permit shall not resume operation unless the 
NOX authorized account representative of the source submits a 
complete NOX Budget permit application under Sec. 97.22 for 
the unit not less than 18 months (or such lesser time provided by the 
permitting authority) before the later of May 31, 2004 or the date on 
which the unit resumes operation.
    (ii) A unit exempt under this section and located at a source that 
is required, or but for this exemption would be required, to have a non-
title V permit shall not resume operation unless the NOX 
authorized account representative of the source submits a complete 
NOX Budget permit application under Sec. 97.22 for the unit 
not less than 18 months (or such lesser time provided by the permitting 
authority) before the later of May 31, 2004 or the date on which the 
unit is to first resume operation.
    (6) On the earlier of the following dates, a unit exempt under 
paragraph (b) of this section shall lose its exemption:
    (i) The date on which the NOX authorized account 
representative submits a NOX Budget permit application under 
paragraph (c)(5) of this section;
    (ii) The date on which the NOX authorized account 
representative is required under paragraph (c)(5) of this section to 
submit a NOX Budget permit application; or
    (iii) The date on which the unit resumes operation, if the unit is 
not required to submit a NOX permit application.
    (7) For the purpose of applying monitoring requirements under 
subpart H of this part, a unit that loses its exemption under this 
section shall be treated as a unit that commences operation or 
commercial operation on the first date on which the unit resumes 
operation.
    (8) A unit that is exempt under this section is not eligible to be a 
NOX Budget opt-in unit under subpart I of this part.

[65 FR 2727, Jan. 18, 2000, as amended at 67 FR 21529, Apr. 30, 2002; 69 
FR 21646, Apr. 21, 2004]



Sec. 97.6  Standard requirements.

    (a) Permit requirements. (1) The NOX authorized account 
representative of each NOX Budget source required to have a 
federally enforceable permit and each NOX Budget unit 
required to have a federally enforceable permit at the source shall:
    (i) Submit to the permitting authority a complete NOX 
Budget permit application under Sec. 97.22 in accordance with the 
deadlines specified in Sec. 97.21(b) and (c);
    (ii) Submit in a timely manner any supplemental information that the 
permitting authority determines is necessary in order to review a 
NOX Budget

[[Page 186]]

permit application and issue or deny a NOX Budget permit.
    (2) The owners and operators of each NOX Budget source 
required to have a federally enforceable permit and each NOX 
Budget unit required to have a federally enforceable permit at the 
source shall have a NOX Budget permit issued by the 
permitting authority and operate the unit in compliance with such 
NOX Budget permit.
    (3) The owners and operators of a NOX Budget source that 
is not otherwise required to have a federally enforceable permit are not 
required to submit a NOX Budget permit application, and to 
have a NOX Budget permit, under subpart C of this part for 
such NOX Budget source.
    (b) Monitoring requirements. (1) The owners and operators and, to 
the extent applicable, the NOX authorized account 
representative of each NOX Budget source and each 
NOX Budget unit at the source shall comply with the 
monitoring requirements of subpart H of this part.
    (2) The emissions measurements recorded and reported in accordance 
with subpart H of this part shall be used to determine compliance by the 
unit with the NOX Budget emissions limitation under paragraph 
(c) of this section.
    (c) Nitrogen oxides requirements. (1) The owners and operators of 
each NOX Budget source and each NOX Budget unit at 
the source shall hold NOX allowances available for compliance 
deductions under Sec. 97.54(a), (b), (e), or (f) as of the 
NOX allowance transfer deadline, in the unit's compliance 
account and the source's overdraft account in an amount not less than 
the total NOX emissions for the control period from the unit, 
as determined in accordance with subpart H of this part, plus any amount 
necessary to account for actual heat input under Sec. 97.42(e) for the 
control period or to account for excess emissions for a prior control 
period under Sec. 97.54(d) or to account for withdrawal from the 
NOX Budget Trading Program, or a change in regulatory status, 
of a NOX Budget opt-in unit under Sec. 97.86 or Sec. 97.87.
    (2) Each ton of nitrogen oxides emitted in excess of the 
NOX Budget emissions limitation shall constitute a separate 
violation of this part, the Clean Air Act, and applicable State law.
    (3) A NOX Budget unit shall be subject to the 
requirements under paragraph (c)(1) of this section starting on the 
later of May 31, 2004 or the date on which the unit commences operation.
    (4) NOX allowances shall be held in, deducted from, or 
transferred among NOX Allowance Tracking System accounts in 
accordance with subparts E, F, G, and I of this part.
    (5) A NOX allowance shall not be deducted, in order to 
comply with the requirements under paragraph (c)(1) of this section, for 
a control period in a year prior to the year for which the 
NOX allowance was allocated.
    (6) A NOX allowance allocated by the Administrator under 
the NOX Budget Trading Program is a limited authorization to 
emit one ton of nitrogen oxides in accordance with the NOX 
Budget Trading Program. No provision of the NOX Budget 
Trading Program, the NOX Budget permit application, the 
NOX Budget permit, or an exemption under Sec. 97.4(b) or 
Sec. 97.5 and no provision of law shall be construed to limit the 
authority of the United States to terminate or limit such authorization.
    (7) A NOX allowance allocated by the Administrator under 
the NOX Budget Trading Program does not constitute a property 
right.
    (8) Upon recordation by the Administrator under subpart F or G of 
this part, every allocation, transfer, or deduction of a NOX 
allowance to or from a NOX Budget unit's compliance account 
or the overdraft account of the source where the unit is located is 
incorporated automatically in any NOX Budget permit of the 
NOX Budget unit.
    (d) Excess emissions requirements. (1) The owners and operators of a 
NOX Budget unit that has excess emissions in any control 
period shall:
    (i) Surrender the NOX allowances required for deduction 
under Sec. 97.54(d)(1); and
    (ii) Pay any fine, penalty, or assessment or comply with any other 
remedy imposed under Sec. 97.54(d)(3).
    (e) Recordkeeping and reporting requirements. (1) Unless otherwise 
provided, the owners and operators of the NOX Budget source 
and each NOX Budget unit at the source shall keep on site

[[Page 187]]

at the source each of the following documents for a period of 5 years 
from the date the document is created. This period may be extended for 
cause, at any time prior to the end of 5 years, in writing by the 
permitting authority or the Administrator.
    (i) The account certificate of representation under Sec. 97.13 for 
the NOX authorized account representative for the source and 
each NOX Budget unit at the source and all documents that 
demonstrate the truth of the statements in the account certificate of 
representation; provided that the certificate and documents shall be 
retained on site at the source beyond such 5-year period until such 
documents are superseded because of the submission of a new account 
certificate of representation under Sec. 97.13 changing the 
NOX authorized account representative.
    (ii) All emissions monitoring information, in accordance with 
subpart H of this part; provided that to the extent that subpart H of 
this part provides for a 3-year period for recordkeeping, the 3-year 
period shall apply.
    (iii) Copies of all reports, compliance certifications, and other 
submissions and all records made or required under the NOX 
Budget Trading Program.
    (iv) Copies of all documents used to complete a NOX 
Budget permit application and any other submission under the 
NOX Budget Trading Program or to demonstrate compliance with 
the requirements of the NOX Budget Trading Program.
    (2) The NOX authorized account representative of a 
NOX Budget source and each NOX Budget unit at the 
source shall submit the reports and compliance certifications required 
under the NOX Budget Trading Program, including those under 
subpart D, H, or I of this part.
    (f) Liability. (1) Any person who knowingly violates any requirement 
or prohibition of the NOX Budget Trading Program, a 
NOX Budget permit, or an exemption under Sec. 97.4(b) or 
Sec. 97.5 shall be subject to enforcement pursuant to applicable State 
or Federal law.
    (2) Any person who knowingly makes a false material statement in any 
record, submission, or report under the NOX Budget Trading 
Program shall be subject to criminal enforcement pursuant to the 
applicable State or Federal law.
    (3) No permit revision shall excuse any violation of the 
requirements of the NOX Budget Trading Program that occurs 
prior to the date that the revision takes effect.
    (4) Each NOX Budget source and each NOX Budget 
unit shall meet the requirements of the NOX Budget Trading 
Program.
    (5) Any provision of the NOX Budget Trading Program that 
applies to a NOX Budget source or the NOX 
authorized account representative of a NOX Budget source 
shall also apply to the owners and operators of such source and of the 
NOX Budget units at the source.
    (6) Any provision of the NOX Budget Trading Program that 
applies to a NOX Budget unit or the NOX authorized 
account representative of a NOX budget unit shall also apply 
to the owners and operators of such unit. Except with regard to the 
requirements applicable to units with a common stack under subpart H of 
this part, the owners and operators and the NOX authorized 
account representative of one NOX Budget unit shall not be 
liable for any violation by any other NOX Budget unit of 
which they are not owners or operators or the NOX authorized 
account representative and that is located at a source of which they are 
not owners or operators or the NOX authorized account 
representative.
    (g) Effect on other authorities. No provision of the NOX 
Budget Trading Program, a NOX Budget permit application, a 
NOX Budget permit, or an exemption under Sec. 97.4(b) or 
Sec. 97.5 shall be construed as exempting or excluding the owners and 
operators and, to the extent applicable, the NOX authorized 
account representative of a NOX Budget source or 
NOX Budget unit from compliance with any other provision of 
the applicable, approved State implementation plan, a federally 
enforceable permit, or the Clean Air Act.

[65 FR 2727, Jan. 18, 2000, as amended at 67 FR 21529, Apr. 30, 2002]



Sec. 97.7  Computation of time.

    (a) Unless otherwise stated, any time period scheduled, under the 
NOX Budget Trading Program, to begin on the occurrence of an 
act or event shall

[[Page 188]]

begin on the day the act or event occurs.
    (b) Unless otherwise stated, any time period scheduled, under the 
NOX Budget Trading Program, to begin before the occurrence of 
an act or event shall be computed so that the period ends the day before 
the act or event occurs.
    (c) Unless otherwise stated, if the final day of any time period, 
under the NOX Budget Trading Program, falls on a weekend or a 
State or Federal holiday, the time period shall be extended to the next 
business day.



 Subpart B_NOX Authorized Account Representative for NOX Budget Sources



Sec. 97.10  Authorization and responsibilities of NOX authorized
account representative.

    (a) Except as provided under Sec. 97.11, each NOX Budget 
source, including all NOX Budget units at the source, shall 
have one and only one NOX authorized account representative, 
with regard to all matters under the NOX Budget Trading 
Program concerning the source or any NOX Budget unit at the 
source.
    (b) The NOX authorized account representative of the 
NOX Budget source shall be selected by an agreement binding 
on the owners and operators of the source and all NOX Budget 
units at the source.
    (c) Upon receipt by the Administrator of a complete account 
certificate of representation under Sec. 97.13, the NOX 
authorized account representative of the source shall represent and, by 
his or her representations, actions, inactions, or submissions, legally 
bind each owner and operator of the NOX Budget source 
represented and each NOX Budget unit at the source in all 
matters pertaining to the NOX Budget Trading Program, not 
withstanding any agreement between the NOX authorized account 
representative and such owners and operators. The owners and operators 
shall be bound by any decision or order issued to the NOX 
authorized account representative by the permitting authority, the 
Administrator, or a court regarding the source or unit.
    (d) No NOX Budget permit shall be issued, and no 
NOX Allowance Tracking System account shall be established 
for a NOX Budget unit at a source, until the Administrator 
has received a complete account certificate of representation under 
Sec. 97.13 for a NOX authorized account representative of 
the source and the NOX Budget units at the source.
    (e) (1) Each submission under the NOX Budget Trading 
Program shall be submitted, signed, and certified by the NOX 
authorized account representative for each NOX Budget source 
on behalf of which the submission is made. Each such submission shall 
include the following certification statement by the NOX 
authorized account representative: ``I am authorized to make this 
submission on behalf of the owners and operators of the NOX 
Budget sources or NOX Budget units for which the submission 
is made. I certify under penalty of law that I have personally examined, 
and am familiar with, the statements and information submitted in this 
document and all its attachments. Based on my inquiry of those 
individuals with primary responsibility for obtaining the information, I 
certify that the statements and information are to the best of my 
knowledge and belief true, accurate, and complete. I am aware that there 
are significant penalties for submitting false statements and 
information or omitting required statements and information, including 
the possibility of fine or imprisonment.''
    (2) The permitting authority and the Administrator will accept or 
act on a submission made on behalf of owner or operators of a 
NOX Budget source or a NOX Budget unit only if the 
submission has been made, signed, and certified in accordance with 
paragraph (e)(1) of this section.



Sec. 97.11  Alternate NOX authorized account representative.

    (a) An account certificate of representation may designate one and 
only one alternate NOX authorized account representative who 
may act on behalf of the NOX authorized account 
representative. The agreement by which the alternate NOX 
authorized account representative is selected shall include a procedure 
for authorizing the

[[Page 189]]

alternate NOX authorized account representative to act in 
lieu of the NOX authorized account representative.
    (b) Upon receipt by the Administrator of a complete account 
certificate of representation under Sec. 97.13, any representation, 
action, inaction, or submission by the alternate NOX 
authorized account representative shall be deemed to be a 
representation, action, inaction, or submission by the NOX 
authorized account representative.
    (c) Except in this section and Sec. Sec. 97.10(a), 97.12, 97.13, 
and 97.51, whenever the term ``NOX authorized account 
representative'' is used in this part, the term shall be construed to 
include the alternate NOX authorized account representative.



Sec. 97.12  Changing NOX authorized account representative and 
alternate NOX authorized account representative; changes in owners
and operators.

    (a) Changing NOX authorized account representative. The 
NOX authorized account representative may be changed at any 
time upon receipt by the Administrator of a superseding complete account 
certificate of representation under Sec. 97.13. Notwithstanding any 
such change, all representations, actions, inactions, and submissions by 
the previous NOX authorized account representative prior to 
the time and date when the Administrator receives the superseding 
account certificate of representation shall be binding on the new 
NOX authorized account representative and the owners and 
operators of the NOX Budget source and the NOX 
Budget units at the source.
    (b) Changing alternate NOX authorized account 
representative. The alternate NOX authorized account 
representative may be changed at any time upon receipt by the 
Administrator of a superseding complete account certificate of 
representation under Sec. 97.13. Notwithstanding any such change, all 
representations, actions, inactions, and submissions by the previous 
alternate NOX authorized account representative prior to the 
time and date when the Administrator receives the superseding account 
certificate of representation shall be binding on the new alternate 
NOX authorized account representative and the owners and 
operators of the NOX Budget source and the NOX 
Budget units at the source.
    (c) Changes in owners and operators. (1) In the event a new owner or 
operator of a NOX Budget source or a NOX Budget 
unit is not included in the list of owners and operators submitted in 
the account certificate of representation under Sec. 97.13, such new 
owner or operator shall be deemed to be subject to and bound by the 
account certificate of representation, the representations, actions, 
inactions, and submissions of the NOX authorized account 
representative and any alternate NOX authorized account 
representative of the source or unit, and the decisions, orders, 
actions, and inactions of the permitting authority or the Administrator, 
as if the new owner or operator were included in such list.
    (2) Within 30 days following any change in the owners and operators 
of a NOX Budget source or a NOX Budget unit, 
including the addition of a new owner or operator, the NOX 
authorized account representative or alternate NOX authorized 
account representative shall submit a revision to the account 
certificate of representation under Sec. 97.13 amending the list of 
owners and operators to include the change.



Sec. 97.13  Account certificate of representation.

    (a) A complete account certificate of representation for a 
NOX authorized account representative or an alternate 
NOX authorized account representative shall include the 
following elements in a format prescribed by the Administrator:
    (1) Identification of the NOX Budget source and each 
NOX Budget unit at the source for which the account 
certificate of representation is submitted.
    (2) The name, address, e-mail address (if any), telephone number, 
and facsimile transmission number (if any) of the NOX 
authorized account representative and any alternate NOX 
authorized account representative.
    (3) A list of the owners and operators of the NOX Budget 
source and of each NOX Budget unit at the source.
    (4) The following certification statement by the NOX 
authorized account representative and any alternate NOX 
authorized account representative: ``I

[[Page 190]]

certify that I was selected as the NOX authorized account 
representative or alternate NOX authorized account 
representative, as applicable, by an agreement binding on the owners and 
operators of the NOX Budget source and each NOX 
Budget unit at the source. I certify that I have all the necessary 
authority to carry out my duties and responsibilities under the 
NOX Budget Trading Program on behalf of the owners and 
operators of the NOX Budget source and of each NOX 
Budget unit at the source and that each such owner and operator shall be 
fully bound by my representations, actions, inactions, or submissions 
and by any decision or order issued to me by the permitting authority, 
the Administrator, or a court regarding the source or unit.''
    (5) The signature of the NOX authorized account 
representative and any alternate NOX authorized account 
representative and the dates signed.
    (b) Unless otherwise required by the permitting authority or the 
Administrator, documents of agreement referred to in the account 
certificate of representation shall not be submitted to the permitting 
authority or the Administrator. Neither the permitting authority nor the 
Administrator shall be under any obligation to review or evaluate the 
sufficiency of such documents, if submitted.



Sec. 97.14  Objections concerning NOX authorized account representative.

    (a) Once a complete account certificate of representation under 
Sec. 97.13 has been submitted and received, the permitting authority 
and the Administrator will rely on the account certificate of 
representation unless and until a superseding complete account 
certificate of representation under Sec. 97.13 is received by the 
Administrator.
    (b) Except as provided in Sec. 97.12 (a) or (b), no objection or 
other communication submitted to the permitting authority or the 
Administrator concerning the authorization, or any representation, 
action, inaction, or submission of the NOX authorized account 
representative shall affect any representation, action, inaction, or 
submission of the NOX authorized account representative or 
the finality of any decision or order by the permitting authority or the 
Administrator under the NOX Budget Trading Program.
    (c) Neither the permitting authority nor the Administrator will 
adjudicate any private legal dispute concerning the authorization or any 
representation, action, inaction, or submission of any NOX 
authorized account representative, including private legal disputes 
concerning the proceeds of NOX allowance transfers.



                            Subpart C_Permits



Sec. 97.20  General NOX Budget Trading Program permit requirements.

    (a) For each NOX Budget source required to have a 
federally enforceable permit, such permit shall include a NOX 
Budget permit administered by the permitting authority for the federally 
enforceable permit.
    (1) For NOX Budget sources required to have a title V 
operating permit, the NOX Budget portion of the title V 
permit shall be administered in accordance with the permitting 
authority's title V operating permits regulations promulgated under part 
70 or 71 of this chapter, except as provided otherwise by this subpart 
or subpart I of this part.
    (2) For NOX Budget sources required to have a non-title V 
permit, the NOX Budget portion of the non-title V permit 
shall be administered in accordance with the permitting authority's 
regulations promulgated to administer non-title V permits, except as 
provided otherwise by this subpart or subpart I of this part.
    (b) Each NOX Budget permit shall contain all applicable 
NOX Budget Trading Program requirements and shall be a 
complete and segregable portion of the permit under paragraph (a) of 
this section.



Sec. 97.21  Submission of NOX Budget permit applications.

    (a) Duty to apply. The NOX authorized account 
representative of any NOX Budget source required to have a 
federally enforceable permit shall submit to the permitting authority a 
complete NOX Budget permit application under Sec. 97.22 by 
the applicable deadline in paragraph (b) of this section.

[[Page 191]]

    (b)(1) For NOX Budget sources required to have a title V 
operating permit:
    (i) For any source, with one or more NOX Budget units 
under Sec. 97.4(a) that commence operation before January 1, 2001, the 
NOX authorized account representative shall submit a complete 
NOX Budget permit application under Sec. 97.22 covering such 
NOX Budget units to the permitting authority at least 18 
months (or such lesser time provided by the permitting authority) before 
May 31, 2004.
    (ii) For any source, with any NOX Budget unit under Sec. 
97.4(a) that commences operation on or after January 1, 2001, the 
NOX authorized account representative shall submit a complete 
NOX Budget permit application under Sec. 97.22 covering such 
NOX Budget unit to the permitting authority at least 18 
months (or such lesser time provided by the permitting authority) before 
the later of May 31, 2004 or the date on which the NOX Budget 
unit commences operation.
    (2) For NOX Budget sources required to have a non-title V 
permit:
    (i) For any source, with one or more NOX Budget units 
under Sec. 97.4(a) that commence operation before January 1, 2001, the 
NOX authorized account representative shall submit a complete 
NOX Budget permit application under Sec. 97.22 covering such 
NOX Budget units to the permitting authority at least 18 
months (or such lesser time provided by the permitting authority) before 
May 31, 2004.
    (ii) For any source, with any NOX Budget unit under Sec. 
97.4(a) that commences operation on or after January 1, 2001, the 
NOX authorized account representative shall submit a complete 
NOX Budget permit application under Sec. 97.22 covering such 
NOX Budget unit to the permitting authority at least 18 
months (or such lesser time provided by the permitting authority) before 
the later of May 31, 2004 or the date on which the NOX Budget 
unit commences operation.
    (c) Duty to reapply. (1) For a NOX Budget source required 
to have a title V operating permit, the NOX authorized 
account representative shall submit a complete NOX Budget 
permit application under Sec. 97.22 for the NOX Budget 
source covering the NOX Budget units at the source in 
accordance with the permitting authority's title V operating permits 
regulations addressing operating permit renewal.
    (2) For a NOX Budget source required to have a non-title 
V permit, the NOX authorized account representative shall 
submit a complete NOX Budget permit application under Sec. 
97.22 for the NOX Budget source covering the NOX 
Budget units at the source in accordance with the permitting authority's 
non-title V permits regulations addressing permit renewal.

[65 FR 2727, Jan. 18, 2000, as amended at 67 FR 21529, Apr. 30, 2002]



Sec. 97.22  Information requirements for NOX Budget permit applications.

    A complete NOX Budget permit application shall include 
the following elements concerning the NOX Budget source for 
which the application is submitted, in a format prescribed by the 
permitting authority:
    (a) Identification of the NOX Budget source, including 
plant name and the ORIS (Office of Regulatory Information Systems) or 
facility code assigned to the source by the Energy Information 
Administration, if applicable;
    (b) Identification of each NOX Budget unit at the 
NOX Budget source and whether it is a NOX Budget 
unit under Sec. 97.4(a) or under subpart I of this part;
    (c) The standard requirements under Sec. 97.6; and
    (d) For each NOX Budget opt-in unit at the NOX 
Budget source, the following certification statements by the 
NOX authorized account representative:
    (1) ``I certify that each unit for which this permit application is 
submitted under subpart I of this part is not a NOX Budget 
unit under 40 CFR 97.4(a) and is not covered by an exemption under 40 
CFR 97.4(b) or 97.5 that is in effect.''
    (2) If the application is for an initial NOX Budget opt-
in permit, ``I certify that each unit for which this permit application 
is submitted under subpart I of 40 CFR part 97 is operating, as that 
term is defined under 40 CFR 97.2.''

[[Page 192]]



Sec. 97.23  NOX Budget permit contents.

    (a) Each NOX Budget permit will contain, in a format 
prescribed by the permitting authority, all elements required for a 
complete NOX Budget permit application under Sec. 97.22.
    (b) Each NOX Budget permit is deemed to incorporate 
automatically the definitions of terms under Sec. 97.2 and, upon 
recordation by the Administrator under subpart F or G of this part, 
every allocation, transfer, or deduction of a NOX allowance 
to or from the compliance accounts of the NOX Budget units 
covered by the permit or the overdraft account of the NOX 
Budget source covered by the permit.



Sec. 97.24  NOX Budget permit revisions.

    (a) For a NOX Budget source with a title V operating 
permit, except as provided in Sec. 97.23(b), the permitting authority 
will revise the NOX Budget permit, as necessary, in 
accordance with the permitting authority's title V operating permits 
regulations addressing permit revisions.
    (b) For a NOX Budget source with a non-title V permit, 
except as provided in Sec. 97.23(b), the permitting authority will 
revise the NOX Budget permit, as necessary, in accordance 
with the permitting authority's non-title V permits regulations 
addressing permit revisions.



                   Subpart D_Compliance Certification



Sec. 97.30  Compliance certification report.

    (a) Applicability and deadline. For each control period in which one 
or more NOX Budget units at a source are subject to the 
NOX Budget emissions limitation, the NOX 
authorized account representative of the source shall submit to the 
permitting authority and the Administrator by November 30 of that year, 
a compliance certification report for each source covering all such 
units.
    (b) Contents of report. The NOX authorized account 
representative shall include in the compliance certification report 
under paragraph (a) of this section the following elements, in a format 
prescribed by the Administrator, concerning each unit at the source and 
subject to the NOX Budget emissions limitation for the 
control period covered by the report:
    (1) Identification of each NOX Budget unit;
    (2) At the NOX authorized account representative's 
option, the serial numbers of the NOX allowances that are to 
be deducted from each unit's compliance account under Sec. 97.54 for 
the control period;
    (3) At the NOX authorized account representative's 
option, for units sharing a common stack and having NOX 
emissions that are not monitored separately or apportioned in accordance 
with subpart H of this part, the percentage of allowances that is to be 
deducted from each unit's compliance account under Sec. 97.54(e); and
    (4) The compliance certification under paragraph (c) of this 
section.
    (c) Compliance certification. In the compliance certification report 
under paragraph (a) of this section, the NOX authorized 
account representative shall certify, based on reasonable inquiry of 
those persons with primary responsibility for operating the source and 
the NOX Budget units at the source in compliance with the 
NOX Budget Trading Program, whether each NOX 
Budget unit for which the compliance certification is submitted was 
operated during the calendar year covered by the report in compliance 
with the requirements of the NOX Budget Trading Program 
applicable to the unit, including:
    (1) Whether the unit was operated in compliance with the 
NOX Budget emissions limitation;
    (2) Whether the monitoring plan that governs the unit has been 
maintained to reflect the actual operation and monitoring of the unit 
and contains all information necessary to attribute NOX 
emissions to the unit, in accordance with subpart H of this part;
    (3) Whether all the NOX emissions from the unit, or a 
group of units (including the unit) using a common stack, were monitored 
or accounted for through the missing data procedures and reported in the 
quarterly monitoring reports, including whether conditional data were 
reported in the quarterly reports in accordance with

[[Page 193]]

subpart H of this part. If conditional data were reported, the owner or 
operator shall indicate whether the status of all conditional data has 
been resolved and all necessary quarterly report resubmissions have been 
made;
    (4) Whether the facts that form the basis for certification under 
subpart H of this part of each monitor at the unit or a group of units 
(including the unit) using a common stack, or for using an excepted 
monitoring method or alternative monitoring method approved under 
subpart H of this part, if any, have changed; and
    (5) If a change is required to be reported under paragraph (c)(4) of 
this section, specify the nature of the change, the reason for the 
change, when the change occurred, and how the unit's compliance status 
was determined subsequent to the change, including what method was used 
to determine emissions when a change mandated the need for monitor 
recertification.



Sec. 97.31  Administrator's action on compliance certifications.

    (a) The Administrator may review and conduct independent audits 
concerning any compliance certification or any other submission under 
the NOX Budget Trading Program and make appropriate 
adjustments of the information in the compliance certifications or other 
submissions.
    (b) The Administrator may deduct NOX allowances from or 
transfer NOX allowances to a unit's compliance account or a 
source's overdraft account based on the information in the compliance 
certifications or other submissions, as adjusted under paragraph (a) of 
this section.



                   Subpart E_NOX Allowance Allocations



Sec. 97.40  Trading program budget.

    In accordance with Sec. Sec. 97.41 and 97.42, the Administrator 
will allocate to the NOX Budget units under Sec. 97.4(a) in 
a State, for each control period specified in Sec. 97.41, a total 
number of NOX allowances equal to the trading budget for the 
State, as set forth in appendix C of this part, less the sum of the 
NOX emission limitations (in tons) for each unit exempt under 
Sec. 97.4(b) that is not allocated any NOX allowances under 
Sec. 97.42 (b) or (c) for the control period and whose NOX 
emission limitation (in tons of NOX) is not included in the 
amount calculated under Sec. 97.42(d)(5)(ii)(B) for the control period.

[65 FR 2727, Jan. 18, 2000, as amended at 69 FR 21646, Apr. 21, 2004]



Sec. 97.41  Timing requirements for NOX allowance allocations.

    (a) The NOX allowance allocations, determined in 
accordance with Sec. Sec. 97.42(a) through (c), for the control periods 
in 2004 through 2007 are set forth in appendices A and B of this part.
    (b) By April 1, 2005, the Administrator will determine by order the 
NOX allowance allocations, in accordance with Sec. Sec. 
97.42 (a) through (c), for the control periods in 2008 through 2012.
    (c) By April 1, 2010, by April 1 of 2015, and thereafter by April 1 
of the year that is 5 years after the last year for which NOX 
allowances allocations are determined, the Administrator will determine 
by order the NOX allowance allocations, in accordance with 
Sec. Sec. 97.42(a) through (c), for the control periods in the years 
that are 3, 4, 5, 6, and 7 years after the applicable deadline under 
this paragraph (c).
    (d) By April 1, 2004 and April 1 of each year thereafter, the 
Administrator will determine by order the NOX allowance 
allocations, in accordance with Sec. 97.42(d), for the control period 
in the year of the applicable deadline under this paragraph (d).
    (e) The Administrator will make available to the public each 
determination of NOX allowance allocations under paragraph 
(b), (c), or (d) of this section and will provide an opportunity for 
submission of objections to the determination. Objections shall be 
limited to addressing whether the determination is in accordance with 
Sec. 97.42. Based on any such objections, the Administrator will adjust 
each determination to the extent necessary to ensure that it is in 
accordance with Sec. 97.42.

[65 FR 2727, Jan. 18, 2000, as amended at 67 FR 21529, Apr. 30, 2002]

[[Page 194]]



Sec. 97.42  NOX allowance allocations.

    (a)(1) The heat input (in mmBtu) used for calculating NOX 
allowance allocations for each NOX Budget unit under Sec. 
97.4(a) will be:
    (i) For a NOX allowance allocation under Sec. 97.41(a):
    (A) For a unit under Sec. 97.4(a)(1), the average of the two 
highest amounts of the unit's heat input for the control periods in 1995 
through 1998; or
    (B) For a unit under Sec. 97.4(a)(2), the control period in 1995 
or, if the Administrator determines that reasonably reliable data are 
available for control periods in 1996 through 1998, the average of the 
two highest amounts of the unit's heat input for the control periods in 
1995 through 1998.
    (ii) For a NOX allowance allocation under Sec. 97.41(b), 
the unit's average heat input for the control periods in 2002 through 
2004.
    (iii) For a NOX allowance allocation under Sec. 
97.41(c), the unit's average heat input for the control period in the 
years that are 4, 5, 6, 7, and 8 years before the first year for which 
the allocation is being calculated.
    (2) The unit's heat input for the control period in each year 
specified under paragraph (a)(1) of this section will be determined in 
accordance with part 75 of this chapter. Notwithstanding the first 
sentence of this paragraph (a)(2):
    (i) For a NOX allowance allocation under Sec. 97.41(a), 
such heat input will be determined using the best available data 
reported to the Administrator for the unit if the unit was not otherwise 
subject to the requirements of part 75 of this chapter for the control 
period.
    (ii) For a NOX allowance allocation under Sec. 97.41(b) 
or (c) for a unit exempt under Sec. 97.4(b), such heat input shall be 
treated as zero if the unit is exempt under Sec. 97.4(b) during the 
control period.
    (b) For each group of control periods specified in Sec. 97.41(a) 
through (c), the Administrator will allocate to all NOX 
Budget units in a given State under Sec. 97.4(a)(1) that commenced 
operation before May 1, 1997 for allocations under Sec. 97.41(a), May 
1, 2003 for allocations under Sec. 97.41(b), and May 1 of the year 5 
years before the first year for which the allocation under Sec. 
97.41(c) is being calculated, a total number of NOX 
allowances equal to 95 percent of the portion of the State's trading 
program budget under Sec. 97.40 covering such units. The Administrator 
will allocate in accordance with the following procedures:
    (1) The Administrator will allocate NOX allowances to 
each NOX Budget unit under Sec. 97.4(a)(1) for each control 
period in an amount equaling 0.15 lb/mmBtu multiplied by the heat input 
determined under paragraph (a) of this section, divided by 2,000 lb/ton, 
and rounded to the nearest whole number of NOX allowances as 
appropriate.
    (2) If the initial total number of NOX allowances 
allocated to all NOX Budget units under Sec. 97.4(a)(1) in 
the State for a control period under paragraph (b)(1) of this section 
does not equal 95 percent of the portion of the State's trading program 
budget under Sec. 97.40 covering such units, the Administrator will 
adjust the total number of NOX allowances allocated to all 
such NOX Budget units for the control period under paragraph 
(b)(1) of this section so that the total number of NOX 
allowances allocated equals 95 percent of such portion of the State's 
trading program budget. This adjustment will be made by: multiplying 
each unit's allocation by 95 percent of such portion of the State's 
trading program budget; dividing by the total number of NOX 
allowances allocated under paragraph (b)(1) of this section for the 
control period; and rounding to the nearest whole number of 
NOX allowances as appropriate.
    (c) For each group of control periods specified in Sec. 97.41(a) 
through (c), the Administrator will allocate to all NOX 
Budget units in a given State under Sec. 97.4(a)(2) that commenced 
operation before May 1, 1997 for allocations under Sec. 97.41(a), May 
1, 2003 for allocations under Sec. 97.41(b), and May 1 of the year 5 
years before the first year for which the allocation under Sec. 
97.41(c) is being calculated, a total number of NOX 
allowances equal to 95 percent of the portion of the State's trading 
program budget under Sec. 97.40 covering such units. The Administrator 
will allocate in accordance with the following procedures:
    (1) The Administrator will allocate NOX allowances to 
each NOX Budget

[[Page 195]]

unit under Sec. 97.4(a)(2) for each control period in an amount 
equaling 0.17 lb/mmBtu multiplied by the heat input determined under 
paragraph (a) of this section, divided by 2,000 lb/ton, and rounded to 
the nearest whole number of NOX allowances as appropriate.
    (2) If the initial total number of NOX allowances 
allocated to all NOX Budget units under Sec. 97.4(a)(2) in 
the State for a control period under paragraph (c)(1) of this section 
does not equal 95 percent of the portion of the State's trading program 
budget under Sec. 97.40 covering such units, the Administrator will 
adjust the total number of NOX allowances allocated to all 
such NOX Budget units for the control period under paragraph 
(a)(1) of this section so that the total number of NOX 
allowances allocated equals 95 percent of the portion of the State's 
trading program budget under Sec. 97.40 covering such units. This 
adjustment will be made by: multiplying each unit's allocation by 95 
percent of the portion of the State's trading program budget under Sec. 
97.40 covering such units; dividing by the total number of 
NOX allowances allocated under paragraph (c)(1) of this 
section for the control period; and rounding to the nearest whole number 
of NOX allowances as appropriate.
    (d) For each control period specified in Sec. 97.41(d), the 
Administrator will allocate NOX allowances to NOX 
Budget units in a given State under Sec. 97.4(a) (except for units 
exempt under Sec. 97.4(b)) that commence operation, or are projected to 
commence operation, on or after: May 1, 1997 (for control periods under 
Sec. 97.41(a)); May 1, 2003, (for control periods under Sec. 
97.41(b)); and May 1 of the year 5 years before the beginning of the 
group of 5 years that includes the control period (for control periods 
under Sec. 97.41(c)). The Administrator will make the allocations under 
this paragraph (d) in accordance with the following procedures:
    (1) The Administrator will establish one allocation set-aside for 
each control period. Each allocation set-aside will be allocated 
NOX allowances equal to 5 percent of the tons of 
NOX emission in the State's trading program budget under 
Sec. 97.40, rounded to the nearest whole number of NOX 
allowances as appropriate.
    (2) The NOX authorized account representative of a 
NOX Budget unit specified in this paragraph (d) may submit to 
the Administrator a request, in a format specified by the Administrator, 
to be allocated NOX allowances for the control period. The 
NOX allowance allocation request must be received by the 
Administrator on or after the date on which the State permitting 
authority issues a permit to construct the unit and by January 1 before 
the control period for which NOX allowances are requested.
    (3) In a NOX allowance allocation request under paragraph 
(d)(2) of this section, the NOX authorized account 
representative for a NOX Budget unit under Sec. 97.4(a)(1) 
may request for the control period NOX allowances in an 
amount that does not exceed the lesser of:
    (i) 0.15 lb/mmBtu multiplied by the unit's maximum design heat 
input, multiplied by the lesser of 3,672 hours or the number of hours 
remaining in the control period starting with the day in the control 
period on which the unit commences operation or is projected to commence 
operation, divided by 2,000 lb/ton, and rounded to the nearest whole 
number of NOX allowances as appropriate; or
    (ii) The unit's most stringent State or Federal NOX 
emission limitation multiplied by the unit's maximum design heat input, 
multiplied by the lesser of 3,672 hours or the number of hours remaining 
in the control period starting with the day in the control period on 
which the unit commences operation or is projected to commence 
operation, divided by 2,000 lb/ton, and rounded to the nearest whole 
number of NOX allowances as appropriate.
    (4) In a NOX allowance allocation request under paragraph 
(d)(2) of this section, the NOX authorized account 
representative for a NOX Budget unit under Sec. 97.4(a)(2) 
may request for the control period NOX allowances in an 
amount that does not exceed the lesser of:
    (i) 0.17 lb/mmBtu multiplied by the unit's maximum design heat 
input, multiplied by the lesser of 3,672 hours or the number of hours 
remaining in the control period starting with the day in the control 
period on which the

[[Page 196]]

unit commences operation or is projected to commence operation, divided 
by 2,000 lb/ton, and rounded to the nearest whole number of 
NOX allowances as appropriate; or
    (ii) The unit's most stringent State or Federal NOX 
emission limitation multiplied by the unit's maximum design heat input, 
multiplied by the lesser of 3,672 hours or the number of hours remaining 
in the control period starting with the day in the control period on 
which the unit commences operation or is projected to commence 
operation, divided by 2,000 lb/ton, and rounded to the nearest whole 
number of NOX allowances as appropriate.
    (5) The Administrator will review each NOX allowance 
allocation request submitted in accordance with paragraph (d)(2) of this 
section and will allocate NOX allowances pursuant to such 
request as follows:
    (i) Upon receipt of the NOX allowance allocation request, 
the Administrator will make any necessary adjustments to the request to 
ensure that the requirements of paragraphs (d) introductory text, 
(d)(2), (d)(3), and (d)(4) are met.
    (ii) The Administrator will determine the following amounts:
    (A) The sum of the NOX allowances requested (as adjusted 
under paragraph (d)(5)(i) of this section) in all NOX 
allowance allocation requests under paragraph (d)(2) of this section for 
the control period; and
    (B) For units exempt under Sec. 97.4(b) in the State that commenced 
operation, or are projected to commence operation, on or after May 1, 
1997 (for control periods under Sec. 97.41(a)); May 1, 2003, (for 
control periods under Sec. 97.41(b)); and May 1 of the year 5 years 
before beginning of the group of 5 years that includes the control 
period (for control periods under Sec. 97.41(c)), the sum of the 
NOX emission limitations (in tons of NOX) on which 
each unit's exemption under Sec. 97.4(b) is based.
    (iii) If the number of NOX allowances in the allocation 
set-aside for the control period less the amount under paragraph 
(d)(5)(ii)(B) of this section is not less than the amount determined 
under paragraph (d)(5)(ii)(A) of this section, the Administrator will 
allocate the amount of the NOX allowances requested (as 
adjusted under paragraph (d)(5)(i) of this section) to the 
NOX Budget unit for which the allocation request was 
submitted.
    (iv) If the number of NOX allowances in the allocation 
set-aside for the control period less the amount under paragraph 
(d)(5)(ii)(B) of this section is less than the amount determined under 
paragraph (d)(5)(ii)(A) of this section, the Administrator will 
allocate, to the NOX Budget unit for which the allocation 
request was submitted, the amount of NOX allowances requested 
(as adjusted under paragraph (d)(5)(i) of this section) multiplied by 
the number of NOX allowances in the allocation set-aside for 
the control period less the amount determined under paragraph 
(d)(5)(ii)(B) of this section, divided by the amount determined under 
paragraph (d)(5)(ii)(A) of this section, and rounded to the nearest 
whole number of NOX allowances as appropriate.
    (e)(1) For a NOX Budget unit that is allocated 
NOX allowances under paragraph (d) of this section for a 
control period, the Administrator will deduct NOX allowances 
under Sec. 97.54(b), (e), or (f) to account for the actual heat input 
of the unit during the control period. The Administrator will calculate 
the number of NOX allowances to be deducted to account for 
the unit's actual heat input using the following formulas and rounding 
to the nearest whole number of NOX allowance as appropriate, 
provided that the number of NOX allowances to be deducted 
shall be zero if the number calculated is less than zero:

NOX allowances deducted for actual heat input for a unit 
under Sec. 97.4(a)(1) = Unit's NOX allowances allocated for 
control period-(Unit's actual control period heat input x the lesser of 
0.15 lb/mmBtu the unit's most stringent State or Federal emission 
limitation x 2,000 lb/ton); and NOX allowances deducted for 
actual heat input for a unit under Sec. 97.4(a)(2) = Unit's 
NOX allowances allocated for control period-(Unit's actual 
control period heat input x the lesser of 0.17 lb/mmBtu the unit's most 
stringent State or Federal emission limitation x 2,000 lb/ton)


[[Page 197]]


Where:

``Unit's NOX allowances allocated for control period'' is the 
          number of NOX allowances allocated to the unit for 
          the control period under paragraph (d) of this section; and
``Unit's actual control period heat input'' is the heat input (in mmBtu) 
          of the unit during the control period.

    (2) The Administrator will transfer any NOX allowances 
deducted under paragraph (e)(1) of this section to the allocation set-
aside for the control period for which they were allocated.
    (f) After making the deductions for compliance under Sec. 97.54(b), 
(e), or (f) for a control period, the Administrator will determine 
whether any NOX allowances remain in the allocation set-aside 
for the control period. The Administrator will allocate any such 
NOX allowances to the NOX Budget units in the 
State using the following formula and rounding to the nearest whole 
number of NOX allowances as appropriate:

Unit's share of NOX allowances remaining in allocation set-
aside = Total NOX allowances remaining in allocation set-
aside x (Unit's NOX allowance allocation / State's trading 
program budget excluding allocation set-aside)

Where:

``Total NOX allowances remaining in allocation set-aside'' is 
          the total number of NOX allowances remaining in the 
          allocation set-aside for the control period;
``Unit's NOX allowance allocation'' is the number of 
          NOX allowances allocated under paragraph (b) or (c) 
          of this section to the unit for the control period to which 
          the allocation set-aside applies; and
``State's trading program budget excluding allocation set-aside'' is the 
          State's trading program budget under Sec. 97.40 for the 
          control period to which the allocation set-aside applies 
          multiplied by 95 percent, rounded to the nearest whole number 
          of NOX allowances as appropriate.

    (g) If the Administrator determines that NOX allowances 
were allocated under paragraph (b), (c), or (d) of this section for a 
control period and the recipient of the allocation is not actually a 
NOX Budget unit under Sec. 97.4(a), the Administrator will 
notify the NOX authorized account representative and then 
will act in accordance with the following procedures:
    (1)(i) The Administrator will not record such NOX 
allowances for the control period in an account under Sec. 97.53;
    (ii) If the Administrator already recorded such NOX 
allowances for the control period in an account under Sec. 97.53 and if 
the Administrator makes such determination before making all deductions 
pursuant to Sec. 97.54 (except deductions pursuant to Sec. 
97.54(d)(2)) for the control period, then the Administrator will deduct 
from the account NOX allowances equal in number to and 
allocated for the same or a prior control period as the NOX 
allowances allocated to such recipient for the control period. The 
NOX authorized account representative shall ensure that the 
account contains the NOX allowances necessary for completion 
of such deduction. If account does not contain the necessary 
NOX allowances, the Administrator will deduct the required 
number of NOX allowances, regardless of the control period 
for which they were allocated, whenever NOX allowances are 
recorded in the account; or
    (iii) If the Administrator already recorded such NOX 
allowances for the control period in an account under Sec. 97.53 and if 
the Administrator makes such determination after making all deductions 
pursuant to Sec. 97.54 (except deductions pursuant to Sec. 
97.54(d)(2)) for the control period, then the Administrator will apply 
paragraph (g)(1)(ii) of this section to any subsequent control period 
for which NOX allowances were allocated to such recipient.
    (2) The Administrator will transfer the NOX allowances 
that are not recorded, or that are deducted, pursuant to paragraph 
(g)(1) of this section to an allocation set-aside for the State in which 
such source is located.

[65 FR 2727, Jan. 18, 2000, as amended at 67 FR 21529, Apr. 30, 2002; 69 
FR 21646, Apr. 21, 2004]



Sec. 97.43  Compliance Supplement Pool.

    (a) For any NOX Budget unit that reduces its 
NOX emission rate in the 2001 through 2003 control period, 
the owners and operators may request early reduction credits in 
accordance with the following requirements:

[[Page 198]]

    (1) Each NOX Budget unit for which the owners and 
operators intend to request, or request, any early reduction credits in 
accordance with paragraph (a)(4) of this section shall monitor and 
report NOX emissions in accordance with subpart H of this 
part starting in the 2000 control period and for each control period for 
which such early reduction credits are requested. The unit's percent 
monitor data availability shall not be less than 90 percent during the 
2000 control period, and the unit must be in full compliance with any 
applicable State or Federal NOX emission control requirements 
during 2000 through 2002.
    (2) NOX emission rate and heat input under paragraphs 
(a)(3) and (4) of this section shall be determined in accordance with 
subpart H of this part.
    (3) Each NOX Budget unit for which the owners and 
operators intend to request, or request, any early reduction credits 
under paragraph (a)(4) of this section shall reduce its NOX 
emission rate, for each control period for which early reduction credits 
are requested, to less than both 0.25 lb/mmBtu and 80 percent of the 
unit's NOX emission rate in the 2000 control period.
    (4) The NOX authorized account representative of a 
NOX Budget unit that meets the requirements of paragraphs (a) 
(1) and (3) of this section may submit to the Administrator a request 
for early reduction credits for the unit based on NOX 
emission rate reductions made by the unit in the control period for 2001 
through 2003.
    (i) In the early reduction credit request, the NOX 
authorized account may request early reduction credits for such control 
period in an amount equal to the unit's heat input for such control 
period multiplied by the difference between 0.25 lb/mmBtu and the unit's 
NOX emission rate for such control period, divided by 2000 
lb/ton, and rounded to the nearest whole number of tons.
    (ii) The early reduction credit request must be submitted, in a 
format specified by the Administrator, by February 1, 2004.
    (b) For any NOX Budget unit that is subject to the Ozone 
Transport Commission NOX Budget Program under title I of the 
Clean Air Act, the owners and operators may request early reduction 
credits in accordance with the following requirements:
    (1) The NOX authorized account representative of the unit 
may submit to the Administrator a request for early reduction credits in 
an amount equal to the amount of banked allowances under the Ozone 
Transport Commission NOX Budget Program that were allocated 
for the control period in 2001 through 2003 and are held by the unit, in 
accordance with the Ozone Transport Commission NOX Budget 
Program, as of the date of submission of the request. During the entire 
control period in 2001 through 2003 for which the allowances were 
allocated, the unit must have monitored and reported NOX 
emissions in accordance with part 75 (except for subpart H) of this 
chapter and the Guidance for Implementation of Emission Monitoring 
Requirements for the NOX Budget Program (January 28, 1997).
    (2) The early reduction credit request under paragraph (b)(1) must 
be submitted, in a format specified by the Administrator, by February 1, 
2004.
    (3) The NOX authorized account representative of the unit 
shall not submit a request for early reduction credits under paragraph 
(b)(1) of this section for banked allowances under the Ozone Transport 
Commission NOX Budget Program that were allocated for any 
control period during which the unit made NOX emission 
reductions for which he or she submits a request for early reduction 
credits under paragraph (a) of this section for the unit.
    (c) The Administrator will review each early reduction credit 
request submitted in accordance with paragraph (a) or (b) of this 
section and will allocate NOX allowances to NOX 
Budget units in a given State and covered by such request as follows:
    (1) Upon receipt of each early reduction credit request, the 
Administrator will make any necessary adjustments to the request to 
ensure that the amount of the early reduction credits requested meets 
the requirements of paragraph (a) or (b) of this section.
    (2) After February 1, 2004, the Administrator will make available to 
the public a statement of the total number of early reduction credits 
requested by NOX Budget units in the State.

[[Page 199]]

    (3) If the State's compliance supplement pool set forth in appendix 
D of this part has a number of NOX allowances not less than 
the amount of early reduction credits in all early reduction credit 
requests under paragraph (a) or (b) of this section for 2001 through 
2003 (as adjusted under paragraph (c)(1) of this section) submitted by 
February 1, 2004, the Administrator will allocate to each NOX 
Budget unit covered by such requests one allowance for each early 
reduction credit requested (as adjusted under paragraph (c)(1) of this 
section).
    (4) If the State's compliance supplement pool set forth in appendix 
D of this part has a smaller number of NOX allowances than 
the amount of early reduction credits in all early reduction credit 
requests under paragraph (a) or (b) of this section for 2001 through 
2003 (as adjusted under paragraph (c)(1) of this section) submitted by 
February 1, 2004, the Administrator will allocate NOX 
allowances to each NOX Budget unit covered by such requests 
according to the following formula and rounding to the nearest whole 
number of NOX allowances as appropriate:

Unit's allocation for early reduction credits = Unit's adjusted early 
reduction credits x (State's compliance supplement pool / Total adjusted 
early reduction credits for all units)

Where:

``Unit's allocation for early reduction credits'' is the number of 
          NOX allowances allocated to the unit for early 
          reduction credits.
``Unit's adjusted early reduction credits'' is the amount of early 
          reduction credits requested for the unit for 2001 and 2002 in 
          early reduction credit requests under paragraph (a) or (b) of 
          this section, as adjusted under paragraph (c)(1) of this 
          section.
``State's compliance supplement pool'' is the number of NOX 
          allowances in the State's compliance supplement pool set forth 
          in appendix D of this part.
``Total adjusted early reduction credits for all units'' is the amount 
          of early reduction credits requested for all units for 2001 
          and 2002 in early reduction credit requests under paragraph 
          (a) or (b) of this section, as adjusted under paragraph (c)(1) 
          of this section.

    (5) By April 1, 2004, the Administrator will determine by order the 
allocations under paragraph (c)(3) or (4) of this section. The 
Administrator will make available to the public each determination of 
NOX allowance allocations and will provide an opportunity for 
submission of objections to the determination. Objections shall be 
limited to addressing whether the determination is in accordance with 
paragraph (c)(1), (3), or (4) of this section. Based on any such 
objections, the Administrator will adjust each determination to the 
extent necessary to ensure that it is in accordance with paragraph 
(c)(1), (3), or (4) of this section.
    (6) By May 1, 2004, the Administrator will record the allocations 
under paragraph (c)(3) or (4) of this section.
    (7) NOX allowances recorded under paragraph (c)(6) of 
this section may be deducted for compliance under Sec. 97.54 for the 
control period in 2004 or 2005. Notwithstanding Sec. 97.55(a), the 
Administrator will deduct as retired any NOX allowance that 
is recorded under paragraph (c)(6) of this section and that is not 
deducted for compliance under Sec. 97.54 for the control period in 2003 
or 2004.

[65 FR 2727, Jan. 18, 2000, as amended at 67 FR 21529, Apr. 30, 2002; 69 
FR 21646, Apr. 21, 2004]



                 Subpart F_NOX Allowance Tracking System



Sec. 97.50  NOX Allowance Tracking System accounts.

    (a) Nature and function of compliance accounts and overdraft 
accounts. Consistent with Sec. 97.51(a), the Administrator will 
establish one compliance account for each NOX Budget unit and 
one overdraft account for each source with two or more NOX 
Budget units. Allocations of NOX allowances pursuant to 
subpart E of this part or Sec. 97.88, and deductions or transfers of 
NOX allowances pursuant to Sec. 97.31, Sec. 96.54, Sec. 
96.56, subpart G of this part, or subpart I of this part will be 
recorded in compliance accounts or overdraft accounts in accordance with 
this subpart.
    (b) Nature and function of general accounts. Consistent with Sec. 
97.51(b), the Administrator will establish, upon request, a general 
account for any person. Allocations of NOX allowances 
pursuant to Sec. 97.4(b)(4)(ii) or Sec. 97.5(c)(2) and

[[Page 200]]

transfers of allowances pursuant to subpart G of this part will be 
recorded in general accounts in accordance with this subpart.



Sec. 97.51  Establishment of accounts.

    (a) Compliance accounts and overdraft accounts. Upon receipt of a 
complete account certificate of representation under Sec. 97.13, the 
Administrator will establish:
    (1) A compliance account for each NOX Budget unit for 
which the account certificate of representation was submitted; and
    (2) An overdraft account for each source for which the account 
certificate of representation was submitted and that has two or more 
NOX Budget units.
    (b) General accounts--(1) Application for general account. (i) Any 
person may apply to open a general account for the purpose of holding 
and transferring allowances. An application for a general account may 
designate one and only one NOX authorized account 
representative and one and only one alternate NOX authorized 
account representative who may act on behalf of the NOX 
authorized account representative. The agreement by which the alternate 
NOX authorized account representative is selected shall 
include a procedure for authorizing the alternate NOX 
authorized account representative to act in lieu of the NOX 
authorized account representative. A complete application for a general 
account shall be submitted to the Administrator and shall include the 
following elements in a format prescribed by the Administrator:
    (A) Name, mailing address, e-mail address (if any), telephone 
number, and facsimile transmission number (if any) of the NOX 
authorized account representative and any alternate NOX 
authorized account representative;
    (B) At the option of the NOX authorized account 
representative, organization name and type of organization;
    (C) A list of all persons subject to a binding agreement for the 
NOX authorized account representative and any alternate 
NOX authorized account representative to represent their 
ownership interest with respect to the allowances held in the general 
account;
    (D) The following certification statement by the NOX 
authorized account representative and any alternate NOX 
authorized account representative: ``I certify that I was selected as 
the NOX authorized account representative or the 
NOX alternate authorized account representative, as 
applicable, by an agreement that is binding on all persons who have an 
ownership interest with respect to NOX allowances held in the 
general account. I certify that I have all the necessary authority to 
carry out my duties and responsibilities under the NOX Budget 
Trading Program on behalf of such persons and that each such person 
shall be fully bound by my representations, actions, inactions, or 
submissions and by any order or decision issued to me by the 
Administrator or a court regarding the general account.;''
    (E) The signature of the NOX authorized account 
representative and any alternate NOX authorized account 
representative and the dates signed.
    (ii) Unless otherwise required by the permitting authority or the 
Administrator, documents of agreement referred to in the application for 
a general account shall not be submitted to the permitting authority or 
the Administrator. Neither the permitting authority nor the 
Administrator shall be under any obligation to review or evaluate the 
sufficiency of such documents, if submitted.
    (2) Authorization of NOX authorized account 
representative. Upon receipt by the Administrator of a complete 
application for a general account under paragraph (b)(1) of this 
section:
    (i) The Administrator will establish a general account for the 
person or persons for whom the application is submitted.
    (ii) The NOX authorized account representative and any 
alternate NOX authorized account representative for the 
general account shall represent and, by his or her representations, 
actions, inactions, or submissions, legally bind each person who has an 
ownership interest with respect to NOX allowances held in the 
general account in all matters pertaining to the NOX Budget 
Trading Program, not withstanding any agreement between the 
NOX authorized account representative or any

[[Page 201]]

alternate NOX authorized account representative and such 
person. Any such person shall be bound by any order or decision issued 
to the NOX authorized account representative or any alternate 
NOX authorized account representative by the Administrator or 
a court regarding the general account.
    (iii) Any representation, action, inaction, or submission by any 
alternate NOX authorized account representative shall be 
deemed to be a representation, action, inaction, or submission by the 
NOX authorized account representative.
    (iv) Each submission concerning the general account shall be 
submitted, signed, and certified by the NOX authorized 
account representative or any alternate NOX authorized 
account representative for the persons having an ownership interest with 
respect to NOX allowances held in the general account. Each 
such submission shall include the following certification statement by 
the NOX authorized account representative or any alternate 
NOX authorizing account representative: ``I am authorized to 
make this submission on behalf of the persons having an ownership 
interest with respect to the NOX allowances held in the 
general account. I certify under penalty of law that I have personally 
examined, and am familiar with, the statements and information submitted 
in this document and all its attachments. Based on my inquiry of those 
individuals with primary responsibility for obtaining the information, I 
certify that the statements and information are to the best of my 
knowledge and belief true, accurate, and complete. I am aware that there 
are significant penalties for submitting false statements and 
information or omitting required statements and information, including 
the possibility of fine or imprisonment.''
    (v) The Administrator will accept or act on a submission concerning 
the general account only if the submission has been made, signed, and 
certified in accordance with paragraph (b)(2)(iv) of this section.
    (3) Changing NOX authorized account representative and 
alternate NOX authorized account representative; changes in 
persons with ownership interest. (i) The NOX authorized 
account representative for a general account may be changed at any time 
upon receipt by the Administrator of a superseding complete application 
for a general account under paragraph (b)(1) of this section. 
Notwithstanding any such change, all representations, actions, 
inactions, and submissions by the previous NOX authorized 
account representative prior to the time and date when the Administrator 
receives the superseding application for a general account shall be 
binding on the new NOX authorized account representative and 
the persons with an ownership interest with respect to the 
NOX allowances in the general account.
    (ii) The alternate NOX authorized account representative 
for a general account may be changed at any time upon receipt by the 
Administrator of a superseding complete application for a general 
account under paragraph (b)(1) of this section. Notwithstanding any such 
change, all representations, actions, inactions, and submissions by the 
previous alternate NOX authorized account representative 
prior to the time and date when the Administrator receives the 
superseding application for a general account shall be binding on the 
new alternate NOX authorized account representative and the 
persons with an ownership interest with respect to the NOX 
allowances in the general account.
    (iii)(A) In the event a new person having an ownership interest with 
respect to NOX allowances in the general account is not 
included in the list of such persons in the account certificate of 
representation, such new person shall be deemed to be subject to and 
bound by the account certificate of representation, the representation, 
actions, inactions, and submissions of the NOX authorized 
account representative and any alternate NOX authorized 
account representative of the source or unit, and the decisions, orders, 
actions, and inactions of the Administrator, as if the new person were 
included in such list.
    (B) Within 30 days following any change in the persons having an 
ownership interest with respect to NOX allowances in the 
general account, including the addition of persons, the NOX 
authorized account representative

[[Page 202]]

or any alternate NOX authorized account representative shall 
submit a revision to the application for a general account amending the 
list of persons having an ownership interest with respect to the 
NOX allowances in the general account to include the change.
    (4) Objections concerning NOX authorized account 
representative. (i) Once a complete application for a general account 
under paragraph (b)(1) of this section has been submitted and received, 
the Administrator will rely on the application unless and until a 
superseding complete application for a general account under paragraph 
(b)(1) of this section is received by the Administrator.
    (ii) Except as provided in paragraph (b)(3)(i) or (ii) of this 
section, no objection or other communication submitted to the 
Administrator concerning the authorization, or any representation, 
action, inaction, or submission of the NOX authorized account 
representative or any alternative NOX authorized account 
representative for a general account shall affect any representation, 
action, inaction, or submission of the NOX authorized account 
representative or any alternative NOX authorized account 
representative or the finality of any decision or order by the 
Administrator under the NOX Budget Trading Program.
    (iii) The Administrator will not adjudicate any private legal 
dispute concerning the authorization or any representation, action, 
inaction, or submission of the NOX authorized account 
representative or any alternative NOX authorized account 
representative for a general account, including private legal disputes 
concerning the proceeds of NOX allowance transfers.
    (c) Account identification. The Administrator will assign a unique 
identifying number to each account established under paragraph (a) or 
(b) of this section.

[65 FR 2727, Jan. 18, 2000, as amended at 69 FR 21646, Apr. 21, 2004]



Sec. 97.52  NOX Allowance Tracking System responsibilities of NOX 
authorized account representative.

    (a) Following the establishment of a NOX Allowance 
Tracking System account, all submissions to the Administrator pertaining 
to the account, including, but not limited to, submissions concerning 
the deduction or transfer of NOX allowances in the account, 
shall be made only by the NOX authorized account 
representative for the account.
    (b) Authorized account representative identification. The 
Administrator will assign a unique identifying number to each 
NOX authorized account representative.



Sec. 97.53  Recordation of NOX allowance allocations.

    (a) The Administrator will record the NOX allowances for 
2004 for a NOX Budget unit allocated under subpart E of this 
part in the unit's compliance account, except for NOX 
allowances under Sec. 97.4(b)(4)(ii) or Sec. 97.5(c)(2), which will be 
recorded in the general account specified by the owners and operators of 
the unit. The Administrator will record NOX allowances for 
2004 for a NOX Budget opt-in unit in the unit's compliance 
account as allocated under Sec. 97.88(a).
    (b) By May 1, 2003, the Administrator will record the NOX 
allowances for 2005 for a NOX Budget unit allocated under 
subpart E of this part in the unit's compliance account, except for 
NOX allowances under Sec. 97.4(b)(4)(ii) or Sec. 
97.5(c)(2), which will be recorded in the general account specified by 
the owners and operators of the unit. The Administrator will record 
NOX allowances for 2005 for a NOX Budget opt-in 
unit in the unit's compliance account as allocated under Sec. 97.88(a).
    (c) By May 1, 2003, the Administrator will record the NOX 
allowances for 2006 for a NOX Budget unit allocated under 
subpart E of this part in the unit's compliance account, except for 
NOX allowances under Sec. 97.4(b)(4)(ii) or Sec. 
97.5(c)(2), which will be recorded in the general account specified by 
the owners and operators of the unit. The Administrator will record 
NOX allowances for 2006 for a NOX Budget opt-in 
unit in the unit's compliance account as allocated under Sec. 97.88(a).
    (d) By May 1, 2004, the Administrator will record the NOX 
allowances for 2007 for a NOX Budget unit allocated under 
subpart E of this part in the unit's

[[Page 203]]

compliance account, except for NOX allowances under Sec. 
97.4(b)(4)(ii) or Sec. 97.5(c)(2), which will be recorded in the 
general account specified by the owners and operators of the unit. The 
Administrator will record NOX allowances for 2007 for a 
NOX Budget opt-in unit in the unit's compliance account as 
allocated under Sec. 97.88(a).
    (e) Each year starting with 2005, after the Administrator has made 
all deductions from a NOX Budget unit's compliance account 
and the overdraft account pursuant to Sec. 97.54 (except deductions 
pursuant to Sec. 97.54(d)(2)), the Administrator will record:
    (1) NOX allowances, in the compliance account, as 
allocated to the unit under subpart E of this part for the third year 
after the year of the control period for which such deductions were or 
could have been made;
    (2) NOX allowances, in the general account specified by 
the owners and operators of the unit, as allocated under Sec. 
97.4(b)(4)(ii) or Sec. 97.5(c)(2) for the third year after the year of 
the control period for which such deductions are or could have been 
made; and
    (3) NOX allowances, in the compliance account, as 
allocated to the unit under Sec. 97.88(a).
    (f) Serial numbers for allocated NOX allowances. When 
allocating NOX allowances to a NOX Budget unit and 
recording them in an account, the Administrator will assign each 
NOX allowance a unique identification number that will 
include digits identifying the year for which the NOX 
allowance is allocated.

[65 FR 2727, Jan. 18, 2000, as amended at 67 FR 21530, Apr. 30, 2002]



Sec. 97.54  Compliance.

    (a) NOX allowance transfer deadline. The NOX 
allowances are available to be deducted for compliance with a unit's 
NOX Budget emissions limitation for a control period in a 
given year only if the NOX allowances:
    (1) Were allocated for a control period in a prior year or the same 
year; and
    (2) Are held in the unit's compliance account, or the overdraft 
account of the source where the unit is located, as of the 
NOX allowance transfer deadline for that control period or 
are transferred into the compliance account or overdraft account by a 
NOX allowance transfer correctly submitted for recordation 
under Sec. 97.60 by the NOX allowance transfer deadline for 
that control period.
    (b) Deductions for compliance. (1) Following the recordation, in 
accordance with Sec. 97.61, of NOX allowance transfers 
submitted for recordation in the unit's compliance account or the 
overdraft account of the source where the unit is located by the 
NOX allowance transfer deadline for a control period, the 
Administrator will deduct NOX allowances available under 
paragraph (a) of this section to cover the unit's NOX 
emissions (as determined in accordance with subpart H of this part), or 
to account for actual heat input under Sec. 97.42(e), for the control 
period:
    (i) From the compliance account; and
    (ii) Only if no more NOX allowances available under 
paragraph (a) of this section remain in the compliance account, from the 
overdraft account. In deducting allowances for units at the source from 
the overdraft account, the Administrator will begin with the unit having 
the compliance account with the lowest account number and end with the 
unit having the compliance account with the highest account number (with 
account numbers sorted beginning with the left-most character and ending 
with the right-most character and the letter characters assigned values 
in alphabetical order and less than all numeric characters).
    (2) The Administrator will deduct NOX allowances first 
under paragraph (b)(1)(i) of this section and then under paragraph 
(b)(1)(ii) of this section:
    (i) Until the number of NOX allowances deducted for the 
control period equals the number of tons of NOX emissions, 
determined in accordance with subpart H of this part, from the unit for 
the control period for which compliance is being determined, plus the 
number of NOX allowances required for deduction to account 
for actual heat input under Sec. 97.42(e) for the control period; or
    (ii) Until no more NOX allowances available under 
paragraph (a) of this section remain in the respective account.
    (c)(1) Identification of NOX allowances by serial number. The 
NOX authorized

[[Page 204]]

account representative for each compliance account may identify by 
serial number the NOX allowances to be deducted from the 
unit's compliance account under paragraph (b), (d), (e), or (f) of this 
section. Such identification shall be made in the compliance 
certification report submitted in accordance with Sec. 97.30.
    (2) First-in, first-out. The Administrator will deduct 
NOX allowances for a control period from the compliance 
account, in the absence of an identification or in the case of a partial 
identification of NOX allowances by serial number under 
paragraph (c)(1) of this section, or the overdraft account on a first-
in, first-out (FIFO) accounting basis in the following order:
    (i) Those NOX allowances that were allocated for the 
control period to the unit under subpart E or I of this part;
    (ii) Those NOX allowances that were allocated for the 
control period to any unit and transferred and recorded in the account 
pursuant to subpart G of this part, in order of their date of 
recordation;
    (iii) Those NOX allowances that were allocated for a 
prior control period to the unit under subpart E or I of this part; and
    (iv) Those NOX allowances that were allocated for a prior 
control period to any unit and transferred and recorded in the account 
pursuant to subpart G of this part, in order of their date of 
recordation.
    (d) Deductions for excess emissions. (1) After making the deductions 
for compliance under paragraph (b) of this section, the Administrator 
will deduct from the unit's compliance account or the overdraft account 
of the source where the unit is located a number of NOX 
allowances, allocated for a control period after the control period in 
which the unit has excess emissions, equal to three times the number of 
the unit's excess emissions.
    (2) If the compliance account or overdraft account does not contain 
sufficient NOX allowances, the Administrator will deduct the 
required number of NOX allowances, regardless of the control 
period for which they were allocated, whenever NOX allowances 
are recorded in either account.
    (3) Any allowance deduction required under paragraph (d) of this 
section shall not affect the liability of the owners and operators of 
the NOX Budget unit for any fine, penalty, or assessment, or 
their obligation to comply with any other remedy, for the same 
violation, as ordered under the Clean Air Act or applicable State law. 
The following guidelines will be followed in assessing fines, penalties 
or other obligations:
    (i) For purposes of determining the number of days of violation, if 
a NOX Budget unit has excess emissions for a control period, 
each day in the control period (153 days) constitutes a day in violation 
unless the owners and operators of the unit demonstrate that a lesser 
number of days should be considered.
    (ii) Each ton of excess emissions is a separate violation.
    (e) Deductions for units sharing a common stack. In the case of 
units sharing a common stack and having emissions that are not 
separately monitored or apportioned in accordance with subpart H of this 
part:
    (1) The NOX authorized account representative of the 
units may identify the percentage of NOX allowances to be 
deducted from each such unit's compliance account to cover the unit's 
share of NOX emissions from the common stack for a control 
period. Such identification shall be made in the compliance 
certification report submitted in accordance with Sec. 97.30.
    (2) Notwithstanding paragraph (b)(2)(i) of this section, the 
Administrator will deduct NOX allowances for each such unit 
until the number of NOX allowances deducted equals the unit's 
identified percentage under paragraph (e)(1) of this section or, if no 
percentage is identified, an equal percentage for each unit multiplied 
by the number of tons of NOX emissions, as determined in 
accordance with subpart H of this part, from the common stack for the 
control period for which compliance is being determined. In addition to 
the deductions under the first sentence of this paragraph (e)(1), the 
Administrator will deduct NOX allowances for each such unit 
until the number of NOX allowances deducted equals the number 
of NOX allowances required to

[[Page 205]]

account for actual heat input under Sec. 97.42(e) for the unit for the 
control period.
    (f) Deduction of banked allowances. Each year starting in 2006, 
after the Administrator has completed the designation of banked 
NOX allowances under Sec. 97.55(b) and before May 1 of the 
year, the Administrator will determine the extent to which banked 
NOX allowances otherwise available under paragraph (a) of 
this section are available for compliance in the control period for the 
current year, as follows. For each State NOX Budget Trading 
Program that is established, and approved and administered by the 
Administrator pursuant to Sec. 51.121 of this chapter, the terms 
``compliance account'' or ``compliance accounts'', ``overdraft account'' 
or ``overdraft accounts'', ``general account'' or ``general accounts'', 
``States'', and ``trading program budgets under Sec. 97.40'' in 
paragraphs (f)(1) through (f)(3) of this section shall be read to 
include respectively: A compliance account or compliance accounts 
established under such State NOX Budget Trading Program; an 
overdraft account or overdraft accounts established under such State 
NOX Budget Trading Program; a general account or general 
accounts established under such State NOX Budget Trading 
Program; the State or portion of a State covered by such State 
NOX Budget Trading Program; and the trading program budget of 
the State or portion of a State covered by such State NOX 
Budget Trading Program.
    (1) The Administrator will determine the total number of banked 
NOX allowances held in compliance accounts, overdraft 
accounts, or general accounts.
    (2) If the total number of banked NOX allowances 
determined, under paragraph (f)(1) of this section, to be held in 
compliance accounts, overdraft accounts, or general accounts is less 
than or equal to 10 percent of the sum of the trading program budgets 
under Sec. 97.40 for all States for the control period, any banked 
NOX allowance may be deducted for compliance in accordance 
with paragraphs (a) through (e) of this section.
    (3) If the total number of banked NOX allowances 
determined, under paragraph (f)(1) of this section, to be held in 
compliance accounts, overdraft accounts, or general accounts exceeds 10 
percent of the sum of the trading program budgets under Sec. 97.40 for 
all States for the control period, any banked allowance may be deducted 
for compliance in accordance with paragraphs (a) through (e) of this 
section, except as follows:
    (i) The Administrator will determine the following ratio: 0.10 
multiplied by the sum of the trading program budgets under Sec. 97.40 
for all States for the control period and divided by the total number of 
banked NOX allowances determined, under paragraph (f)(1) of 
this section, to be held in compliance accounts, overdraft accounts, or 
general accounts.
    (ii) The Administrator will multiply the number of banked 
NOX allowances in each compliance account or overdraft 
account by the ratio determined under paragraph (f)(3)(i) of this 
section. The resulting product is the number of banked NOX 
allowances in the account that may be deducted for compliance in 
accordance with paragraphs (a) through (e) of this section. Any banked 
NOX allowances in excess of the resulting product may be 
deducted for compliance in accordance with paragraphs (a) through (e) of 
this section, except that, if such NOX allowances are used to 
make a deduction under paragraph (b) or (e) of this section, two (rather 
than one) such NOX allowances shall authorize up to one ton 
of NOX emissions during the control period and must be 
deducted for each deduction of one NOX allowance required 
under paragraph (b) or (e) of this section.
    (g) Recordation of deductions. The Administrator will record in the 
appropriate compliance account or overdraft account all deductions from 
such an account pursuant to paragraph (b), (d), (e), or (f) of this 
section.

[65 FR 2727, Jan. 18, 2000, as amended at 67 FR 21530, Apr. 30, 2002; 69 
FR 21646, Apr. 21, 2004]



Sec. 97.55  Banking.

    NOX allowances may be banked for future use or transfer 
in a compliance account, an overdraft account, or a general account, as 
follows:

[[Page 206]]

    (a) Any NOX allowance that is held in a compliance 
account, an overdraft account, or a general account will remain in such 
account unless and until the NOX allowance is deducted or 
transferred under Sec. 97.31, Sec. 97.54, Sec. 97.56, or subpart G or 
I of this part.
    (b) The Administrator will designate, as a ``banked'' NOX 
allowance, any NOX allowance that remains in a compliance 
account, an overdraft account, or a general account after the 
Administrator has made all deductions for a given control period from 
the compliance account or overdraft account pursuant to Sec. 97.54 
(except deductions pursuant to Sec. 97.54(d)(2)) and that was allocated 
for that control period or a control period in a prior year.



Sec. 97.56  Account error.

    The Administrator may, at his or her sole discretion and on his or 
her own motion, correct any error in any NOX Allowance 
Tracking System account. Within 10 business days of making such 
correction, the Administrator will notify the NOX authorized 
account representative for the account.



Sec. 97.57  Closing of general accounts.

    (a) The NOX authorized account representative of a 
general account may instruct the Administrator to close the account by 
submitting a statement requesting deletion of the account from the 
NOX Allowance Tracking System and by correctly submitting for 
recordation under Sec. 97.60 an allowance transfer of all 
NOX allowances in the account to one or more other 
NOX Allowance Tracking System accounts.
    (b) If a general account shows no activity for a period of a year or 
more and does not contain any NOX allowances, the 
Administrator may notify the NOX authorized account 
representative for the account that the account will be closed and 
deleted from the NOX Allowance Tracking System following 20 
business days after the notice is sent. The account will be closed after 
the 20-day period unless before the end of the 20-day period the 
Administrator receives a correctly submitted transfer of NOX 
allowances into the account under Sec. 97.60 or a statement submitted 
by the NOX authorized account representative demonstrating to 
the satisfaction of the Administrator good cause as to why the account 
should not be closed.



                    Subpart G_NOX Allowance Transfers



Sec. 97.60  Submission of NOX allowance transfers.

    The NOX authorized account representatives seeking 
recordation of a NOX allowance transfer shall submit the 
transfer to the Administrator. To be considered correctly submitted, the 
NOX allowance transfer shall include the following elements 
in a format specified by the Administrator:
    (a) The numbers identifying both the transferor and transferee 
accounts;
    (b) A specification by serial number of each NOX 
allowance to be transferred; and
    (c) The printed name and signature of the NOX authorized 
account representative of the transferor account and the date signed.



Sec. 97.61  EPA recordation.

    (a) Within 5 business days of receiving a NOX allowance 
transfer, except as provided in paragraph (b) of this section, the 
Administrator will record a NOX allowance transfer by moving 
each NOX allowance from the transferor account to the 
transferee account as specified by the request, provided that:
    (1) The transfer is correctly submitted under Sec. 97.60; and
    (2) The transferor account includes each NOX allowance 
identified by serial number in the transfer.
    (b) A NOX allowance transfer that is submitted for 
recordation following the NOX allowance transfer deadline and 
that includes any NOX allowances allocated for a control 
period prior to or the same as the control period to which the 
NOX allowance transfer deadline applies will not be recorded 
until after the Administrator completes the recordation of 
NOX allowance allocations under Sec. 97.53 for the control 
period in the fourth year after the control period to which the 
NOX allowance transfer deadline applies.
    (c) Where a NOX allowance transfer submitted for 
recordation fails to meet the requirements of paragraph (a) of

[[Page 207]]

this section, the Administrator will not record such transfer.

[65 FR 2727, Jan. 18, 2000, as amended at 69 FR 21647, Apr. 21, 2004]



Sec. 97.62  Notification.

    (a) Notification of recordation. Within 5 business days of 
recordation of a NOX allowance transfer under Sec. 97.61, 
the Administrator will notify the NOX authorized account 
representatives of both the transferor and transferee accounts.
    (b) Notification of non-recordation. Within 10 business days of 
receipt of a NOX allowance transfer that fails to meet the 
requirements of Sec. 97.61(a), the Administrator will notify the 
NOX authorized account representatives of both accounts 
subject to the transfer of:
    (1) A decision not to record the transfer; and
    (2) The reasons for such non-recordation.
    (c) Nothing in this section shall preclude the submission of a 
NOX allowance transfer for recordation following notification 
of non-recordation.



                   Subpart H_Monitoring and Reporting



Sec. 97.70  General requirements.

    The owners and operators, and to the extent applicable, the 
NOX authorized account representative of a NOX 
Budget unit, shall comply with the monitoring, recordkeeping, and 
reporting requirements as provided in this subpart and in subpart H of 
part 75 of this chapter. For purposes of complying with such 
requirements, the definitions in Sec. 97.2 and in Sec. 72.2 of this 
chapter shall apply, and the terms ``affected unit,'' ``designated 
representative,'' and ``continuous emission monitoring system'' (or 
``CEMS'') in part 75 of this chapter shall be deemed to refer to the 
terms ``NOX Budget unit,'' ``NOX authorized 
account representative,'' and ``continuous emission monitoring system'' 
(or ``CEMS'') respectively, as defined in Sec. 97.2. The owner or 
operator of a unit that is not a NOX Budget unit but that is 
monitored under Sec. 75.72(b)(2)(ii) of this chapter shall comply with 
the monitoring, recordkeeping, and reporting requirements for a 
NOX Budget unit under this part.
    (a) Requirements for installation, certification, and data 
accounting. The owner or operator of each NOX Budget unit 
shall meet the following requirements. These provisions shall also apply 
to a unit for which an application for a NOX Budget opt-in 
permit is submitted and not denied or withdrawn, as provided in subpart 
I of this part:
    (1) Install all monitoring systems required under this subpart for 
monitoring NOX mass emissions. This includes all systems 
required to monitor NOX emission rate, NOX 
concentration, heat input rate, and stack flow rate, in accordance with 
Sec. Sec. 75.71 and 75.72 of this chapter.
    (2) Install all monitoring systems for monitoring heat input rate.
    (3) Successfully complete all certification tests required under 
Sec. 97.71 and meet all other requirements of this subpart and part 75 
of this chapter applicable to the monitoring systems under paragraphs 
(a)(1) and (2) of this section.
    (4) Record, report, and quality-assure the data from the monitoring 
systems under paragraphs (a)(1) and (2) of this section.
    (b) Compliance deadlines. The owner or operator shall meet the 
certification and other requirements of paragraphs (a)(1) through (a)(3) 
of this section on or before the following dates. The owner or operator 
shall record, report and quality-assure the data from the monitoring 
systems under paragraphs (a)(1) and (a)(2) of this section on and after 
the following dates.
    (1) For the owner or operator of a NOX Budget unit for 
which the owner or operator intends to apply for early reduction credits 
under Sec. 97.43, by May 1, 2001. If the owner or operator of a 
NOX Budget unit fails to meet this deadline, he or she is not 
eligible to apply for early reduction credits and is subject to the 
deadline under paragraph (b)(2) of this section.
    (2) For the owner or operator of a NOX Budget unit under 
Sec. 97.4(a) that commences operation before January 1, 2003 and that 
is not subject to or does not meet the deadline under paragraph (b)(1) 
of this section, by May 1, 2003.

[[Page 208]]

    (3) For the owner or operator of a NOX Budget unit under 
Sec. 97.4(a) that commences operation on or after January 1, 2003 and 
that reports on an annual basis under Sec. 97.74(d) by the following 
dates:
    (i) The earlier of 90 unit operating days after the date on which 
the unit commences commercial operation or 180 calendar days after the 
date on which the unit commences commercial operation; or
    (ii) May 1, 2003, if the compliance date under paragraph (b)(3)(i) 
of this section is before May 1, 2003.
    (4) For the owner or operator of a NOX Budget unit under 
Sec. 97.4(a) that commences operation on or after January 1, 2003 and 
that reports on a control period basis under Sec. 97.74(d)(2)(ii), by 
the following dates:
    (i) The earlier of 90 unit operating days or 180 calendar days after 
the date on which the unit commences commercial operation, if this 
compliance date is during a control period; or
    (ii) May 1 immediately following the compliance date under paragraph 
(b)(4)(i) of this section, if such compliance date is not during a 
control period.
    (5) For the owner or operator of a NOX Budget unit that 
has a new stack or flue or add-on NOX emission controls for 
which construction is completed after the applicable deadline under 
paragraph (b)(1), (b)(2), (b)(3), or (b)(4) of this section or under 
subpart I of this part and that reports on an annual basis under Sec. 
97.74(d), by the earlier of 90 unit operating days or 180 calendar days 
after the date on which emissions first exit to the atmosphere through 
the new stack or flue or add-on NOX emission controls.
    (6) For the owner or operator of a NOX Budget unit that 
has a new stack or flue or add-on NOX emission controls for 
which construction is completed after the applicable deadline under 
paragraph (b)(1), (b)(2), (b)(3), or (b)(4) of this section or under 
subpart I of this part and that reports on a control period basis under 
Sec. 97.74(d)(2)(ii), by the following dates:
    (i) The earlier of 90 unit operating days or 180 calendar days after 
the date on which emissions first exit to the atmosphere through the new 
stack or flue or add-on NOX emission controls, if this 
compliance date is during a control period; or
    (ii) May 1 immediately following the compliance date under paragraph 
(b)(6)(i) of this section, if such compliance date is not during a 
control period.
    (7) For the owner or operator of a unit for which an application for 
a NOX Budget opt-in permit is submitted and not denied or 
withdrawn, by the date specified under subpart I of this part.
    (c) Commencement of data reporting. (1) The owner or operator of 
NOX Budget units under paragraph (b)(1) or (b)(2) of this 
section shall determine, record and report NOX mass 
emissions, heat input rate, and any other values required to determine 
NOX mass emissions (e.g., NOX emission rate and 
heat input rate, or NOX concentration and stack flow rate) in 
accordance with Sec. 75.70(g) of this chapter, beginning on the first 
hour of the applicable compliance deadline in paragraph (b)(1) or (b)(2) 
of this section.
    (2) The owner or operator of a NOX Budget unit under 
paragraph (b)(3) or (b)(4) of this section shall determine, record and 
report NOX mass emissions, heat input rate, and any other 
values required to determine NOX mass emissions (e.g., 
NOX emission rate and heat input rate, or NOX 
concentration and stack flow rate) and electric and thermal output in 
accordance with Sec. 75.70(g) of this chapter, beginning on:
    (i) The date and hour on which the unit commences operation, if the 
date and hour on which the unit commences operation is during a control 
period; or
    (ii) The first hour on May 1 of the first control period after the 
date and hour on which the unit commences operation, if the date and 
hour on which the unit commences operation is not during a control 
period.
    (3) Notwithstanding paragraphs (c)(2)(i) and (c)(2)(ii) of this 
section, the owner or operator may begin reporting NOX mass 
emission data and heat input data before the date and hour under 
paragraph (c)(2)(i) or (c)(2)(ii) of this section if the unit reports on 
an annual basis and if the required monitoring systems are certified 
before the applicable date and hour under paragraph (c)(1) or (c)(2) of 
this section.

[[Page 209]]

    (d) Prohibitions. (1) No owner or operator of a NOX 
Budget unit shall use any alternative monitoring system, alternative 
reference method, or any other alternative for the required continuous 
emission monitoring system without having obtained prior written 
approval in accordance with Sec. 97.75.
    (2) No owner or operator of a NOX Budget unit shall 
operate the unit so as to discharge, or allow to be discharged, 
NOX emissions to the atmosphere without accounting for all 
such emissions in accordance with the applicable provisions of this 
subpart and part 75 of this chapter, except as provided in Sec. 75.74 
of this chapter.
    (3) No owner or operator of a NOX Budget unit shall 
disrupt the continuous emission monitoring system, any portion thereof, 
or any other approved emission monitoring method, and thereby avoid 
monitoring and recording NOX mass emissions discharged into 
the atmosphere, except for periods of recertification or periods when 
calibration, quality assurance testing, or maintenance is performed in 
accordance with the applicable provisions of this subpart and part 75 of 
this chapter or except as provided in Sec. 75.74 of this chapter.
    (4) No owner or operator of a NOX Budget unit shall 
retire or permanently discontinue use of the continuous emission 
monitoring system, any component thereof, or any other approved emission 
monitoring system under this subpart, except under any one of the 
following circumstances:
    (i) During the period that the unit is covered by an exemption under 
Sec. 97.4(b) or Sec. 97.5 that is in effect;
    (ii) The owner or operator is monitoring emissions from the unit 
with another certified monitoring system approved, in accordance with 
the applicable provisions of this subpart and part 75 of this chapter, 
by the permitting authority for use at that unit that provides emission 
data for the same pollutant or parameter as the retired or discontinued 
monitoring system; or
    (iii) The NOX authorized account representative submits 
notification of the date of certification testing of a replacement 
monitoring system for the retired or discontinued monitoring system in 
accordance with Sec. 97.71(b)(2).

[65 FR 2727, Jan. 18, 2000, as amended at 67 FR 21530, Apr. 30, 2002; 69 
FR 21647, Apr. 21, 2004]



Sec. 97.71  Initial certification and recertification procedures.

    (a) The owner or operator of a NOX Budget unit that is 
subject to an Acid Rain emissions limitation shall comply with the 
initial certification and recertification procedures of part 75 of this 
chapter for NOX-diluent CEMS, flow monitors, NOX 
concentration CEMS, or excepted monitoring systems under appendix E of 
part 75 of this chapter for NOX. under appendix D for heat 
input, or under Sec. 75.19 for NOX and heat input, except 
that:
    (1) If, prior to January 1, 1998, the Administrator approved a 
petition under Sec. 75.17(a) or (b) of this chapter for apportioning 
the NOX emission rate measured in a common stack or a 
petition under Sec. 75.66 of this chapter for an alternative to a 
requirement in Sec. 75.17 of this chapter, the NOX 
authorized account representative shall resubmit the petition to the 
Administrator under Sec. 97.75(a) to determine if the approval applies 
under the NOX Budget Trading Program.
    (2) For any additional CEMS required under the common stack 
provisions in Sec. 75.72 of this chapter or for any NOX 
concentration CEMS used under the provisions of Sec. 75.71(a)(2) of 
this chapter, the owner or operator shall meet the requirements of 
paragraph (b) of this section.
    (b) The owner or operator of a NOX Budget unit that is 
not subject to an Acid Rain emissions limitation shall comply with the 
following initial certification and recertification procedures. The 
owner or operator of such a unit that qualifies to use the low mass 
emissions excepted monitoring methodology under Sec. 75.19 of this 
chapter or that qualifies to use an alternative monitoring system under 
subpart E of part 75 of this chapter shall comply with the following 
procedures, as modified by paragraph (c) or (d) of this section. The 
owner or operator of a NOX Budget unit that is subject to an 
Acid

[[Page 210]]

Rain emissions limitation and that requires additional CEMS under the 
common stack provisions in Sec. 75.72 of this chapter or uses a 
NOX concentration CEMS under Sec. 75.71(a)(2) of this 
chapter shall comply with the following procedures.
    (1) Requirements for initial certification. The owner or operator 
shall ensure that each emission monitoring system required by subpart H 
of part 75 of this chapter (which includes the automated data 
acquisition and handling system) successfully completes all of the 
initial certification testing required under Sec. 75.20 of this chapter 
by the applicable deadline in Sec. 97.70(b). In addition, whenever the 
owner or operator installs an emission monitoring system in order to 
meet the requirements of this part in a location where no such emission 
monitoring system was previously installed, initial certification in 
accordance with Sec. 75.20 of this chapter is required.
    (2) Requirements for recertification. Whenever the owner or operator 
makes a replacement, modification, or change in a certified emission 
monitoring system that may significantly affect the ability of the 
system to accurately measure or record NOX mass emissions or 
heat input rate or to meet the requirements of Sec. 75.21 of this 
chapter or appendix B to part 75 of this chapter, the owner or operator 
shall recertify the emission monitoring system in accordance with Sec. 
75.20(b) of this chapter. Furthermore, whenever the owner or operator 
makes a replacement, modification, or change to the flue gas handling 
system or the unit's operation that may significantly change the stack 
flow or concentration profile, the owner or operator shall recertify the 
continuous emissions monitoring system in accordance with Sec. 75.20(b) 
of this chapter. Examples of changes that require recertification 
include: replacement of the analyzer, complete replacement of an 
existing continuous emission monitoring system, or change in location or 
orientation of the sampling probe or site.
    (3) Certification approval process for initial certification and 
recertification--(i) Notification of certification. The NOX 
authorized account representative shall submit to the Administrator, the 
appropriate EPA Regional Office and the permitting authority written 
notice of the dates of certification in accordance with Sec. 97.73.
    (ii) Certification application. The NOX authorized 
account representative shall submit to the Administrator, the 
appropriate EPA Regional Office and the permitting authority a 
certification application for each emission monitoring system required 
under subpart H of part 75 of this chapter. A complete certification 
application shall include the information specified in subpart H of part 
75 of this chapter.
    (iii) Except for units using the low mass emission excepted 
methodology under Sec. 75.19 of this chapter, the provisional 
certification date for a monitor shall be determined in accordance with 
Sec. 75.20(a)(3) of this chapter. A provisionally certified monitor may 
be used under the NOX Budget Trading Program for a period not 
to exceed 120 days after receipt by the Administrator of the complete 
certification application for the monitoring system under paragraph 
(b)(3)(ii) of this section. Data measured and recorded by the 
provisionally certified monitoring system, in accordance with the 
requirements of part 75 of this chapter, will be considered valid 
quality-assured data (retroactive to the date and time of provisional 
certification), provided that the Administrator does not invalidate the 
provisional certification by issuing a notice of disapproval within 120 
days of receipt of the complete certification application by the 
Administrator.
    (iv) Certification application formal approval process. The 
Administrator will issue a written notice of approval or disapproval of 
the certification application to the owner or operator within 120 days 
of receipt of the complete certification application under paragraph 
(b)(3)(ii) of this section. In the event the Administrator does not 
issue such a notice within such 120-day period, each monitoring system 
that meets the applicable performance requirements of part 75 of this 
chapter and is included in the certification application will be deemed 
certified for use under the NOX Budget Trading Program.
    (A) Approval notice. If the certification application is complete 
and shows that each monitoring system

[[Page 211]]

meets the applicable performance requirements of part 75 of this 
chapter, then the Administrator will issue a written notice of approval 
of the certification application within 120 days of receipt.
    (B) Incomplete application notice. A certification application will 
be considered complete when all of the applicable information required 
to be submitted under paragraph (b)(3)(ii) of this section has been 
received by the Administrator. If the certification application is not 
complete, then the Administrator will issue a written notice of 
incompleteness that sets a reasonable date by which the NOX 
authorized account representative must submit the additional information 
required to complete the certification application. If the 
NOX authorized account representative does not comply with 
the notice of incompleteness by the specified date, then the 
Administrator may issue a notice of disapproval under paragraph 
(b)(3)(iv)(C) of this section. The 120-day review period shall not begin 
prior to receipt of a complete certification application.
    (C) Disapproval notice. If the certification application shows that 
any monitoring system or component thereof does not meet the performance 
requirements of this part, or if the certification application is 
incomplete and the requirement for disapproval under paragraph 
(b)(3)(iv)(B) of this section has been met, then the Administrator will 
issue a written notice of disapproval of the certification application. 
Upon issuance of such notice of disapproval, the provisional 
certification is invalidated by the Administrator and the data measured 
and recorded by each uncertified monitoring system shall not be 
considered valid quality-assured data beginning with the date and hour 
of provisional certification (as defined under Sec. 75.20(a)(3) of this 
chapter). The owner or operator shall follow the procedures for loss of 
certification in paragraph (b)(3)(v) of this section for each monitoring 
system that is disapproved for initial certification.
    (D) Audit decertification. The Administrator may issue a notice of 
disapproval of the certification status of a monitor in accordance with 
Sec. 97.72(b).
    (v) Procedures for loss of certification. If the Administrator 
issues a notice of disapproval of a certification application under 
paragraph (b)(3)(iv)(C) of this section or a notice of disapproval of 
certification status under paragraph (b)(3)(iv)(D) of this section, 
then:
    (A) The owner or operator shall substitute the following values, for 
each hour of unit operation during the period of invalid data specified 
under Sec. 75.20(a)(4)(iii), Sec. 75.20(b)(5), Sec. 75.20(h)(4), or 
Sec. 75.21(e) and continuing until the date and hour specified under 
Sec. 75.20(a)(5)(i) of this chapter:
    (1) For units that the owner or operator intends to monitor or 
monitors for NOX emission rate and heat input rate or intends 
to determine or determines NOX mass emissions using the low 
mass emission excepted methodology under Sec. 75.19 of this chapter, 
the maximum potential NOX emission rate and the maximum 
potential hourly heat input of the unit; and
    (2) For units that the owner or operator intends to monitor or 
monitors for NOX mass emissions using a NOX 
pollutant concentration monitor and a flow monitor, the maximum 
potential concentration of NOX and the maximum potential flow 
rate of the unit under section 2 of appendix A of part 75 of this 
chapter.
    (B) The NOX authorized account representative shall 
submit a notification of certification retest dates and a new 
certification application in accordance with paragraphs (b)(3)(i) and 
(ii) of this section.
    (C) The owner or operator shall repeat all certification tests or 
other requirements that were failed by the monitoring system, as 
indicated in the Administrator's notice of disapproval, no later than 30 
unit operating days after the date of issuance of the notice of 
disapproval.
    (c) Initial certification and recertification procedures for low 
mass emission units using the excepted methodologies under Sec. 75.19 
of this chapter. The owner or operator of a gas-fired or oil-fired unit 
using the low mass emissions excepted methodology under Sec. 75.19 of 
this chapter and not subject to an Acid Rain emissions limitation shall 
meet the applicable general operating requirements of Sec. 75.10 of 
this chapter and

[[Page 212]]

the applicable requirements of Sec. 75.19 of this chapter. The owner or 
operator of such a unit shall also meet the applicable certification and 
recertification procedures of paragraph (b) of this section, except that 
the excepted methodology shall be deemed provisionally certified for use 
under the NOX Budget Trading Program as of the date on which 
a complete certification application is received by the Administrator. 
The methodology shall be considered to be certified either upon receipt 
of a written notice of approval from the Administrator or, if such 
notice is not provided, at the end of the Administrator's 120 day review 
period. However, a provisionally certified or certified low mass 
emissions excepted methodology shall not be used to report data under 
the NOX Budget Trading Program prior to the applicable 
commencement date specified in Sec. 75.19(a)(1)(ii) of this chapter.
    (d) Certification/recertification procedures for alternative 
monitoring systems. The NOX authorized account representative 
of each unit not subject to an Acid Rain emissions limitation for which 
the owner or operator intends to use an alternative monitoring system 
approved by the Administrator under subpart E of part 75 of this chapter 
shall comply with the applicable certification procedures of paragraph 
(b) of this section before using the system under the NOX 
Budget Trading Program. The NOX authorized account 
representative shall also comply with the applicable recertification 
procedures of paragraph (b) of this section. Section 75.20(f) of this 
chapter shall apply to such alternative monitoring system.

[65 FR 2727, Jan. 18, 2000, as amended at 69 FR 21647, Apr. 21, 2004]



Sec. 97.72  Out of control periods.

    (a) Whenever any emission monitoring system fails to meet the 
quality assurance or data validation requirements of part 75 of this 
chapter, data shall be substituted using the applicable procedures in 
subpart D, subpart H, appendix D, or appendix E of part 75 of this 
chapter.
    (b) Audit decertification. Whenever both an audit of an emission 
monitoring system and a review of the initial certification or 
recertification application reveal that any system should not have been 
certified or recertified because it did not meet a particular 
performance specification or other requirement under Sec. 97.71 or the 
applicable provisions of part 75 of this chapter, both at the time of 
the initial certification or recertification application submission and 
at the time of the audit, the Administrator will issue a notice of 
disapproval of the certification status of such system. For the purposes 
of this paragraph, an audit shall be either a field audit or an audit of 
any information submitted to the permitting authority or the 
Administrator. By issuing the notice of disapproval, the Administrator 
revokes prospectively the certification status of the system. The data 
measured and recorded by the system shall not be considered valid 
quality-assured data from the date of issuance of the notification of 
the revoked certification status until the date and time that the owner 
or operator completes subsequently approved initial certification or 
recertification tests for the system. The owner or operator shall follow 
the initial certification or recertification procedures in Sec. 97.71 
for each disapproved system.

[65 FR 2727, Jan. 18, 2000, as amended at 69 FR 21648, Apr. 21, 2004]



Sec. 97.73  Notifications.

    (a) The NOX authorized account representative for a 
NOX Budget unit shall submit written notice to the 
Administrator, the appropriate EPA Regional Office, and the permitting 
authority in accordance with Sec. 75.61 of this chapter.
    (b) For any unit that does not have an Acid Rain emissions 
limitation, the permitting authority may waive the requirement to notify 
the permitting authority in paragraph (a) of this section.



Sec. 97.74  Recordkeeping and reporting.

    (a) General provisions. (1) The NOX authorized account 
representative shall comply with all recordkeeping and reporting 
requirements in this section, with the recordkeeping and reporting 
requirements under Sec. 75.73 of this chapter, and with the 
requirements of Sec. 97.10(e)(1).

[[Page 213]]

    (2) If the NOX authorized account representative for a 
NOX Budget unit subject to an Acid Rain emission limitation 
who signed and certified any submission that is made under subpart F or 
G of part 75 of this chapter and that includes data and information 
required under this subpart or subpart H of part 75 of this chapter is 
not the same person as the designated representative or the alternative 
designated representative for the unit under part 72 of this chapter, 
then the submission must also be signed by the designated representative 
or the alternative designated representative.
    (b) Monitoring plans. (1) The owner or operator of a unit subject to 
an Acid Rain emissions limitation shall comply with requirements of 
Sec. 75.62 of this chapter, except that the monitoring plan shall also 
include all of the information required by subpart H of part 75 of this 
chapter.
    (2) The owner or operator of a unit that is not subject to an Acid 
Rain emissions limitation shall comply with requirements of Sec. 75.62 
of this chapter, except that the monitoring plan is only required to 
include the information required by subpart H of part 75 of this 
chapter.
    (c) Certification applications. The NOX authorized 
account representative shall submit an application to the Administrator, 
the appropriate EPA Regional Office, and the permitting authority within 
45 days after completing all initial certification or recertification 
tests required under Sec. 97.71 including the information required 
under subpart H of part 75 of this chapter.
    (d) Quarterly reports. The NOX authorized account 
representative shall submit quarterly reports, as follows:
    (1) If a unit is subject to an Acid Rain emission limitation or if 
the owner or operator of the NOX budget unit chooses to meet 
the annual reporting requirements of this subpart H, the NOX 
authorized account representative shall submit a quarterly report for 
each calendar quarter beginning with:
    (i) For a unit for which the owner or operator intends to apply or 
applies for the early reduction credits under Sec. 97.43, the calendar 
quarter that covers May 1, 2000 through June 30, 2000. The 
NOX mass emission data shall be recorded and reported from 
the first hour on May 1, 2000; or
    (ii) For a unit that commences operation before January 1, 2003 and 
that is not subject to paragraph (d)(1)(i) of this section, the calendar 
quarter covering May 1, 2003 through June 30, 2003. The NOX 
mass emission data shall be recorded and reported from the first hour on 
May 1, 2003; or
    (iii) For a unit that commences operation on or after January 1, 
2003:
    (A) The calendar quarter in which the unit commences operation, if 
unit operation commences during a control period. The NOX 
mass emission data shall be recorded and reported from the date and hour 
when the unit commences operation; or
    (B) The calendar quarter which includes May 1 through June 30 of the 
first control period following the date on which the unit commences 
operation, if the unit does not commence operation during a control 
period. The NOX mass emission data shall be recorded and 
reported from the first hour on May 1 of that control period; or
    (iv) A calendar quarter before the quarter specified in paragraph 
(d)(1)(i), (d)(1)(ii), or (d)(1)(iii)(B) of this section, if the owner 
or operator elects to begin reporting early under Sec. 97.70(c)(3).
    (2) If a NOX budget unit is not subject to an Acid Rain 
emission limitation, then the NOX authorized account 
representative shall either:
    (i) Meet all of the requirements of part 75 related to monitoring 
and reporting NOX mass emissions during the entire year and 
meet the deadlines specified in paragraph (d)(1) of this section; or
    (ii) Submit quarterly reports, documenting NOX mass 
emissions from the unit, only for the period from May 1 through 
September 30 of each year and including the data described in Sec. 
75.74(c)(6) of this chapter. The NOX authorized account 
representative shall submit such quarterly reports, beginning with:
    (A) For a unit for which the owner or operator intends to apply or 
applies for the early reduction credits under Sec. 97.43, the calendar 
quarter that covers May 1, 2000 through June 30, 2000. The

[[Page 214]]

NOX mass emission data shall be recorded and reported from 
the first hour on May 1, 2000; or
    (B) For a unit that commences operation before January 1, 2003 and 
that is not subject to paragraph (d)(2)(ii)(A) of this section, the 
calendar quarter covering May 1, 2003 through June 30, 2003. The 
NOX mass emission data shall be recorded and reported from 
the first hour on May 1, 2003; or
    (C) For a unit that commences operation on or after January 1, 2003 
and during a control period, the calendar quarter in which the unit 
commences operation. The NOX mass emission data shall be 
recorded and reported from the date and hour when the unit commences 
operation; or
    (D) For a unit that commences operation on or after January 1, 2003 
and not during a control period, the calendar quarter which includes May 
1 through June 30 of the first control period following the date on 
which the unit commences operation. The NOX mass emission 
data shall be recorded and reported from the first hour on May 1 of that 
control period.
    (3) The NOX authorized account representative shall 
submit each quarterly report to the Administrator within 30 days 
following the end of the calendar quarter covered by the report. 
Quarterly reports shall be submitted in the manner specified in subpart 
H of part 75 of this chapter and Sec. 75.64 of this chapter.
    (i) For units subject to an Acid Rain emissions limitation, 
quarterly reports shall include all of the data and information required 
in subpart H of part 75 of this chapter for each NOX Budget 
unit (or group of units using a common stack) and the data and 
information required in subpart G of part 75 of this chapter.
    (ii) For units not subject to an Acid Rain emissions limitation, 
quarterly reports are only required to include all of the data and 
information required in subpart H of part 75 of this chapter for each 
NOX Budget unit (or group of units using a common stack).
    (4) Compliance certification. The NOX authorized account 
representative shall submit to the Administrator a compliance 
certification in support of each quarterly report based on reasonable 
inquiry of those persons with primary responsibility for ensuring that 
all of the unit's emissions are correctly and fully monitored. The 
certification shall state that:
    (i) The monitoring data submitted were recorded in accordance with 
the applicable requirements of this subpart and part 75 of this chapter, 
including the quality assurance procedures and specifications;
    (ii) For a unit with add-on NOX emission controls and for 
all hours where data are substituted in accordance with Sec. 
75.34(a)(1) of this chapter, the add-on emission controls were operating 
within the range of parameters listed in the quality assurance/quality 
control program under appendix B of part 75 of this chapter and the 
substitute values do not systematically underestimate NOX 
emissions; and
    (iii) For a unit that is reporting on a control period basis under 
paragraph (d)(2)(ii) of this section, the NOX emission rate 
and NOX concentration values substituted for missing data 
under subpart D of part 75 of this chapter are calculated using only 
values from a control period and do not systematically underestimate 
NOX emissions.

[65 FR 2727, Jan. 18, 2000, as amended at 67 FR 21530, Apr. 30, 2002; 69 
FR 21648, Apr. 21, 2004]



Sec. 97.75  Petitions.

    (a) The NOX authorized account representative of a 
NOX Budget unit may submit a petition under Sec. 75.66 of 
this chapter to the Administrator requesting approval to apply an 
alternative to any requirement of this subpart.
    (b) Application of an alternative to any requirement of this subpart 
is in accordance with this subpart only to the extent that the petition 
is approved by the Administrator under Sec. 75.66 of this chapter.



Sec. 97.76  Additional requirements to provide heat input data.

    The owner or operator of a NOX Budget unit that monitors 
and reports NOX mass emissions using a NOX 
concentration system and a flow system shall also monitor and report 
heat input rate at the unit level using the procedures set forth in part 
75 of this chapter.

[[Page 215]]



                    Subpart I_Individual Unit Opt-ins



Sec. 97.80  Applicability.

    A unit that is in a State (as defined in Sec. 97.2), is not a 
NOX Budget unit under Sec. 97.4(a), is not a unit exempt 
under Sec. 97.4(b), vents all of its emissions to a stack, and is 
operating, may qualify to be a NOX Budget opt-in unit under 
this subpart. A unit that is a NOX Budget unit under Sec. 
97.4(a), is covered by an exemption under Sec. 97.4(b) or Sec. 97.5 
that is in effect, or is not operating is not eligible to be a 
NOX Budget opt-in unit.



Sec. 97.81  General.

    Except otherwise as provided in this part, a NOX Budget 
opt-in unit shall be treated as a NOX Budget unit for 
purposes of applying subparts A through H of this part.



Sec. 97.82  NOX authorized account representative.

    A unit for which an application for a NOX Budget opt-in 
permit is submitted, or a NOX Budget opt-in unit, located at 
the same source as one or more NOX Budget units, shall have 
the same NOX authorized account representative as such 
NOX Budget units.



Sec. 97.83  Applying for NOX Budget opt-in permit.

    (a) Applying for initial NOX Budget opt-in permit. In 
order to apply for an initial NOX Budget opt-in permit, the 
NOX authorized account representative of a unit qualified 
under Sec. 97.80 may submit to the Administrator and the permitting 
authority at any time, except as provided under Sec. 97.86(g):
    (1) A complete NOX Budget permit application under Sec. 
97.22;
    (2) A monitoring plan submitted in accordance with subpart H of this 
part; and
    (3) A complete account certificate of representation under Sec. 
97.13, if no NOX authorized account representative has been 
previously designated for the unit.
    (b) Duty to reapply. Unless the NOX Budget opt-in permit 
is terminated or revised under Sec. 97.86(e) or Sec. 97.87(b)(1)(i), 
the NOX authorized account representative of a NOX 
Budget opt-in unit shall submit to the Administrator and permitting 
authority a complete NOX Budget permit application under 
Sec. 97.22 to renew the NOX Budget opt-in permit in 
accordance with Sec. 97.21(c) and, if applicable, an updated monitoring 
plan in accordance with subpart H of this part.



Sec. 97.84  Opt-in process.

    The permitting authority will issue or deny an initial 
NOX Budget opt-in permit for a unit for which an application 
for a NOX Budget opt-in permit under Sec. 97.83 is 
submitted, in accordance with Sec. 97.20 and the following:
    (a) Interim review of monitoring plan. The Administrator will 
determine, on an interim basis, the sufficiency of the monitoring plan 
accompanying the initial application for a NOX Budget opt-in 
permit under Sec. 97.83. A monitoring plan is sufficient, for purposes 
of interim review, if the plan appears to contain information 
demonstrating that the NOX emissions rate and heat input rate 
of the unit are monitored and reported in accordance with subpart H of 
this part. A determination of sufficiency shall not be construed as 
acceptance or approval of the unit's monitoring plan.
    (b) If the Administrator determines that the unit's monitoring plan 
is sufficient under paragraph (a) of this section and after completion 
of monitoring system certification under subpart H of this part, the 
NOX emissions rate and the heat input of the unit shall be 
monitored and reported in accordance with subpart H of this part for one 
full control period during which percent monitor data availability is 
not less than 90 percent and during which the unit is in full compliance 
with any applicable State or Federal emissions or emissions-related 
requirements. Solely for purposes of applying the requirements in the 
prior sentence, the unit shall be treated as a ``NOX Budget 
unit'' prior to issuance of a NOX Budget opt-in permit 
covering the unit.
    (c) Based on the information monitored and reported under paragraph 
(b) of this section, the Administrator will calculate the unit's 
baseline heat input, which will equal the unit's total heat input (in 
mmBtu) for the control period, and the unit's baseline NOX 
emissions rate, which will equal the unit's total NOX mass 
emissions (in lb)

[[Page 216]]

for the control period divided by the unit's baseline heat input.
    (d) Issuance of draft NOX Budget opt-in permit for public 
comment. The permitting authority will issue a draft NOX 
Budget opt-in permit for public comment in accordance with Sec. 97.20.
    (e) Not withstanding paragraphs (a) through (d) of this section, if 
at any time before issuance of a draft NOX Budget opt-in 
permit for public comment for the unit, the Administrator or the 
permitting authority determines that the unit does not qualify as a 
NOX Budget opt-in unit under Sec. 97.80, the permitting 
authority will issue a draft denial of a NOX Budget opt-in 
permit for public comment for the unit in accordance with Sec. 97.20.
    (f) Withdrawal of application for NOX Budget opt-in 
permit. A NOX authorized account representative of a unit may 
withdraw its application for an initial NOX Budget opt-in 
permit under Sec. 97.83 at any time prior to the issuance of the 
initial NOX Budget opt-in permit. Once the application for a 
NOX Budget opt-in permit is withdrawn, a NOX 
authorized account representative wanting to reapply must submit a new 
application for an initial NOX Budget permit under Sec. 
97.83.
    (g) The unit shall be a NOX Budget opt-in unit and a 
NOX Budget unit starting May 1 of the first control period 
starting after the issuance of the initial NOX Budget opt-in 
permit by the permitting authority.



Sec. 97.85  NOX Budget opt-in permit contents.

    (a) Each NOX Budget opt-in permit will contain all 
elements required for a complete NOX Budget opt-in permit 
application under Sec. 97.22.
    (b) Each NOX Budget opt-in permit is deemed to 
incorporate automatically the definitions of terms under Sec. 97.2 and, 
upon recordation by the Administrator under subpart F or G of this part, 
every allocation, transfer, or deduction of NOX allowances to 
or from the compliance accounts of each NOX Budget opt-in 
unit covered by the NOX Budget opt-in permit or the overdraft 
account of the NOX Budget source where the NOX 
Budget opt-in unit is located.



Sec. 97.86  Withdrawal from NOX Budget Trading Program.

    (a) Requesting withdrawal. To withdraw from the NOX 
Budget Trading Program, the NOX authorized account 
representative of a NOX Budget opt-in unit shall submit to 
the Administrator and the permitting authority a request to withdraw 
effective as of a specified date prior to May 1 or after September 30. 
The submission shall be made no later than 90 days prior to the 
requested effective date of withdrawal.
    (b) Conditions for withdrawal. Before a NOX Budget opt-in 
unit covered by a request under paragraph (a) of this section may 
withdraw from the NOX Budget Trading Program and the 
NOX Budget opt-in permit may be terminated under paragraph 
(e) of this section, the following conditions must be met:
    (1) For the control period immediately before the withdrawal is to 
be effective, the NOX authorized account representative must 
submit or must have submitted to the Administrator and the permitting 
authority an annual compliance certification report in accordance with 
Sec. 97.30.
    (2) If the NOX Budget opt-in unit has excess emissions 
for the control period immediately before the withdrawal is to be 
effective, the Administrator will deduct or has deducted from the 
NOX Budget opt-in unit's compliance account, or the overdraft 
account of the NOX Budget source where the NOX 
Budget opt-in unit is located, the full amount required under Sec. 
97.54(d) for the control period.
    (3) After the requirements for withdrawal under paragraphs (b)(1) 
and (2) of this section are met, the Administrator will deduct from the 
NOX Budget opt-in unit's compliance account, or the overdraft 
account of the NOX Budget source where the NOX 
Budget opt-in unit is located, NOX allowances equal in number 
to and allocated for the same or a prior control period as any 
NOX allowances allocated to that source under Sec. 97.88 for 
any control period for which the withdrawal is to be effective. The 
Administrator will close the NOX Budget opt-in unit's 
compliance account and transfer any remaining allowances to a general 
account specified by the owners and operators of the NOX 
Budget opt-in unit.

[[Page 217]]

    (c) A NOX Budget opt-in unit that withdraws from the 
NOX Budget Trading Program shall comply with all requirements 
under the NOX Budget Trading Program concerning all years for 
which such NOX Budget opt-in unit was a NOX Budget 
opt-in unit, even if such requirements arise or must be complied with 
after the withdrawal takes effect.
    (d) Notification. (1) After the requirements for withdrawal under 
paragraphs (a) and (b) of this section are met (including deduction of 
the full amount of NOX allowances required), the 
Administrator will issue a notification to the permitting authority and 
the NOX authorized account representative of the 
NOX Budget opt-in unit of the acceptance of the withdrawal of 
the NOX Budget opt-in unit as of a specified effective date 
that is after such requirements have been met and that is prior to May 1 
or after September 30.
    (2) If the requirements for withdrawal under paragraphs (a) and (b) 
of this section are not met, the Administrator will issue a notification 
to the permitting authority and the NOX authorized account 
representative of the NOX Budget opt-in unit that the request 
to withdraw is denied. If the NOX Budget opt-in unit's 
request to withdraw is denied, the NOX Budget opt-in unit 
shall remain subject to the requirements for a NOX Budget 
opt-in unit.
    (e) Permit revision. After the Administrator issues a notification 
under paragraph (d)(1) of this section that the requirements for 
withdrawal have been met, the permitting authority will revise the 
NOX Budget permit covering the NOX Budget opt-in 
unit to terminate the NOX Budget opt-in permit as of the 
effective date specified under paragraph (d)(1) of this section. A 
NOX Budget opt-in unit shall continue to be a NOX 
Budget opt-in unit until the effective date of the termination.
    (f) Reapplication upon failure to meet conditions of withdrawal. If 
the Administrator denies the request to withdraw the NOX 
Budget opt-in unit, the NOX authorized account representative 
may submit another request to withdraw in accordance with paragraphs (a) 
and (b) of this section.
    (g) Ability to return to the NOX Budget Trading Program. Once a 
NOX Budget opt-in unit withdraws from the NOX 
Budget Trading Program and its NOX Budget opt-in permit is 
terminated under paragraph (e) of this section, the NOX 
authorized account representative may not submit another application for 
a NOX Budget opt-in permit under Sec. 97.83 for the unit 
prior to the date that is 4 years after the date on which the terminated 
NOX Budget opt-in permit became effective.



Sec. 97.87  Change in regulatory status.

    (a) Notification. When a NOX Budget opt-in unit becomes a 
NOX Budget unit under Sec. 97.4(a), the NOX 
authorized account representative shall notify in writing the permitting 
authority and the Administrator of such change in the NOX 
Budget opt-in unit's regulatory status, within 30 days of such change.
    (b) Permitting authority's and Administrator's action. (1)(i) When 
the NOX Budget opt-in unit becomes a NOX Budget 
unit under Sec. 97.4(a), the permitting authority will revise the 
NOX Budget opt-in unit's NOX Budget opt-in permit 
to meet the requirements of a NOX Budget permit under Sec. 
97.23 as of an effective date that is the date on which such 
NOX Budget opt-in unit becomes a NOX Budget unit 
under Sec. 97.4(a).
    (ii)(A) The Administrator will deduct from the compliance account 
for the NOX Budget unit under paragraph (b)(1)(i) of this 
section, or the overdraft account of the NOX Budget source 
where the unit is located, NOX allowances equal in number to 
and allocated for the same or a prior control period as:
    (1) Any NOX allowances allocated to the NOX 
Budget unit (as a NOX Budget opt-in unit) under Sec. 97.88 
for any control period after the last control period during which the 
unit's NOX Budget opt-in permit was effective; and
    (2) If the effective date of the NOX Budget permit 
revision under paragraph (b)(1)(i) of this section is during a control 
period, the NOX allowances allocated to the NOX 
Budget unit (as a NOX Budget opt-in unit) under Sec. 97.88 
for the control period multiplied by the number of days in the control 
period

[[Page 218]]

starting with the effective date of the permit revision under paragraph 
(b)(1)(i) of this section, divided by the total number of days in the 
control period, and rounded to the nearest whole number of 
NOX allowances as appropriate.
    (B) The NOX authorized account representative shall 
ensure that the compliance account of the NOX Budget unit 
under paragraph (b)(1)(i) of this section, or the overdraft account of 
the NOX Budget source where the unit is located, contains the 
NOX allowances necessary for completion of the deduction 
under paragraph (b)(1)(ii)(A) of this section. If the compliance account 
or overdraft account does not contain the necessary NOX 
allowances, the Administrator will deduct the required number of 
NOX allowances, regardless of the control period for which 
they were allocated, whenever NOX allowances are recorded in 
either account.
    (iii)(A) For every control period during which the NOX 
Budget permit revised under paragraph (b)(1)(i) of this section is in 
effect, the NOX Budget unit under paragraph (b)(1)(i) of this 
section will be treated, solely for purposes of NOX allowance 
allocations under Sec. 97.42, as a unit that commenced operation on the 
effective date of the NOX Budget permit revision under 
paragraph (b)(1)(i) of this section and will be allocated NOX 
allowances under Sec. 97.42. The unit's deadline under Sec. 97.84(b) 
for meeting monitoring requirements in accordance with subpart H of this 
part shall not be changed by the change in the unit's regulatory status 
or by the revision of the NOX Budget permit under paragraph 
(b)(1)(i) of this section.
    (B) Notwithstanding paragraph (b)(1)(iii)(A) of this section, if the 
effective date of the NOX Budget permit revision under 
paragraph (b)(1)(i) of this section is during a control period, the 
following number of NOX allowances will be allocated to the 
NOX Budget unit under paragraph (b)(1)(i) of this section 
under Sec. 97.42 for the control period: the number of NOX 
allowances otherwise allocated to the NOX Budget unit under 
Sec. 97.42 for the control period multiplied by the number of days in 
the control period starting with the effective date of the permit 
revision under paragraph (b)(1)(i) of this section, divided by the total 
number of days in the control period, and rounded to the nearest whole 
number of NOX allowances as appropriate.
    (2)(i) When the NOX authorized account representative of 
a NOX Budget opt-in unit does not renew its NOX 
Budget opt-in permit under Sec. 97.83(b), the Administrator will deduct 
from the NOX Budget opt-in unit's compliance account, or the 
overdraft account of the NOX Budget source where the 
NOX Budget opt-in unit is located, NOX allowances 
equal in number to and allocated for the same or a prior control period 
as any NOX allowances allocated to the NOX Budget 
opt-in unit under Sec. 97.88 for any control period after the last 
control period for which the NOX Budget opt-in permit is 
effective. The NOX authorized account representative shall 
ensure that the NOX Budget opt-in unit's compliance account 
or the overdraft account of the NOX Budget source where the 
NOX Budget opt-in unit is located contains the NOX 
allowances necessary for completion of such deduction. If the compliance 
account or overdraft account does not contain the necessary 
NOX allowances, the Administrator will deduct the required 
number of NOX allowances, regardless of the control period 
for which they were allocated, whenever NOX allowances are 
recorded in either account.
    (ii) After the deduction under paragraph (b)(2)(i) of this section 
is completed, the Administrator will close the NOX Budget 
opt-in unit's compliance account. If any NOX allowances 
remain in the compliance account after completion of such deduction and 
any deduction under Sec. 97.54, the Administrator will close the 
NOX Budget opt-in unit's compliance account and transfer any 
remaining allowances to a general account specified by the owners and 
operators of the NOX Budget opt-in unit.

[65 FR 2727, Jan. 18, 2000, as amended at 69 FR 21648, Apr. 21, 2004]



Sec. 97.88  NOX allowance allocations to opt-in units.

    (a) NOX allotment allocation. (1) By April 1 immediately before the 
first control period for which the NOX Budget opt-in permit 
is effective, the Administrator will determine by order

[[Page 219]]

the NOX allowance allocations for the NOX Budget 
opt-in unit for the control period in accordance with paragraph (b) of 
this section.
    (2) By no later than April 1, after the first control period for 
which the NOX Budget opt-in permit is in effect, and April 1 
of each year thereafter, the Administrator will determine by order the 
NOX allowance allocations for the NOX Budget opt-
in unit for the next control period, in accordance with paragraph (b) of 
this section.
    (3) The Administrator will make available to the public each 
determination of NOX allowance allocations under paragraph 
(a)(1) or (2) of this section and will provide an opportunity for 
submission of objections to the determination. Objections shall be 
limited to addressing whether the determination is in accordance with 
paragraph (b) of this section. Based on any such objections, the 
Administrator will adjust each determination to the extent necessary to 
ensure that it is in accordance with paragraph (b) of this section.
    (b) For each control period for which the NOX Budget opt-
in unit has an approved NOX Budget opt-in permit, the 
NOX Budget opt-in unit will be allocated NOX 
allowances in accordance with the following procedures:
    (1) The heat input (in mmBtu) used for calculating NOX 
allowance allocations will be the lesser of:
    (i) The unit's baseline heat input determined pursuant to Sec. 
97.84(c); or
    (ii) The unit's heat input, as determined in accordance with subpart 
H of this part, for the control period in the year prior to the year of 
the control period for which the NOX allocations are being 
calculated.
    (2) The Administrator will allocate NOX allowances to the 
unit in an amount equaling the heat input determined under paragraph 
(b)(1) of this section multiplied by the lesser of the unit's baseline 
NOX emissions rate determined under Sec. 97.84(c) or the 
most stringent State or federal NOX emissions limitation 
applicable to the unit during the control period, divided by 2,000 lb/
ton, and rounded to the nearest whole number of NOX 
allowances as appropriate.



                       Subpart J_Appeal Procedures



Sec. 97.90  Appeal procedures.

    The appeal procedures for the NOX Budget Trading Program 
are set forth in part 78 of this chapter.

[69 FR 21648, Apr. 21, 2004]



      Subpart AA_CAIR NOX Annual Trading Program General Provisions



Sec. 97.101  Purpose.

    This subpart and subparts BB through II set forth the general 
provisions and the designated representative, permitting, allowance, 
monitoring, and opt-in provisions for the Federal Clean Air Interstate 
Rule (CAIR) NOX Annual Trading Program, under section 110 of 
the Clean Air Act and Sec. 52.35 of this chapter, as a means of 
mitigating interstate transport of fine particulates and nitrogen 
oxides.



Sec. 97.102  Definitions.

    The terms used in this subpart and subparts BB through II shall have 
the meanings set forth in this section as follows:
    Account number means the identification number given by the 
Administrator to each CAIR NOX Allowance Tracking System 
account.
    Acid Rain emissions limitation means a limitation on emissions of 
sulfur dioxide or nitrogen oxides under the Acid Rain Program.
    Acid Rain Program means a multi-state sulfur dioxide and nitrogen 
oxides air pollution control and emission reduction program established 
by the Administrator under title IV of the CAA and parts 72 through 78 
of this chapter.
    Actual weighted average NOX emission rate means, for a 
NOX averaging plan under Sec. 76.11 of this chapter and for 
a year:
    (1) The sum of the products of the actual annual average 
NOX emission rate and actual annual heat input (as determined 
in accordance with part 75 of this chapter) for all units in the 
NOX averaging plan for the year; divided by
    (2) The sum of the actual annual heat input (as determined in 
accordance with part 75 of this chapter) for all

[[Page 220]]

units in the NOX averaging plan for the year.
    Administrator means the Administrator of the United States 
Environmental Protection Agency or the Administrator's duly authorized 
representative.
    Allocate or allocation means, with regard to CAIR NOX 
allowances, the determination by a permitting authority or the 
Administrator of the amount of such CAIR NOX allowances to be 
initially credited to a CAIR NOX unit, a new unit set-aside, 
or other entity.
    Allowance transfer deadline means, for a control period, midnight of 
March 1 (if it is a business day), or midnight of the first business day 
thereafter (if March 1 is not a business day), immediately following the 
control period and is the deadline by which a CAIR NOX 
allowance transfer must be submitted for recordation in a CAIR 
NOX source's compliance account in order to be used to meet 
the source's CAIR NOX emissions limitation for such control 
period in accordance with Sec. 97.154.
    Alternate CAIR designated representative means, for a CAIR 
NOX source and each CAIR NOX unit at the source, 
the natural person who is authorized by the owners and operators of the 
source and all such units at the source, in accordance with subparts BB 
and II of this part, to act on behalf of the CAIR designated 
representative in matters pertaining to the CAIR NOX Annual 
Trading Program. If the CAIR NOX source is also a CAIR 
SO2 source, then this natural person shall be the same person 
as the alternate CAIR designated representative under the CAIR 
SO2 Trading Program. If the CAIR NOX source is 
also a CAIR NOX Ozone Season source, then this natural person 
shall be the same person as the alternate CAIR designated representative 
under the CAIR NOX Ozone Season Trading Program. If the CAIR 
NOX source is also subject to the Acid Rain Program, then 
this natural person shall be the same person as the alternate designated 
representative under the Acid Rain Program. If the CAIR NOX 
source is also subject to the Hg Budget Trading Program, then this 
natural person shall be the same person as the alternate Hg designated 
representative under the Hg Budget Trading Program.
    Automated data acquisition and handling system or DAHS means that 
component of the continuous emission monitoring system, or other 
emissions monitoring system approved for use under subpart HH of this 
part, designed to interpret and convert individual output signals from 
pollutant concentration monitors, flow monitors, diluent gas monitors, 
and other component parts of the monitoring system to produce a 
continuous record of the measured parameters in the measurement units 
required by subpart HH of this part.
    Biomass means--
    (1) Any organic material grown for the purpose of being converted to 
energy;
    (2) Any organic byproduct of agriculture that can be converted into 
energy; or
    (3) Any material that can be converted into energy and is 
nonmerchantable for other purposes, that is segregated from other 
nonmerchantable material, and that is;
    (i) A forest-related organic resource, including mill residues, 
precommercial thinnings, slash, brush, or byproduct from conversion of 
trees to merchantable material; or
    (ii) A wood material, including pallets, crates, dunnage, 
manufacturing and construction materials (other than pressure-treated, 
chemically-treated, or painted wood products), and landscape or right-
of-way tree trimmings.
    Boiler means an enclosed fossil- or other-fuel-fired combustion 
device used to produce heat and to transfer heat to recirculating water, 
steam, or other medium.
    Bottoming-cycle cogeneration unit means a cogeneration unit in which 
the energy input to the unit is first used to produce useful thermal 
energy and at least some of the reject heat from the useful thermal 
energy application or process is then used for electricity production.
    CAIR authorized account representative means, with regard to a 
general account, a responsible natural person who is authorized, in 
accordance with subparts BB, FF, and II of this part, to transfer and 
otherwise dispose of CAIR

[[Page 221]]

NOX allowances held in the general account and, with regard 
to a compliance account, the CAIR designated representative of the 
source.
    CAIR designated representative means, for a CAIR NOX 
source and each CAIR NOX unit at the source, the natural 
person who is authorized by the owners and operators of the source and 
all such units at the source, in accordance with subparts BB and II of 
this part, to represent and legally bind each owner and operator in 
matters pertaining to the CAIR NOX Annual Trading Program. If 
the CAIR NOX source is also a CAIR SO2 source, 
then this natural person shall be the same person as the CAIR designated 
representative under the CAIR SO2 Trading Program. If the 
CAIR NOX source is also a CAIR NOX Ozone Season 
source, then this natural person shall be the same person as the CAIR 
designated representative under the CAIR NOX Ozone Season 
Trading Program. If the CAIR NOX source is also subject to 
the Acid Rain Program, then this natural person shall be the same person 
as the designated representative under the Acid Rain Program. If the 
CAIR NOX source is also subject to the Hg Budget Trading 
Program, then this natural person shall be the same person as the Hg 
designated representative under the Hg Budget Trading Program.
    CAIR NOX allowance means a limited authorization issued by a 
permitting authority or the Administrator under subpart EE of this part 
or Sec. 97.188, or under provisions of a State implementation plan that 
are approved under Sec. 51.123(o)(1) or (2) or (p) of this chapter, to 
emit one ton of nitrogen oxides during a control period of the specified 
calendar year for which the authorization is allocated or of any 
calendar year thereafter under the CAIR NOX Program. An 
authorization to emit nitrogen oxides that is not issued under subpart 
EE of this part, Sec. 97.188, or provisions of a State implementation 
plan that are approved under Sec. 51.123(o)(1) or (2) or (p) of this 
chapter shall not be a CAIR NOX allowance.
    CAIR NOX allowance deduction or deduct CAIR NOX allowances means the 
permanent withdrawal of CAIR NOX allowances by the 
Administrator from a compliance account, e.g., in order to account for a 
specified number of tons of total nitrogen oxides emissions from all 
CAIR NOX units at a CAIR NOX source for a control 
period, determined in accordance with subpart HH of this part, or to 
account for excess emissions.
    CAIR NOX Allowance Tracking System means the system by which the 
Administrator records allocations, deductions, and transfers of CAIR 
NOX allowances under the CAIR NOX Annual Trading 
Program. Such allowances will be allocated, held, deducted, or 
transferred only as whole allowances.
    CAIR NOX Allowance Tracking System account means an account in the 
CAIR NOX Allowance Tracking System established by the 
Administrator for purposes of recording the allocation, holding, 
transferring, or deducting of CAIR NOX allowances.
    CAIR NOX allowances held or hold CAIR NOX allowances means the CAIR 
NOX allowances recorded by the Administrator, or submitted to 
the Administrator for recordation, in accordance with subparts FF, GG, 
and II of this part, in a CAIR NOX Allowance Tracking System 
account.
    CAIR NOX Annual Trading Program means a multi-state nitrogen oxides 
air pollution control and emission reduction program established by the 
Administrator in accordance with subparts AA through II of this part and 
Sec. Sec. 51.123(p) and 52.35 of this chapter or approved and 
administered by the Administrator in accordance with subparts AA through 
II of part 96 of this chapter and Sec. 51.123(o)(1) or (2) of this 
chapter, as a means of mitigating interstate transport of fine 
particulates and nitrogen oxides.
    CAIR NOX emissions limitation means, for a CAIR NOX 
source, the tonnage equivalent, in NOX emissions in a control 
period, of the CAIR NOX allowances available for deduction 
for the source under Sec. 97.154 (a) and (b) for the control period.
    CAIR NOX Ozone Season source means a source that is subject to the 
CAIR NOX Ozone Season Trading Program.
    CAIR NOX Ozone Season Trading Program means a multi-state nitrogen 
oxides air pollution control and emission reduction program established 
by the

[[Page 222]]

Administrator in accordance with subparts AAAA through IIII of this part 
and Sec. Sec. 51.123(ee) and 52.35 of this chapter or approved and 
administered by the Administrator in accordance with subparts AAAA 
through IIII of part 96 and Sec. 51.123(aa)(1) or (2) (and (bb)(1)), 
(bb)(2), or (dd) of this chapter, as a means of mitigating interstate 
transport of ozone and nitrogen oxides.
    CAIR NOX source means a source that includes one or more CAIR 
NOX units.
    CAIR NOX unit means a unit that is subject to the CAIR 
NOX Annual Trading Program under Sec. 97.104 and, except for 
purposes of Sec. 97.105 and subpart EE of this part, a CAIR 
NOX opt-in unit under subpart II of this part.
    CAIR permit means the legally binding and federally enforceable 
written document, or portion of such document, issued by the permitting 
authority under subpart CC of this part, including any permit revisions, 
specifying the CAIR NOX Annual Trading Program requirements 
applicable to a CAIR NOX source, to each CAIR NOX 
unit at the source, and to the owners and operators and the CAIR 
designated representative of the source and each such unit.
    CAIR SO2 source means a source that is subject to the CAIR 
SO2 Trading Program.
    CAIR SO2 Trading Program means a multi-state sulfur dioxide air 
pollution control and emission reduction program established by the 
Administrator in accordance with subparts AAA through III of this part 
and Sec. Sec. 51.124(r) and 52.36 of this chapter or approved and 
administered by the Administrator in accordance with subparts AAA 
through III of part 96 of this chapter and Sec. 51.124(o)(1) or (2) of 
this chapter, as a means of mitigating interstate transport of fine 
particulates and sulfur dioxide.
    Certifying official means:
    (1) For a corporation, a president, secretary, treasurer, or vice-
president or the corporation in charge of a principal business function 
or any other person who performs similar policy or decision-making 
functions for the corporation;
    (2) For a partnership or sole proprietorship, a general partner or 
the proprietor respectively; or
    (3) For a local government entity or State, Federal, or other public 
agency, a principal executive officer or ranking elected official.
    Clean Air Act or CAA means the Clean Air Act, 42 U.S.C. 7401, et 
seq.
    Coal means any solid fuel classified as anthracite, bituminous, 
subbituminous, or lignite.
    Coal-derived fuel means any fuel (whether in a solid, liquid, or 
gaseous state) produced by the mechanical, thermal, or chemical 
processing of coal.
    Coal-fired means:
    (1) Except for purposes of subpart EE of this part, combusting any 
amount of coal or coal-derived fuel, alone or in combination with any 
amount of any other fuel, during any year; or
    (2) For purposes of subpart EE of this part, combusting any amount 
of coal or coal-derived fuel, alone or in combination with any amount of 
any other fuel, during a specified year.
    Cogeneration unit means a stationary, fossil-fuel-fired boiler or 
stationary, fossil-fuel-fired combustion turbine:
    (1) Having equipment used to produce electricity and useful thermal 
energy for industrial, commercial, heating, or cooling purposes through 
the sequential use of energy; and
    (2) Producing during the 12-month period starting on the date the 
unit first produces electricity and during any calendar year after the 
calendar year in which the unit first produces electricity--
    (i) For a topping-cycle cogeneration unit, (A) Useful thermal energy 
not less than 5 percent of total energy output; and
    (B) Useful power that, when added to one-half of useful thermal 
energy produced, is not less then 42.5 percent of total energy input, if 
useful thermal energy produced is 15 percent or more of total energy 
output, or not less than 45 percent of total energy input, if useful 
thermal energy produced is less than 15 percent of total energy output.
    (ii) For a bottoming-cycle cogeneration unit, useful power not less 
than 45 percent of total energy input;
    (3) Provided that the total energy input under paragraphs (2)(i)(B) 
and (2)(ii) of this definition shall equal the

[[Page 223]]

unit's total energy input from all fuel except biomass if the unit is a 
boiler.
    Combustion turbine means:
    (1) An enclosed device comprising a compressor, a combustor, and a 
turbine and in which the flue gas resulting from the combustion of fuel 
in the combustor passes through the turbine, rotating the turbine; and
    (2) If the enclosed device under paragraph (1) of this definition is 
combined cycle, any associated duct burner, heat recovery steam 
generator, and steam turbine.
    Commence commercial operation means, with regard to a unit:
    (1) To have begun to produce steam, gas, or other heated medium used 
to generate electricity for sale or use, including test generation, 
except as provided in Sec. 97.105 and Sec. 97.184(h).
    (i) For a unit that is a CAIR NOX unit under Sec. 97.104 
on the later of November 15, 1990 or the date the unit commences 
commercial operation as defined in paragraph (1) of this definition and 
that subsequently undergoes a physical change (other than replacement of 
the unit by a unit at the same source), such date shall remain the date 
of commencement of commercial operation of the unit, which shall 
continue to be treated as the same unit.
    (ii) For a unit that is a CAIR NOX unit under Sec. 
97.104 on the later of November 15, 1990 or the date the unit commences 
commercial operation as defined in paragraph (1) of this definition and 
that is subsequently replaced by a unit at the same source (e.g., 
repowered), such date shall remain the replaced unit's date of 
commencement of commercial operation, and the replacement unit shall be 
treated as a separate unit with a separate date for commencement of 
commercial operation as defined in paragraph (1) or (2) of this 
definition as appropriate.
    (2) Notwithstanding paragraph (1) of this definition and except as 
provided in Sec. 97.105, for a unit that is not a CAIR NOX 
unit under Sec. 97.104 on the later of November 15, 1990 or the date 
the unit commences commercial operation as defined in paragraph (1) of 
this definition, the unit's date for commencement of commercial 
operation shall be the date on which the unit becomes a CAIR 
NOX unit under Sec. 97.104.
    (i) For a unit with a date for commencement of commercial operation 
as defined in paragraph (2) of this definition and that subsequently 
undergoes a physical change (other than replacement of the unit by a 
unit at the same source), such date shall remain the date of 
commencement of commercial operation of the unit, which shall continue 
to be treated as the same unit.
    (ii) For a unit with a date for commencement of commercial operation 
as defined in paragraph (2) of this definition and that is subsequently 
replaced by a unit at the same source (e.g., repowered), such date shall 
remain the replaced unit's date of commencement of commercial operation, 
and the replacement unit shall be treated as a separate unit with a 
separate date for commencement of commercial operation as defined in 
paragraph (1) or (2) of this definition as appropriate.
    Commence operation means:
    (1) To have begun any mechanical, chemical, or electronic process, 
including, with regard to a unit, start-up of a unit's combustion 
chamber, except as provided in Sec. 97.184(h).
    (2) For a unit that undergoes a physical change (other than 
replacement of the unit by a unit at the same source) after the date the 
unit commences operation as defined in paragraph (1) of this definition, 
such date shall remain the date of commencement of operation of the 
unit, which shall continue to be treated as the same unit.
    (3) For a unit that is replaced by a unit at the same source (e.g., 
repowered) after the date the unit commences operation as defined in 
paragraph (1) of this definition, such date shall remain the replaced 
unit's date of commencement of operation, and the replacement unit shall 
be treated as a separate unit with a separate date for commencement of 
operation as defined in paragraph (1), (2), or (3) of this definition as 
appropriate, except as provided in Sec. 97.184(h).
    Common stack means a single flue through which emissions from 2 or 
more units are exhausted.
    Compliance account means a CAIR NOX Allowance Tracking 
System account, established by the Administrator for a CAIR 
NOX source under subpart FF or II of this part, in which

[[Page 224]]

any CAIR NOX allowance allocations for the CAIR 
NOX units at the source are initially recorded and in which 
are held any CAIR NOX allowances available for use for a 
control period in order to meet the source's CAIR NOX 
emissions limitation in accordance with Sec. 97.154.
    Continuous emission monitoring system or CEMS means the equipment 
required under subpart HH of this part to sample, analyze, measure, and 
provide, by means of readings recorded at least once every 15 minutes 
(using an automated data acquisition and handling system (DAHS)), a 
permanent record of nitrogen oxides emissions, stack gas volumetric flow 
rate, stack gas moisture content, and oxygen or carbon dioxide 
concentration (as applicable), in a manner consistent with part 75 of 
this chapter. The following systems are the principal types of 
continuous emission monitoring systems required under subpart HH of this 
part:
    (1) A flow monitoring system, consisting of a stack flow rate 
monitor and an automated data acquisition and handling system and 
providing a permanent, continuous record of stack gas volumetric flow 
rate, in standard cubic feet per hour (scfh);
    (2) A nitrogen oxides concentration monitoring system, consisting of 
a NOX pollutant concentration monitor and an automated data 
acquisition and handling system and providing a permanent, continuous 
record of NOX emissions, in parts per million (ppm);
    (3) A nitrogen oxides emission rate (or NOX-diluent) 
monitoring system, consisting of a NOX pollutant 
concentration monitor, a diluent gas (CO2 or O2) 
monitor, and an automated data acquisition and handling system and 
providing a permanent, continuous record of NOX 
concentration, in parts per million (ppm), diluent gas concentration, in 
percent CO2 or O2, and NOX emission 
rate, in pounds per million British thermal units (lb/mmBtu);
    (4) A moisture monitoring system, as defined in Sec. 75.11(b)(2) of 
this chapter and providing a permanent, continuous record of the stack 
gas moisture content, in percent H2O;
    (5) A carbon dioxide monitoring system, consisting of a 
CO2 pollutant concentration monitor (or an oxygen monitor 
plus suitable mathematical equations from which the CO2 
concentration is derived) and an automated data acquisition and handling 
system and providing a permanent, continuous record of CO2 
emissions, in percent CO2; and
    (6) An oxygen monitoring system, consisting of an O2 
concentration monitor and an automated data acquisition and handling 
system and providing a permanent, continuous record of O2, in 
percent O2.
    Control period means the period beginning January 1 of a calendar 
year, except as provided in Sec. 97.106(c)(2), and ending on December 
31 of the same year, inclusive.
    Emissions means air pollutants exhausted from a unit or source into 
the atmosphere, as measured, recorded, and reported to the Administrator 
by the CAIR designated representative and as determined by the 
Administrator in accordance with subpart HH of this part.
    Excess emissions means any ton of nitrogen oxides emitted by the 
CAIR NOX units at a CAIR NOX source during a 
control period that exceeds the CAIR NOX emissions limitation 
for the source.
    Fossil fuel means natural gas, petroleum, coal, or any form of 
solid, liquid, or gaseous fuel derived from such material.
    Fossil-fuel-fired means, with regard to a unit, combusting any 
amount of fossil fuel in any calendar year.
    Fuel oil means any petroleum-based fuel (including diesel fuel or 
petroleum derivatives such as oil tar) and any recycled or blended 
petroleum products or petroleum by-products used as a fuel whether in a 
liquid, solid, or gaseous state.
    General account means a CAIR NOX Allowance Tracking 
System account, established under subpart FF of this part, that is not a 
compliance account.
    Generator means a device that produces electricity.
    Gross electrical output means, with regard to a cogeneration unit, 
electricity made available for use, including any such electricity used 
in the power production process (which process includes, but is not 
limited to, any on-site processing or treatment of fuel

[[Page 225]]

combusted at the unit and any on-site emission controls).
    Heat input means, with regard to a specified period of time, the 
product (in mmBtu/time) of the gross calorific value of the fuel (in 
Btu/lb) divided by 1,000,000 Btu/mmBtu and multiplied by the fuel feed 
rate into a combustion device (in lb of fuel/time), as measured, 
recorded, and reported to the Administrator by the CAIR designated 
representative and determined by the Administrator in accordance with 
subpart HH of this part and excluding the heat derived from preheated 
combustion air, recirculated flue gases, or exhaust from other sources.
    Heat input rate means the amount of heat input (in mmBtu) divided by 
unit operating time (in hr) or, with regard to a specific fuel, the 
amount of heat input attributed to the fuel (in mmBtu) divided by the 
unit operating time (in hr) during which the unit combusts the fuel.
    Hg Budget Trading Program means a multi-state Hg air pollution 
control and emission reduction program approved and administered by the 
Administrator in accordance subpart HHHH of part 60 of this chapter and 
Sec. 60.24(h)(6), or established by the Administrator under section 111 
of the Clean Air Act, as a means of reducing national Hg emissions.
    Life-of-the-unit, firm power contractual arrangement means a unit 
participation power sales agreement under which a utility or industrial 
customer reserves, or is entitled to receive, a specified amount or 
percentage of nameplate capacity and associated energy generated by any 
specified unit and pays its proportional amount of such unit's total 
costs, pursuant to a contract:
    (1) For the life of the unit;
    (2) For a cumulative term of no less than 30 years, including 
contracts that permit an election for early termination; or
    (3) For a period no less than 25 years or 70 percent of the economic 
useful life of the unit determined as of the time the unit is built, 
with option rights to purchase or release some portion of the nameplate 
capacity and associated energy generated by the unit at the end of the 
period.
    Maximum design heat input means the maximum amount of fuel per hour 
(in Btu/hr) that a unit is capable of combusting on a steady state basis 
as of the initial installation of the unit as specified by the 
manufacturer of the unit.
    Monitoring system means any monitoring system that meets the 
requirements of subpart HH of this part, including a continuous 
emissions monitoring system, an alternative monitoring system, or an 
excepted monitoring system under part 75 of this chapter.
    Most stringent State or Federal NOX emissions limitation 
means, with regard to a unit, the lowest NOX emissions 
limitation (in terms of lb/mmBtu) that is applicable to the unit under 
State or Federal law, regardless of the averaging period to which the 
emissions limitation applies.
    Nameplate capacity means, starting from the initial installation of 
a generator, the maximum electrical generating output (in MWe) that the 
generator is capable of producing on a steady state basis and during 
continuous operation (when not restricted by seasonal or other 
deratings) as of such installation as specified by the manufacturer of 
the generator or, starting from the completion of any subsequent 
physical change in the generator resulting in an increase in the maximum 
electrical generating output (in MWe) that the generator is capable of 
producing on a steady state basis and during continuous operation (when 
not restricted by seasonal or other deratings), such increased maximum 
amount as of such completion as specified by the person conducting the 
physical change.
    Oil-fired means, for purposes of subpart EE of this part, combusting 
fuel oil for more than 15.0 percent of the annual heat input in a 
specified year and not qualifying as coal-fired.
    Operator means any person who operates, controls, or supervises a 
CAIR NOX unit or a CAIR NOX source and shall 
include, but not be limited to, any holding company, utility system, or 
plant manager of such a unit or source.
    Owner means any of the following persons:

[[Page 226]]

    (1) With regard to a CAIR NOX source or a CAIR 
NOX unit at a source, respectively:
    (i) Any holder of any portion of the legal or equitable title in a 
CAIR NOX unit at the source or the CAIR NOX unit;
    (ii) Any holder of a leasehold interest in a CAIR NOX 
unit at the source or the CAIR NOX unit; or
    (iii) Any purchaser of power from a CAIR NOX unit at the 
source or the CAIR NOX unit under a life-of-the-unit, firm 
power contractual arrangement; provided that, unless expressly provided 
for in a leasehold agreement, owner shall not include a passive lessor, 
or a person who has an equitable interest through such lessor, whose 
rental payments are not based (either directly or indirectly) on the 
revenues or income from such CAIR NOX unit; or
    (2) With regard to any general account, any person who has an 
ownership interest with respect to the CAIR NOX allowances 
held in the general account and who is subject to the binding agreement 
for the CAIR authorized account representative to represent the person's 
ownership interest with respect to CAIR NOX allowances.
    Permitting authority means the State air pollution control agency, 
local agency, other State agency, or other agency authorized by the 
Administrator to issue or revise permits to meet the requirements of the 
CAIR NOX Annual Trading Program or, if no such agency has 
been so authorized, the Administrator.
    Potential electrical output capacity means 33 percent of a unit's 
maximum design heat input, divided by 3,413 Btu/kWh, divided by 1,000 
kWh/MWh, and multiplied by 8,760 hr/yr.
    Receive or receipt of means, when referring to the permitting 
authority or the Administrator, to come into possession of a document, 
information, or correspondence (whether sent in hard copy or by 
authorized electronic transmission), as indicated in an official log, or 
by a notation made on the document, information, or correspondence, by 
the permitting authority or the Administrator in the regular course of 
business.
    Recordation, record, or recorded means, with regard to CAIR 
NOX allowances, the movement of CAIR NOX 
allowances by the Administrator into or between CAIR NOX 
Allowance Tracking System accounts, for purposes of allocation, 
transfer, or deduction.
    Reference method means any direct test method of sampling and 
analyzing for an air pollutant as specified in Sec. 75.22 of this 
chapter.
    Replacement, replace, or replaced means, with regard to a unit, the 
demolishing of a unit, or the permanent shutdown and permanent disabling 
of a unit, and the construction of another unit (the replacement unit) 
to be used instead of the demolished or shutdown unit (the replaced 
unit).
    Repowered means, with regard to a unit, replacement of a coal-fired 
boiler with one of the following coal-fired technologies at the same 
source as the coal-fired boiler:
    (1) Atmospheric or pressurized fluidized bed combustion;
    (2) Integrated gasification combined cycle;
    (3) Magnetohydrodynamics;
    (4) Direct and indirect coal-fired turbines;
    (5) Integrated gasification fuel cells; or
    (6) As determined by the Administrator in consultation with the 
Secretary of Energy, a derivative of one or more of the technologies 
under paragraphs (1) through (5) of this definition and any other coal-
fired technology capable of controlling multiple combustion emissions 
simultaneously with improved boiler or generation efficiency and with 
significantly greater waste reduction relative to the performance of 
technology in widespread commercial use as of January 1, 2005.
    Sequential use of energy means:
    (1) For a topping-cycle cogeneration unit, the use of reject heat 
from electricity production in a useful thermal energy application or 
process; or
    (2) For a bottoming-cycle cogeneration unit, the use of reject heat 
from useful thermal energy application or process in electricity 
production.
    Serial number means, for a CAIR NOX allowance, the unique 
identification number assigned to each CAIR NOX allowance by 
the Administrator.
    Solid waste incineration unit means a stationary, fossil-fuel-fired 
boiler or

[[Page 227]]

stationary, fossil-fuel-fired combustion turbine that is a ``solid waste 
incineration unit'' as defined in section 129(g)(1) of the Clean Air 
Act.
    Source means all buildings, structures, or installations located in 
one or more contiguous or adjacent properties under common control of 
the same person or persons. For purposes of section 502(c) of the Clean 
Air Act, a ``source,'' including a ``source'' with multiple units, shall 
be considered a single ``facility.''
    State means one of the States or the District of Columbia that is 
subject to the CAIR NOX Annual Trading Program pursuant to 
Sec. 52.35 of this chapter.
    Submit or serve means to send or transmit a document, information, 
or correspondence to the person specified in accordance with the 
applicable regulation:
    (1) In person;
    (2) By United States Postal Service; or
    (3) By other means of dispatch or transmission and delivery. 
Compliance with any ``submission'' or ``service'' deadline shall be 
determined by the date of dispatch, transmission, or mailing and not the 
date of receipt.
    Title V operating permit means a permit issued under title V of the 
Clean Air Act and part 70 or part 71 of this chapter.
    Title V operating permit regulations means the regulations that the 
Administrator has approved or issued as meeting the requirements of 
title V of the Clean Air Act and part 70 or 71 of this chapter.
    Ton means 2,000 pounds. For the purpose of determining compliance 
with the CAIR NOX emissions limitation, total tons of 
nitrogen oxides emissions for a control period shall be calculated as 
the sum of all recorded hourly emissions (or the mass equivalent of the 
recorded hourly emission rates) in accordance with subpart HH of this 
part, but with any remaining fraction of a ton equal to or greater than 
0.50 tons deemed to equal one ton and any remaining fraction of a ton 
less than 0.50 tons deemed to equal zero tons.
    Topping-cycle cogeneration unit means a cogeneration unit in which 
the energy input to the unit is first used to produce useful power, 
including electricity, and at least some of the reject heat from the 
electricity production is then used to provide useful thermal energy.
    Total energy input means, with regard to a cogeneration unit, total 
energy of all forms supplied to the cogeneration unit, excluding energy 
produced by the cogeneration unit itself. Each form of energy supplied 
shall be measured by the lower heating value of that form of energy 
calculated as follows:

LHV = HHV - 10.55(W + 9H)

Where:

LHV = lower heating value of fuel in Btu/lb,
HHV = higher heating value of fuel in Btu/lb,
W = Weight % of moisture in fuel, and
H = Weight % of hydrogen in fuel.

    Total energy output means, with regard to a cogeneration unit, the 
sum of useful power and useful thermal energy produced by the 
cogeneration unit.
    Unit means a stationary, fossil-fuel-fired boiler or combustion 
turbine or other stationary, fossil-fuel-fired combustion device.
    Unit operating day means a calendar day in which a unit combusts any 
fuel.
    Unit operating hour or hour of unit operation means an hour in which 
a unit combusts any fuel.
    Useful power means, with regard to a cogeneration unit, electricity 
or mechanical energy made available for use, excluding any such energy 
used in the power production process (which process includes, but is not 
limited to, any on-site processing or treatment of fuel combusted at the 
unit and any on-site emission controls).
    Useful thermal energy means, with regard to a cogeneration unit, 
thermal energy that is:
    (1) Made available to an industrial or commercial process (not a 
power production process), excluding any heat contained in condensate 
return or makeup water;
    (2) Used in a heating application (e.g., space heating or domestic 
hot water heating); or
    (3) Used in a space cooling application (i.e., thermal energy used 
by an absorption chiller).
    Utility power distribution system means the portion of an 
electricity grid owned

[[Page 228]]

or operated by a utility and dedicated to delivering electricity to 
customers.

[65 FR 2727, Jan. 18, 2000, as amended at 71 FR 74795, Dec. 13, 2006; 72 
FR 59206, Oct. 19, 2007]



Sec. 97.103  Measurements, abbreviations, and acronyms.

    Measurements, abbreviations, and acronyms used in this subpart and 
subparts BB through II are defined as follows:

Btu--British thermal unit
CO2--carbon dioxide
H2O--water
Hg--mercury
hr--hour
kW--kilowatt electrical
kWh--kilowatt hour
lb--pound
mmBtu--million Btu
MWe--megawatt electrical
MWh--megawatt hour
NOX--nitrogen oxides
O2--oxygen
ppm--parts per million
scfh--standard cubic feet per hour
SO2--sulfur dioxide
yr--year



Sec. 97.104  Applicability.

    (a) Except as provided in paragraph (b) of this section:
    (1) The following units in a State shall be CAIR NOX 
units, and any source that includes one or more such units shall be a 
CAIR NOX source, subject to the requirements of this subpart 
and subparts BB through HH of this part: any stationary, fossil-fuel-
fired boiler or stationary, fossil-fuel-fired combustion turbine serving 
at any time, since the later of November 15, 1990 or the start-up of the 
unit's combustion chamber, a generator with nameplate capacity of more 
than 25 MWe producing electricity for sale.
    (2) If a stationary boiler or stationary combustion turbine that, 
under paragraph (a)(1) of this section, is not a CAIR NOX 
unit begins to combust fossil fuel or to serve a generator with 
nameplate capacity of more than 25 MWe producing electricity for sale, 
the unit shall become a CAIR NOX unit as provided in 
paragraph (a)(1) of this section on the first date on which it both 
combusts fossil fuel and serves such generator.
    (b) The units in a State that meet the requirements set forth in 
paragraph (b)(1)(i), (b)(2)(i), or (b)(2)(ii) of this section shall not 
be CAIR NOX units:
    (1)(i) Any unit that is a CAIR NOX unit under paragraph 
(a)(1) or (2) of this section:
    (A) Qualifying as a cogeneration unit during the 12-month period 
starting on the date the unit first produces electricity and continuing 
to qualify as a cogeneration unit; and
    (B) Not serving at any time, since the later of November 15, 1990 or 
the start-up of the unit's combustion chamber, a generator with 
nameplate capacity of more than 25 MWe supplying in any calendar year 
more than one-third of the unit's potential electric output capacity or 
219,000 MWh, whichever is greater, to any utility power distribution 
system for sale.
    (ii) If a unit qualifies as a cogeneration unit during the 12-month 
period starting on the date the unit first produces electricity and 
meets the requirements of paragraphs (b)(1)(i) of this section for at 
least one calendar year, but subsequently no longer meets all such 
requirements, the unit shall become a CAIR NOX unit starting 
on the earlier of January 1 after the first calendar year during which 
the unit first no longer qualifies as a cogeneration unit or January 1 
after the first calendar year during which the unit no longer meets the 
requirements of paragraph (b)(1)(i)(B) of this section.
    (2)(i) Any unit that is a CAIR NOX unit under paragraph 
(a)(1) or (2) of this section commencing operation before January 1, 
1985:
    (A) Qualifying as a solid waste incineration unit; and
    (B) With an average annual fuel consumption of non-fossil fuel for 
1985-1987 exceeding 80 percent (on a Btu basis) and an average annual 
fuel consumption of non-fossil fuel for any 3 consecutive calendar years 
after 1990 exceeding 80 percent (on a Btu basis).
    (ii) Any unit that is a CAIR NOX unit under paragraph 
(a)(1) or (2) of this section commencing operation on or after January 
1, 1985:
    (A) Qualifying as a solid waste incineration unit; and

[[Page 229]]

    (B) With an average annual fuel consumption of non-fossil fuel for 
the first 3 calendar years of operation exceeding 80 percent (on a Btu 
basis) and an average annual fuel consumption of non-fossil fuel for any 
3 consecutive calendar years after 1990 exceeding 80 percent (on a Btu 
basis).
    (iii) If a unit qualifies as a solid waste incineration unit and 
meets the requirements of paragraph (b)(2)(i) or (ii) of this section 
for at least 3 consecutive calendar years, but subsequently no longer 
meets all such requirements, the unit shall become a CAIR NOX 
unit starting on the earlier of January 1 after the first calendar year 
during which the unit first no longer qualifies as a solid waste 
incineration unit or January 1 after the first 3 consecutive calendar 
years after 1990 for which the unit has an average annual fuel 
consumption of fossil fuel of 20 percent or more.
    (c) A certifying official of an owner or operator of any unit may 
petition the Administrator at any time for a determination concerning 
the applicability, under paragraphs (a) and (b) of this section, of the 
CAIR NOX Annual Trading Program to the unit.
    (1) Petition content. The petition shall be in writing and include 
the identification of the unit and the relevant facts about the unit. 
The petition and any other documents provided to the Administrator in 
connection with the petition shall include the following certification 
statement, signed by the certifying official: ``I am authorized to make 
this submission on behalf of the owners and operators of the unit for 
which the submission is made. I certify under penalty of law that I have 
personally examined, and am familiar with, the statements and 
information submitted in this document and all its attachments. Based on 
my inquiry of those individuals with primary responsibility for 
obtaining the information, I certify that the statements and information 
are to the best of my knowledge and belief true, accurate, and complete. 
I am aware that there are significant penalties for submitting false 
statements and information or omitting required statements and 
information, including the possibility of fine or imprisonment.''
    (2) Submission. The petition and any other documents provided in 
connection with the petition shall be submitted to the Director of the 
Clean Air Markets Division (or its successor), U.S. Environmental 
Protection Agency, who will act on the petition as the Administrator's 
duly authorized representative.
    (3) Response. The Administrator will issue a written response to the 
petition and may request supplemental information relevant to such 
petition. The Administrator's determination concerning the 
applicability, under paragraphs (a) and (b) of this section, of the CAIR 
NOX Annual Trading Program to the unit shall be binding on 
the permitting authority unless the petition or other information or 
documents provided in connection with the petition are found to have 
contained significant, relevant errors or omissions.



Sec. 97.105  Retired unit exemption.

    (a)(1) Any CAIR NOX unit that is permanently retired and 
is not a CAIR NOX opt-in unit under subpart II of this part 
shall be exempt from the CAIR NOX Annual Trading Program, 
except for the provisions of this section, Sec. Sec. 97.102, 97.103, 
97.104, 97.106(c)(4) through (7), 97.107, 97.108, and subparts BB and EE 
through GG of this part.
    (2) The exemption under paragraph (a)(1) of this section shall 
become effective the day on which the CAIR NOX unit is 
permanently retired. Within 30 days of the unit's permanent retirement, 
the CAIR designated representative shall submit a statement to the 
permitting authority otherwise responsible for administering any CAIR 
permit for the unit and shall submit a copy of the statement to the 
Administrator. The statement shall state, in a format prescribed by the 
permitting authority, that the unit was permanently retired on a 
specific date and will comply with the requirements of paragraph (b) of 
this section.
    (3) After receipt of the statement under paragraph (a)(2) of this 
section, the permitting authority will amend any permit under subpart CC 
of this part covering the source at which the unit is located to add the 
provisions and requirements of the exemption

[[Page 230]]

under paragraphs (a)(1) and (b) of this section.
    (b) Special provisions. (1) A unit exempt under paragraph (a) of 
this section shall not emit any nitrogen oxides, starting on the date 
that the exemption takes effect.
    (2) The Administrator or the permitting authority will allocate CAIR 
NOX allowances under subpart EE of this part to a unit exempt 
under paragraph (a) of this section.
    (3) For a period of 5 years from the date the records are created, 
the owners and operators of a unit exempt under paragraph (a) of this 
section shall retain, at the source that includes the unit, records 
demonstrating that the unit is permanently retired. The 5-year period 
for keeping records may be extended for cause, at any time before the 
end of the period, in writing by the permitting authority or the 
Administrator. The owners and operators bear the burden of proof that 
the unit is permanently retired.
    (4) The owners and operators and, to the extent applicable, the CAIR 
designated representative of a unit exempt under paragraph (a) of this 
section shall comply with the requirements of the CAIR NOX 
Annual Trading Program concerning all periods for which the exemption is 
not in effect, even if such requirements arise, or must be complied 
with, after the exemption takes effect.
    (5) A unit exempt under paragraph (a) of this section and located at 
a source that is required, or but for this exemption would be required, 
to have a title V operating permit shall not resume operation unless the 
CAIR designated representative of the source submits a complete CAIR 
permit application under Sec. 97.122 for the unit not less than 18 
months (or such lesser time provided by the permitting authority) before 
the later of January 1, 2009 or the date on which the unit resumes 
operation.
    (6) On the earlier of the following dates, a unit exempt under 
paragraph (a) of this section shall lose its exemption:
    (i) The date on which the CAIR designated representative submits a 
CAIR permit application for the unit under paragraph (b)(5) of this 
section;
    (ii) The date on which the CAIR designated representative is 
required under paragraph (b)(5) of this section to submit a CAIR permit 
application for the unit; or
    (iii) The date on which the unit resumes operation, if the CAIR 
designated representative is not required to submit a CAIR permit 
application for the unit.
    (7) For the purpose of applying monitoring, reporting, and 
recordkeeping requirements under subpart HH of this part, a unit that 
loses its exemption under paragraph (a) of this section shall be treated 
as a unit that commences commercial operation on the first date on which 
the unit resumes operation.



Sec. 97.106  Standard requirements.

    (a) Permit requirements. (1) The CAIR designated representative of 
each CAIR NOX source required to have a title V operating 
permit and each CAIR NOX unit required to have a title V 
operating permit at the source shall:
    (i) Submit to the permitting authority a complete CAIR permit 
application under Sec. 97.122 in accordance with the deadlines 
specified in Sec. 97.121; and
    (ii) Submit in a timely manner any supplemental information that the 
permitting authority determines is necessary in order to review a CAIR 
permit application and issue or deny a CAIR permit.
    (2) The owners and operators of each CAIR NOX source 
required to have a title V operating permit and each CAIR NOX 
unit required to have a title V operating permit at the source shall 
have a CAIR permit issued by the permitting authority under subpart CC 
of this part for the source and operate the source and the unit in 
compliance with such CAIR permit.
    (3) Except as provided in subpart II of this part, the owners and 
operators of a CAIR NOX source that is not otherwise required 
to have a title V operating permit and each CAIR NOX unit 
that is not otherwise required to have a title V operating permit are 
not required to submit a CAIR permit application, and to have a CAIR 
permit, under subpart CC of this part for such CAIR NOX 
source and such CAIR NOX unit.

[[Page 231]]

    (b) Monitoring, reporting, and recordkeeping requirements. (1) The 
owners and operators, and the CAIR designated representative, of each 
CAIR NOX source and each CAIR NOX unit at the 
source shall comply with the monitoring, reporting, and recordkeeping 
requirements of subpart HH of this part.
    (2) The emissions measurements recorded and reported in accordance 
with subpart HH of this part shall be used to determine compliance by 
each CAIR NOX source with the CAIR NOX emissions 
limitation under paragraph (c) of this section.
    (c) Nitrogen oxides emission requirements. (1) As of the allowance 
transfer deadline for a control period, the owners and operators of each 
CAIR NOX source and each CAIR NOX unit at the 
source shall hold, in the source's compliance account, CAIR 
NOX allowances available for compliance deductions for the 
control period under Sec. 97.154(a) in an amount not less than the tons 
of total nitrogen oxides emissions for the control period from all CAIR 
NOX units at the source, as determined in accordance with 
subpart HH of this part.
    (2) A CAIR NOX unit shall be subject to the requirements 
under paragraph (c)(1) of this section for the control period starting 
on the later of January 1, 2009 or the deadline for meeting the unit's 
monitor certification requirements under Sec. 97.170(b)(1), (2), or (5) 
and for each control period thereafter.
    (3) A CAIR NOX allowance shall not be deducted, for 
compliance with the requirements under paragraph (c)(1) of this section, 
for a control period in a calendar year before the year for which the 
CAIR NOX allowance was allocated.
    (4) CAIR NOX allowances shall be held in, deducted from, 
or transferred into or among CAIR NOX Allowance Tracking 
System accounts in accordance with subparts EE, FF, GG, and II of this 
part.
    (5) A CAIR NOX allowance is a limited authorization to 
emit one ton of nitrogen oxides in accordance with the CAIR 
NOX Annual Trading Program. No provision of the CAIR 
NOX Annual Trading Program, the CAIR permit application, the 
CAIR permit, or an exemption under Sec. 97.105 and no provision of law 
shall be construed to limit the authority of the United States to 
terminate or limit such authorization.
    (6) A CAIR NOX allowance does not constitute a property 
right.
    (7) Upon recordation by the Administrator under subpart EE, FF, GG, 
or II of this part, every allocation, transfer, or deduction of a CAIR 
NOX allowance to or from a CAIR NOX source's 
compliance account is incorporated automatically in any CAIR permit of 
the source.
    (d) Excess emissions requirements. If a CAIR NOX source 
emits nitrogen oxides during any control period in excess of the CAIR 
NOX emissions limitation, then:
    (1) The owners and operators of the source and each CAIR 
NOX unit at the source shall surrender the CAIR 
NOX allowances required for deduction under Sec. 
97.154(d)(1) and pay any fine, penalty, or assessment or comply with any 
other remedy imposed, for the same violations, under the Clean Air Act 
or applicable State law; and
    (2) Each ton of such excess emissions and each day of such control 
period shall constitute a separate violation of this subpart, the Clean 
Air Act, and applicable State law.
    (e) Recordkeeping and reporting requirements. (1) Unless otherwise 
provided, the owners and operators of the CAIR NOX source and 
each CAIR NOX unit at the source shall keep on site at the 
source each of the following documents for a period of 5 years from the 
date the document is created. This period may be extended for cause, at 
any time before the end of 5 years, in writing by the permitting 
authority or the Administrator.
    (i) The certificate of representation under Sec. 97.113 for the 
CAIR designated representative for the source and each CAIR 
NOX unit at the source and all documents that demonstrate the 
truth of the statements in the certificate of representation; provided 
that the certificate and documents shall be retained on site at the 
source beyond such 5-year period until such documents are superseded 
because of the submission of a new certificate of representation under 
Sec. 97.113 changing the CAIR designated representative.
    (ii) All emissions monitoring information, in accordance with 
subpart HH

[[Page 232]]

of this part, provided that to the extent that subpart HH of this part 
provides for a 3-year period for recordkeeping, the 3-year period shall 
apply.
    (iii) Copies of all reports, compliance certifications, and other 
submissions and all records made or required under the CAIR 
NOX Annual Trading Program.
    (iv) Copies of all documents used to complete a CAIR permit 
application and any other submission under the CAIR NOX 
Annual Trading Program or to demonstrate compliance with the 
requirements of the CAIR NOX Annual Trading Program.
    (2) The CAIR designated representative of a CAIR NOX 
source and each CAIR NOX unit at the source shall submit the 
reports required under the CAIR NOX Annual Trading Program, 
including those under subpart HH of this part.
    (f) Liability. (1) Each CAIR NOX source and each CAIR 
NOX unit shall meet the requirements of the CAIR 
NOX Annual Trading Program.
    (2) Any provision of the CAIR NOX Annual Trading Program 
that applies to a CAIR NOX source or the CAIR designated 
representative of a CAIR NOX source shall also apply to the 
owners and operators of such source and of the CAIR NOX units 
at the source.
    (3) Any provision of the CAIR NOX Annual Trading Program 
that applies to a CAIR NOX unit or the CAIR designated 
representative of a CAIR NOX unit shall also apply to the 
owners and operators of such unit.
    (g) Effect on other authorities. No provision of the CAIR 
NOX Annual Trading Program, a CAIR permit application, a CAIR 
permit, or an exemption under Sec. 97.105 shall be construed as 
exempting or excluding the owners and operators, and the CAIR designated 
representative, of a CAIR NOX source or CAIR NOX 
unit from compliance with any other provision of the applicable, 
approved State implementation plan, a federally enforceable permit, or 
the Clean Air Act.



Sec. 97.107  Computation of time.

    (a) Unless otherwise stated, any time period scheduled, under the 
CAIR NOX Annual Trading Program, to begin on the occurrence 
of an act or event shall begin on the day the act or event occurs.
    (b) Unless otherwise stated, any time period scheduled, under the 
CAIR NOX Annual Trading Program, to begin before the 
occurrence of an act or event shall be computed so that the period ends 
the day before the act or event occurs.
    (c) Unless otherwise stated, if the final day of any time period, 
under the CAIR NOX Annual Trading Program, falls on a weekend 
or a State or Federal holiday, the time period shall be extended to the 
next business day.



Sec. 97.108  Appeal procedures.

    The appeal procedures for decisions of the Administrator under the 
CAIR NOX Annual Trading Program are set forth in part 78 of 
this chapter.



     Subpart BB_CAIR Designated Representative for CAIR NOX Sources



Sec. 97.110  Authorization and responsibilities of CAIR designated
representative.

    (a) Except as provided under Sec. 97.111, each CAIR NOX 
source, including all CAIR NOX units at the source, shall 
have one and only one CAIR designated representative, with regard to all 
matters under the CAIR NOX Annual Trading Program concerning 
the source or any CAIR NOX unit at the source.
    (b) The CAIR designated representative of the CAIR NOX 
source shall be selected by an agreement binding on the owners and 
operators of the source and all CAIR NOX units at the source 
and shall act in accordance with the certification statement in Sec. 
97.113(a)(4)(iv).
    (c) Upon receipt by the Administrator of a complete certificate of 
representation under Sec. 97.113, the CAIR designated representative of 
the source shall represent and, by his or her representations, actions, 
inactions, or submissions, legally bind each owner and operator of the 
CAIR NOX source represented and each CAIR NOX unit 
at the source in all matters pertaining to the CAIR NOX 
Annual Trading Program, notwithstanding any agreement

[[Page 233]]

between the CAIR designated representative and such owners and 
operators. The owners and operators shall be bound by any decision or 
order issued to the CAIR designated representative by the permitting 
authority, the Administrator, or a court regarding the source or unit.
    (d) No CAIR permit will be issued, no emissions data reports will be 
accepted, and no CAIR NOX Allowance Tracking System account 
will be established for a CAIR NOX unit at a source, until 
the Administrator has received a complete certificate of representation 
under Sec. 97.113 for a CAIR designated representative of the source 
and the CAIR NOX units at the source.
    (e)(1) Each submission under the CAIR NOX Annual Trading 
Program shall be submitted, signed, and certified by the CAIR designated 
representative for each CAIR NOX source on behalf of which 
the submission is made. Each such submission shall include the following 
certification statement by the CAIR designated representative: ``I am 
authorized to make this submission on behalf of the owners and operators 
of the source or units for which the submission is made. I certify under 
penalty of law that I have personally examined, and am familiar with, 
the statements and information submitted in this document and all its 
attachments. Based on my inquiry of those individuals with primary 
responsibility for obtaining the information, I certify that the 
statements and information are to the best of my knowledge and belief 
true, accurate, and complete. I am aware that there are significant 
penalties for submitting false statements and information or omitting 
required statements and information, including the possibility of fine 
or imprisonment.''
    (2) The permitting authority and the Administrator will accept or 
act on a submission made on behalf of owner or operators of a CAIR 
NOX source or a CAIR NOX unit only if the 
submission has been made, signed, and certified in accordance with 
paragraph (e)(1) of this section.



Sec. 97.111  Alternate CAIR designated representative.

    (a) A certificate of representation under Sec. 97.113 may designate 
one and only one alternate CAIR designated representative, who may act 
on behalf of the CAIR designated representative. The agreement by which 
the alternate CAIR designated representative is selected shall include a 
procedure for authorizing the alternate CAIR designated representative 
to act in lieu of the CAIR designated representative.
    (b) Upon receipt by the Administrator of a complete certificate of 
representation under Sec. 97.113, any representation, action, inaction, 
or submission by the alternate CAIR designated representative shall be 
deemed to be a representation, action, inaction, or submission by the 
CAIR designated representative.
    (c) Except in this section and Sec. Sec. 97.102, 97.110(a) and (d), 
97.112, 97.113, 97.115, 97.151 and 97.182, whenever the term ``CAIR 
designated representative'' is used in subparts AA through II of this 
part, the term shall be construed to include the CAIR designated 
representative or any alternate CAIR designated representative.



Sec. 97.112  Changing CAIR designated representative and alternate 
CAIR designated representative; changes in owners and operators.

    (a) Changing CAIR designated representative. The CAIR designated 
representative may be changed at any time upon receipt by the 
Administrator of a superseding complete certificate of representation 
under Sec. 97.113. Notwithstanding any such change, all 
representations, actions, inactions, and submissions by the previous 
CAIR designated representative before the time and date when the 
Administrator receives the superseding certificate of representation 
shall be binding on the new CAIR designated representative and the 
owners and operators of the CAIR NOX source and the CAIR 
NOX units at the source.
    (b) Changing alternate CAIR designated representative. The alternate 
CAIR designated representative may be changed at any time upon receipt 
by the Administrator of a superseding complete certificate of 
representation under

[[Page 234]]

Sec. 97.113. Notwithstanding any such change, all representations, 
actions, inactions, and submissions by the previous alternate CAIR 
designated representative before the time and date when the 
Administrator receives the superseding certificate of representation 
shall be binding on the new alternate CAIR designated representative and 
the owners and operators of the CAIR NOX source and the CAIR 
NOX units at the source.
    (c) Changes in owners and operators. (1) In the event an owner or 
operator of a CAIR NOX source or a CAIR NOX unit 
is not included in the list of owners and operators in the certificate 
of representation under Sec. 97.113, such owner or operator shall be 
deemed to be subject to and bound by the certificate of representation, 
the representations, actions, inactions, and submissions of the CAIR 
designated representative and any alternate CAIR designated 
representative of the source or unit, and the decisions and orders of 
the permitting authority, the Administrator, or a court, as if the owner 
or operator were included in such list.
    (2) Within 30 days following any change in the owners and operators 
of a CAIR NOX source or a CAIR NOX unit, including 
the addition of a new owner or operator, the CAIR designated 
representative or any alternate CAIR designated representative shall 
submit a revision to the certificate of representation under Sec. 
97.113 amending the list of owners and operators to include the change.



Sec. 97.113  Certificate of representation.

    (a) A complete certificate of representation for a CAIR designated 
representative or an alternate CAIR designated representative shall 
include the following elements in a format prescribed by the 
Administrator:
    (1) Identification of the CAIR NOX source, and each CAIR 
NOX unit at the source, for which the certificate of 
representation is submitted, including identification and nameplate 
capacity of each generator served by each such unit.
    (2) The name, address, e-mail address (if any), telephone number, 
and facsimile transmission number (if any) of the CAIR designated 
representative and any alternate CAIR designated representative.
    (3) A list of the owners and operators of the CAIR NOX 
source and of each CAIR NOX unit at the source.
    (4) The following certification statements by the CAIR designated 
representative and any alternate CAIR designated representative--
    (i) ``I certify that I was selected as the CAIR designated 
representative or alternate CAIR designated representative, as 
applicable, by an agreement binding on the owners and operators of the 
source and each CAIR NOX unit at the source.''
    (ii) ``I certify that I have all the necessary authority to carry 
out my duties and responsibilities under the CAIR NOX Annual 
Trading Program on behalf of the owners and operators of the source and 
of each CAIR NOX unit at the source and that each such owner 
and operator shall be fully bound by my representations, actions, 
inactions, or submissions.''
    (iii) ``I certify that the owners and operators of the source and of 
each CAIR NOX unit at the source shall be bound by any order 
issued to me by the Administrator, the permitting authority, or a court 
regarding the source or unit.''
    (iv) Where there are multiple holders of a legal or equitable title 
to, or a leasehold interest in, a CAIR NOX unit, or where a 
utility or industrial customer purchases power from a CAIR 
NOX unit under a life-of-the-unit, firm power contractual 
arrangement, I certify that: I have given a written notice of my 
selection as the `CAIR designated representative' or `alternate CAIR 
designated representative', as applicable, and of the agreement by which 
I was selected to each owner and operator of the source and of each CAIR 
NOX unit at the source; and CAIR NOX allowances 
and proceeds of transactions involving CAIR NOX allowances 
will be deemed to be held or distributed in proportion to each holder's 
legal, equitable, leasehold, or contractual reservation or entitlement, 
except that, if such multiple holders have expressly provided for a 
different distribution of CAIR NOX allowances by contract, 
CAIR NOX allowances and proceeds of

[[Page 235]]

transactions involving CAIR NOX allowances will be deemed to 
be held or distributed in accordance with the contract.''
    (5) The signature of the CAIR designated representative and any 
alternate CAIR designated representative and the dates signed.
    (b) Unless otherwise required by the permitting authority or the 
Administrator, documents of agreement referred to in the certificate of 
representation shall not be submitted to the permitting authority or the 
Administrator. Neither the permitting authority nor the Administrator 
shall be under any obligation to review or evaluate the sufficiency of 
such documents, if submitted.

[65 FR 2727, Jan. 18, 2000, as amended at 71 FR 74795, Dec. 13, 2006]



Sec. 97.114  Objections concerning CAIR designated representative.

    (a) Once a complete certificate of representation under Sec. 97.113 
has been submitted and received, the permitting authority and the 
Administrator will rely on the certificate of representation unless and 
until a superseding complete certificate of representation under Sec. 
97.113 is received by the Administrator.
    (b) Except as provided in Sec. 97.112(a) or (b), no objection or 
other communication submitted to the permitting authority or the 
Administrator concerning the authorization, or any representation, 
action, inaction, or submission, of the CAIR designated representative 
shall affect any representation, action, inaction, or submission of the 
CAIR designated representative or the finality of any decision or order 
by the permitting authority or the Administrator under the CAIR 
NOX Annual Trading Program.
    (c) Neither the permitting authority nor the Administrator will 
adjudicate any private legal dispute concerning the authorization or any 
representation, action, inaction, or submission of any CAIR designated 
representative, including private legal disputes concerning the proceeds 
of CAIR NOX allowance transfers.



Sec. 97.115  Delegation by CAIR designated representative and alternate
CAIR designated representative.

    (a) A CAIR designated representative may delegate, to one or more 
natural persons, his or her authority to make an electronic submission 
to the Administrator provided for or required under this part.
    (b) An alternate CAIR designated representative may delegate, to one 
or more natural persons, his or her authority to make an electronic 
submission to the Administrator provided for or required under this 
part.
    (c) In order to delegate authority to make an electronic submission 
to the Administrator in accordance with paragraph (a) or (b) of this 
section, the CAIR designated representative or alternate CAIR designated 
representative, as appropriate, must submit to the Administrator a 
notice of delegation, in a format prescribed by the Administrator, that 
includes the following elements:
    (1) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of such CAIR designated 
representative or alternate CAIR designated representative;
    (2) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of each such natural person 
(referred to as an ``agent'');
    (3) For each such natural person, a list of the type or types of 
electronic submissions under paragraph (a) or (b) of this section for 
which authority is delegated to him or her; and
    (4) The following certification statements by such CAIR designated 
representative or alternate CAIR designated representative:
    (i) ``I agree that any electronic submission to the Administrator 
that is by an agent identified in this notice of delegation and of a 
type listed for such agent in this notice of delegation and that is made 
when I am a CAIR designated representative or alternate CAIR designated 
representative, as appropriate, and before this notice of delegation is 
superseded by another notice of delegation under 40 CFR 97.115(d) shall 
be deemed to be an electronic submission by me.''

[[Page 236]]

    (ii) ``Until this notice of delegation is superseded by another 
notice of delegation under 40 CFR 97.115(d), I agree to maintain an e-
mail account and to notify the Administrator immediately of any change 
in my e-mail address unless all delegation of authority by me under 40 
CFR 97.115 is terminated.''.
    (d) A notice of delegation submitted under paragraph (c) of this 
section shall be effective, with regard to the CAIR designated 
representative or alternate CAIR designated representative identified in 
such notice, upon receipt of such notice by the Administrator and until 
receipt by the Administrator of a superseding notice of delegation 
submitted by such CAIR designated representative or alternate CAIR 
designated representative, as appropriate. The superseding notice of 
delegation may replace any previously identified agent, add a new agent, 
or eliminate entirely any delegation of authority.
    (e) Any electronic submission covered by the certification in 
paragraph (c)(4)(i) of this section and made in accordance with a notice 
of delegation effective under paragraph (d) of this section shall be 
deemed to be an electronic submission by the CAIR designated 
representative or alternate CAIR designated representative submitting 
such notice of delegation.



                           Subpart CC_Permits



Sec. 97.120  General CAIR NOX Annual Trading Program permit 
requirements.

    (a) For each CAIR NOX source required to have a title V 
operating permit or required, under subpart II of this part, to have a 
title V operating permit or other federally enforceable permit, such 
permit shall include a CAIR permit administered by the permitting 
authority for the title V operating permit or the federally enforceable 
permit as applicable. The CAIR portion of the title V permit or other 
federally enforceable permit as applicable shall be administered in 
accordance with the permitting authority's title V operating permits 
regulations promulgated under part 70 or 71 of this chapter or the 
permitting authority's regulations for other federally enforceable 
permits as applicable, except as provided otherwise by Sec. 97.105, 
this subpart, and subpart II of this part.
    (b) Each CAIR permit shall contain, with regard to the CAIR 
NOX source and the CAIR NOX units at the source 
covered by the CAIR permit, all applicable CAIR NOX Annual 
Trading Program, CAIR NOX Ozone Season Trading Program, and 
CAIR SO2 Trading Program requirements and shall be a complete 
and separable portion of the title V operating permit or other federally 
enforceable permit under paragraph (a) of this section.



Sec. 97.121  Submission of CAIR permit applications.

    (a) Duty to apply. The CAIR designated representative of any CAIR 
NOX source required to have a title V operating permit shall 
submit to the permitting authority a complete CAIR permit application 
under Sec. 97.122 for the source covering each CAIR NOX unit 
at the source at least 18 months (or such lesser time provided by the 
permitting authority) before the later of January 1, 2009 or the date on 
which the CAIR NOX unit commences commercial operation, 
except as provided in Sec. 97.183(a).
    (b) Duty to reapply. For a CAIR NOX source required to 
have a title V operating permit, the CAIR designated representative 
shall submit a complete CAIR permit application under Sec. 97.122 for 
the source covering each CAIR NOX unit at the source to renew 
the CAIR permit in accordance with the permitting authority's title V 
operating permits regulations addressing permit renewal, except as 
provided in Sec. 97.183(b).



Sec. 97.122  Information requirements for CAIR permit applications.

    A complete CAIR permit application shall include the following 
elements concerning the CAIR NOX source for which the 
application is submitted, in a format prescribed by the permitting 
authority:
    (a) Identification of the CAIR NOX source;
    (b) Identification of each CAIR NOX unit at the CAIR 
NOX source; and
    (c) The standard requirements under Sec. 97.106.

[[Page 237]]



Sec. 97.123  CAIR permit contents and term.

    (a) Each CAIR permit will contain, in a format prescribed by the 
permitting authority, all elements required for a complete CAIR permit 
application under Sec. 97.122.
    (b) Each CAIR permit is deemed to incorporate automatically the 
definitions of terms under Sec. 97.102 and, upon recordation by the 
Administrator under subpart EE, FF, GG, or II of this part, every 
allocation, transfer, or deduction of a CAIR NOX allowance to 
or from the compliance account of the CAIR NOX source covered 
by the permit.
    (c) The term of the CAIR permit will be set by the permitting 
authority, as necessary to facilitate coordination of the renewal of the 
CAIR permit with issuance, revision, or renewal of the CAIR 
NOX source's title V operating permit or other federally 
enforceable permit as applicable.



Sec. 97.124  CAIR permit revisions.

    Except as provided in Sec. 97.123(b), the permitting authority will 
revise the CAIR permit, as necessary, in accordance with the permitting 
authority's title V operating permits regulations or the permitting 
authority's regulations for other federally enforceable permits as 
applicable addressing permit revisions.

Subpart DD [Reserved]



                Subpart EE_CAIR NOX Allowance Allocations



Sec. 97.140  State trading budgets.

    The State trading budgets for annual allocations of CAIR 
NOX allowances for the control periods in 2009 through 2014 
and in 2015 and thereafter are respectively as follows:

------------------------------------------------------------------------
                                                           State trading
                                           State trading    budget for
                  State                     budget for       2015 and
                                             2009-2014      thereafter
                                              (tons)          (tons)
------------------------------------------------------------------------
Alabama.................................          69,020          57,517
Delaware................................           4,166           3,472
District of Columbia....................             144             120
Florida.................................          99,445          82,871
Georgia.................................          66,321          55,268
Illinois................................          76,230          63,525
Indiana.................................         108,935          90,779
Iowa....................................          32,692          27,243
Kentucky................................          83,205          69,337
Louisiana...............................          35,512          29,593
Maryland................................          27,724          23,104
Michigan................................          65,304          54,420
Minnesota...............................          31,443          26,203
Mississippi.............................          17,807          14,839
Missouri................................          59,871          49,892
New Jersey..............................          12,670          10,558
New York................................          45,617          38,014
North Carolina..........................          62,183          51,819
Ohio....................................         108,667          90,556
Pennsylvania............................          99,049          82,541
South Carolina..........................          32,662          27,219
Tennessee...............................          50,973          42,478
Texas...................................         181,014         150,845
Virginia................................          36,074          30,062
West Virginia...........................          74,220          61,850
Wisconsin...............................          40,759          33,966
                                         -------------------------------
    Total...............................       1,521,707       1,268,091
------------------------------------------------------------------------



Sec. 97.141  Timing requirements for CAIR NOX allowance allocations.

    (a) The Administrator will determine by order the CAIR 
NOX allowance allocations, in accordance with Sec. 97.142(a) 
and (b), for the control periods in 2009, 2010, 2011, 2012, 2013, and 
2014.
    (b) By July 31, 2011 and July 31 of each year thereafter, the 
Administrator will determine by order the CAIR NOX allowance 
allocations, in accordance with Sec. 97.142(a) and (b), for the control 
period in the fourth year after the year of the applicable deadline for 
determination under this paragraph.
    (c) By July 31, 2009 and July 31 of each year thereafter, the 
Administrator will determine by order the CAIR NOX allowance 
allocations, in accordance with Sec. 97.142(a),(c), and (d), for the 
control period in the year of the applicable deadline for determination 
under this paragraph.
    (d) The Administrator will make available to the public each 
determination of CAIR NOX allowances under paragraph (a), 
(b), or (c) of this section and will provide an opportunity for 
submission of objections to the determination. Objections shall be 
limited to addressing whether the determination is in accordance with 
Sec. 97.142. Based on any such objections, the Administrator will 
adjust each determination to the extent necessary to ensure that it is 
in accordance with Sec. 97.142.

[[Page 238]]



Sec. 97.142  CAIR NOX allowance allocations.

    (a)(1) The baseline heat input (in mmBtu) used with respect to CAIR 
NOX allowance allocations under paragraph (b) of this section 
for each CAIR NOX unit will be:
    (i) For units commencing operation before January 1, 2001 the 
average of the 3 highest amounts of the unit's adjusted control period 
heat input for 2000 through 2004, with the adjusted control period heat 
input for each year calculated as follows:
    (A) If the unit is coal-fired during the year, the unit's control 
period heat input for such year is multiplied by 100 percent;
    (B) If the unit is oil-fired during the year, the unit's control 
period heat input for such year is multiplied by 60 percent; and
    (C) If the unit is not subject to paragraph (a)(1)(i)(A) or (B) of 
this section, the unit's control period heat input for such year is 
multiplied by 40 percent.
    (ii) For units commencing operation on or after January 1, 2001 and 
operating each calendar year during a period of 5 or more consecutive 
calendar years, the average of the 3 highest amounts of the unit's total 
converted control period heat input over the first such 5 years.
    (2)(i) A unit's control period heat input, and a unit's status as 
coal-fired or oil-fired, for a calendar year under paragraph (a)(1)(i) 
of this section, and a unit's total tons of NOX emissions 
during a calendar year under paragraph (c)(3) of this section, will be 
determined in accordance with part 75 of this chapter, to the extent the 
unit was otherwise subject to the requirements of part 75 of this 
chapter for the year, or will be based on the best available data 
reported to the Administrator for the unit (in a format prescribed by 
the Administrator), to the extent the unit was not otherwise subject to 
the requirements of part 75 of this chapter for the year.
    (ii) A unit's converted control period heat input for a calendar 
year specified under paragraph (a)(1)(ii) of this section equals:
    (A) Except as provided in paragraph (a)(2)(ii)(B) or (C) of this 
section, the control period gross electrical output of the generator or 
generators served by the unit multiplied by 7,900 Btu/kWh, if the unit 
is coal-fired for the year, or 6,675 Btu/kWh, if the unit is not coal-
fired for the year, and divided by 1,000,000 Btu/mmBtu, provided that if 
a generator is served by 2 or more units, then the gross electrical 
output of the generator will be attributed to each unit in proportion to 
the unit's share of the total control period heat input of such units 
for the year;
    (B) For a unit that is a boiler and has equipment used to produce 
electricity and useful thermal energy for industrial, commercial, 
heating, or cooling purposes through the sequential use of energy, the 
total heat energy (in Btu) of the steam produced by the boiler during 
the control period, divided by 0.8 and by 1,000,000 Btu/mmBtu; or
    (C) For a unit that is a combustion turbine and has equipment used 
to produce electricity and useful thermal energy for industrial, 
commercial, heating, or cooling purposes through the sequential use of 
energy, the control period gross electrical output of the enclosed 
device comprising the compressor, combustor, and turbine multiplied by 
3,413 Btu/kWh, plus the total heat energy (in Btu) of the steam produced 
by any associated heat recovery steam generator during the control 
period divided by 0.8, and with the sum divided by 1,000,000 Btu/mmBtu.
    (iii) Gross electrical output and total heat energy under paragraph 
(a)(2)(ii) of this section will be determined based on the best 
available data reported to the Administrator for the unit (in a format 
prescribed by the Administrator).
    (3) The Administrator will determine what data are the best 
available data under paragraph (a)(2) of this section by weighing the 
likelihood that data are accurate and reliable and giving greater weight 
to data submitted to a governmental entity in compliance with legal 
requirements or substantiated by an independent entity.
    (b)(1) For each control period in 2009 and thereafter, the 
Administrator will allocate to all CAIR NOX units in a State 
that have a baseline heat input (as determined under paragraph (a) of 
this section) a total amount of CAIR NOX allowances equal to 
95 percent for

[[Page 239]]

a control period during 2009 through 2014, and 97 percent for a control 
period during 2015 and thereafter, of the tons of NOX 
emissions in the applicable State trading budget under Sec. 97.140 
(except as provided in paragraphs (d) and (e) of this section).
    (2) The Administrator will allocate CAIR NOX allowances 
to each CAIR NOX unit under paragraph (b)(1) of this section 
in an amount determined by multiplying the total amount of CAIR 
NOX allowances allocated under paragraph (b)(1) of this 
section by the ratio of the baseline heat input of such CAIR 
NOX unit to the total amount of baseline heat input of all 
such CAIR NOX units in the State and rounding to the nearest 
whole allowance as appropriate.
    (c) For each control period in 2009 and thereafter, the 
Administrator will allocate CAIR NOX allowances to CAIR 
NOX units in a State that are not allocated CAIR 
NOX allowances under paragraph (b) of this section because 
the units do not yet have a baseline heat input under paragraph (a) of 
this section or because the units have a baseline heat input but all 
CAIR NOX allowances available under paragraph (b) of this 
section for the control period are already allocated, in accordance with 
the following procedures:
    (1) The Administrator will establish a separate new unit set-aside 
for each control period. Each new unit set-aside will be allocated CAIR 
NOX allowances equal to 5 percent for a control period in 
2009 through 2014, and 3 percent for a control period in 2015 and 
thereafter, of the amount of tons of NOX emissions in the 
applicable State trading budget under Sec. 97.140.
    (2) The CAIR designated representative of such a CAIR NOX 
unit may submit to the Administrator a request, in a format specified by 
the Administrator, to be allocated CAIR NOX allowances, 
starting with the later of the control period in 2009 or the first 
control period after the control period in which the CAIR NOX 
unit commences commercial operation and until the first control period 
for which the unit is allocated CAIR NOX allowances under 
paragraph (b) of this section. A separate CAIR NOX allowance 
allocation request for each control period for which CAIR NOX 
allowances are sought must be submitted on or before May 1 of such 
control period and after the date on which the CAIR NOX unit 
commences commercial operation.
    (3) In a CAIR NOX allowance allocation request under 
paragraph (c)(2) of this section, the CAIR designated representative may 
request for a control period CAIR NOX allowances in an amount 
not exceeding the CAIR NOX unit's total tons of 
NOX emissions during the calendar year immediately before 
such control period.
    (4) The Administrator will review each CAIR NOX allowance 
allocation request under paragraph (c)(2) of this section and will 
allocate CAIR NOX allowances for each control period pursuant 
to such request as follows:
    (i) The Administrator will accept an allowance allocation request 
only if the request meets, or is adjusted by the Administrator as 
necessary to meet, the requirements of paragraphs (c)(2) and (3) of this 
section.
    (ii) On or after May 1 of the control period, the Administrator will 
determine the sum of the CAIR NOX allowances requested (as 
adjusted under paragraph (c)(4)(i) of this section) in all allowance 
allocation requests accepted under paragraph (c)(4)(i) of this section 
for the control period.
    (iii) If the amount of CAIR NOX allowances in the new 
unit set-aside for the control period is greater than or equal to the 
sum under paragraph (c)(4)(ii) of this section, then the Administrator 
will allocate the amount of CAIR NOX allowances requested (as 
adjusted under paragraph (c)(4)(i) of this section) to each CAIR 
NOX unit covered by an allowance allocation request accepted 
under paragraph (c)(4)(i) of this section.
    (iv) If the amount of CAIR NOX allowances in the new unit 
set-aside for the control period is less than the sum under paragraph 
(c)(4)(ii) of this section, then the Administrator will allocate to each 
CAIR NOX unit covered by an allowance allocation request 
accepted under paragraph (c)(4)(i) of this section the amount of the 
CAIR NOX allowances requested (as adjusted under paragraph 
(c)(4)(i) of this section), multiplied by the amount of CAIR 
NOX allowances in the new unit set-aside for

[[Page 240]]

the control period, divided by the sum determined under paragraph 
(c)(4)(ii) of this section, and rounded to the nearest whole allowance 
as appropriate.
    (v) The Administrator will notify each CAIR designated 
representative that submitted an allowance allocation request of the 
amount of CAIR NOX allowances (if any) allocated for the 
control period to the CAIR NOX unit covered by the request.
    (d) If, after completion of the procedures under paragraph (c)(4) of 
this section for a control period, any unallocated CAIR NOX 
allowances remain in the new unit set-aside under paragraph (c) of this 
section for a State for the control period, the Administrator will 
allocate to each CAIR NOX unit that was allocated CAIR 
NOX allowances under paragraph (b) of this section in the 
State an amount of CAIR NOX allowances equal to the total 
amount of such remaining unallocated CAIR NOX allowances, 
multiplied by the unit's allocation under paragraph (b) of this section, 
divided by 95 percent for a control period during 2009 through 2014, and 
97 percent for a control period during 2015 and thereafter, of the 
amount of tons of NOX emissions in the applicable State 
trading budget under Sec. 97.140, and rounded to the nearest whole 
allowance as appropriate.
    (e) If the Administrator determines that CAIR NOX 
allowances were allocated under paragraphs (a) and (b) of this section, 
paragraphs (a) and (c) of this section, or paragraph (d) of this section 
for a control period and that the recipient of the allocation is not 
actually a CAIR NOX unit under Sec. 97.104 in such control 
period, then the Administrator will notify the CAIR designated 
representative and will act in accordance with the following procedures:
    (1) Except as provided in paragraph (e)(2) or (3) of this section, 
the Administrator will not record such CAIR NOX allowances 
under Sec. 97.153.
    (2) If the Administrator already recorded such CAIR NOX 
allowances under Sec. 97.153 and if the Administrator makes such 
determination before making deductions for the source that includes such 
recipient under Sec. 97.154(b) for the control period, then the 
Administrator will deduct from the account in which such CAIR 
NOX allowances were recorded under Sec. 97.153 an amount of 
CAIR NOX allowances allocated for the same or a prior control 
period equal to the amount of such already recorded CAIR NOX 
allowances. The CAIR designated representative shall ensure that there 
are sufficient CAIR NOX allowances in such account for 
completion of the deduction.
    (3) If the Administrator already recorded such CAIR NOX 
allowances under Sec. 97.153 and if the Administrator makes such 
determination after making deductions for the source that includes such 
recipient under Sec. 97.154(b) for the control period, then the 
Administrator will apply paragraph (e)(1) or (2) of this section, as 
appropriate, to any subsequent control period for which CAIR 
NOX allowances were allocated to such recipient.
    (4) The Administrator will transfer the CAIR NOX 
allowances that are not recorded, or that are deducted, in accordance 
with paragraphs (e)(1), (2), and (3) of this section to a new unit set-
aside for the State in which such recipient is located.



Sec. 97.143  Compliance supplement pool.

    (a) In addition to the CAIR NOX allowances allocated 
under Sec. 97.142, the Administrator may allocate for the control 
period in 2009 up to the following amount of CAIR NOX 
allowances to CAIR NOX units in the respective State:

------------------------------------------------------------------------
                                                           Compliance
                         State                           supplement pool
------------------------------------------------------------------------
Alabama...............................................            10,166
Delaware..............................................               843
District of Columbia..................................                 0
Florida...............................................             8,335
Georgia...............................................            12,397
Illinois..............................................            11,299
Indiana...............................................            20,155
Iowa..................................................             6,978
Kentucky..............................................            14,935
Louisiana.............................................             2,251
Maryland..............................................             4,670
Michigan..............................................             8,347
Minnesota.............................................             6,528
Mississippi...........................................             3,066
Missouri..............................................             9,044
New Jersey............................................               660
New York..............................................                 0
North Carolina........................................                 0
Ohio..................................................            25,037
Pennsylvania..........................................            16,009
South Carolina........................................             2,600

[[Page 241]]

 
Tennessee.............................................             8,944
Texas.................................................               772
Virginia..............................................             5,134
West Virginia.........................................            16,929
Wisconsin.............................................             4,898
                                                       -----------------
    Total.............................................           199,997
------------------------------------------------------------------------

    (b) For any CAIR NOX unit in a State, if the unit's 
average annual NOX emission rate for 2007 or 2008 is less 
than 0.25 lb/mmBtu and, where such unit is included in a NOX 
averaging plan under Sec. 76.11 of this chapter under the Acid Rain 
Program for such year, the unit's NOX averaging plan has an 
actual weighted average NOX emission rate for such year equal 
to or less than the actual weighted average NOX emission rate 
for the year before such year and if the unit achieves NOX 
emission reductions in 2007 and 2008, the CAIR designated representative 
of the unit may request early reduction credits, and allocation of CAIR 
NOX allowances from the compliance supplement pool under 
paragraph (a) of this section for such early reduction credits, in 
accordance with the following:
    (1) The owners and operators of such CAIR NOX unit shall 
monitor and report the NOX emissions rate and the heat input 
of the unit in accordance with subpart HH of this part in each control 
period for which early reduction credit is requested.
    (2) The CAIR designated representative of such CAIR NOX 
unit shall submit to the Administrator by May 1, 2009 a request, in a 
format specified by the Administrator, for allocation of an amount of 
CAIR NOX allowances from the compliance supplement pool not 
exceeding the sum of the unit's heat input for the control period in 
2007 multiplied by the difference (if any greater than zero) between 
0.25 lb/mmBtu and the unit's NOX emission rate for the 
control period in 2007 plus the unit's heat input for the control period 
in 2008 multiplied by the difference (if any greater than zero) between 
0.25 lb/mmBtu and the unit's NOX emission rate for the 
control period in 2008, determined in accordance with subpart HH of this 
part and with the sum divided by 2,000 lb/ton and rounded to the nearest 
whole number of tons as appropriate.
    (c) For any CAIR NOX unit in a State whose compliance 
with the CAIR NOX emissions limitation for the control period 
in 2009 would create an undue risk to the reliability of electricity 
supply during such control period, the CAIR designated representative of 
the unit may request the allocation of CAIR NOX allowances 
from the compliance supplement pool under paragraph (a) of this section, 
in accordance with the following:
    (1) The CAIR designated representative of such CAIR NOX 
unit shall submit to the Administrator by May 1, 2009 a request, in a 
format specified by the Administrator, for allocation of an amount of 
CAIR NOX allowances from the compliance supplement pool not 
exceeding the minimum amount of CAIR NOX allowances necessary 
to remove such undue risk to the reliability of electricity supply.
    (2) In the request under paragraph (c)(1) of this section, the CAIR 
designated representative of such CAIR NOX unit shall 
demonstrate that, in the absence of allocation to the unit of the amount 
of CAIR NOX allowances requested, the unit's compliance with 
the CAIR NOX emissions limitation for the control period in 
2009 would create an undue risk to the reliability of electricity supply 
during such control period. This demonstration must include a showing 
that it would not be feasible for the owners and operators of the unit 
to:
    (i) Obtain a sufficient amount of electricity from other electricity 
generation facilities, during the installation of control technology at 
the unit for compliance with the CAIR NOX emissions 
limitation, to prevent such undue risk; or
    (ii) Obtain under paragraphs (b) and (d) of this section, or 
otherwise obtain, a sufficient amount of CAIR NOX allowances 
to prevent such undue risk.
    (d) The Administrator will review each request under paragraph (b) 
or (c) of this section submitted by May 1, 2009 and will allocate CAIR 
NOX allowances for the control period in 2009 to CAIR 
NOX units in a State and covered by such request as follows:

[[Page 242]]

    (1) Upon receipt of each such request, the Administrator will make 
any necessary adjustments to the request to ensure that the amount of 
the CAIR NOX allowances requested meets the requirements of 
paragraph (b) or (c) of this section.
    (2) If the State's compliance supplement pool under paragraph (a) of 
this section has an amount of CAIR NOX allowances not less 
than the total amount of CAIR NOX allowances in all such 
requests (as adjusted under paragraph (d)(1) of this section), the 
Administrator will allocate to each CAIR NOX unit covered by 
such requests the amount of CAIR NOX allowances requested (as 
adjusted under paragraph (d)(1) of this section).
    (3) If the State's compliance supplement pool under paragraph (a) of 
this section has a smaller amount of CAIR NOX allowances than 
the total amount of CAIR NOX allowances in all such requests 
(as adjusted under paragraph (d)(1) of this section), the Administrator 
will allocate CAIR NOX allowances to each CAIR NOX 
unit covered by such requests according to the following formula and 
rounding to the nearest whole allowance as appropriate:

Unit's allocation = Unit's adjusted allocation x (State's compliance 
supplement pool / Total adjusted allocations for all units)

Where:

``Unit's allocation'' is the amount of CAIR NOX allowances 
          allocated to the unit from the State's compliance supplement 
          pool.
``Unit's adjusted allocation'' is the amount of CAIR NOX 
          allowances requested for the unit under paragraph (b) or (c) 
          of this section, as adjusted under paragraph (d)(1) of this 
          section.
``State's compliance supplement pool'' is the amount of CAIR 
          NOX allowances in the State's compliance supplement 
          pool.
``Total adjusted allocations for all units'' is the sum of the amounts 
          of allocations requested for all units under paragraph (b) or 
          (c) of this section, as adjusted under paragraph (d)(1) of 
          this section.

    (4) By July 31, 2009, the Administrator will determine by order the 
allocations under paragraph (d)(2) or (3) of this section. The 
Administrator will make available to the public each determination of 
CAIR NOX allowances under such paragraph and will provide an 
opportunity for submission of objections to the determination. 
Objections shall be limited to addressing whether the determination is 
in accordance with paragraph (b) or (c) of this section and paragraph 
(d)(2) or (3) of this section, as appropriate. Based on any such 
objections, the Administrator will adjust each determination to the 
extent necessary to ensure that it is in accordance with such 
paragraphs.
    (5) By January 1, 2010, the Administrator will record the 
allocations under paragraph (d)(4) of this section.

[65 FR 2727, Jan. 18, 2000, as amended at 71 FR 74795, Dec. 13, 2006]



Sec. 97.144  Alternative of allocation of CAIR NOX allowances and
compliance supplement pool by permitting authority.

    (a) Notwithstanding Sec. Sec. 97.141, 97.142, and 97.153 if a State 
submits, and the Administrator approves, a State implementation plan 
revision in accordance with Sec. 51.123(p)(1) of this chapter providing 
for allocation of CAIR NOX allowances by the permitting 
authority, then the permitting authority shall make such allocations in 
accordance with such approved State implementation plan revision, the 
Administrator will not make allocations under Sec. Sec. 97.141 and 
97.142 for the CAIR NOX units in the State, and under Sec. 
97.153, the Administrator will record the allocations made under such 
approved State implementation plan revision instead of allocations made 
under Sec. Sec. 97.141 and 97.142.
    (b) Notwithstanding Sec. 97.143, if a State submits, and the 
Administrator approves, a State implementation plan revision in 
accordance with Sec. 51.123(p)(2) of this chapter providing for 
allocation of the State's compliance supplement pool by the permitting 
authority, then the permitting authority shall make such allocations in 
accordance with such approved State implementation plan revision, the 
Administrator will not make allocations under Sec. 97.143(d)(4) for the 
CAIR NOX units in the State, and under Sec. 97.143(d)(5), 
the Administrator will record the allocations of the State's compliance 
supplement pool made

[[Page 243]]

under such approved State implementation plan revision instead of 
allocations made under Sec. 97.143(d)(4).
    (c)(1) In implementing paragraph (a) of this section and Sec. Sec. 
97.141, 97.142, and 97.153, the Administrator will ensure that the total 
amount of CAIR NOX allowances allocated, under such 
provisions and under a State's State implementation plan revision 
approved in accordance with Sec. 51.123(p)(1) of this chapter, for a 
control period for CAIR NOX sources in the State or for other 
entities specified by the permitting authority will not exceed the 
State's State trading budget for the year of the control period.
    (2) In implementing paragraph (b) of this section and Sec. 97.143, 
the Administrator will ensure that the total amount of CAIR 
NOX allowances allocated, under such provisions and under a 
State's State implementation plan revision approved in accordance with 
Sec. 51.123(p)(2), for CAIR NOX sources in the State will 
not exceed the State's compliance supplement pool.

[65 FR 2727, Jan. 18, 2000, as amended at 71 FR 74795, Dec. 13, 2006]



  Sec. Appendix A to Subpart EE of Part 97--States With Approved State 
          Implementation Plan Revisions Concerning Allocations

    1. The following States have State Implementation Plan revisions 
under Sec. 51.123(p)(1) of this chapter approved by the Administrator 
and providing for allocation of CAIR NOX allowances by the 
permitting authority under Sec. 97.144(a):

Indiana
Louisiana
Michigan
New Jersey
North Carolina
Ohio
South Carolina
Tennessee
Texas (for control periods 2009-2014)
West Virginia (for control periods 2009-2014)
Wisconsin

    2. The following States have State Implementation Plan revisions 
under Sec. 51.123(p)(2) of this chapter approved by the Administrator 
and providing for allocation of the Compliance Supplement Pool by the 
permitting authority under Sec. 97.144(b):

Indiana
Michigan
New Jersey
Ohio
South Carolina
Texas

[65 FR 2727, Jan. 18, 2000, as amended at 72 FR 41459, July 30, 2007; 72 
FR 46394, Aug. 20, 2007; 72 FR 52293, Sept. 13, 2007; 72 FR 55068, Sept. 
28, 2007; 72 FR 55672, Oct. 1, 2007; 72 FR 56920, Oct. 5, 2007; 72 FR 
57215, Oct. 9, 2007; 72 FR 58546, Oct. 16, 2007; 72 FR 59487, Oct. 22, 
2007; 72 FR 71579, Dec. 18, 2007; 72 FR 72262, Dec. 20, 2007; 73 FR 
6040, Feb. 1, 2008]



              Subpart FF_CAIR NOX Allowance Tracking System



Sec. 97.150  [Reserved]



Sec. 97.151  Establishment of accounts.

    (a) Compliance accounts. Except as provided in Sec. 97.184(e), upon 
receipt of a complete certificate of representation under Sec. 97.113, 
the Administrator will establish a compliance account for the CAIR 
NOX source for which the certificate of representation was 
submitted, unless the source already has a compliance account.
    (b) General accounts--(1) Application for general account. (i) Any 
person may apply to open a general account for the purpose of holding 
and transferring CAIR NOX allowances. An application for a 
general account may designate one and only one CAIR authorized account 
representative and one and only one alternate CAIR authorized account 
representative who may act on behalf of the CAIR authorized account 
representative. The agreement by which the alternate CAIR authorized 
account representative is selected shall include a procedure for 
authorizing the alternate CAIR authorized account representative to act 
in lieu of the CAIR authorized account representative.
    (ii) A complete application for a general account shall be submitted 
to the Administrator and shall include the following elements in a 
format prescribed by the Administrator:
    (A) Name, mailing address, e-mail address (if any), telephone 
number, and facsimile transmission number (if any) of the CAIR 
authorized account representative and any alternate CAIR authorized 
account representative;
    (B) Organization name and type of organization, if applicable;
    (C) A list of all persons subject to a binding agreement for the 
CAIR authorized account representative and

[[Page 244]]

any alternate CAIR authorized account representative to represent their 
ownership interest with respect to the CAIR NOX allowances 
held in the general account;
    (D) The following certification statement by the CAIR authorized 
account representative and any alternate CAIR authorized account 
representative: ``I certify that I was selected as the CAIR authorized 
account representative or the alternate CAIR authorized account 
representative, as applicable, by an agreement that is binding on all 
persons who have an ownership interest with respect to CAIR 
NOX allowances held in the general account. I certify that I 
have all the necessary authority to carry out my duties and 
responsibilities under the CAIR NOX Annual Trading Program on 
behalf of such persons and that each such person shall be fully bound by 
my representations, actions, inactions, or submissions and by any order 
or decision issued to me by the Administrator or a court regarding the 
general account.''
    (E) The signature of the CAIR authorized account representative and 
any alternate CAIR authorized account representative and the dates 
signed.
    (iii) Unless otherwise required by the permitting authority or the 
Administrator, documents of agreement referred to in the application for 
a general account shall not be submitted to the permitting authority or 
the Administrator. Neither the permitting authority nor the 
Administrator shall be under any obligation to review or evaluate the 
sufficiency of such documents, if submitted.
    (2) Authorization of CAIR authorized account representative and 
alternate CAIR authorized account representative. (i) Upon receipt by 
the Administrator of a complete application for a general account under 
paragraph (b)(1) of this section:
    (A) The Administrator will establish a general account for the 
person or persons for whom the application is submitted.
    (B) The CAIR authorized account representative and any alternate 
CAIR authorized account representative for the general account shall 
represent and, by his or her representations, actions, inactions, or 
submissions, legally bind each person who has an ownership interest with 
respect to CAIR NOX allowances held in the general account in 
all matters pertaining to the CAIR NOX Annual Trading 
Program, notwithstanding any agreement between the CAIR authorized 
account representative or any alternate CAIR authorized account 
representative and such person. Any such person shall be bound by any 
order or decision issued to the CAIR authorized account representative 
or any alternate CAIR authorized account representative by the 
Administrator or a court regarding the general account.
    (C) Any representation, action, inaction, or submission by any 
alternate CAIR authorized account representative shall be deemed to be a 
representation, action, inaction, or submission by the CAIR authorized 
account representative.
    (ii) Each submission concerning the general account shall be 
submitted, signed, and certified by the CAIR authorized account 
representative or any alternate CAIR authorized account representative 
for the persons having an ownership interest with respect to CAIR 
NOX allowances held in the general account. Each such 
submission shall include the following certification statement by the 
CAIR authorized account representative or any alternate CAIR authorized 
account representative: ``I am authorized to make this submission on 
behalf of the persons having an ownership interest with respect to the 
CAIR NOX allowances held in the general account. I certify 
under penalty of law that I have personally examined, and am familiar 
with, the statements and information submitted in this document and all 
its attachments. Based on my inquiry of those individuals with primary 
responsibility for obtaining the information, I certify that the 
statements and information are to the best of my knowledge and belief 
true, accurate, and complete. I am aware that there are significant 
penalties for submitting false statements and information or omitting 
required statements and information, including the possibility of fine 
or imprisonment.''
    (iii) The Administrator will accept or act on a submission 
concerning the

[[Page 245]]

general account only if the submission has been made, signed, and 
certified in accordance with paragraph (b)(2)(ii) of this section.
    (3) Changing CAIR authorized account representative and alternate 
CAIR authorized account representative; changes in persons with 
ownership interest. (i) The CAIR authorized account representative for a 
general account may be changed at any time upon receipt by the 
Administrator of a superseding complete application for a general 
account under paragraph (b)(1) of this section. Notwithstanding any such 
change, all representations, actions, inactions, and submissions by the 
previous CAIR authorized account representative before the time and date 
when the Administrator receives the superseding application for a 
general account shall be binding on the new CAIR authorized account 
representative and the persons with an ownership interest with respect 
to the CAIR NOX allowances in the general account.
    (ii) The alternate CAIR authorized account representative for a 
general account may be changed at any time upon receipt by the 
Administrator of a superseding complete application for a general 
account under paragraph (b)(1) of this section. Notwithstanding any such 
change, all representations, actions, inactions, and submissions by the 
previous alternate CAIR authorized account representative before the 
time and date when the Administrator receives the superseding 
application for a general account shall be binding on the new alternate 
CAIR authorized account representative and the persons with an ownership 
interest with respect to the CAIR NOX allowances in the 
general account.
    (iii)(A) In the event a person having an ownership interest with 
respect to CAIR NOX allowances in the general account is not 
included in the list of such persons in the application for a general 
account, such person shall be deemed to be subject to and bound by the 
application for a general account, the representation, actions, 
inactions, and submissions of the CAIR authorized account representative 
and any alternate CAIR authorized account representative of the account, 
and the decisions and orders of the Administrator or a court, as if the 
person were included in such list.
    (B) Within 30 days following any change in the persons having an 
ownership interest with respect to CAIR NOX allowances in the 
general account, including the addition of a new person, the CAIR 
authorized account representative or any alternate CAIR authorized 
account representative shall submit a revision to the application for a 
general account amending the list of persons having an ownership 
interest with respect to the CAIR NOX allowances in the 
general account to include the change.
    (4) Objections concerning CAIR authorized account representative and 
alternate CAIR authorized account representative. (i) Once a complete 
application for a general account under paragraph (b)(1) of this section 
has been submitted and received, the Administrator will rely on the 
application unless and until a superseding complete application for a 
general account under paragraph (b)(1) of this section is received by 
the Administrator.
    (ii) Except as provided in paragraph (b)(3)(i) or (ii) of this 
section, no objection or other communication submitted to the 
Administrator concerning the authorization, or any representation, 
action, inaction, or submission of the CAIR authorized account 
representative or any alternate CAIR authorized account representative 
for a general account shall affect any representation, action, inaction, 
or submission of the CAIR authorized account representative or any 
alternate CAIR authorized account representative or the finality of any 
decision or order by the Administrator under the CAIR NOX 
Annual Trading Program.
    (iii) The Administrator will not adjudicate any private legal 
dispute concerning the authorization or any representation, action, 
inaction, or submission of the CAIR authorized account representative or 
any alternate CAIR authorized account representative for a general 
account, including private legal disputes concerning the proceeds of 
CAIR NOX allowance transfers.
    (5) Delegation by CAIR authorized account representative and 
alternate CAIR authorized account representative. (i) A

[[Page 246]]

CAIR authorized account representative may delegate, to one or more 
natural persons, his or her authority to make an electronic submission 
to the Administrator provided for or required under subparts FF and GG 
of this part.
    (ii) An alternate CAIR authorized account representative may 
delegate, to one or more natural persons, his or her authority to make 
an electronic submission to the Administrator provided for or required 
under subparts FF and GG of this part.
    (iii) In order to delegate authority to make an electronic 
submission to the Administrator in accordance with paragraph (b)(5)(i) 
or (ii) of this section, the CAIR authorized account representative or 
alternate CAIR authorized account representative, as appropriate, must 
submit to the Administrator a notice of delegation, in a format 
prescribed by the Administrator, that includes the following elements:
    (A) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of such CAIR authorized account 
representative or alternate CAIR authorized account representative;
    (B) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of each such natural person 
(referred to as an ``agent'');
    (C) For each such natural person, a list of the type or types of 
electronic submissions under paragraph (b)(5)(i) or (ii) of this section 
for which authority is delegated to him or her;
    (D) The following certification statement by such CAIR authorized 
account representative or alternate CAIR authorized account 
representative: ``I agree that any electronic submission to the 
Administrator that is by an agent identified in this notice of 
delegation and of a type listed for such agent in this notice of 
delegation and that is made when I am a CAIR authorized account 
representative or alternate CAIR authorized representative, as 
appropriate, and before this notice of delegation is superseded by 
another notice of delegation under 40 CFR 97.151(b)(5)(iv) shall be 
deemed to be an electronic submission by me.''; and
    (E) The following certification statement by such CAIR authorized 
account representative or alternate CAIR authorized account 
representative: ``Until this notice of delegation is superseded by 
another notice of delegation under 40 CFR 97.151(b)(5)(iv), I agree to 
maintain an e-mail account and to notify the Administrator immediately 
of any change in my e-mail address unless all delegation of authority by 
me under 40 CFR 97.151(b)(5) is terminated.''.
    (iv) A notice of delegation submitted under paragraph (b)(5)(iii) of 
this section shall be effective, with regard to the CAIR authorized 
account representative or alternate CAIR authorized account 
representative identified in such notice, upon receipt of such notice by 
the Administrator and until receipt by the Administrator of a 
superseding notice of delegation submitted by such CAIR authorized 
account representative or alternate CAIR authorized account 
representative, as appropriate. The superseding notice of delegation may 
replace any previously identified agent, add a new agent, or eliminate 
entirely any delegation of authority.
    (v) Any electronic submission covered by the certification in 
paragraph (b)(5)(iii)(D) of this section and made in accordance with a 
notice of delegation effective under paragraph (b)(5)(iv) of this 
section shall be deemed to be an electronic submission by the CAIR 
designated representative or alternate CAIR designated representative 
submitting such notice of delegation.
    (c) Account identification. The Administrator will assign a unique 
identifying number to each account established under paragraph (a) or 
(b) of this section.



Sec. 97.152  Responsibilities of CAIR authorized account 
representative.

    Following the establishment of a CAIR NOX Allowance 
Tracking System account, all submissions to the Administrator pertaining 
to the account, including, but not limited to, submissions concerning 
the deduction or transfer of CAIR NOX allowances in the 
account, shall be made only by the CAIR authorized account 
representative for the account.

[[Page 247]]



Sec. 97.153  Recordation of CAIR NOX allowance allocations.

    (a) By September 30, 2007, the Administrator will record in the CAIR 
NOX source's compliance account the CAIR NOX 
allowances allocated for the CAIR NOX units at the source in 
accordance with Sec. 97.142(a) and (b) for the control period in 2009.
    (b) By September 30, 2008, the Administrator will record in the CAIR 
NOX source's compliance account the CAIR NOX 
allowances allocated for the CAIR NOX units at the source in 
accordance with Sec. 97.142(a) and (b) for the control period in 2010.
    (c) By September 30, 2009, the Administrator will record in the CAIR 
NOX source's compliance account the CAIR NOX 
allowances allocated for the CAIR NOX units at the source in 
accordance with Sec. 97.142(a) and (b) for the control periods in 2011, 
2012, and 2013.
    (d) By December 1, 2010 and December 1 of each year thereafter, the 
Administrator will record in the CAIR NOX source's compliance 
account the CAIR NOX allowances allocated for the CAIR 
NOX units at the source in accordance with Sec. 97.142(a) 
and (b) for the control period in the fourth year after the year of the 
applicable deadline for recordation under this paragraph.
    (e) By December 1, 2009 and December 1 of each year thereafter, the 
Administrator will record in the CAIR NOX source's compliance 
account the CAIR NOX allowances allocated for the CAIR 
NOX units at the source in accordance with Sec. 97.142(a) 
and (c) for the control period in the year of the applicable deadline 
for recordation under this paragraph.
    (f) Serial numbers for allocated CAIR NOX allowances. When recording 
the allocation of CAIR NOX allowances for a CAIR 
NOX unit in a compliance account, the Administrator will 
assign each CAIR NOX allowance a unique identification number 
that will include digits identifying the year of the control period for 
which the CAIR NOX allowance is allocated.



Sec. 97.154  Compliance with CAIR NOX emissions limitation.

    (a) Allowance transfer deadline. The CAIR NOX allowances 
are available to be deducted for compliance with a source's CAIR 
NOX emissions limitation for a control period in a given 
calendar year only if the CAIR NOX allowances:
    (1) Were allocated for the control period in the year or a prior 
year; and
    (2) Are held in the compliance account as of the allowance transfer 
deadline for the control period or are transferred into the compliance 
account by a CAIR NOX allowance transfer correctly submitted 
for recordation under Sec. Sec. 97.160 and 97.161 by the allowance 
transfer deadline for the control period.
    (b) Deductions for compliance. Following the recordation, in 
accordance with Sec. 97.161, of CAIR NOX allowance transfers 
submitted for recordation in a source's compliance account by the 
allowance transfer deadline for a control period, the Administrator will 
deduct from the compliance account CAIR NOX allowances 
available under paragraph (a) of this section in order to determine 
whether the source meets the CAIR NOX emissions limitation 
for the control period, as follows:
    (1) Until the amount of CAIR NOX allowances deducted 
equals the number of tons of total nitrogen oxides emissions, determined 
in accordance with subpart HH of this part, from all CAIR NOX 
units at the source for the control period; or
    (2) If there are insufficient CAIR NOX allowances to 
complete the deductions in paragraph (b)(1) of this section, until no 
more CAIR NOX allowances available under paragraph (a) of 
this section remain in the compliance account.
    (c)(1) Identification of CAIR NOX allowances by serial number. The 
CAIR authorized account representative for a source's compliance account 
may request that specific CAIR NOX allowances, identified by 
serial number, in the compliance account be deducted for emissions or 
excess emissions for a control period in accordance with paragraph (b) 
or (d) of this section. Such request shall be submitted to the 
Administrator by the allowance transfer deadline for the control period 
and include, in a format prescribed by the Administrator, the 
identification of the CAIR NOX source and the appropriate 
serial numbers.

[[Page 248]]

    (2) First-in, first-out. The Administrator will deduct CAIR 
NOX allowances under paragraph (b) or (d) of this section 
from the source's compliance account, in the absence of an 
identification or in the case of a partial identification of CAIR 
NOX allowances by serial number under paragraph (c)(1) of 
this section, on a first-in, first-out (FIFO) accounting basis in the 
following order:
    (i) Any CAIR NOX allowances that were allocated to the 
units at the source, in the order of recordation; and then
    (ii) Any CAIR NOX allowances that were allocated to any 
entity and transferred and recorded in the compliance account pursuant 
to subpart GG of this part, in the order of recordation.
    (d) Deductions for excess emissions. (1) After making the deductions 
for compliance under paragraph (b) of this section for a control period 
in a calendar year in which the CAIR NOX source has excess 
emissions, the Administrator will deduct from the source's compliance 
account an amount of CAIR NOX allowances, allocated for the 
control period in the immediately following calendar year, equal to 3 
times the number of tons of the source's excess emissions.
    (2) Any allowance deduction required under paragraph (d)(1) of this 
section shall not affect the liability of the owners and operators of 
the CAIR NOX source or the CAIR NOX units at the 
source for any fine, penalty, or assessment, or their obligation to 
comply with any other remedy, for the same violations, as ordered under 
the Clean Air Act or applicable State law.
    (e) Recordation of deductions. The Administrator will record in the 
appropriate compliance account all deductions from such an account under 
paragraphs (b) and (d) of this section and subpart II.
    (f) Administrator's action on submissions. (1) The Administrator may 
review and conduct independent audits concerning any submission under 
the CAIR NOX Annual Trading Program and make appropriate 
adjustments of the information in the submissions.
    (2) The Administrator may deduct CAIR NOX allowances from 
or transfer CAIR NOX allowances to a source's compliance 
account based on the information in the submissions, as adjusted under 
paragraph (f)(1) of this section, and record such deductions and 
transfers.



Sec. 97.155  Banking.

    (a) CAIR NOX allowances may be banked for future use or 
transfer in a compliance account or a general account in accordance with 
paragraph (b) of this section.
    (b) Any CAIR NOX allowance that is held in a compliance 
account or a general account will remain in such account unless and 
until the CAIR NOX allowance is deducted or transferred under 
Sec. 97.142, Sec. 97.154, Sec. 97.156, or subpart GG or II of this 
part.



Sec. 97.156  Account error.

    The Administrator may, at his or her sole discretion and on his or 
her own motion, correct any error in any CAIR NOX Allowance 
Tracking System account. Within 10 business days of making such 
correction, the Administrator will notify the CAIR authorized account 
representative for the account.



Sec. 97.157  Closing of general accounts.

    (a) The CAIR authorized account representative of a general account 
may submit to the Administrator a request to close the account, which 
shall include a correctly submitted allowance transfer under Sec. Sec. 
97.160 and 97.161 for any CAIR NOX allowances in the account 
to one or more other CAIR NOX Allowance Tracking System 
accounts.
    (b) If a general account has no allowance transfers in or out of the 
account for a 12-month period or longer and does not contain any CAIR 
NOX allowances, the Administrator may notify the CAIR 
authorized account representative for the account that the account will 
be closed following 20 business days after the notice is sent. The 
account will be closed after the 20-day period unless, before the end of 
the 20-day period, the Administrator receives a correctly submitted 
transfer of CAIR NOX allowances into the account under 
Sec. Sec. 97.160 and 97.161 or a statement submitted by the CAIR 
authorized account representative demonstrating to the satisfaction of 
the Administrator good

[[Page 249]]

cause as to why the account should not be closed.



                 Subpart GG_CAIR NOX Allowance Transfers



Sec. 97.160  Submission of CAIR NOX allowance transfers.

    A CAIR authorized account representative seeking recordation of a 
CAIR NOX allowance transfer shall submit the transfer to the 
Administrator. To be considered correctly submitted, the CAIR 
NOX allowance transfer shall include the following elements, 
in a format specified by the Administrator:
    (a) The account numbers for both the transferor and transferee 
accounts;
    (b) The serial number of each CAIR NOX allowance that is 
in the transferor account and is to be transferred; and
    (c) The name and signature of the CAIR authorized account 
representative of the transferor account and the date signed.



Sec. 97.161  EPA recordation.

    (a) Within 5 business days (except as provided in paragraph (b) of 
this section) of receiving a CAIR NOX allowance transfer, the 
Administrator will record a CAIR NOX allowance transfer by 
moving each CAIR NOX allowance from the transferor account to 
the transferee account as specified by the request, provided that:
    (1) The transfer is correctly submitted under Sec. 97.160; and
    (2) The transferor account includes each CAIR NOX 
allowance identified by serial number in the transfer.
    (b) A CAIR NOX allowance transfer that is submitted for 
recordation after the allowance transfer deadline for a control period 
and that includes any CAIR NOX allowances allocated for any 
control period before such allowance transfer deadline will not be 
recorded until after the Administrator completes the deductions under 
Sec. 97.154 for the control period immediately before such allowance 
transfer deadline.
    (c) Where a CAIR NOX allowance transfer submitted for 
recordation fails to meet the requirements of paragraph (a) of this 
section, the Administrator will not record such transfer.



Sec. 97.162  Notification.

    (a) Notification of recordation. Within 5 business days of 
recordation of a CAIR NOX allowance transfer under Sec. 
97.161, the Administrator will notify the CAIR authorized account 
representatives of both the transferor and transferee accounts.
    (b) Notification of non-recordation. Within 10 business days of 
receipt of a CAIR NOX allowance transfer that fails to meet 
the requirements of Sec. 97.161(a), the Administrator will notify the 
CAIR authorized account representatives of both accounts subject to the 
transfer of:
    (1) A decision not to record the transfer, and
    (2) The reasons for such non-recordation.
    (c) Nothing in this section shall preclude the submission of a CAIR 
NOX allowance transfer for recordation following notification 
of non-recordation.



                   Subpart HH_Monitoring and Reporting



Sec. 97.170  General requirements.

    The owners and operators, and to the extent applicable, the CAIR 
designated representative, of a CAIR NOX unit, shall comply 
with the monitoring, recordkeeping, and reporting requirements as 
provided in this subpart and in subpart H of part 75 of this chapter. 
For purposes of complying with such requirements, the definitions in 
Sec. 97.102 and in Sec. 72.2 of this chapter shall apply, and the 
terms ``affected unit,'' ``designated representative,'' and ``continuous 
emission monitoring system'' or ``CEMS'') in part 75 of this chapter 
shall be deemed to refer to the terms ``CAIR NOX unit,`` 
``CAIR designated representative,'' and ``continuous emission monitoring 
system'' (or ``CEMS'') respectively, as defined in Sec. 97.102. The 
owner or operator of a unit that is not a CAIR NOX unit but 
that is monitored under Sec. 75.72(b)(2)(ii) of this chapter shall 
comply with the same monitoring, recordkeeping, and reporting 
requirements as a CAIR NOX unit.
    (a) Requirements for installation, certification, and data 
accounting. The owner or operator of each CAIR NOX unit 
shall:

[[Page 250]]

    (1) Install all monitoring systems required under this subpart for 
monitoring NOX mass emissions and individual unit heat input 
(including all systems required to monitor NOX emission rate, 
NOX concentration, stack gas moisture content, stack gas flow 
rate, CO2 or O2 concentration, and fuel flow rate, 
as applicable, in accordance with (Sec. Sec. 75.71 and 75.72 of this 
chapter);
    (2) Successfully complete all certification tests required under 
Sec. 97.171 and meet all other requirements of this subpart and part 75 
of this chapter applicable to the monitoring systems under paragraph 
(a)(1) of this section; and
    (3) Record, report, and quality-assure the data from the monitoring 
systems under paragraph (a)(1) of this section.
    (b) Compliance deadlines. Except as provided in paragraph (e) of 
this section, the owner or operator shall meet the monitoring system 
certification and other requirements of paragraphs (a)(1) and (2) of 
this section on or before the following dates. The owner or operator 
shall record, report, and quality-assure the data from the monitoring 
systems under paragraph (a)(1) of this section on and after the 
following dates.
    (1) For the owner or operator of a CAIR NOX unit that 
commences commercial operation before July 1, 2007, by January 1, 2008.
    (2) For the owner or operator of a CAIR NOX unit that 
commences commercial operation on or after July 1, 2007, by the later of 
the following dates:
    (i) January 1, 2008; or
    (ii) 90 unit operating days or 180 calendar days, whichever occurs 
first, after the date on which the unit commences commercial operation.
    (3) For the owner or operator of a CAIR NOX unit for 
which construction of a new stack or flue or installation of add-on 
NOX emission controls is completed after the applicable 
deadline under paragraph (b)(1), (2), (4), or (5) of this section, by 90 
unit operating days or 180 calendar days, whichever occurs first, after 
the date on which emissions first exit to the atmosphere through the new 
stack or flue or add-on NOX emissions controls.
    (4) Notwithstanding the dates in paragraphs (b)(1) and (2) of this 
section, for the owner or operator of a unit for which a CAIR opt-in 
permit application is submitted and not withdrawn and a CAIR opt-in 
permit is not yet issued or denied under subpart II of this part, by the 
date specified in Sec. 97.184(b).
    (5) Notwithstanding the dates in paragraphs (b)(1) and (2) of this 
section, for the owner or operator of a CAIR NOX opt-in unit 
under subpart II of this part, by the date on which the CAIR 
NOX opt-in unit enters the CAIR NOX Annual Trading 
Program as provided in Sec. 97.184(g).
    (c) Reporting data. The owner or operator of a CAIR NOX 
unit that does not meet the applicable compliance date set forth in 
paragraph (b) of this section for any monitoring system under paragraph 
(a)(1) of this section shall, for each such monitoring system, 
determine, record, and report maximum potential (or, as appropriate, 
minimum potential) values for NOX concentration, 
NOX emission rate, stack gas flow rate, stack gas moisture 
content, fuel flow rate, and any other parameters required to determine 
NOX mass emissions and heat input in accordance with Sec. 
75.31(b)(2) or (c)(3) of this chapter, section 2.4 of appendix D to part 
75 of this chapter, or section 2.5 of appendix E to part 75 of this 
chapter, as applicable.
    (d) Prohibitions. (1) No owner or operator of a CAIR NOX 
unit shall use any alternative monitoring system, alternative reference 
method, or any other alternative to any requirement of this subpart 
without having obtained prior written approval in accordance with Sec. 
97.175.
    (2) No owner or operator of a CAIR NOX unit shall operate 
the unit so as to discharge, or allow to be discharged, NOX 
emissions to the atmosphere without accounting for all such emissions in 
accordance with the applicable provisions of this subpart and part 75 of 
this chapter.
    (3) No owner or operator of a CAIR NOX unit shall disrupt 
the continuous emission monitoring system, any portion thereof, or any 
other approved emission monitoring method, and thereby avoid monitoring 
and recording NOX mass emissions discharged

[[Page 251]]

into the atmosphere or heat input, except for periods of recertification 
or periods when calibration, quality assurance testing, or maintenance 
is performed in accordance with the applicable provisions of this 
subpart and part 75 of this chapter.
    (4) No owner or operator of a CAIR NOX unit shall retire 
or permanently discontinue use of the continuous emission monitoring 
system, any component thereof, or any other approved monitoring system 
under this subpart, except under any one of the following circumstances:
    (i) During the period that the unit is covered by an exemption under 
Sec. 97.105 that is in effect;
    (ii) The owner or operator is monitoring emissions from the unit 
with another certified monitoring system approved, in accordance with 
the applicable provisions of this subpart and part 75 of this chapter, 
by the Administrator for use at that unit that provides emission data 
for the same pollutant or parameter as the retired or discontinued 
monitoring system; or
    (iii) The CAIR designated representative submits notification of the 
date of certification testing of a replacement monitoring system for the 
retired or discontinued monitoring system in accordance with Sec. 
97.171(d)(3)(i).
    (e) Long-term cold storage. The owner or operator of a CAIR 
NOX unit is subject to the applicable provisions of part 75 
of this chapter concerning units in long-term cold storage.



Sec. 97.171  Initial certification and recertification procedures.

    (a) The owner or operator of a CAIR NOX unit shall be 
exempt from the initial certification requirements of this section for a 
monitoring system under Sec. 97.170(a)(1) if the following conditions 
are met:
    (1) The monitoring system has been previously certified in 
accordance with part 75 of this chapter; and
    (2) The applicable quality-assurance and quality-control 
requirements of Sec. 75.21 of this chapter and appendix B, appendix D, 
and appendix E to part 75 of this chapter are fully met for the 
certified monitoring system described in paragraph (a)(1) of this 
section.
    (b) The recertification provisions of this section shall apply to a 
monitoring system under Sec. 97.170(a)(1) exempt from initial 
certification requirements under paragraph (a) of this section.
    (c) If the Administrator has previously approved a petition under 
Sec. 75.17(a) or (b) of this chapter for apportioning the 
NOX emission rate measured in a common stack or a petition 
under Sec. 75.66 of this chapter for an alternative to a requirement in 
Sec. 75.12 or Sec. 75.17 of this chapter, the CAIR designated 
representative shall resubmit the petition to the Administrator under 
Sec. 97.175 to determine whether the approval applies under the CAIR 
NOX Annual Trading Program.
    (d) Except as provided in paragraph (a) of this section, the owner 
or operator of a CAIR NOX unit shall comply with the 
following initial certification and recertification procedures for a 
continuous monitoring system (i.e., a continuous emission monitoring 
system and an excepted monitoring system under appendices D and E to 
part 75 of this chapter) under Sec. 97.170(a)(1). The owner or operator 
of a unit that qualifies to use the low mass emissions excepted 
monitoring methodology under Sec. 75.19 of this chapter or that 
qualifies to use an alternative monitoring system under subpart E of 
part 75 of this chapter shall comply with the procedures in paragraph 
(e) or (f) of this section respectively.
    (1) Requirements for initial certification. The owner or operator 
shall ensure that each continuous monitoring system under Sec. 
97.170(a)(1) (including the automated data acquisition and handling 
system) successfully completes all of the initial certification testing 
required under Sec. 75.20 of this chapter by the applicable deadline in 
Sec. 97.170(b). In addition, whenever the owner or operator installs a 
monitoring system to meet the requirements of this subpart in a location 
where no such monitoring system was previously installed, initial 
certification in accordance with Sec. 75.20 of this chapter is 
required.
    (2) Requirements for recertification. Whenever the owner or operator 
makes a replacement, modification, or change in any certified continuous 
emission monitoring system under Sec. 97.170(a)(1)

[[Page 252]]

that may significantly affect the ability of the system to accurately 
measure or record NOX mass emissions or heat input rate or to 
meet the quality-assurance and quality-control requirements of Sec. 
75.21 of this chapter or appendix B to part 75 of this chapter, the 
owner or operator shall recertify the monitoring system in accordance 
with Sec. 75.20(b) of this chapter. Furthermore, whenever the owner or 
operator makes a replacement, modification, or change to the flue gas 
handling system or the unit's operation that may significantly change 
the stack flow or concentration profile, the owner or operator shall 
recertify each continuous emission monitoring system whose accuracy is 
potentially affected by the change, in accordance with Sec. 75.20(b) of 
this chapter. Examples of changes to a continuous emission monitoring 
system that require recertification include replacement of the analyzer, 
complete replacement of an existing continuous emission monitoring 
system, or change in location or orientation of the sampling probe or 
site. Any fuel flowmeter system, and any excepted NOX 
monitoring system under appendix E to part 75 of this chapter, under 
Sec. 97.170(a)(1) are subject to the recertification requirements in 
Sec. 75.20(g)(6) of this chapter.
    (3) Approval process for initial certification and recertification. 
Paragraphs (d)(3)(i) through (iv) of this section apply to both initial 
certification and recertification of a continuous monitoring system 
under Sec. 97.170(a)(1). For recertifications, replace the words 
``certification'' and ``initial certification'' with the word 
``recertification'', replace the word ``certified'' with the word 
``recertified'', and follow the procedures in Sec. Sec. 75.20(b)(5) and 
(g)(7) of this chapter in lieu of the procedures in paragraph (d)(3)(v) 
of this section.
    (i) Notification of certification. The CAIR designated 
representative shall submit to the appropriate EPA Regional Office and 
the Administrator written notice of the dates of certification testing, 
in accordance with Sec. 97.173.
    (ii) Certification application. The CAIR designated representative 
shall submit to the Administrator a certification application for each 
monitoring system. A complete certification application shall include 
the information specified in Sec. 75.63 of this chapter.
    (iii) Provisional certification date. The provisional certification 
date for a monitoring system shall be determined in accordance with 
Sec. 75.20(a)(3) of this chapter. A provisionally certified monitoring 
system may be used under the CAIR NOX Annual Trading Program 
for a period not to exceed 120 days after receipt by the Administrator 
of the complete certification application for the monitoring system 
under paragraph (d)(3)(ii) of this section. Data measured and recorded 
by the provisionally certified monitoring system, in accordance with the 
requirements of part 75 of this chapter, will be considered valid 
quality-assured data (retroactive to the date and time of provisional 
certification), provided that the Administrator does not invalidate the 
provisional certification by issuing a notice of disapproval within 120 
days of the date of receipt of the complete certification application by 
the Administrator.
    (iv) Certification application approval process. The Administrator 
will issue a written notice of approval or disapproval of the 
certification application to the owner or operator within 120 days of 
receipt of the complete certification application under paragraph 
(d)(3)(ii) of this section. In the event the Administrator does not 
issue such a notice within such 120-day period, each monitoring system 
that meets the applicable performance requirements of part 75 of this 
chapter and is included in the certification application will be deemed 
certified for use under the CAIR NOX Annual Trading Program.
    (A) Approval notice. If the certification application is complete 
and shows that each monitoring system meets the applicable performance 
requirements of part 75 of this chapter, then the Administrator will 
issue a written notice of approval of the certification application 
within 120 days of receipt.
    (B) Incomplete application notice. If the certification application 
is not complete, then the Administrator will issue a written notice of 
incompleteness that sets a reasonable date by

[[Page 253]]

which the CAIR designated representative must submit the additional 
information required to complete the certification application. If the 
CAIR designated representative does not comply with the notice of 
incompleteness by the specified date, then the Administrator may issue a 
notice of disapproval under paragraph (d)(3)(iv)(C) of this section. The 
120-day review period shall not begin before receipt of a complete 
certification application.
    (C) Disapproval notice. If the certification application shows that 
any monitoring system does not meet the performance requirements of part 
75 of this chapter or if the certification application is incomplete and 
the requirement for disapproval under paragraph (d)(3)(iv)(B) of this 
section is met, then the Administrator will issue a written notice of 
disapproval of the certification application. Upon issuance of such 
notice of disapproval, the provisional certification is invalidated by 
the Administrator and the data measured and recorded by each uncertified 
monitoring system shall not be considered valid quality-assured data 
beginning with the date and hour of provisional certification (as 
defined under Sec. 75.20(a)(3) of this chapter). The owner or operator 
shall follow the procedures for loss of certification in paragraph 
(d)(3)(v) of this section for each monitoring system that is disapproved 
for initial certification.
    (D) Audit decertification. The Administrator may issue a notice of 
disapproval of the certification status of a monitor in accordance with 
Sec. 97.172(b).
    (v) Procedures for loss of certification. If the Administrator 
issues a notice of disapproval of a certification application under 
paragraph (d)(3)(iv)(C) of this section or a notice of disapproval of 
certification status under paragraph (d)(3)(iv)(D) of this section, 
then:
    (A) The owner or operator shall substitute the following values, for 
each disapproved monitoring system, for each hour of unit operation 
during the period of invalid data specified under Sec. 
75.20(a)(4)(iii), Sec. 75.20(g)(7), or Sec. 75.21(e) of this chapter 
and continuing until the applicable date and hour specified under Sec. 
75.20(a)(5)(i) or (g)(7) of this chapter:
    (1) For a disapproved NOX emission rate (i.e.,, 
NOX-diluent) system, the maximum potential NOX 
emission rate, as defined in Sec. 72.2 of this chapter.
    (2) For a disapproved NOX pollutant concentration monitor 
and disapproved flow monitor, respectively, the maximum potential 
concentration of NOX and the maximum potential flow rate, as 
defined in sections 2.1.2.1 and 2.1.4.1 of appendix A to part 75 of this 
chapter.
    (3) For a disapproved moisture monitoring system and disapproved 
diluent gas monitoring system, respectively, the minimum potential 
moisture percentage and either the maximum potential CO2 
concentration or the minimum potential O2 concentration (as 
applicable), as defined in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of 
appendix A to part 75 of this chapter.
    (4) For a disapproved fuel flowmeter system, the maximum potential 
fuel flow rate, as defined in section 2.4.2.1 of appendix D to part 75 
of this chapter.
    (5) For a disapproved excepted NOX monitoring system 
under appendix E to part 75 of this chapter, the fuel-specific maximum 
potential NOX emission rate, as defined in Sec. 72.2 of this 
chapter.
    (B) The CAIR designated representative shall submit a notification 
of certification retest dates and a new certification application in 
accordance with paragraphs (d)(3)(i) and (ii) of this section.
    (C) The owner or operator shall repeat all certification tests or 
other requirements that were failed by the monitoring system, as 
indicated in the Administrator's notice of disapproval, no later than 30 
unit operating days after the date of issuance of the notice of 
disapproval.
    (e) Initial certification and recertification procedures for units 
using the low mass emission excepted methodology under Sec. 75.19 of 
this chapter. The owner or operator of a unit qualified to use the low 
mass emissions (LME) excepted methodology under Sec. 75.19 of this 
chapter shall meet the applicable certification and recertification 
requirements in Sec. Sec. 75.19(a)(2) and 75.20(h) of this chapter. If 
the owner or operator of such a unit elects to certify a fuel flowmeter 
system for heat input determination, the owner or operator shall

[[Page 254]]

also meet the certification and recertification requirements in Sec. 
75.20(g) of this chapter.
    (f) Certification/recertification procedures for alternative 
monitoring systems. The CAIR designated representative of each unit for 
which the owner or operator intends to use an alternative monitoring 
system approved by the Administrator under subpart E of part 75 of this 
chapter shall comply with the applicable notification and application 
procedures of Sec. 75.20(f) of this chapter.



Sec. 97.172  Out of control periods.

    (a) Whenever any monitoring system fails to meet the quality-
assurance and quality-control requirements or data validation 
requirements of part 75 of this chapter, data shall be substituted using 
the applicable missing data procedures in subpart D or subpart H of, or 
appendix D or appendix E to, part 75 of this chapter.
    (b) Audit decertification. Whenever both an audit of a monitoring 
system and a review of the initial certification or recertification 
application reveal that any monitoring system should not have been 
certified or recertified because it did not meet a particular 
performance specification or other requirement under Sec. 97.171 or the 
applicable provisions of part 75 of this chapter, both at the time of 
the initial certification or recertification application submission and 
at the time of the audit, the Administrator will issue a notice of 
disapproval of the certification status of such monitoring system. For 
the purposes of this paragraph, an audit shall be either a field audit 
or an audit of any information submitted to the permitting authority or 
the Administrator. By issuing the notice of disapproval, the 
Administrator revokes prospectively the certification status of the 
monitoring system. The data measured and recorded by the monitoring 
system shall not be considered valid quality-assured data from the date 
of issuance of the notification of the revoked certification status 
until the date and time that the owner or operator completes 
subsequently approved initial certification or recertification tests for 
the monitoring system. The owner or operator shall follow the applicable 
initial certification or recertification procedures in Sec. 97.171 for 
each disapproved monitoring system.



Sec. 97.173  Notifications.

    The CAIR designated representative for a CAIR NOX unit 
shall submit written notice to the Administrator in accordance with 
Sec. 75.61 of this chapter.



Sec. 97.174  Recordkeeping and reporting.

    (a) General provisions. The CAIR designated representative shall 
comply with all recordkeeping and reporting requirements in this 
section, the applicable recordkeeping and reporting requirements under 
Sec. 75.73 of this chapter, and the requirements of Sec. 97.110(e)(1).
    (b) Monitoring plans. The owner or operator of a CAIR NOX 
unit shall comply with requirements of Sec. 75.73(c) and (e) of this 
chapter and, for a unit for which a CAIR opt-in permit application is 
submitted and not withdrawn and a CAIR opt-in permit is not yet issued 
or denied under subpart II of this part, Sec. Sec. 97.183 and 
97.184(a).
    (c) Certification applications. The CAIR designated representative 
shall submit an application to the Administrator within 45 days after 
completing all initial certification or recertification tests required 
under Sec. 97.171, including the information required under Sec. 75.63 
of this chapter.
    (d) Quarterly reports. The CAIR designated representative shall 
submit quarterly reports, as follows:
    (1) The CAIR designated representative shall report the 
NOX mass emissions data and heat input data for the CAIR 
NOX unit, in an electronic quarterly report in a format 
prescribed by the Administrator, for each calendar quarter beginning 
with:
    (i) For a unit that commences commercial operation before July 1, 
2007, the calendar quarter covering January 1, 2008 through March 31, 
2008;
    (ii) For a unit that commences commercial operation on or after July 
1, 2007, the calendar quarter corresponding to the earlier of the date 
of provisional certification or the applicable deadline for initial 
certification under Sec. 97.170(b), unless that quarter is the third or 
fourth quarter of 2007, in which case reporting shall commence

[[Page 255]]

in the quarter covering January 1, 2008 through March 31, 2008;
    (iii) Notwithstanding paragraphs (d)(1)(i) and (ii) of this section, 
for a unit for which a CAIR opt-in permit application is submitted and 
not withdrawn and a CAIR opt-in permit is not yet issued or denied under 
subpart II of this part, the calendar quarter corresponding to the date 
specified in Sec. 97.184(b); and
    (iv) Notwithstanding paragraphs (d)(1)(i) and (ii) of this section, 
for a CAIR NOX opt-in unit under subpart II of this part, the 
calendar quarter corresponding to the date on which the CAIR 
NOX opt-in unit enters the CAIR NOX Annual Trading 
Program as provided in Sec. 97.184(g).
    (2) The CAIR designated representative shall submit each quarterly 
report to the Administrator within 30 days following the end of the 
calendar quarter covered by the report. Quarterly reports shall be 
submitted in the manner specified in Sec. 75.73(f) of this chapter.
    (3) For CAIR NOX units that are also subject to an Acid 
Rain emissions limitation or the CAIR NOX Ozone Season 
Trading Program, CAIR SO2 Trading Program, or Hg Budget 
Trading Program, quarterly reports shall include the applicable data and 
information required by subparts F through I of part 75 of this chapter 
as applicable, in addition to the NOX mass emission data, 
heat input data, and other information required by this subpart.
    (e) Compliance certification. The CAIR designated representative 
shall submit to the Administrator a compliance certification (in a 
format prescribed by the Administrator) in support of each quarterly 
report based on reasonable inquiry of those persons with primary 
responsibility for ensuring that all of the unit's emissions are 
correctly and fully monitored. The certification shall state that:
    (1) The monitoring data submitted were recorded in accordance with 
the applicable requirements of this subpart and part 75 of this chapter, 
including the quality assurance procedures and specifications; and
    (2) For a unit with add-on NOX emission controls and for 
all hours where NOX data are substituted in accordance with 
Sec. 75.34(a)(1) of this chapter, the add-on emission controls were 
operating within the range of parameters listed in the quality 
assurance/quality control program under appendix B to part 75 of this 
chapter and the substitute data values do not systematically 
underestimate NOX emissions.



Sec. 97.175  Petitions.

    The CAIR designated representative of a CAIR NOX unit may 
submit a petition under Sec. 75.66 of this chapter to the Administrator 
requesting approval to apply an alternative to any requirement of this 
subpart. Application of an alternative to any requirement of this 
subpart is in accordance with this subpart only to the extent that the 
petition is approved in writing by the Administrator, in consultation 
with the permitting authority.



                    Subpart II_CAIR NOX Opt-In Units



Sec. 97.180  Applicability.

    A CAIR NOX opt-in unit must be a unit that:
    (a) Is located in a State that submits, and for which the 
Administrator approves, a State implementation plan revision in 
accordance with Sec. 51.123(p)(3)(i), (ii), or (iii) of this chapter 
establishing procedures concerning CAIR opt-in units;
    (b) Is not a CAIR NOX unit under Sec. 97.104 and is not 
covered by a retired unit exemption under Sec. 97.105 that is in 
effect;
    (c) Is not covered by a retired unit exemption under Sec. 72.8 of 
this chapter that is in effect;
    (d) Has or is required or qualified to have a title V operating 
permit or other federally enforceable permit; and
    (e) Vents all of its emissions to a stack and can meet the 
monitoring, recordkeeping, and reporting requirements of subpart HH of 
this part.



Sec. 97.181  General.

    (a) Except as otherwise provided in Sec. Sec. 97.101 through 
97.104, Sec. Sec. 97.106 through 97.108, and subparts BB and CC and 
subparts FF through HH of this part, a CAIR NOX opt-in unit 
shall be treated as a CAIR NOX unit for purposes of applying 
such sections and subparts of this part.

[[Page 256]]

    (b) Solely for purposes of applying, as provided in this subpart, 
the requirements of subpart HH of this part to a unit for which a CAIR 
opt-in permit application is submitted and not withdrawn and a CAIR opt-
in permit is not yet issued or denied under this subpart, such unit 
shall be treated as a CAIR NOX unit before issuance of a CAIR 
opt-in permit for such unit.



Sec. 97.182  CAIR designated representative.

    Any CAIR NOX opt-in unit, and any unit for which a CAIR 
opt-in permit application is submitted and not withdrawn and a CAIR opt-
in permit is not yet issued or denied under this subpart, located at the 
same source as one or more CAIR NOX units shall have the same 
CAIR designated representative and alternate CAIR designated 
representative as such CAIR NOX units.



Sec. 97.183  Applying for CAIR opt-in permit.

    (a) Applying for initial CAIR opt-in permit. The CAIR designated 
representative of a unit meeting the requirements for a CAIR 
NOX opt-in unit in Sec. 97.180 may apply for an initial CAIR 
opt-in permit at any time, except as provided under Sec. 97.186(f) and 
(g), and, in order to apply, must submit the following:
    (1) A complete CAIR permit application under Sec. 97.122;
    (2) A certification, in a format specified by the permitting 
authority, that the unit:
    (i) Is not a CAIR NOX unit under Sec. 97.104 and is not 
covered by a retired unit exemption under Sec. 97.105 that is in 
effect;
    (ii) Is not covered by a retired unit exemption under Sec. 72.8 of 
this chapter that is in effect;
    (iii) Vents all of its emissions to a stack; and
    (iv) Has documented heat input for more than 876 hours during the 6 
months immediately preceding submission of the CAIR permit application 
under Sec. 97.122;
    (3) A monitoring plan in accordance with subpart HH of this part;
    (4) A complete certificate of representation under Sec. 97.113 
consistent with Sec. 97.182, if no CAIR designated representative has 
been previously designated for the source that includes the unit; and
    (5) A statement, in a format specified by the permitting authority, 
whether the CAIR designated representative requests that the unit be 
allocated CAIR NOX allowances under Sec. 97.188(b) or Sec. 
97.188(c) (subject to the conditions in Sec. Sec. 97.184(h) and 
97.186(g)), to the extent such allocation is provided in a State 
implementation plan revision submitted in accordance with Sec. 
51.123(p)(3)(i), (ii), or (iii) of this chapter and approved by the 
Administrator. If allocation under Sec. 97.188(c) is requested, this 
statement shall include a statement that the owners and operators of the 
unit intend to repower the unit before January 1, 2015 and that they 
will provide, upon request, documentation demonstrating such intent.
    (b) Duty to reapply. (1) The CAIR designated representative of a 
CAIR NOX opt-in unit shall submit a complete CAIR permit 
application under Sec. 97.122 to renew the CAIR opt-in unit permit in 
accordance with the permitting authority's regulations for title V 
operating permits, or the permitting authority's regulations for other 
federally enforceable permits if applicable, addressing permit renewal.
    (2) Unless the permitting authority issues a notification of 
acceptance of withdrawal of the CAIR NOX opt-in unit from the 
CAIR NOX Annual Trading Program in accordance with Sec. 
97.186 or the unit becomes a CAIR NOX unit under Sec. 
97.104, the CAIR NOX opt-in unit shall remain subject to the 
requirements for a CAIR NOX opt-in unit, even if the CAIR 
designated representative for the CAIR NOX opt-in unit fails 
to submit a CAIR permit application that is required for renewal of the 
CAIR opt-in permit under paragraph (b)(1) of this section.



Sec. 97.184  Opt-in process.

    The permitting authority will issue or deny a CAIR opt-in permit for 
a unit for which an initial application for a CAIR opt-in permit under 
Sec. 97.183 is submitted in accordance with the following, to the 
extent provided in a State implementation plan revision submitted in 
accordance with Sec. 51.123(p)(3)(i), (ii), or (iii) of this chapter 
and approved by the Administrator:

[[Page 257]]

    (a) Interim review of monitoring plan. The permitting authority and 
the Administrator will determine, on an interim basis, the sufficiency 
of the monitoring plan accompanying the initial application for a CAIR 
opt-in permit under Sec. 97.183. A monitoring plan is sufficient, for 
purposes of interim review, if the plan appears to contain information 
demonstrating that the NOX emissions rate and heat input of 
the unit and all other applicable parameters are monitored and reported 
in accordance with subpart HH of this part. A determination of 
sufficiency shall not be construed as acceptance or approval of the 
monitoring plan.
    (b) Monitoring and reporting. (1)(i) If the permitting authority and 
the Administrator determine that the monitoring plan is sufficient under 
paragraph (a) of this section, the owner or operator shall monitor and 
report the NOX emissions rate and the heat input of the unit 
and all other applicable parameters, in accordance with subpart HH of 
this part, starting on the date of certification of the appropriate 
monitoring systems under subpart HH of this part and continuing until a 
CAIR opt-in permit is denied under Sec. 97.184(f) or, if a CAIR opt-in 
permit is issued, the date and time when the unit is withdrawn from the 
CAIR NOX Annual Trading Program in accordance with Sec. 
97.186.
    (ii) The monitoring and reporting under paragraph (b)(1)(i) of this 
section shall include the entire control period immediately before the 
date on which the unit enters the CAIR NOX Annual Trading 
Program under Sec. 97.184(g), during which period monitoring system 
availability must not be less than 90 percent under subpart HH of this 
part and the unit must be in full compliance with any applicable State 
or Federal emissions or emissions-related requirements.
    (2) To the extent the NOX emissions rate and the heat 
input of the unit are monitored and reported in accordance with subpart 
HH of this part for one or more control periods, in addition to the 
control period under paragraph (b)(1)(ii) of this section, during which 
control periods monitoring system availability is not less than 90 
percent under subpart HH of this part and the unit is in full compliance 
with any applicable State or Federal emissions or emissions-related 
requirements and which control periods begin not more than 3 years 
before the unit enters the CAIR NOX Annual Trading Program 
under Sec. 97.184(g), such information shall be used as provided in 
paragraphs (c) and (d) of this section.
    (c) Baseline heat input. The unit's baseline heat input shall equal:
    (1) If the unit's NOX emissions rate and heat input are 
monitored and reported for only one control period, in accordance with 
paragraph (b)(1) of this section, the unit's total heat input (in mmBtu) 
for the control period; or
    (2) If the unit's NOX emissions rate and heat input are 
monitored and reported for more than one control period, in accordance 
with paragraphs (b)(1) and (2) of this section, the average of the 
amounts of the unit's total heat input (in mmBtu) for the control 
periods under paragraphs (b)(1)(ii) and (2) of this section.
    (d) Baseline NOX emission rate. The unit's baseline NOX 
emission rate shall equal:
    (1) If the unit's NOX emissions rate and heat input are 
monitored and reported for only one control period, in accordance with 
paragraph (b)(1) of this section, the unit's NOX emissions 
rate (in lb/mmBtu) for the control period;
    (2) If the unit's NOX emissions rate and heat input are 
monitored and reported for more than one control period, in accordance 
with paragraphs (b)(1) and (2) of this section, and the unit does not 
have add-on NOX emission controls during any such control 
periods, the average of the amounts of the unit's NOX 
emissions rate (in lb/mmBtu) for the control periods under paragraphs 
(b)(1)(ii) and (2) of this section; or
    (3) If the unit's NOX emissions rate and heat input are 
monitored and reported for more than one control period, in accordance 
with paragraphs (b)(1) and (2) of this section, and the unit has add-on 
NOX emission controls during any such control periods, the 
average of the amounts of the unit's NOX emissions rate (in 
lb/mmBtu) for such control periods during which the unit has add-on 
NOX emission controls.

[[Page 258]]

    (e) Issuance of CAIR opt-in permit. After calculating the baseline 
heat input and the baseline NOX emissions rate for the unit 
under paragraphs (c) and (d) of this section and if the permitting 
authority determines that the CAIR designated representative shows that 
the unit meets the requirements for a CAIR NOX opt-in unit in 
Sec. 97.180 and meets the elements certified in Sec. 97.183(a)(2), the 
permitting authority will issue a CAIR opt-in permit. The permitting 
authority will provide a copy of the CAIR opt-in permit to the 
Administrator, who will then establish a compliance account for the 
source that includes the CAIR NOX opt-in unit unless the 
source already has a compliance account.
    (f) Issuance of denial of CAIR opt-in permit. Notwithstanding 
paragraphs (a) through (e) of this section, if at any time before 
issuance of a CAIR opt-in permit for the unit, the permitting authority 
determines that the CAIR designated representative fails to show that 
the unit meets the requirements for a CAIR NOX opt-in unit in 
Sec. 97.180 or meets the elements certified in Sec. 97.183(a)(2), the 
permitting authority will issue a denial of a CAIR opt-in permit for the 
unit.
    (g) Date of entry into CAIR NOX Annual Trading Program. A 
unit for which an initial CAIR opt-in permit is issued by the permitting 
authority shall become a CAIR NOX opt-in unit, and a CAIR 
NOX unit, as of the later of January 1, 2009 or January 1 of 
the first control period during which such CAIR opt-in permit is issued.
    (h) Repowered CAIR NOX opt-in unit. (1) If CAIR 
designated representative requests, and the permitting authority issues 
a CAIR opt-in permit providing for, allocation to a CAIR NOX 
opt-in unit of CAIR NOX allowances under Sec. 97.188(c) and 
such unit is repowered after its date of entry into the CAIR 
NOX Annual Trading Program under paragraph (g) of this 
section, the repowered unit shall be treated as a CAIR NOX 
opt-in unit replacing the original CAIR NOX opt-in unit, as 
of the date of start-up of the repowered unit's combustion chamber.
    (2) Notwithstanding paragraphs (c) and (d) of this section, as of 
the date of start-up under paragraph (h)(1) of this section, the 
repowered unit shall be deemed to have the same date of commencement of 
operation, date of commencement of commercial operation, baseline heat 
input, and baseline NOX emission rate as the original CAIR 
NOX opt-in unit, and the original CAIR NOX opt-in 
unit shall no longer be treated as a CAIR NOX opt-in unit or 
a CAIR NOX unit.

[65 FR 2727, Jan. 18, 2000, as amended at 71 FR 74795, Dec. 13, 2006]



Sec. 97.185  CAIR opt-in permit contents.

    (a) Each CAIR opt-in permit will contain:
    (1) All elements required for a complete CAIR permit application 
under Sec. 97.122;
    (2) The certification in Sec. 97.183(a)(2);
    (3) The unit's baseline heat input under Sec. 97.184(c);
    (4) The unit's baseline NOX emission rate under Sec. 
97.184(d);
    (5) A statement whether the unit is to be allocated CAIR 
NOX allowances under Sec. 97.188(b) or Sec. 97.188(c) 
(subject to the conditions in Sec. Sec. 97.184(h) and 97.186(g));
    (6) A statement that the unit may withdraw from the CAIR 
NOX Annual Trading Program only in accordance with Sec. 
97.186; and
    (7) A statement that the unit is subject to, and the owners and 
operators of the unit must comply with, the requirements of Sec. 
97.187.
    (b) Each CAIR opt-in permit is deemed to incorporate automatically 
the definitions of terms under Sec. 97.102 and, upon recordation by the 
Administrator under subpart FF or GG of this part or this subpart, every 
allocation, transfer, or deduction of CAIR NOX allowances to 
or from the compliance account of the source that includes a CAIR 
NOX opt-in unit covered by the CAIR opt-in permit.
    (c) The CAIR opt-in permit shall be included, in a format specified 
by the permitting authority, in the CAIR permit for the source where the 
CAIR NOX opt-in unit is located and in a title V operating 
permit or other federally enforceable permit for the source.

[[Page 259]]



Sec. 97.186  Withdrawal from CAIR NOX Annual Trading Program.

    Except as provided under paragraph (g) of this section, a CAIR 
NOX opt-in unit may withdraw from the CAIR NOX 
Annual Trading Program, but only if the permitting authority issues a 
notification to the CAIR designated representative of the CAIR 
NOX opt-in unit of the acceptance of the withdrawal of the 
CAIR NOX opt-in unit in accordance with paragraph (d) of this 
section.
    (a) Requesting withdrawal. In order to withdraw a CAIR 
NOX opt-in unit from the CAIR NOX Annual Trading 
Program, the CAIR designated representative of the CAIR NOX 
opt-in unit shall submit to the permitting authority a request to 
withdraw effective as of midnight of December 31 of a specified calendar 
year, which date must be at least 4 years after December 31 of the year 
of entry into the CAIR NOX Annual Trading Program under Sec. 
97.184(g). The request must be submitted no later than 90 days before 
the requested effective date of withdrawal.
    (b) Conditions for withdrawal. Before a CAIR NOX opt-in 
unit covered by a request under paragraph (a) of this section may 
withdraw from the CAIR NOX Annual Trading Program and the 
CAIR opt-in permit may be terminated under paragraph (e) of this 
section, the following conditions must be met:
    (1) For the control period ending on the date on which the 
withdrawal is to be effective, the source that includes the CAIR 
NOX opt-in unit must meet the requirement to hold CAIR 
NOX allowances under Sec. 97.106(c) and cannot have any 
excess emissions.
    (2) After the requirement for withdrawal under paragraph (b)(1) of 
this section is met, the Administrator will deduct from the compliance 
account of the source that includes the CAIR NOX opt-in unit 
CAIR NOX allowances equal in amount to and allocated for the 
same or a prior control period as any CAIR NOX allowances 
allocated to the CAIR NOX opt-in unit under Sec. 97.188 for 
any control period for which the withdrawal is to be effective. If there 
are no remaining CAIR NOX units at the source, the 
Administrator will close the compliance account, and the owners and 
operators of the CAIR NOX opt-in unit may submit a CAIR 
NOX allowance transfer for any remaining CAIR NOX 
allowances to another CAIR NOX Allowance Tracking System in 
accordance with subpart GG of this part.
    (c) Notification. (1) After the requirements for withdrawal under 
paragraphs (a) and (b) of this section are met (including deduction of 
the full amount of CAIR NOX allowances required), the 
permitting authority will issue a notification to the CAIR designated 
representative of the CAIR NOX opt-in unit of the acceptance 
of the withdrawal of the CAIR NOX opt-in unit as of midnight 
on December 31 of the calendar year for which the withdrawal was 
requested.
    (2) If the requirements for withdrawal under paragraphs (a) and (b) 
of this section are not met, the permitting authority will issue a 
notification to the CAIR designated representative of the CAIR 
NOX opt-in unit that the CAIR NOX opt-in unit's 
request to withdraw is denied. Such CAIR NOX opt-in unit 
shall continue to be a CAIR NOX opt-in unit.
    (d) Permit amendment. After the permitting authority issues a 
notification under paragraph (c)(1) of this section that the 
requirements for withdrawal have been met, the permitting authority will 
revise the CAIR permit covering the CAIR NOX opt-in unit to 
terminate the CAIR opt-in permit for such unit as of the effective date 
specified under paragraph (c)(1) of this section. The unit shall 
continue to be a CAIR NOX opt-in unit until the effective 
date of the termination and shall comply with all requirements under the 
CAIR NOX Annual Trading Program concerning any control 
periods for which the unit is a CAIR NOX opt-in unit, even if 
such requirements arise or must be complied with after the withdrawal 
takes effect.
    (e) Reapplication upon failure to meet conditions of withdrawal. If 
the permitting authority denies the CAIR NOX opt-in unit's 
request to withdraw, the CAIR designated representative may submit 
another request to withdraw in accordance with paragraphs (a) and (b) of 
this section.
    (f) Ability to reapply to the CAIR NOX Annual Trading 
Program. Once a CAIR NOX opt-in unit withdraws from the

[[Page 260]]

CAIR NOX Annual Trading Program and its CAIR opt-in permit is 
terminated under this section, the CAIR designated representative may 
not submit another application for a CAIR opt-in permit under Sec. 
97.183 for such CAIR NOX opt-in unit before the date that is 
4 years after the date on which the withdrawal became effective. Such 
new application for a CAIR opt-in permit will be treated as an initial 
application for a CAIR opt-in permit under Sec. 97.184.
    (g) Inability to withdraw. Notwithstanding paragraphs (a) through 
(f) of this section, a CAIR NOX opt-in unit shall not be 
eligible to withdraw from the CAIR NOX Annual Trading Program 
if the CAIR designated representative of the CAIR NOX opt-in 
unit requests, and the permitting authority issues a CAIR NOX 
opt-in permit providing for, allocation to the CAIR NOX opt-
in unit of CAIR NOX allowances under Sec. 97.188(c).



Sec. 97.187  Change in regulatory status.

    (a) Notification. If a CAIR NOX opt-in unit becomes a 
CAIR NOX unit under Sec. 97.104, then the CAIR designated 
representative shall notify in writing the permitting authority and the 
Administrator of such change in the CAIR NOX opt-in unit's 
regulatory status, within 30 days of such change.
    (b) Permitting authority's and Administrator's actions. (1) If a 
CAIR NOX opt-in unit becomes a CAIR NOX unit under 
Sec. 97.104, the permitting authority will revise the CAIR 
NOX opt-in unit's CAIR opt-in permit to meet the requirements 
of a CAIR permit under Sec. 97.123, and remove the CAIR opt-in permit 
provisions, as of the date on which the CAIR NOX opt-in unit 
becomes a CAIR NOX unit under Sec. 97.104.
    (2)(i) The Administrator will deduct from the compliance account of 
the source that includes the CAIR NOX opt-in unit that 
becomes a CAIR NOX unit under Sec. 97.104, CAIR 
NOX allowances equal in amount to and allocated for the same 
or a prior control period as:
    (A) Any CAIR NOX allowances allocated to the CAIR 
NOX opt-in unit under Sec. 97.188 for any control period 
after the date on which the CAIR NOX opt-in unit becomes a 
CAIR NOX unit under Sec. 97.104; and
    (B) If the date on which the CAIR NOX opt-in unit becomes 
a CAIR NOX unit under Sec. 97.104 is not December 31, the 
CAIR NOX allowances allocated to the CAIR NOX opt-
in unit under Sec. 97.188 for the control period that includes the date 
on which the CAIR NOX opt-in unit becomes a CAIR 
NOX unit under Sec. 97.104, multiplied by the ratio of the 
number of days, in the control period, starting with the date on which 
the CAIR NOX opt-in unit becomes a CAIR NOX unit 
under Sec. 97.104 divided by the total number of days in the control 
period and rounded to the nearest whole allowance as appropriate.
    (ii) The CAIR designated representative shall ensure that the 
compliance account of the source that includes the CAIR NOX 
opt-in unit that becomes a CAIR NOX unit under Sec. 97.104 
contains the CAIR NOX allowances necessary for completion of 
the deduction under paragraph (b)(2)(i) of this section.
    (3)(i) For every control period after the date on which the CAIR 
NOX opt-in unit becomes a CAIR NOX unit under 
Sec. 97.104, the CAIR NOX opt-in unit will be allocated CAIR 
NOX allowances under Sec. 97.142.
    (ii) If the date on which the CAIR NOX opt-in unit 
becomes a CAIR NOX unit under Sec. 97.104 is not December 
31, the following amount of CAIR NOX allowances will be 
allocated to the CAIR NOX opt-in unit (as a CAIR 
NOX unit) under (97.142 for the control period that includes 
the date on which the CAIR NOX opt-in unit becomes a CAIR 
NOX unit under Sec. 97.104:
    (A) The amount of CAIR NOX allowances otherwise allocated 
to the CAIR NOX opt-in unit (as a CAIR NOX unit) 
under Sec. 97.142 for the control period multiplied by;
    (B) The ratio of the number of days, in the control period, starting 
with the date on which the CAIR NOX opt-in unit becomes a 
CAIR NOX unit under Sec. 97.104, divided by the total number 
of days in the control period; and
    (C) Rounded to the nearest whole allowance as appropriate.

[65 FR 2727, Jan. 18, 2000, as amended at 71 FR 74795, Dec. 13, 2006]

[[Page 261]]



Sec. 97.188  CAIR NOX allowance allocations to CAIR NOX opt-in units.

    (a) Timing requirements. (1) When the CAIR opt-in permit is issued 
under Sec. 97.184(e), the permitting authority will allocate CAIR 
NOX allowances to the CAIR NOX opt-in unit, and 
submit to the Administrator the allocation for the control period in 
which a CAIR NOX opt-in unit enters the CAIR NOX 
Annual Trading Program under Sec. 97.184(g), in accordance with 
paragraph (b) or (c) of this section.
    (2) By no later than October 31 of the control period after the 
control period in which a CAIR NOX opt-in unit enters the 
CAIR NOX Annual Trading Program under Sec. 97.184(g) and 
October 31 of each year thereafter, the permitting authority will 
allocate CAIR NOX allowances to the CAIR NOX opt-
in unit, and submit to the Administrator the allocation for the control 
period that includes such submission deadline and in which the unit is a 
CAIR NOX opt-in unit, in accordance with paragraph (b) or (c) 
of this section.
    (b) Calculation of allocation. For each control period for which a 
CAIR NOX opt-in unit is to be allocated CAIR NOX 
allowances, the permitting authority will allocate in accordance with 
the following procedures, if provided in a State implementation plan 
revision submitted in accordance with Sec. 51.123(p)(3)(i), (ii), or 
(iii) of this chapter and approved by the Administrator:
    (1) The heat input (in mmBtu) used for calculating the CAIR 
NOX allowance allocation will be the lesser of:
    (i) The CAIR NOX opt-in unit's baseline heat input 
determined under Sec. 97.184(c); or
    (ii) The CAIR NOX opt-in unit's heat input, as determined 
in accordance with subpart HH of this part, for the immediately prior 
control period, except when the allocation is being calculated for the 
control period in which the CAIR NOX opt-in unit enters the 
CAIR NOX Annual Trading Program under Sec. 97.184(g).
    (2) The NOX emission rate (in lb/mmBtu) used for 
calculating CAIR NOX allowance allocations will be the lesser 
of:
    (i) The CAIR NOX opt-in unit's baseline NOX 
emissions rate (in lb/mmBtu) determined under Sec. 97.184(d) and 
multiplied by 70 percent; or
    (ii) The most stringent State or Federal NOX emissions 
limitation applicable to the CAIR NOX opt-in unit at any time 
during the control period for which CAIR NOX allowances are 
to be allocated.
    (3) The permitting authority will allocate CAIR NOX 
allowances to the CAIR NOX opt-in unit in an amount equaling 
the heat input under paragraph (b)(1) of this section, multiplied by the 
NOX emission rate under paragraph (b)(2) of this section, 
divided by 2,000 lb/ton, and rounded to the nearest whole allowance as 
appropriate.
    (c) Notwithstanding paragraph (b) of this section and if the CAIR 
designated representative requests, and the permitting authority issues 
a CAIR opt-in permit (based on a demonstration of the intent to repower 
stated under Sec. 97.183(a)(5)) providing for, allocation to a CAIR 
NOX opt-in unit of CAIR NOX allowances under this 
paragraph (subject to the conditions in Sec. Sec. 97.184(h) and 
97.186(g)), the permitting authority will allocate to the CAIR 
NOX opt-in unit as follows, if provided in a State 
implementation plan revision submitted in accordance with 
(51.123(p)(3)(i), (ii), or (iii) of this chapter and approved by the 
Administrator:
    (1) For each control period in 2009 through 2014 for which the CAIR 
NOX opt-in unit is to be allocated CAIR NOX 
allowances,
    (i) The heat input (in mmBtu) used for calculating CAIR 
NOX allowance allocations will be determined as described in 
paragraph (b)(1) of this section.
    (ii) The NOX emission rate (in lb/mmBtu) used for 
calculating CAIR NOX allowance allocations will be the lesser 
of:
    (A) The CAIR NOX opt-in unit's baseline NOX 
emissions rate (in lb/mmBtu) determined under Sec. 97.184(d); or
    (B) The most stringent State or Federal NOX emissions 
limitation applicable to the CAIR NOX opt-in unit at any time 
during the control period in which the CAIR NOX opt-in unit 
enters the CAIR NOX Annual Trading Program under Sec. 
97.184(g).
    (iii) The permitting authority will allocate CAIR NOX 
allowances to the

[[Page 262]]

CAIR NOX opt-in unit in an amount equaling the heat input 
under paragraph (c)(1)(i) of this section, multiplied by the 
NOX emission rate under paragraph (c)(1)(ii) of this section, 
divided by 2,000 lb/ton, and rounded to the nearest whole allowance as 
appropriate.
    (2) For each control period in 2015 and thereafter for which the 
CAIR NOX opt-in unit is to be allocated CAIR NOX 
allowances,
    (i) The heat input (in mmBtu) used for calculating the CAIR 
NOX allowance allocations will be determined as described in 
paragraph (b)(1) of this section.
    (ii) The NOX emission rate (in lb/mmBtu) used for 
calculating the CAIR NOX allowance allocation will be the 
lesser of:
    (A) 0.15 lb/mmBtu;
    (B) The CAIR NOX opt-in unit's baseline NOX 
emissions rate (in lb/mmBtu) determined under Sec. 97.184(d); or
    (C) The most stringent State or Federal NOX emissions 
limitation applicable to the CAIR NOX opt-in unit at any time 
during the control period for which CAIR NOX allowances are 
to be allocated.
    (iii) The permitting authority will allocate CAIR NOX 
allowances to the CAIR NOX opt-in unit in an amount equaling 
the heat input under paragraph (c)(2)(i) of this section, multiplied by 
the NOX emission rate under paragraph (c)(2)(ii) of this 
section, divided by 2,000 lb/ton, and rounded to the nearest whole 
allowance as appropriate.
    (d) Recordation. If provided in a State implementation plan revision 
submitted in accordance with Sec. 51.123(p)(3)(i), (ii), or (iii) of 
this chapter and approved by the Administrator:
    (1) The Administrator will record, in the compliance account of the 
source that includes the CAIR NOX opt-in unit, the CAIR 
NOX allowances allocated by the permitting authority to the 
CAIR NOX opt-in unit under paragraph (a)(1) of this section.
    (2) By December 1 of the control period in which a CAIR 
NOX opt-in unit enters the CAIR NOX Annual Trading 
Program under Sec. 97.184(g) and December 1 of each year thereafter, 
the Administrator will record, in the compliance account of the source 
that includes the CAIR NOX opt-in unit, the CAIR 
NOX allowances allocated by the permitting authority to the 
CAIR NOX opt-in unit under paragraph (a)(2) of this section.



  Sec. Appendix A to Subpart II of Part 97--States With Approved State 
  Implementation Plan Revisions Concerning CAIR NOX Opt-In 
                                  Units

    1. The following States have State Implementation Plan revisions 
under Sec. 51.123(p)(3) of this chapter approved by the Administrator 
and establishing procedures providing for CAIR NOX opt-in 
units under subpart II of this part and allocation of CAIR 
NOX allowances to such units under Sec. 97.188(b):

Indiana
Michigan
North Carolina
Ohio
South Carolina
Tennessee

    2. The following States have State Implementation Plan revisions 
under Sec. 51.123(p)(3) of this chapter approved by the Administrator 
and establishing procedures providing for CAIR NOX opt-in 
units under subpart II of this part and allocation of CAIR 
NOX allowances to such units under Sec. 97.188(c):

Indiana
Michigan
Ohio
North Carolina
South Carolina
Tennessee

[65 FR 2727, Jan. 18, 2000, as amended at 72 FR 46394, Aug. 20, 2007; 72 
FR 56920, Oct. 5, 2007; 72 FR 57215, Oct. 9, 2007; 72 FR 59487, Oct. 22, 
2007; 72 FR 72262, Dec. 20, 2007; 73 FR 6040, Feb. 1, 2008]



         Subpart AAA_CAIR SO2 Trading Program General Provisions



Sec. 97.201  Purpose.

    This subpart and subparts BBB through III set forth the general 
provisions and the designated representative, permitting, allowance, 
monitoring, and opt-in provisions for the Federal Clean Air Interstate 
Rule (CAIR) SO2 Trading Program, under section 110 of the 
Clean Air Act and Sec. 52.36 of this chapter, as a means of mitigating 
interstate transport of fine particulates and sulfur dioxide.



Sec. 97.202  Definitions.

    The terms used in this subpart and subparts BBB through III shall 
have

[[Page 263]]

the meanings set forth in this section as follows:
    Account number means the identification number given by the 
Administrator to each CAIR SO2 Allowance Tracking System 
account.
    Acid Rain emissions limitation means a limitation on emissions of 
sulfur dioxide or nitrogen oxides under the Acid Rain Program.
    Acid Rain Program means a multi-state sulfur dioxide and nitrogen 
oxides air pollution control and emission reduction program established 
by the Administrator under title IV of the CAA and parts 72 through 78 
of this chapter.
    Administrator means the Administrator of the United States 
Environmental Protection Agency or the Administrator's duly authorized 
representative.
    Allocate or allocation means, with regard to CAIR SO2 
allowances issued under the Acid Rain Program, the determination by the 
Administrator of the amount of such CAIR SO2 allowances to be 
initially credited to a CAIR SO2 unit or other entity and, 
with regard to CAIR SO2 allowances issued under Sec. 97.288 
or provisions of a State implementation plan that are approved under 
Sec. 51.124(o)(1) or (2) or (r) of this chapter, the determination by a 
permitting authority of the amount of such CAIR SO2 
allowances to be initially credited to a CAIR SO2 unit or 
other entity.
    Allowance transfer deadline means, for a control period, midnight of 
March 1 (if it is a business day), or midnight of the first business day 
thereafter (if March 1 is not a business day), immediately following the 
control period and is the deadline by which a CAIR SO2 
allowance transfer must be submitted for recordation in a CAIR 
SO2 source's compliance account in order to be used to meet 
the source's CAIR SO2 emissions limitation for such control 
period in accordance with Sec. 97.254.
    Alternate CAIR designated representative means, for a CAIR 
SO2 source and each CAIR SO2 unit at the source, 
the natural person who is authorized by the owners and operators of the 
source and all such units at the source, in accordance with subparts BBB 
and III of this part, to act on behalf of the CAIR designated 
representative in matters pertaining to the CAIR SO2 Trading 
Program. If the CAIR SO2 source is also a CAIR NOX 
source, then this natural person shall be the same person as the 
alternate CAIR designated representative under the CAIR NOX 
Annual Trading Program. If the CAIR SO2 source is also a CAIR 
NOX Ozone Season source, then this natural person shall be 
the same person as the alternate CAIR designated representative under 
the CAIR NOX Ozone Season Trading Program. If the CAIR 
SO2 source is also subject to the Acid Rain Program, then 
this natural person shall be the same person as the alternate designated 
representative under the Acid Rain Program. If the CAIR SO2 
source is also subject to the Hg Budget Trading Program, then this 
natural person shall be the same person as the alternate Hg designated 
representative under the Hg Budget Trading Program.
    Automated data acquisition and handling system or DAHS means that 
component of the continuous emission monitoring system, or other 
emissions monitoring system approved for use under subpart HHH of this 
part, designed to interpret and convert individual output signals from 
pollutant concentration monitors, flow monitors, diluent gas monitors, 
and other component parts of the monitoring system to produce a 
continuous record of the measured parameters in the measurement units 
required by subpart HHH of this part.
    Biomass means--
    (1) Any organic material grown for the purpose of being converted to 
energy;
    (2) Any organic byproduct of agriculture that can be converted into 
energy; or
    (3) Any material that can be converted into energy and is 
nonmerchantable for other purposes, that is segregated from other 
nonmerchantable material, and that is;
    (i) A forest-related organic resource, including mill residues, 
precommercial thinnings, slash, brush, or byproduct from conversion of 
trees to merchantable material; or
    (ii) A wood material, including pallets, crates, dunnage, 
manufacturing and construction materials (other than

[[Page 264]]

pressure-treated, chemically-treated, or painted wood products), and 
landscape or right-of-way tree trimmings.
    Boiler means an enclosed fossil- or other-fuel-fired combustion 
device used to produce heat and to transfer heat to recirculating water, 
steam, or other medium.
    Bottoming-cycle cogeneration unit means a cogeneration unit in which 
the energy input to the unit is first used to produce useful thermal 
energy and at least some of the reject heat from the useful thermal 
energy application or process is then used for electricity production.
    CAIR authorized account representative means, with regard to a 
general account, a responsible natural person who is authorized, in 
accordance with subparts BBB, FFF, and III of this part, to transfer and 
otherwise dispose of CAIR SO2 allowances held in the general 
account and, with regard to a compliance account, the CAIR designated 
representative of the source.
    CAIR designated representative means, for a CAIR SO2 
source and each CAIR SO2 unit at the source, the natural 
person who is authorized by the owners and operators of the source and 
all such units at the source, in accordance with subparts BBB and III of 
this part, to represent and legally bind each owner and operator in 
matters pertaining to the CAIR SO2 Trading Program. If the 
CAIR SO2 source is also a CAIR NOX source, then 
this natural person shall be the same person as the CAIR designated 
representative under the CAIR NOX Annual Trading Program. If 
the CAIR SO2 source is also a CAIR NOX Ozone 
Season source, then this natural person shall be the same person as the 
CAIR designated representative under the CAIR NOX Ozone 
Season Trading Program. If the CAIR SO2 source is also 
subject to the Acid Rain Program, then this natural person shall be the 
same person as the designated representative under the Acid Rain 
Program. If the CAIR SO2 source is also subject to the Hg 
Budget Trading Program, then this natural person shall be the same 
person as the Hg designated representative under the Hg Budget Trading 
Program.
    CAIR NOX Annual Trading Program means a multi-state nitrogen oxides 
air pollution control and emission reduction program established by the 
Administrator in accordance with subparts AA through II of this part and 
Sec. 51.123(p) and 52.35 of this chapter or approved and administered 
by the Administrator in accordance with subparts AA through II of part 
96 of this chapter and Sec. 51.123(o)(1) or (2) of this chapter, as a 
means of mitigating interstate transport of fine particulates and 
nitrogen oxides.
    CAIR NOX Ozone Season source means a source that is subject to the 
CAIR NOX Ozone Season Trading Program.
    CAIR NOX Ozone Season Trading Program means a multi-state nitrogen 
oxides air pollution control and emission reduction program established 
by the Administrator in accordance with subparts AAAA through IIII of 
this part and Sec. 51.123(ee) and 52.35 of this chapter or approved and 
administered by the Administrator in accordance with subparts AAAA 
through IIII of part 96 and Sec. 51.123(aa)(1) or (2) (and (bb)(1)), 
(bb)(2), or (dd) of this chapter, as a means of mitigating interstate 
transport of ozone and nitrogen oxides.
    CAIR NOX source means a source that is subject to the 
CAIR NOX Annual Trading Program.
    CAIR permit means the legally binding and federally enforceable 
written document, or portion of such document, issued by the permitting 
authority under subpart CCC of this part, including any permit 
revisions, specifying the CAIR SO2 Trading Program 
requirements applicable to a CAIR SO2 source, to each CAIR 
SO2 unit at the source, and to the owners and operators and 
the CAIR designated representative of the source and each such unit.
    CAIR SO2 allowance means a limited authorization issued by the 
Administrator under the Acid Rain Program, by a permitting authority 
under Sec. 97.288, or by a permitting authority under provisions of a 
State implementation plan that are approved under Sec. 51.124(o)(1) or 
(2) or (r) of this chapter, to emit sulfur dioxide during the control 
period of the specified calendar year for which the authorization is 
allocated or of any calendar year thereafter under the CAIR 
SO2 Trading Program as follows:

[[Page 265]]

    (1) For one CAIR SO2 allowance allocated for a control 
period in a year before 2010, one ton of sulfur dioxide, except as 
provided in Sec. 97.254(b);
    (2) For one CAIR SO2 allowance allocated for a control 
period in 2010 through 2014, 0.50 ton of sulfur dioxide, except as 
provided in Sec. 97.254(b); and
    (3) For one CAIR SO2 allowance allocated for a control 
period in 2015 or later, 0.35 ton of sulfur dioxide, except as provided 
in Sec. 97.254(b).
    (4) An authorization to emit sulfur dioxide that is not issued under 
the Acid Rain Program, Sec. 97.288, or provisions of a State 
implementation plan that are approved under Sec. 51.124(o)(1) or (2) or 
(r) of this chapter shall not be a CAIR SO2 allowance.
    CAIR SO2 allowance deduction or deduct CAIR SO2 allowances means the 
permanent withdrawal of CAIR SO2 allowances by the 
Administrator from a compliance account, e.g., in order to account for a 
specified number of tons of total sulfur dioxide emissions from all CAIR 
SO2 units at a CAIR SO2 source for a control 
period, determined in accordance with subpart HHH of this part, or to 
account for excess emissions.
    CAIR SO2 Allowance Tracking System means the system by which the 
Administrator records allocations, deductions, and transfers of CAIR 
SO2 allowances under the CAIR SO2 Trading Program. 
This is the same system as the Allowance Tracking System under Sec. 
72.2 of this chapter by which the Administrator records allocations, 
deduction, and transfers of Acid Rain SO2 allowances under 
the Acid Rain Program.
    CAIR SO2 Allowance Tracking System account means an account in the 
CAIR SO2 Allowance Tracking System established by the Administrator for 
purposes of recording the allocation, holding, transferring, or 
deducting of CAIR SO2 allowances. Such allowances will be 
allocated, held, deducted, or transferred only as whole allowances.
    CAIR SO2 allowances held or hold CAIR SO2 allowances means the CAIR 
SO2 allowances recorded by the Administrator, or submitted to 
the Administrator for recordation, in accordance with subparts FFF, GGG, 
and III of this part or part 73 of this chapter, in a CAIR 
SO2 Allowance Tracking System account.
    CAIR SO2 emissions limitation means, for a CAIR SO2 
source, the tonnage equivalent, in SO2 emissions in a control 
period, of the CAIR SO2 allowances available for deduction 
for the source under Sec. 97.254(a) and (b) for the control period.
    CAIR SO2 source means a source that includes one or more CAIR 
SO2 units.
    CAIR SO2 Trading Program means a multi-state sulfur dioxide air 
pollution control and emission reduction program established by the 
Administrator in accordance with subparts AAA through III of this part 
and Sec. Sec. 51.124(r) and 52.36 of this chapter or approved and 
administered by the Administrator in accordance with subparts AAA 
through III of part 96 of this chapter and Sec. 51.124(o) (1) or (2) of 
this chapter, as a means of mitigating interstate transport of fine 
particulates and sulfur dioxide.
    CAIR SO2 unit means a unit that is subject to the CAIR 
SO2 Trading Program under Sec. 97.204 and, except for 
purposes of Sec. 97.205, a CAIR SO2 opt-in unit under 
subpart III of this part.
    Certifying official means:
    (1) For a corporation, a president, secretary, treasurer, or vice-
president or the corporation in charge of a principal business function 
or any other person who performs similar policy or decision-making 
functions for the corporation;
    (2) For a partnership or sole proprietorship, a general partner or 
the proprietor respectively; or
    (3) For a local government entity or State, Federal, or other public 
agency, a principal executive officer or ranking elected official.
    Clean Air Act or CAA means the Clean Air Act, 42 U.S.C. 7401, et 
seq.
    Coal means any solid fuel classified as anthracite, bituminous, 
subbituminous, or lignite.
    Coal-derived fuel means any fuel (whether in a solid, liquid, or 
gaseous state) produced by the mechanical, thermal, or chemical 
processing of coal.
    Coal-fired means combusting any amount of coal or coal-derived fuel, 
alone, or in combination with any amount of any other fuel.

[[Page 266]]

    Cogeneration unit means a stationary, fossil-fuel-fired boiler or 
stationary, fossil-fuel-fired combustion turbine:
    (1) Having equipment used to produce electricity and useful thermal 
energy for industrial, commercial, heating, or cooling purposes through 
the sequential use of energy; and
    (2) Producing during the 12-month period starting on the date the 
unit first produces electricity and during any calendar year after the 
calendar year in which the unit first produces electricity--
    (i) For a topping-cycle cogeneration unit,
    (A) Useful thermal energy not less than 5 percent of total energy 
output; and
    (B) Useful power that, when added to one-half of useful thermal 
energy produced, is not less then 42.5 percent of total energy input, if 
useful thermal energy produced is 15 percent or more of total energy 
output, or not less than 45 percent of total energy input, if useful 
thermal energy produced is less than 15 percent of total energy output.
    (ii) For a bottoming-cycle cogeneration unit, useful power not less 
than 45 percent of total energy input;
    (3) Provided that the total energy input under paragraphs (2)(i)(B) 
and (2)(ii) of this definition shall equal the unit's total energy input 
from all fuel except biomass if the unit is a boiler.
    Combustion turbine means:
    (1) An enclosed device comprising a compressor, a combustor, and a 
turbine and in which the flue gas resulting from the combustion of fuel 
in the combustor passes through the turbine, rotating the turbine; and
    (2) If the enclosed device under paragraph (1) of this definition is 
combined cycle, any associated duct burner, heat recovery steam 
generator, and steam turbine.
    Commence commercial operation means, with regard to a unit:
    (1) To have begun to produce steam, gas, or other heated medium used 
to generate electricity for sale or use, including test generation, 
except as provided in Sec. 97.205 and Sec. 97.284(h).
    (i) For a unit that is a CAIR SO2 unit under Sec. 97.204 
on the later of November 15, 1990 or the date the unit commences 
commercial operation as defined in paragraph (1) of this definition and 
that subsequently undergoes a physical change (other than replacement of 
the unit by a unit at the same source), such date shall remain the date 
of commencement of commercial operation of the unit, which shall 
continue to be treated as the same unit.
    (ii) For a unit that is a CAIR SO2 unit under Sec. 
97.204 on the later of November 15, 1990 or the date the unit commences 
commercial operation as defined in paragraph (1) of this definition and 
that is subsequently replaced by a unit at the same source (e.g., 
repowered), such date shall remain the replaced unit's date of 
commencement of commercial operation, and the replacement unit shall be 
treated as a separate unit with a separate date for commencement of 
commercial operation as defined in paragraph (1) or (2) of this 
definition as appropriate.
    (2) Notwithstanding paragraph (1) of this definition and except as 
provided in Sec. 97.205, for a unit that is not a CAIR SO2 
unit under Sec. 97.204 on the later of November 15, 1990 or the date 
the unit commences commercial operation as defined in paragraph (1) of 
this definition, the unit's date for commencement of commercial 
operation shall be the date on which the unit becomes a CAIR 
SO2 unit under Sec. 97.204.
    (i) For a unit with a date for commencement of commercial operation 
as defined in paragraph (2) of this definition and that subsequently 
undergoes a physical change (other than replacement of the unit by a 
unit at the same source), such date shall remain the date of 
commencement of commercial operation of the unit, which shall continue 
to be treated as the same unit.
    (ii) For a unit with a date for commencement of commercial operation 
as defined in paragraph (2) of this definition and that is subsequently 
replaced by a unit at the same source (e.g., repowered), such date shall 
remain the replaced unit's date of commencement of commercial operation, 
and the replacement unit shall be treated as a separate unit with a 
separate date for commencement of commercial operation as defined in 
paragraph (1) or (2) of this definition as appropriate.
    Commence operation means:

[[Page 267]]

    (1) To have begun any mechanical, chemical, or electronic process, 
including, with regard to a unit, start-up of a unit's combustion 
chamber, except as provided in Sec. 97.284(h).
    (2) For a unit that undergoes a physical change (other than 
replacement of the unit by a unit at the same source) after the date the 
unit commences operation as defined in paragraph (1) of this definition, 
such date shall remain the date of commencement of operation of the 
unit, which shall continue to be treated as the same unit.
    (3) For a unit that is replaced by a unit at the same source (e.g., 
repowered) after the date the unit commences operation as defined in 
paragraph (1) of this definition, such date shall remain the replaced 
unit's date of commencement of operation, and the replacement unit shall 
be treated as a separate unit with a separate date for commencement of 
operation as defined in paragraph (1), (2), or (3) of this definition as 
appropriate, except as provided in Sec. 97.284(h).
    Common stack means a single flue through which emissions from 2 or 
more units are exhausted.
    Compliance account means a CAIR SO2 Allowance Tracking 
System account, established by the Administrator for a CAIR 
SO2 source subject to an Acid Rain emissions limitations 
under Sec. 73.31(a) or (b) of this chapter or for any other CAIR 
SO2 source under subpart FFF or III of this part, in which 
any CAIR SO2 allowance allocations for the CAIR 
SO2 units at the source are initially recorded and in which 
are held any CAIR SO2 allowances available for use for a 
control period in order to meet the source's CAIR SO2 
emissions limitation in accordance with Sec. 97.254.
    Continuous emission monitoring system or CEMS means the equipment 
required under subpart HHH of this part to sample, analyze, measure, and 
provide, by means of readings recorded at least once every 15 minutes 
(using an automated data acquisition and handling system (DAHS)), a 
permanent record of sulfur dioxide emissions, stack gas volumetric flow 
rate, stack gas moisture content, and oxygen or carbon dioxide 
concentration (as applicable), in a manner consistent with part 75 of 
this chapter. The following systems are the principal types of 
continuous emission monitoring systems required under subpart HHH of 
this part:
    (1) A flow monitoring system, consisting of a stack flow rate 
monitor and an automated data acquisition and handling system and 
providing a permanent, continuous record of stack gas volumetric flow 
rate, in standard cubic feet per hour (scfh);
    (2) A sulfur dioxide monitoring system, consisting of a 
SO2 pollutant concentration monitor and an automated data 
acquisition and handling system and providing a permanent, continuous 
record of SO2 emissions, in parts per million (ppm);
    (3) A moisture monitoring system, as defined in Sec. 75.11(b)(2) of 
this chapter and providing a permanent, continuous record of the stack 
gas moisture content, in percent H2O;
    (4) A carbon dioxide monitoring system, consisting of a 
CO2 pollutant concentration monitor (or an oxygen monitor 
plus suitable mathematical equations from which the CO2 
concentration is derived) and an automated data acquisition and handling 
system and providing a permanent, continuous record of CO2 
emissions, in percent CO2; and
    (5) An oxygen monitoring system, consisting of an O2 
concentration monitor and an automated data acquisition and handling 
system and providing a permanent, continuous record of O2 in 
percent O2.
    Control period means the period beginning January 1 of a calendar 
year, except as provided in Sec. 97.206(c)(2), and ending on December 
31 of the same year, inclusive.
    Emissions means air pollutants exhausted from a unit or source into 
the atmosphere, as measured, recorded, and reported to the Administrator 
by the CAIR designated representative and as determined by the 
Administrator in accordance with subpart HHH of this part.
    Excess emissions means any ton, or portion of a ton, of sulfur 
dioxide emitted by the CAIR SO2 units at a CAIR 
SO2 source during a control period that exceeds the CAIR 
SO2 emissions limitation for the source, provided that any 
portion of a ton of excess emissions

[[Page 268]]

shall be treated as one ton of excess emissions.
    Fossil fuel means natural gas, petroleum, coal, or any form of 
solid, liquid, or gaseous fuel derived from such material.
    Fossil-fuel-fired means, with regard to a unit, combusting any 
amount of fossil fuel in any calendar year.
    General account means a CAIR SO2 Allowance Tracking 
System account, established under subpart FFF of this part, that is not 
a compliance account.
    Generator means a device that produces electricity.
    Heat input means, with regard to a specified period of time, the 
product (in mmBtu/time) of the gross calorific value of the fuel (in 
Btu/lb) divided by 1,000,000 Btu/mmBtu and multiplied by the fuel feed 
rate into a combustion device (in lb of fuel/time), as measured, 
recorded, and reported to the Administrator by the CAIR designated 
representative and determined by the Administrator in accordance with 
subpart HHH of this part and excluding the heat derived from preheated 
combustion air, recirculated flue gases, or exhaust from other sources.
    Heat input rate means the amount of heat input (in mmBtu) divided by 
unit operating time (in hr) or, with regard to a specific fuel, the 
amount of heat input attributed to the fuel (in mmBtu) divided by the 
unit operating time (in hr) during which the unit combusts the fuel.
    Hg Budget Trading Program means a multi-state Hg air pollution 
control and emission reduction program approved and administered by the 
Administrator in accordance subpart HHHH of part 60 of this chapter and 
Sec. 60.24(h)(6), or established by the Administrator under section 111 
of the Clean Air Act, as a means of reducing national Hg emissions.
    Life-of-the-unit, firm power contractual arrangement means a unit 
participation power sales agreement under which a utility or industrial 
customer reserves, or is entitled to receive, a specified amount or 
percentage of nameplate capacity and associated energy generated by any 
specified unit and pays its proportional amount of such unit's total 
costs, pursuant to a contract:
    (1) For the life of the unit;
    (2) For a cumulative term of no less than 30 years, including 
contracts that permit an election for early termination; or
    (3) For a period no less than 25 years or 70 percent of the economic 
useful life of the unit determined as of the time the unit is built, 
with option rights to purchase or release some portion of the nameplate 
capacity and associated energy generated by the unit at the end of the 
period.
    Maximum design heat input means the maximum amount of fuel per hour 
(in Btu/hr) that a unit is capable of combusting on a steady state basis 
as of the initial installation of the unit as specified by the 
manufacturer of the unit.
    Monitoring system means any monitoring system that meets the 
requirements of subpart HHH of this part, including a continuous 
emissions monitoring system, an alternative monitoring system, or an 
excepted monitoring system under part 75 of this chapter.
    Most stringent State or Federal SO2 emissions limitation means, with 
regard to a unit, the lowest SO2 emissions limitation (in 
terms of lb/mmBtu) that is applicable to the unit under State or Federal 
law, regardless of the averaging period to which the emissions 
limitation applies.
    Nameplate capacity means, starting from the initial installation of 
a generator, the maximum electrical generating output (in MWe) that the 
generator is capable of producing on a steady state basis and during 
continuous operation (when not restricted by seasonal or other 
deratings) as of such installation as specified by the manufacturer of 
the generator or, starting from the completion of any subsequent 
physical change in the generator resulting in an increase in the maximum 
electrical generating output (in MWe) that the generator is capable of 
producing on a steady state basis and during continuous operation (when 
not restricted by seasonal or other deratings), such increased maximum 
amount as of such completion as specified by the person conducting the 
physical change.
    Operator means any person who operates, controls, or supervises a 
CAIR

[[Page 269]]

SO2 unit or a CAIR SO2 source and shall include, 
but not be limited to, any holding company, utility system, or plant 
manager of such a unit or source.
    Owner means any of the following persons:
    (1) With regard to a CAIR SO2 source or a CAIR 
SO2 unit at a source, respectively:
    (i) Any holder of any portion of the legal or equitable title in a 
CAIR SO2 unit at the source or the CAIR SO2 unit;
    (ii) Any holder of a leasehold interest in a CAIR SO2 
unit at the source or the CAIR SO2 unit; or
    (iii) Any purchaser of power from a CAIR SO2 unit at the 
source or the CAIR SO2 unit under a life-of-the-unit, firm 
power contractual arrangement; provided that, unless expressly provided 
for in a leasehold agreement, owner shall not include a passive lessor, 
or a person who has an equitable interest through such lessor, whose 
rental payments are not based (either directly or indirectly) on the 
revenues or income from such CAIR SO2 unit; or
    (2) With regard to any general account, any person who has an 
ownership interest with respect to the CAIR SO2 allowances 
held in the general account and who is subject to the binding agreement 
for the CAIR authorized account representative to represent the person's 
ownership interest with respect to CAIR SO2 allowances.
    Permitting authority means the State air pollution control agency, 
local agency, other State agency, or other agency authorized by the 
Administrator to issue or revise permits to meet the requirements of the 
CAIR SO2 Trading Program or, if no such agency has been so 
authorized, the Administrator.
    Potential electrical output capacity means 33 percent of a unit's 
maximum design heat input, divided by 3,413 Btu/kWh, divided by 1,000 
kWh/MWh, and multiplied by 8,760 hr/yr.
    Receive or receipt of means, when referring to the permitting 
authority or the Administrator, to come into possession of a document, 
information, or correspondence (whether sent in hard copy or by 
authorized electronic transmission), as indicated in an official log, or 
by a notation made on the document, information, or correspondence, by 
the permitting authority or the Administrator in the regular course of 
business.
    Recordation, record, or recorded means, with regard to CAIR 
SO2 allowances, the movement of CAIR SO2 
allowances by the Administrator into or between CAIR SO2 
Allowance Tracking System accounts, for purposes of allocation, 
transfer, or deduction.
    Reference method means any direct test method of sampling and 
analyzing for an air pollutant as specified in Sec. 75.22 of this 
chapter.
    Replacement, replace, or replaced means, with regard to a unit, the 
demolishing of a unit, or the permanent shutdown and permanent disabling 
of a unit, and the construction of another unit (the replacement unit) 
to be used instead of the demolished or shutdown unit (the replaced 
unit).
    Repowered means, with regard to a unit, replacement of a coal-fired 
boiler with one of the following coal-fired technologies at the same 
source as the coal-fired boiler:
    (1) Atmospheric or pressurized fluidized bed combustion;
    (2) Integrated gasification combined cycle;
    (3) Magnetohydrodynamics;
    (4) Direct and indirect coal-fired turbines;
    (5) Integrated gasification fuel cells; or
    (6) As determined by the Administrator in consultation with the 
Secretary of Energy, a derivative of one or more of the technologies 
under paragraphs (1) through (5) of this definition and any other coal-
fired technology capable of controlling multiple combustion emissions 
simultaneously with improved boiler or generation efficiency and with 
significantly greater waste reduction relative to the performance of 
technology in widespread commercial use as of January 1, 2005.
    Sequential use of energy means:
    (1) For a topping-cycle cogeneration unit, the use of reject heat 
from electricity production in a useful thermal energy application or 
process; or
    (2) For a bottoming-cycle cogeneration unit, the use of reject heat 
from

[[Page 270]]

useful thermal energy application or process in electricity production.
    Serial number means, for a CAIR SO2 allowance, the unique 
identification number assigned to each CAIR SO2 allowance by 
the Administrator.
    Solid waste incineration unit means a stationary, fossil-fuel-fired 
boiler or stationary, fossil-fuel-fired combustion turbine that is a 
``solid waste incineration unit'' as defined in section 129(g)(1) of the 
Clean Air Act.
    Source means all buildings, structures, or installations located in 
one or more contiguous or adjacent properties under common control of 
the same person or persons. For purposes of section 502(c) of the Clean 
Air Act, a ``source,'' including a ``source'' with multiple units, shall 
be considered a single ``facility.''
    State means one of the States or the District of Columbia that is 
subject to the CAIR SO2 Trading Program pursuant to Sec. 
52.35 of this chapter.
    Submit or serve means to send or transmit a document, information, 
or correspondence to the person specified in accordance with the 
applicable regulation:
    (1) In person;
    (2) By United States Postal Service; or
    (3) By other means of dispatch or transmission and delivery. 
Compliance with any ``submission'' or ``service'' deadline shall be 
determined by the date of dispatch, transmission, or mailing and not the 
date of receipt.
    Title V operating permit means a permit issued under title V of the 
Clean Air Act and part 70 or part 71 of this chapter.
    Title V operating permit regulations means the regulations that the 
Administrator has approved or issued as meeting the requirements of 
title V of the Clean Air Act and part 70 or 71 of this chapter.
    Ton means 2,000 pounds. For the purpose of determining compliance 
with the CAIR SO2 emissions limitation, total tons of sulfur 
dioxide emissions for a control period shall be calculated as the sum of 
all recorded hourly emissions (or the mass equivalent of the recorded 
hourly emission rates) in accordance with subpart HHH of this part, but 
with any remaining fraction of a ton equal to or greater than 0.50 tons 
deemed to equal one ton and any remaining fraction of a ton less than 
0.50 tons deemed to equal zero tons.
    Topping-cycle cogeneration unit means a cogeneration unit in which 
the energy input to the unit is first used to produce useful power, 
including electricity, and at least some of the reject heat from the 
electricity production is then used to provide useful thermal energy.
    Total energy input means, with regard to a cogeneration unit, total 
energy of all forms supplied to the cogeneration unit, excluding energy 
produced by the cogeneration unit itself. Each form of energy supplied 
shall be measured by the lower heating value of that form of energy 
calculated as follows:

LHV = HHV-10.55(W + 9H)

Where:

LHV = lower heating value of fuel in Btu/lb,
HHV = higher heating value of fuel in Btu/lb,
W = Weight % of moisture in fuel, and
H = Weight % of hydrogen in fuel.

    Total energy output means, with regard to a cogeneration unit, the 
sum of useful power and useful thermal energy produced by the 
cogeneration unit.
    Unit means a stationary, fossil-fuel-fired boiler or combustion 
turbine or other stationary, fossil-fuel-fired combustion device. Unit 
operating day means a calendar day in which a unit combusts any fuel.
    Unit operating hour or hour of unit operation means an hour in which 
a unit combusts any fuel.
    Useful power means, with regard to a cogeneration unit, electricity 
or mechanical energy made available for use, excluding any such energy 
used in the power production process (which process includes, but is not 
limited to, any on-site processing or treatment of fuel combusted at the 
unit and any on-site emission controls).
    Useful thermal energy means, with regard to a cogeneration unit, 
thermal energy that is:
    (1) Made available to an industrial or commercial process (not a 
power production process), excluding any heat contained in condensate 
return or makeup water;

[[Page 271]]

    (2) Used in a heating application (e.g., space heating or domestic 
hot water heating); or
    (3) Used in a space cooling application (i.e., thermal energy used 
by an absorption chiller).
    Utility power distribution system means the portion of an 
electricity grid owned or operated by a utility and dedicated to 
delivering electricity to customers.

[65 FR 2727, Jan. 18, 2000, as amended at 71 FR 74795, Dec. 13, 2006; 72 
FR 59207, Oct. 19, 2007]



Sec. 97.203  Measurements, abbreviations, and acronyms.

    Measurements, abbreviations, and acronyms used in this subpart and 
subparts BBB through III are defined as follows:

Btu--British thermal unit.
CO2--carbon dioxide.
H2O--water.
Hg--mercury.
hr--hour.
kW--kilowatt electrical.
kWh--kilowatt hour.
lb--pound.
mmBtu--million Btu.
MWe--megawatt electrical.
MWh--megawatt hour.
NOX--nitrogen oxides.
O2--oxygen.
ppm--parts per million.
scfh--standard cubic feet per hour.
SO2--sulfur dioxide.
yr--year.



Sec. 97.204  Applicability.

    (a) Except as provided in paragraph (b) of this section:
    (1) The following units in a State shall be CAIR SO2 
units, and any source that includes one or more such units shall be a 
CAIR SO2 source, subject to the requirements of this subpart 
and subparts BBB through HHH of this part: any stationary, fossil-fuel-
fired boiler or stationary, fossil-fuel-fired combustion turbine serving 
at any time, since the later of November 15, 1990 or the start-up of the 
unit's combustion chamber, a generator with nameplate capacity of more 
than 25 MWe producing electricity for sale.
    (2) If a stationary boiler or stationary combustion turbine that, 
under paragraph (a)(1) of this section, is not a CAIR SO2 
unit begins to combust fossil fuel or to serve a generator with 
nameplate capacity of more than 25 MWe producing electricity for sale, 
the unit shall become a CAIR SO2 unit as provided in 
paragraph (a)(1) of this section on the first date on which it both 
combusts fossil fuel and serves such generator.
    (b) The units in a State that meet the requirements set forth in 
paragraph (b)(1)(i), (b)(2)(i), or (b)(2)(ii) of this section shall not 
be CAIR SO2 units:
    (1)(i) Any unit that is a CAIR SO2 unit under paragraph 
(a)(1) or (2) of this section:
    (A) Qualifying as a cogeneration unit during the 12-month period 
starting on the date the unit first produces electricity and continuing 
to qualify as a cogeneration unit; and
    (B) Not serving at any time, since the later of November 15, 1990 or 
the start-up of the unit's combustion chamber, a generator with 
nameplate capacity of more than 25 MWe supplying in any calendar year 
more than one-third of the unit's potential electric output capacity or 
219,000 MWh, whichever is greater, to any utility power distribution 
system for sale.
    (ii) If a unit qualifies as a cogeneration unit during the 12-month 
period starting on the date the unit first produces electricity and 
meets the requirements of paragraphs (b)(1)(i) of this section for at 
least one calendar year, but subsequently no longer meets all such 
requirements, the unit shall become a CAIR SO2 unit starting 
on the earlier of January 1 after the first calendar year during which 
the unit first no longer qualifies as a cogeneration unit or January 1 
after the first calendar year during which the unit no longer meets the 
requirements of paragraph (b)(1)(i)(B) of this section.
    (2)(i) Any unit that is a CAIR SO2 unit under paragraph 
(a)(1) or (2) of this section commencing operation before January 1, 
1985:
    (A) Qualifying as a solid waste incineration unit; and
    (B) With an average annual fuel consumption of non-fossil fuel for 
1985-1987 exceeding 80 percent (on a Btu basis)

[[Page 272]]

and an average annual fuel consumption of non-fossil fuel for any 3 
consecutive calendar years after 1990 exceeding 80 percent (on a Btu 
basis).
    (ii) Any unit that is a CAIR SO2 unit under paragraph 
(a)(1) or (2) of this section commencing operation on or after January 
1, 1985:
    (A) Qualifying as a solid waste incineration unit; and
    (B) With an average annual fuel consumption of non-fossil fuel for 
the first 3 calendar years of operation exceeding 80 percent (on a Btu 
basis) and an average annual fuel consumption of non-fossil fuel for any 
3 consecutive calendar years after 1990 exceeding 80 percent (on a Btu 
basis).
    (iii) If a unit qualifies as a solid waste incineration unit and 
meets the requirements of paragraph (b)(2)(i) or (ii) of this section 
for at least 3 consecutive calendar years, but subsequently no longer 
meets all such requirements, the unit shall become a CAIR SO2 
unit starting on the earlier of January 1 after the first calendar year 
during which the unit first no longer qualifies as a solid waste 
incineration unit or January 1 after the first 3 consecutive calendar 
years after 1990 for which the unit has an average annual fuel 
consumption of fossil fuel of 20 percent or more.
    (c) A certifying official of an owner or operator of any unit may 
petition the Administrator at any time for a determination concerning 
the applicability, under paragraphs (a) and (b) of this section, of the 
CAIR SO2 Trading Program to the unit.
    (1) Petition content. The petition shall be in writing and include 
the identification of the unit and the relevant facts about the unit. 
The petition and any other documents provided to the Administrator in 
connection with the petition shall include the following certification 
statement, signed by the certifying official: ``I am authorized to make 
this submission on behalf of the owners and operators of the unit for 
which the submission is made. I certify under penalty of law that I have 
personally examined, and am familiar with, the statements and 
information submitted in this document and all its attachments. Based on 
my inquiry of those individuals with primary responsibility for 
obtaining the information, I certify that the statements and information 
are to the best of my knowledge and belief true, accurate, and complete. 
I am aware that there are significant penalties for submitting false 
statements and information or omitting required statements and 
information, including the possibility of fine or imprisonment.''
    (2) Submission. The petition and any other documents provided in 
connection with the petition shall be submitted to the Director of the 
Clean Air Markets Division (or its successor), U.S. Environmental 
Protection Agency, who will act on the petition as the Administrator's 
duly authorized representative.
    (3) Response. The Administrator will issue a written response to the 
petition and may request supplemental information relevant to such 
petition. The Administrator's determination concerning the 
applicability, under paragraphs (a) and (b) of this section, of the CAIR 
SO2 Trading Program to the unit shall be binding on the 
permitting authority unless the petition or other information or 
documents provided in connection with the petition are found to have 
contained significant, relevant errors or omissions.



Sec. 97.205  Retired unit exemption.

    (a)(1) Any CAIR SO2 unit that is permanently retired and 
is not a CAIR SO2 opt-in unit under subpart III of this part 
shall be exempt from the CAIR SO2 Trading Program, except for 
the provisions of this section, Sec. Sec. 97.202, 97.203, 97.204, 
97.206(c)(4) through (7), 97.207, 97.208, and subparts BBB, FFF, and GGG 
of this part.
    (2) The exemption under paragraph (a)(1) of this section shall 
become effective the day on which the CAIR SO2 unit is 
permanently retired. Within 30 days of the unit's permanent retirement, 
the CAIR designated representative shall submit a statement to the 
permitting authority otherwise responsible for administering any CAIR 
permit for the unit and shall submit a copy of the statement to the 
Administrator. The statement shall state, in a format prescribed by the 
permitting authority, that the unit was permanently retired on a 
specific date and

[[Page 273]]

will comply with the requirements of paragraph (b) of this section.
    (3) After receipt of the statement under paragraph (a)(2) of this 
section, the permitting authority will amend any permit under subpart 
CCC of this part covering the source at which the unit is located to add 
the provisions and requirements of the exemption under paragraphs (a)(1) 
and (b) of this section.
    (b) Special provisions. (1) A unit exempt under paragraph (a) of 
this section shall not emit any sulfur dioxide, starting on the date 
that the exemption takes effect.
    (2) For a period of 5 years from the date the records are created, 
the owners and operators of a unit exempt under paragraph (a) of this 
section shall retain, at the source that includes the unit, records 
demonstrating that the unit is permanently retired. The 5-year period 
for keeping records may be extended for cause, at any time before the 
end of the period, in writing by the permitting authority or the 
Administrator. The owners and operators bear the burden of proof that 
the unit is permanently retired.
    (3) The owners and operators and, to the extent applicable, the CAIR 
designated representative of a unit exempt under paragraph (a) of this 
section shall comply with the requirements of the CAIR SO2 
Trading Program concerning all periods for which the exemption is not in 
effect, even if such requirements arise, or must be complied with, after 
the exemption takes effect.
    (4) A unit exempt under paragraph (a) of this section and located at 
a source that is required, or but for this exemption would be required, 
to have a title V operating permit shall not resume operation unless the 
CAIR designated representative of the source submits a complete CAIR 
permit application under Sec. 97.222 for the unit not less than 18 
months (or such lesser time provided by the permitting authority) before 
the later of January 1, 2010 or the date on which the unit resumes 
operation.
    (5) On the earlier of the following dates, a unit exempt under 
paragraph (a) of this section shall lose its exemption:
    (i) The date on which the CAIR designated representative submits a 
CAIR permit application for the unit under paragraph (b)(4) of this 
section;
    (ii) The date on which the CAIR designated representative is 
required under paragraph (b)(4) of this section to submit a CAIR permit 
application for the unit; or
    (iii) The date on which the unit resumes operation, if the CAIR 
designated representative is not required to submit a CAIR permit 
application for the unit.
    (6) For the purpose of applying monitoring, reporting, and 
recordkeeping requirements under subpart HHH of this part, a unit that 
loses its exemption under paragraph (a) of this section shall be treated 
as a unit that commences commercial operation on the first date on which 
the unit resumes operation.



Sec. 97.206  Standard requirements.

    (a) Permit requirements. (1) The CAIR designated representative of 
each CAIR SO2 source required to have a title V operating 
permit and each CAIR SO2 unit required to have a title V 
operating permit at the source shall:
    (i) Submit to the permitting authority a complete CAIR permit 
application under Sec. 97.222 in accordance with the deadlines 
specified in Sec. 97.221; and
    (ii) Submit in a timely manner any supplemental information that the 
permitting authority determines is necessary in order to review a CAIR 
permit application and issue or deny a CAIR permit.
    (2) The owners and operators of each CAIR SO2 source 
required to have a title V operating permit and each CAIR SO2 
unit required to have a title V operating permit at the source shall 
have a CAIR permit issued by the permitting authority under subpart CCC 
of this part for the source and operate the source and the unit in 
compliance with such CAIR permit.
    (3) Except as provided in subpart III of this part, the owners and 
operators of a CAIR SO2 source that is not otherwise required 
to have a title V operating permit and each CAIR SO2 unit 
that is not otherwise required to have

[[Page 274]]

a title V operating permit are not required to submit a CAIR permit 
application, and to have a CAIR permit, under subpart CCC of this part 
for such CAIR SO2 source and such CAIR SO2 unit.
    (b) Monitoring, reporting, and recordkeeping requirements. (1) The 
owners and operators, and the CAIR designated representative, of each 
CAIR SO2 source and each CAIR SO2 unit at the 
source shall comply with the monitoring, reporting, and recordkeeping 
requirements of subpart HHH of this part.
    (2) The emissions measurements recorded and reported in accordance 
with subpart HHH of this part shall be used to determine compliance by 
each CAIR SO2 source with the CAIR SO2 emissions 
limitation under paragraph (c) of this section.
    (c) Sulfur dioxide emission requirements. (1) As of the allowance 
transfer deadline for a control period, the owners and operators of each 
CAIR SO2 source and each CAIR SO2 unit at the 
source shall hold, in the source's compliance account, a tonnage 
equivalent in CAIR SO2 allowances available for compliance 
deductions for the control period, as determined in accordance with 
Sec. 97.254(a) and (b), not less than the tons of total sulfur dioxide 
emissions for the control period from all CAIR SO2 units at 
the source, as determined in accordance with subpart HHH of this part.
    (2) A CAIR SO2 unit shall be subject to the requirements 
under paragraph (c)(1) of this section for the control period starting 
on the later of January 1, 2010 or the deadline for meeting the unit(s 
monitor certification requirements under Sec. 97.270(b)(1),(2), or (5) 
and for each control period thereafter.
    (3) A CAIR SO2 allowance shall not be deducted, for 
compliance with the requirements under paragraph (c)(1) of this section, 
for a control period in a calendar year before the year for which the 
CAIR SO2 allowance was allocated.
    (4) CAIR SO2 allowances shall be held in, deducted from, 
or transferred into or among CAIR SO2 Allowance Tracking 
System accounts in accordance with subparts FFF, GGG, and III of this 
part.
    (5) A CAIR SO2 allowance is a limited authorization to 
emit sulfur dioxide in accordance with the CAIR SO2 Trading 
Program. No provision of the CAIR SO2 Trading Program, the 
CAIR permit application, the CAIR permit, or an exemption under Sec. 
97.205 and no provision of law shall be construed to limit the authority 
of the United States to terminate or limit such authorization.
    (6) A CAIR SO2 allowance does not constitute a property 
right.
    (7) Upon recordation by the Administrator under subpart FFF, GGG, or 
III of this part, every allocation, transfer, or deduction of a CAIR 
SO2 allowance to or from a CAIR SO2 source's 
compliance account is incorporated automatically in any CAIR permit of 
the source.
    (d) Excess emissions requirements. If a CAIR SO2 source 
emits sulfur dioxide during any control period in excess of the CAIR 
SO2 emissions limitation, then:
    (1) The owners and operators of the source and each CAIR 
SO2 unit at the source shall surrender the CAIR 
SO2 allowances required for deduction under Sec. 
97.254(d)(1) and pay any fine, penalty, or assessment or comply with any 
other remedy imposed, for the same violations, under the Clean Air Act 
or applicable State law; and
    (2) Each ton of such excess emissions and each day of such control 
period shall constitute a separate violation of this subpart, the Clean 
Air Act, and applicable State law.
    (e) Recordkeeping and reporting requirements. (1) Unless otherwise 
provided, the owners and operators of the CAIR SO2 source and 
each CAIR SO2 unit at the source shall keep on site at the 
source each of the following documents for a period of 5 years from the 
date the document is created. This period may be extended for cause, at 
any time before the end of 5 years, in writing by the permitting 
authority or the Administrator.
    (i) The certificate of representation under Sec. 97.213 for the 
CAIR designated representative for the source and each CAIR 
SO2 unit at the source and all documents that demonstrate the 
truth of the statements in the certificate of representation; provided 
that the certificate and documents shall be retained on site at the 
source beyond

[[Page 275]]

such 5-year period until such documents are superseded because of the 
submission of a new certificate of representation under Sec. 97.213 
changing the CAIR designated representative.
    (ii) All emissions monitoring information, in accordance with 
subpart HHH of this part, provided that to the extent that subpart HHH 
of this part provides for a 3-year period for recordkeeping, the 3-year 
period shall apply.
    (iii) Copies of all reports, compliance certifications, and other 
submissions and all records made or required under the CAIR 
SO2 Trading Program.
    (iv) Copies of all documents used to complete a CAIR permit 
application and any other submission under the CAIR SO2 
Trading Program or to demonstrate compliance with the requirements of 
the CAIR SO2 Trading Program.
    (2) The CAIR designated representative of a CAIR SO2 
source and each CAIR SO2 unit at the source shall submit the 
reports required under the CAIR SO2 Trading Program, 
including those under subpart HHH of this part.
    (f) Liability. (1) Each CAIR SO2 source and each CAIR 
SO2 unit shall meet the requirements of the CAIR 
SO2 Trading Program.
    (2) Any provision of the CAIR SO2 Trading Program that 
applies to a CAIR SO2 source or the CAIR designated 
representative of a CAIR SO2 source shall also apply to the 
owners and operators of such source and of the CAIR SO2 units 
at the source.
    (3) Any provision of the CAIR SO2 Trading Program that 
applies to a CAIR SO2 unit or the CAIR designated 
representative of a CAIR SO2 unit shall also apply to the 
owners and operators of such unit.
    (g) Effect on other authorities. No provision of the CAIR 
SO2 Trading Program, a CAIR permit application, a CAIR 
permit, or an exemption under Sec. 97.205 shall be construed as 
exempting or excluding the owners and operators, and the CAIR designated 
representative, of a CAIR SO2 source or CAIR SO2 
unit from compliance with any other provision of the applicable, 
approved State implementation plan, a federally enforceable permit, or 
the Clean Air Act.



Sec. 97.207  Computation of time.

    (a) Unless otherwise stated, any time period scheduled, under the 
CAIR SO2 Trading Program, to begin on the occurrence of an 
act or event shall begin on the day the act or event occurs.
    (b) Unless otherwise stated, any time period scheduled, under the 
CAIR SO2 Trading Program, to begin before the occurrence of 
an act or event shall be computed so that the period ends the day before 
the act or event occurs.
    (c) Unless otherwise stated, if the final day of any time period, 
under the CAIR SO2 Trading Program, falls on a weekend or a 
State or Federal holiday, the time period shall be extended to the next 
business day.



Sec. 97.208  Appeal procedures.

    The appeal procedures for decisions of the Administrator under the 
CAIR SO2 Trading Program are set forth in part 78 of this 
chapter.



     Subpart BBB_CAIR Designated Representative for CAIR SO2 Sources



Sec. 97.210  Authorization and responsibilities of CAIR designated
representative.

    (a) Except as provided under Sec. 97.211, each CAIR SO2 
source, including all CAIR SO2 units at the source, shall 
have one and only one CAIR designated representative, with regard to all 
matters under the CAIR SO2 Trading Program concerning the 
source or any CAIR SO2 unit at the source.
    (b) The CAIR designated representative of the CAIR SO2 
source shall be selected by an agreement binding on the owners and 
operators of the source and all CAIR SO2 units at the source 
and shall act in accordance with the certification statement in Sec. 
97.213(a)(4)(iv).
    (c) Upon receipt by the Administrator of a complete certificate of 
representation under Sec. 97.213, the CAIR designated representative of 
the source shall represent and, by his or her representations, actions, 
inactions, or submissions, legally bind each owner and operator of the 
CAIR SO2 source represented and each CAIR SO2 unit 
at the source in all matters pertaining to the

[[Page 276]]

CAIR SO2 Trading Program, notwithstanding any agreement 
between the CAIR designated representative and such owners and 
operators. The owners and operators shall be bound by any decision or 
order issued to the CAIR designated representative by the permitting 
authority, the Administrator, or a court regarding the source or unit.
    (d) No CAIR permit will be issued, no emissions data reports will be 
accepted, and no CAIR SO2 Allowance Tracking System account 
will be established for a CAIR SO2 unit at a source, until 
the Administrator has received a complete certificate of representation 
under Sec. 97.213 for a CAIR designated representative of the source 
and the CAIR SO2 units at the source.
    (e)(1) Each submission under the CAIR SO2 Trading Program 
shall be submitted, signed, and certified by the CAIR designated 
representative for each CAIR SO2 source on behalf of which 
the submission is made. Each such submission shall include the following 
certification statement by the CAIR designated representative: ``I am 
authorized to make this submission on behalf of the owners and operators 
of the source or units for which the submission is made. I certify under 
penalty of law that I have personally examined, and am familiar with, 
the statements and information submitted in this document and all its 
attachments. Based on my inquiry of those individuals with primary 
responsibility for obtaining the information, I certify that the 
statements and information are to the best of my knowledge and belief 
true, accurate, and complete. I am aware that there are significant 
penalties for submitting false statements and information or omitting 
required statements and information, including the possibility of fine 
or imprisonment.''
    (2) The permitting authority and the Administrator will accept or 
act on a submission made on behalf of owner or operators of a CAIR 
SO2 source or a CAIR SO2 unit only if the 
submission has been made, signed, and certified in accordance with 
paragraph (e)(1) of this section.



Sec. 97.211  Alternate CAIR designated representative.

    (a) A certificate of representation under Sec. 97.213 may designate 
one and only one alternate CAIR designated representative, who may act 
on behalf of the CAIR designated representative. The agreement by which 
the alternate CAIR designated representative is selected shall include a 
procedure for authorizing the alternate CAIR designated representative 
to act in lieu of the CAIR designated representative.
    (b) Upon receipt by the Administrator of a complete certificate of 
representation under Sec. 97.213, any representation, action, inaction, 
or submission by the alternate CAIR designated representative shall be 
deemed to be a representation, action, inaction, or submission by the 
CAIR designated representative.
    (c) Except in this section and Sec. Sec. 97.202, 97.210(a) and (d), 
97.212, 97.213, 97.215, 97.251 and 97.282, whenever the term ``CAIR 
designated representative'' is used in subparts AAA through III of this 
part, the term shall be construed to include the CAIR designated 
representative or any alternate CAIR designated representative.



Sec. 97.212  Changing CAIR designated representative and alternate
CAIR designated representative; changes in owners and operators.

    (a) Changing CAIR designated representative. The CAIR designated 
representative may be changed at any time upon receipt by the 
Administrator of a superseding complete certificate of representation 
under Sec. 97.213. Notwithstanding any such change, all 
representations, actions, inactions, and submissions by the previous 
CAIR designated representative before the time and date when the 
Administrator receives the superseding certificate of representation 
shall be binding on the new CAIR designated representative and the 
owners and operators of the CAIR SO2 source and the CAIR 
SO2 units at the source.
    (b) Changing alternate CAIR designated representative. The alternate 
CAIR designated representative may be changed at any time upon receipt 
by the Administrator of a superseding complete certificate of 
representation under

[[Page 277]]

Sec. 97.213. Notwithstanding any such change, all representations, 
actions, inactions, and submissions by the previous alternate CAIR 
designated representative before the time and date when the 
Administrator receives the superseding certificate of representation 
shall be binding on the new alternate CAIR designated representative and 
the owners and operators of the CAIR SO2 source and the CAIR 
SO2 units at the source.
    (c) Changes in owners and operators. (1) In the event an owner or 
operator of a CAIR SO2 source or a CAIR SO2 unit 
is not included in the list of owners and operators in the certificate 
of representation under Sec. 97.213, such owner or operator shall be 
deemed to be subject to and bound by the certificate of representation, 
the representations, actions, inactions, and submissions of the CAIR 
designated representative and any alternate CAIR designated 
representative of the source or unit, and the decisions and orders of 
the permitting authority, the Administrator, or a court, as if the owner 
or operator were included in such list.
    (2) Within 30 days following any change in the owners and operators 
of a CAIR SO2 source or a CAIR SO2 unit, including 
the addition of a new owner or operator, the CAIR designated 
representative or any alternate CAIR designated representative shall 
submit a revision to the certificate of representation under Sec. 
97.213 amending the list of owners and operators to include the change.



Sec. 97.213  Certificate of representation.

    (a) A complete certificate of representation for a CAIR designated 
representative or an alternate CAIR designated representative shall 
include the following elements in a format prescribed by the 
Administrator:
    (1) Identification of the CAIR SO2 source, and each CAIR 
SO2 unit at the source, for which the certificate of 
representation is submitted, including identification and nameplate 
capacity of each generator served by each such unit.
    (2) The name, address, e-mail address (if any), telephone number, 
and facsimile transmission number (if any) of the CAIR designated 
representative and any alternate CAIR designated representative.
    (3) A list of the owners and operators of the CAIR SO2 
source and of each CAIR SO2 unit at the source.
    (4) The following certification statements by the CAIR designated 
representative and any alternate CAIR designated representative--
    (i) ``I certify that I was selected as the CAIR designated 
representative or alternate CAIR designated representative, as 
applicable, by an agreement binding on the owners and operators of the 
source and each CAIR SO2 unit at the source.''
    (ii) ``I certify that I have all the necessary authority to carry 
out my duties and responsibilities under the CAIR SO2 Trading 
Program on behalf of the owners and operators of the source and of each 
CAIR SO2 unit at the source and that each such owner and 
operator shall be fully bound by my representations, actions, inactions, 
or submissions.''
    (iii) ``I certify that the owners and operators of the source and of 
each CAIR SO2 unit at the source shall be bound by any order 
issued to me by the Administrator, the permitting authority, or a court 
regarding the source or unit.''
    (iv) ``Where there are multiple holders of a legal or equitable 
title to, or a leasehold interest in, a CAIR SO2 unit, or 
where a utility or industrial customer purchases power from a CAIR 
SO2 unit under a life-of-the-unit, firm power contractual 
arrangement, I certify that: I have given a written notice of my 
selection as the `CAIR designated representative' or `alternate CAIR 
designated representative', as applicable, and of the agreement by which 
I was selected to each owner and operator of the source and of each CAIR 
SO2 unit at the source; and CAIR SO2 allowances 
and proceeds of transactions involving CAIR SO2 allowances 
will be deemed to be held or distributed in proportion to each holder's 
legal, equitable, leasehold, or contractual reservation or entitlement, 
except that, if such multiple holders have expressly provided for a 
different distribution of CAIR SO2 allowances by contract, 
CAIR SO2 allowances and proceeds of

[[Page 278]]

transactions involving CAIR SO2 allowances will be deemed to 
be held or distributed in accordance with the contract.''
    (5) The signature of the CAIR designated representative and any 
alternate CAIR designated representative and the dates signed.
    (b) Unless otherwise required by the permitting authority or the 
Administrator, documents of agreement referred to in the certificate of 
representation shall not be submitted to the permitting authority or the 
Administrator. Neither the permitting authority nor the Administrator 
shall be under any obligation to review or evaluate the sufficiency of 
such documents, if submitted.



Sec. 97.214  Objections concerning CAIR designated representative.

    (a) Once a complete certificate of representation under Sec. 97.213 
has been submitted and received, the permitting authority and the 
Administrator will rely on the certificate of representation unless and 
until a superseding complete certificate of representation under Sec. 
97.213 is received by the Administrator.
    (b) Except as provided in Sec. 97.212(a) or (b), no objection or 
other communication submitted to the permitting authority or the 
Administrator concerning the authorization, or any representation, 
action, inaction, or submission, of the CAIR designated representative 
shall affect any representation, action, inaction, or submission of the 
CAIR designated representative or the finality of any decision or order 
by the permitting authority or the Administrator under the CAIR 
SO2 Trading Program.
    (c) Neither the permitting authority nor the Administrator will 
adjudicate any private legal dispute concerning the authorization or any 
representation, action, inaction, or submission of any CAIR designated 
representative, including private legal disputes concerning the proceeds 
of CAIR SO2 allowance transfers.



Sec. 97.215  Delegation by CAIR designated representative and
alternate CAIR designated representative.

    (a) A CAIR designated representative may delegate, to one or more 
natural persons, his or her authority to make an electronic submission 
to the Administrator provided for or required under this part.
    (b) An alternate CAIR designated representative may delegate, to one 
or more natural persons, his or her authority to make an electronic 
submission to the Administrator provided for or required under this 
part.
    (c) In order to delegate authority to make an electronic submission 
to the Administrator in accordance with paragraph (a) or (b) of this 
section, the CAIR designated representative or alternate CAIR designated 
representative, as appropriate, must submit to the Administrator a 
notice of delegation, in a format prescribed by the Administrator, that 
includes the following elements:
    (1) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of such CAIR designated 
representative or alternate CAIR designated representative;
    (2) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of each such natural person 
(referred to as an ``agent'');
    (3) For each such natural person, a list of the type or types of 
electronic submissions under paragraph (a) or (b) of this section for 
which authority is delegated to him or her; and
    (4) The following certification statements by such CAIR designated 
representative or alternate CAIR designated representative:
    (i) ``I agree that any electronic submission to the Administrator 
that is by an agent identified in this notice of delegation and of a 
type listed for such agent in this notice of delegation and that is made 
when I am a CAIR designated representative or alternate CAIR designated 
representative, as appropriate, and before this notice of delegation is 
superseded by another notice of delegation under 40 CFR 97.215(d) shall 
be deemed to be an electronic submission by me.''

[[Page 279]]

    (ii) ``Until this notice of delegation is superseded by another 
notice of delegation under 40 CFR 97.215(d), I agree to maintain an e-
mail account and to notify the Administrator immediately of any change 
in my e-mail address unless all delegation of authority by me under 40 
CFR 97.215 is terminated.''.
    (d) A notice of delegation submitted under paragraph (c) of this 
section shall be effective, with regard to the CAIR designated 
representative or alternate CAIR designated representative identified in 
such notice, upon receipt of such notice by the Administrator and until 
receipt by the Administrator of a superseding notice of delegation 
submitted by such CAIR designated representative or alternate CAIR 
designated representative, as appropriate. The superseding notice of 
delegation may replace any previously identified agent, add a new agent, 
or eliminate entirely any delegation of authority.
    (e) Any electronic submission covered by the certification in 
paragraph (c)(4)(i) of this section and made in accordance with a notice 
of delegation effective under paragraph (d) of this section shall be 
deemed to be an electronic submission by the CAIR designated 
representative or alternate CAIR designated representative submitting 
such notice of delegation.



                           Subpart CCC_Permits



Sec. 97.220  General CAIR SO[bdi2] Trading Program permit 
requirements.

    (a) For each CAIR SO2 source required to have a title V 
operating permit or required, under subpart III of this part, to have a 
title V operating permit or other federally enforceable permit, such 
permit shall include a CAIR permit administered by the permitting 
authority for the title V operating permit or the federally enforceable 
permit as applicable. The CAIR portion of the title V permit or other 
federally enforceable permit as applicable shall be administered in 
accordance with the permitting authority's title V operating permits 
regulations promulgated under part 70 or 71 of this chapter or the 
permitting authority's regulations for other federally enforceable 
permits as applicable, except as provided otherwise by Sec. 97.205, 
this subpart, and subpart III of this part.
    (b) Each CAIR permit shall contain, with regard to the CAIR 
SO2 source and the CAIR SO2 units at the source 
covered by the CAIR permit, all applicable CAIR SO2 Trading 
Program, CAIR NOX Annual Trading Program, and CAIR 
NOX Ozone Season Trading Program requirements and shall be a 
complete and separable portion of the title V operating permit or other 
federally enforceable permit under paragraph (a) of this section.



Sec. 97.221  Submission of CAIR permit applications.

    (a) Duty to apply. The CAIR designated representative of any CAIR 
SO2 source required to have a title V operating permit shall 
submit to the permitting authority a complete CAIR permit application 
under Sec. 97.222 for the source covering each CAIR SO2 unit 
at the source at least 18 months (or such lesser time provided by the 
permitting authority) before the later of January 1, 2010 or the date on 
which the CAIR SO2 unit commences commercial operation, 
except as provided in Sec. 97.283(a).
    (b) Duty to reapply. For a CAIR SO2 source required to 
have a title V operating permit, the CAIR designated representative 
shall submit a complete CAIR permit application under Sec. 97.222 for 
the source covering each CAIR SO2 unit at the source to renew 
the CAIR permit in accordance with the permitting authority's title V 
operating permits regulations addressing permit renewal, except as 
provided in Sec. 97.283(b).



Sec. 97.222  Information requirements for CAIR permit applications.

    A complete CAIR permit application shall include the following 
elements concerning the CAIR SO2 source for which the 
application is submitted, in a format prescribed by the permitting 
authority:
    (a) Identification of the CAIR SO2 source;
    (b) Identification of each CAIR SO2 unit at the CAIR 
SO2 source; and
    (c) The standard requirements under Sec. 97.206.

[[Page 280]]



Sec. 97.223  CAIR permit contents and term.

    (a) Each CAIR permit will contain, in a format prescribed by the 
permitting authority, all lements required for a complete CAIR permit 
application under Sec. 97.222.
    (b) Each CAIR permit is deemed to incorporate automatically the 
definitions of terms under Sec. 97.202 and, upon recordation by the 
Administrator under subpart FFF, GGG, or III of this part, every 
allocation, transfer, or deduction of a CAIR SO2 allowance to 
or from the compliance account of the CAIR SO2 source covered 
by the permit.
    (c) The term of the CAIR permit will be set by the permitting 
authority, as necessary to facilitate coordination of the renewal of the 
CAIR permit with issuance, revision, or renewal of the CAIR 
SO2 source's title V operating permit or other federally 
enforceable permit as applicable.



Sec. 97.224  CAIR permit revisions.

    Except as provided in Sec. 97.223(b), the permitting authority will 
revise the CAIR permit, as necessary, in accordance with the permitting 
authority's title V operating permits regulations or the permitting 
authority's regulations for other federally enforceable permits as 
applicable addressing permit revisions.

Subparts DDD-EEE [Reserved]



             Subpart FFF_CAIR SO2 Allowance Tracking System



Sec. 97.250  [Reserved]



Sec. 97.251  Establishment of accounts.

    (a) Compliance accounts. Except as provided in Sec. 97.284(e), upon 
receipt of a complete certificate of representation under Sec. 97.213, 
the Administrator will establish a compliance account for the CAIR 
SO2 source for which the certificate of representation was 
submitted, unless the source already has a compliance account.
    (b) General accounts--(1) Application for general account. (i) Any 
person may apply to open a general account for the purpose of holding 
and transferring CAIR SO2 allowances. An application for a 
general account may designate one and only one CAIR authorized account 
representative and one and only one alternate CAIR authorized account 
representative who may act on behalf of the CAIR authorized account 
representative. The agreement by which the alternate CAIR authorized 
account representative is selected shall include a procedure for 
authorizing the alternate CAIR authorized account representative to act 
in lieu of the CAIR authorized account representative.
    (ii) A complete application for a general account shall be submitted 
to the Administrator and shall include the following elements in a 
format prescribed by the Administrator:
    (A) Name, mailing address, e-mail address (if any), telephone 
number, and facsimile transmission number (if any) of the CAIR 
authorized account representative and any alternate CAIR authorized 
account representative;
    (B) Organization name and type of organization, if applicable;
    (C) A list of all persons subject to a binding agreement for the 
CAIR authorized account representative and any alternate CAIR authorized 
account representative to represent their ownership interest with 
respect to the CAIR SO2 allowances held in the general 
account;
    (D) The following certification statement by the CAIR authorized 
account representative and any alternate CAIR authorized account 
representative: ``I certify that I was selected as the CAIR authorized 
account representative or the alternate CAIR authorized account 
representative, as applicable, by an agreement that is binding on all 
persons who have an ownership interest with respect to CAIR 
SO2 allowances held in the general account. I certify that I 
have all the necessary authority to carry out my duties and 
responsibilities under the CAIR SO2 Trading Program on behalf 
of such persons and that each such person shall be fully bound by my 
representations, actions, inactions, or submissions and by any order or 
decision issued to me by the Administrator or a court regarding the 
general account.''
    (E) The signature of the CAIR authorized account representative and

[[Page 281]]

any alternate CAIR authorized account representative and the dates 
signed.
    (iii) Unless otherwise required by the permitting authority or the 
Administrator, documents of agreement referred to in the application for 
a general account shall not be submitted to the permitting authority or 
the Administrator. Neither the permitting authority nor the 
Administrator shall be under any obligation to review or evaluate the 
sufficiency of such documents, if submitted.
    (2) Authorization of CAIR authorized account representative and 
alternate CAIR authorized account representative. (i) Upon receipt by 
the Administrator of a complete application for a general account under 
paragraph (b)(1) of this section:
    (A) The Administrator will establish a general account for the 
person or persons for whom the application is submitted.
    (B) The CAIR authorized account representative and any alternate 
CAIR authorized account representative for the general account shall 
represent and, by his or her representations, actions, inactions, or 
submissions, legally bind each person who has an ownership interest with 
respect to CAIR SO2 allowances held in the general account in 
all matters pertaining to the CAIR SO2 Trading Program, 
notwithstanding any agreement between the CAIR authorized account 
representative or any alternate CAIR authorized account representative 
and such person. Any such person shall be bound by any order or decision 
issued to the CAIR authorized account representative or any alternate 
CAIR authorized account representative by the Administrator or a court 
regarding the general account.
    (C) Any representation, action, inaction, or submission by any 
alternate CAIR authorized account representative shall be deemed to be a 
representation, action, inaction, or submission by the CAIR authorized 
account representative.
    (ii) Each submission concerning the general account shall be 
submitted, signed, and certified by the CAIR authorized account 
representative or any alternate CAIR authorized account representative 
for the persons having an ownership interest with respect to CAIR 
SO2 allowances held in the general account. Each such 
submission shall include the following certification statement by the 
CAIR authorized account representative or any alternate CAIR authorized 
account representative: ``I am authorized to make this submission on 
behalf of the persons having an ownership interest with respect to the 
CAIR SO2 allowances held in the general account. I certify 
under penalty of law that I have personally examined, and am familiar 
with, the statements and information submitted in this document and all 
its attachments. Based on my inquiry of those individuals with primary 
responsibility for obtaining the information, I certify that the 
statements and information are to the best of my knowledge and belief 
true, accurate, and complete. I am aware that there are significant 
penalties for submitting false statements and information or omitting 
required statements and information, including the possibility of fine 
or imprisonment.''
    (iii) The Administrator will accept or act on a submission 
concerning the general account only if the submission has been made, 
signed, and certified in accordance with paragraph (b)(2)(ii) of this 
section.
    (3) Changing CAIR authorized account representative and alternate 
CAIR authorized account representative; changes in persons with 
ownership interest. (i) The CAIR authorized account representative for a 
general account may be changed at any time upon receipt by the 
Administrator of a superseding complete application for a general 
account under paragraph (b)(1) of this section. Notwithstanding any such 
change, all representations, actions, inactions, and submissions by the 
previous CAIR authorized account representative before the time and date 
when the Administrator receives the superseding application for a 
general account shall be binding on the new CAIR authorized account 
representative and the persons with an ownership interest with respect 
to the CAIR SO2 allowances in the general account.
    (ii) The alternate CAIR authorized account representative for a 
general account may be changed at any time upon receipt by the 
Administrator of a

[[Page 282]]

superseding complete application for a general account under paragraph 
(b)(1) of this section. Notwithstanding any such change, all 
representations, actions, inactions, and submissions by the previous 
alternate CAIR authorized account representative before the time and 
date when the Administrator receives the superseding application for a 
general account shall be binding on the new alternate CAIR authorized 
account representative and the persons with an ownership interest with 
respect to the CAIR SO2 allowances in the general account.
    (iii)(A) In the event a person having an ownership interest with 
respect to CAIR SO2 allowances in the general account is not 
included in the list of such persons in the application for a general 
account, such person shall be deemed to be subject to and bound by the 
application for a general account, the representation, actions, 
inactions, and submissions of the CAIR authorized account representative 
and any alternate CAIR authorized account representative of the account, 
and the decisions and orders of the Administrator or a court, as if the 
person were included in such list.
    (B) Within 30 days following any change in the persons having an 
ownership interest with respect to CAIR SO2 allowances in the 
general account, including the addition of a new person, the CAIR 
authorized account representative or any alternate CAIR authorized 
account representative shall submit a revision to the application for a 
general account amending the list of persons having an ownership 
interest with respect to the CAIR SO2 allowances in the 
general account to include the change.
    (4) Objections concerning CAIR authorized account representative and 
alternate CAIR authorized account representative. (i) Once a complete 
application for a general account under paragraph (b)(1) of this section 
has been submitted and received, the Administrator will rely on the 
application unless and until a superseding complete application for a 
general account under paragraph (b)(1) of this section is received by 
the Administrator.
    (ii) Except as provided in paragraph (b)(3)(i) or (ii) of this 
section, no objection or other communication submitted to the 
Administrator concerning the authorization, or any representation, 
action, inaction, or submission of the CAIR authorized account 
representative or any alternate CAIR authorized account representative 
for a general account shall affect any representation, action, inaction, 
or submission of the CAIR authorized account representative or any 
alternate CAIR authorized account representative or the finality of any 
decision or order by the Administrator under the CAIR SO2 
Trading Program.
    (iii) The Administrator will not adjudicate any private legal 
dispute concerning the authorization or any representation, action, 
inaction, or submission of the CAIR authorized account representative or 
any alternate CAIR authorized account representative for a general 
account, including private legal disputes concerning the proceeds of 
CAIR SO2 allowance transfers.
    (5) Delegation by CAIR authorized account representative and 
alternate CAIR authorized account representative. (i) A CAIR authorized 
account representative may delegate, to one or more natural persons, his 
or her authority to make an electronic submission to the Administrator 
provided for or required under subparts FFF and GGG of this part.
    (ii) An alternate CAIR authorized account representative may 
delegate, to one or more natural persons, his or her authority to make 
an electronic submission to the Administrator provided for or required 
under subparts FFF and GGG of this part.
    (iii) In order to delegate authority to make an electronic 
submission to the Administrator in accordance with paragraph (b)(5)(i) 
or (ii) of this section, the CAIR authorized account representative or 
alternate CAIR authorized account representative, as appropriate, must 
submit to the Administrator a notice of delegation, in a format 
prescribed by the Administrator, that includes the following elements:
    (A) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of such

[[Page 283]]

CAIR authorized account representative or alternate CAIR authorized 
account representative;
    (B) The name, address, e-mail address, telephone number, and, 
facsimile transmission number (if any) of each such natural person 
(referred to as an ``agent'');
    (C) For each such natural person, a list of the type or types of 
electronic submissions under paragraph (b)(5)(i) or (ii) of this section 
for which authority is delegated to him or her;
    (D) The following certification statement by such CAIR authorized 
account representative or alternate CAIR authorized account 
representative: ``I agree that any electronic submission to the 
Administrator that is by an agent identified in this notice of 
delegation and of a type listed for such agent in this notice of 
delegation and that is made when I am a CAIR authorized account 
representative or alternate CAIR authorized representative, as 
appropriate, and before this notice of delegation is superseded by 
another notice of delegation under 40 CFR 97.251(b)(5)(iv) shall be 
deemed to be an electronic submission by me.''; and
    (E) The following certification statement by such CAIR authorized 
account representative or alternate CAIR authorized account 
representative: ``Until this notice of delegation is superseded by 
another notice of delegation under 40 CFR 97.251 (b)(5)(iv), I agree to 
maintain an e-mail account and to notify the Administrator immediately 
of any change in my e-mail address, unless all delegation of authority 
by me under 40 CFR 97.251 (b)(5) is terminated.''.
    (iv) A notice of delegation submitted under paragraph (b)(5)(iii) of 
this section shall be effective, with regard to the CAIR authorized 
account representative or alternate CAIR authorized account 
representative identified in such notice, upon receipt of such notice by 
the Administrator and until receipt by the Administrator of a 
superseding notice of delegation submitted by such CAIR authorized 
account representative or alternate CAIR authorized account 
representative, as appropriate. The superseding notice of delegation may 
replace any previously identified agent, add a new agent, or eliminate 
entirely any delegation of authority.
    (v) Any electronic submission covered by the certification in 
paragraph (b)(5)(iii)(D) of this section and made in accordance with a 
notice of delegation effective under paragraph (b)(5)(iv) of this 
section shall be deemed to be an electronic submission by the CAIR 
designated representative or alternate CAIR designated representative 
submitting such notice of delegation.
    (c) Account identification. The Administrator will assign a unique 
identifying number to each account established under paragraph (a) or 
(b) of this section.



Sec. 97.252  Responsibilities of CAIR authorized account 
representative.

    Following the establishment of a CAIR SO2 Allowance 
Tracking System account, all submissions to the Administrator pertaining 
to the account, including, but not limited to, submissions concerning 
the deduction or transfer of CAIR SO2 allowances in the 
account, shall be made only by the CAIR authorized account 
representative for the account.



Sec. 97.253  Recordation of CAIR SO[bdi2] allowances.

    (a)(1) After a compliance account is established under Sec. 
97.251(a) or Sec. 73.31(a) or (b) of this chapter, the Administrator 
will record in the compliance account any CAIR SO2 allowance 
allocated to any CAIR SO2 unit at the source for each of the 
30 years starting the later of 2010 or the year in which the compliance 
account is established and any CAIR SO2 allowance allocated 
for each of the 30 years starting the later of 2010 or the year in which 
the compliance account is established and transferred to the source in 
accordance with subpart GGG of this part or subpart D of part 73 of this 
chapter.
    (2) In 2011 and each year thereafter, after Administrator has 
completed all deductions under Sec. 97.254(b), the Administrator will 
record in the compliance account any CAIR SO2 allowance 
allocated to any CAIR SO2 unit at the source for the new 30th 
year (i.e., the year that is 30 years after the calendar year for which 
such deductions are or

[[Page 284]]

could be made) and any CAIR SO2 allowance allocated for the 
new 30th year and transferred to the source in accordance with subpart 
GGG of this part or subpart D of part 73 of this chapter.
    (b)(1) After a general account is established under Sec. 97.251(b) 
or Sec. 73.31(c) of this chapter, the Administrator will record in the 
general account any CAIR SO2 allowance allocated for each of 
the 30 years starting the later of 2010 or the year in which the general 
account is established and transferred to the general account in 
accordance with subpart GGG of this part or subpart D of part 73 of this 
chapter.
    (2) In 2011 and each year thereafter, after Administrator has 
completed all deductions under Sec. 97.254(b), the Administrator will 
record in the general account any CAIR SO2 allowance 
allocated for the new 30th year (i.e., the year that is 30 years after 
the calendar year for which such deductions are or could be made) and 
transferred to the general account in accordance with subpart GGG of 
this part or subpart D of part 73 of this chapter.
    (c) Serial numbers for allocated CAIR SO2 allowances. When recording 
the allocation of CAIR SO2 allowances issued by a permitting 
authority under Sec. 97.288, the Administrator will assign each such 
CAIR SO2 allowance a unique identification number that will 
include digits identifying the year of the control period for which the 
CAIR SO2 allowance is allocated.



Sec. 97.254  Compliance with CAIR SO[bdi2] emissions limitation.

    (a) Allowance transfer deadline. The CAIR SO2 allowances 
are available to be deducted for compliance with a source's CAIR 
SO2 emissions limitation for a control period in a given 
calendar year only if the CAIR SO2 allowances:
    (1) Were allocated for the control period in the year or a prior 
year; and
    (2) Are held in the compliance account as of the allowance transfer 
deadline for the control period or are transferred into the compliance 
account by a CAIR SO2 allowance transfer correctly submitted 
for recordation under Sec. Sec. 97.260 and 97.261 by the allowance 
transfer deadline for the control period.
    (b) Deductions for compliance. Following the recordation, in 
accordance with Sec. 97.261, of CAIR SO2 allowance transfers 
submitted for recordation in a source's compliance account by the 
allowance transfer deadline for a control period, the Administrator will 
deduct from the compliance account CAIR SO2 allowances 
available under paragraph (a) of this section in order to determine 
whether the source meets the CAIR SO2 emissions limitation 
for the control period as follows:
    (1) For a CAIR SO2 source subject to an Acid Rain 
emissions limitation, the Administrator will, in the following order:
    (i) Deduct the amount of CAIR SO2 allowances, available 
under paragraph (a) of this section and not issued by a permitting 
authority under Sec. 97.288, that is required under Sec. Sec. 73.35(b) 
and (c) of this part. If there are sufficient CAIR SO2 
allowances to complete this deduction, the deduction will be treated as 
satisfying the requirements of Sec. Sec. 73.35(b) and (c) of this 
chapter.
    (ii) Deduct the amount of CAIR SO2 allowances, not issued 
by a permitting authority under Sec. 97.288, that is required under 
Sec. Sec. 73.35(d) and 77.5 of this part. If there are sufficient CAIR 
SO2 allowances to complete this deduction, the deduction will 
be treated as satisfying the requirements of Sec. Sec. 73.35(d) and 
77.5 of this chapter.
    (iii) Treating the CAIR SO2 allowances deducted under 
paragraph (b)(1)(i) of this section as also being deducted under this 
paragraph (b)(1)(iii), deduct CAIR SO2 allowances available 
under paragraph (a) of this section (including any issued by a 
permitting authority under Sec. 97.288) in order to determine whether 
the source meets the CAIR SO2 emissions limitation for the 
control period, as follows:
    (A) Until the tonnage equivalent of the CAIR SO2 
allowances deducted equals, or exceeds in accordance with paragraphs 
(c)(1) and (2) of this section, the number of tons of total sulfur 
dioxide emissions, determined in accordance with subpart HHH of this 
part, from all CAIR SO2 units at the source for the control 
period; or
    (B) If there are insufficient CAIR SO2 allowances to 
complete the deductions

[[Page 285]]

in paragraph (b)(1)(iii)(A) of this section, until no more CAIR 
SO2 allowances available under paragraph (a) of this section 
(including any issued by a permitting authority under Sec. 97.288) 
remain in the compliance account.
    (2) For a CAIR SO2 source not subject to an Acid Rain 
emissions limitation, the Administrator will deduct CAIR SO2 
allowances available under paragraph (a) of this section (including any 
issued by a permitting authority under Sec. 97.288) in order to 
determine whether the source meets the CAIR SO2 emissions 
limitation for the control period, as follows:
    (i) Until the tonnage equivalent of the CAIR SO2 
allowances deducted equals, or exceeds in accordance with paragraphs 
(c)(1) and (2) of this section, the number of tons of total sulfur 
dioxide emissions, determined in accordance with subpart HHH of this 
part, from all CAIR SO2 units at the source for the control 
period; or
    (ii) If there are insufficient CAIR SO2 allowances to 
complete the deductions in paragraph (b)(2)(i) of this section, until no 
more CAIR SO2 allowances available under paragraph (a) of 
this section (including any issued by a permitting authority under Sec. 
97.288) remain in the compliance account.
    (c)(1) Identification of CAIR SO2 allowances by serial 
number. The CAIR authorized account representative for a source's 
compliance account may request that specific CAIR SO2 
allowances, identified by serial number, in the compliance account be 
deducted for emissions or excess emissions for a control period in 
accordance with paragraph (b) or (d) of this section. Such request shall 
be submitted to the Administrator by the allowance transfer deadline for 
the control period and include, in a format prescribed by the 
Administrator, the identification of the CAIR SO2 source and 
the appropriate serial numbers.
    (2) First-in, first-out. The Administrator will deduct CAIR 
SO2 allowances under paragraph (b) or (d) of this section 
from the source's compliance account, in the absence of an 
identification or in the case of a partial identification of CAIR 
SO2 allowances by serial number under paragraph (c)(1) of 
this section, on a first-in, first-out (FIFO) accounting basis in the 
following order:
    (i) Any CAIR SO2 allowances that were allocated to the 
units at the source for a control period before 2010, in the order of 
recordation;
    (ii) Any CAIR SO2 allowances that were allocated to any 
entity for a control period before 2010 and transferred and recorded in 
the compliance account pursuant to subpart GGG of this part or subpart D 
of part 73 of this chapter, in the order of recordation;
    (iii) Any CAIR SO2 allowances that were allocated to the 
units at the source for a control period during 2010 through 2014, in 
the order of recordation;
    (iv) Any CAIR SO2 allowances that were allocated to any 
entity for a control period during 2010 through 2014 and transferred and 
recorded in the compliance account pursuant to subpart GGG of this part 
or subpart D of part 73 of this chapter, in the order of recordation;
    (v) Any CAIR SO2 allowances that were allocated to the 
units at the source for a control period in 2015 or later, in the order 
of recordation; and
    (vi) Any CAIR SO2 allowances that were allocated to any 
entity for a control period in 2015 or later and transferred and 
recorded in the compliance account pursuant to subpart GGG of this part 
or subpart D of part 73 of this chapter, in the order of recordation.
    (d) Deductions for excess emissions. (1) After making the deductions 
for compliance under paragraph (b) of this section for a control period 
in a calendar year in which the CAIR SO2 source has excess 
emissions, the Administrator will deduct from the source's compliance 
account the tonnage equivalent in CAIR SO2 allowances, 
allocated for the control period in the immediately following calendar 
year (including any issued by a permitting authority under Sec. 
97.288), equal to, or exceeding in accordance with paragraphs (c)(1) and 
(2) of this section 3 times the following amount: the number of tons of 
the source's excess emissions minus, if the source is subject to an Acid 
Rain emissions limitation, the amount of the CAIR SO2 
allowances required to be deducted under paragraph (b)(1)(ii) of this 
section.

[[Page 286]]

    (2) Any allowance deduction required under paragraph (d)(1) of this 
section shall not affect the liability of the owners and operators of 
the CAIR SO2 source or the CAIR SO2 units at the 
source for any fine, penalty, or assessment, or their obligation to 
comply with any other remedy, for the same violations, as ordered under 
the Clean Air Act or applicable State law.
    (e) Recordation of deductions. The Administrator will record in the 
appropriate compliance account all deductions from such an account under 
paragraphs (b) and (d) of this section and subpart III.
    (f) Administrator's action on submissions. (1) The Administrator may 
review and conduct independent audits concerning any submission under 
the CAIR SO2 Trading Program and make appropriate adjustments 
of the information in the submissions.
    (2) The Administrator may deduct CAIR SO2 allowances from 
or transfer CAIR SO2 allowances to a source's compliance 
account based on the information in the submissions, as adjusted under 
paragraph (f)(1) of this section, and record such deductions and 
transfers.



Sec. 97.255  Banking.

    (a) CAIR SO2 allowances may be banked for future use or 
transfer in a compliance account or a general account in accordance with 
paragraph (b) of this section.
    (b) Any CAIR SO2 allowance that is held in a compliance 
account or a general account will remain in such account unless and 
until the CAIR SO2 allowance is deducted or transferred under 
Sec. 97.254, Sec. 97.256, or subpart GGG or III of this part.



Sec. 97.256  Account error.

    The Administrator may, at his or her sole discretion and on his or 
her own motion, correct any error in any CAIR SO2 Allowance 
Tracking System account. Within 10 business days of making such 
correction, the Administrator will notify the CAIR authorized account 
representative for the account.



Sec. 97.257  Closing of general accounts.

    (a) The CAIR authorized account representative of a general account 
may submit to the Administrator a request to close the account, which 
shall include a correctly submitted allowance transfer under Sec. Sec. 
97.260 and 97.261 for any CAIR SO2 allowances in the account 
to one or more other CAIR SO2 Allowance Tracking System 
accounts.
    (b) If a general account has no allowance transfers in or out of the 
account for a 12-month period or longer and does not contain any CAIR 
SO2 allowances, the Administrator may notify the CAIR 
authorized account representative for the account that the account will 
be closed following 20 business days after the notice is sent. The 
account will be closed after the 20-day period unless, before the end of 
the 20-day period, the Administrator receives a correctly submitted 
transfer of CAIR SO2 allowances into the account under 
Sec. Sec. 97.260 and 97.261 or a statement submitted by the CAIR 
authorized account representative demonstrating to the satisfaction of 
the Administrator good cause as to why the account should not be closed.



                Subpart GGG_CAIR SO2 Allowance Transfers



Sec. 97.260  Submission of CAIR SO[bdi2] allowance transfers.

    (a) A CAIR authorized account representative seeking recordation of 
a CAIR SO2 allowance transfer shall submit the transfer to 
the Administrator. To be considered correctly submitted, the CAIR 
SO2 allowance transfer shall include the following elements, 
in a format specified by the Administrator:
    (1) The account numbers of both the transferor and transferee 
accounts;
    (2) The serial number of each CAIR SO2 allowance that is 
in the transferor account and is to be transferred; and
    (3) The name and signature of the CAIR authorized account 
representatives of the transferor and transferee accounts and the dates 
signed.
    (b)(1) The CAIR authorized account representative for the transferee 
account can meet the requirements in paragraph (a)(3) of this section by 
submitting, in a format prescribed by the Administrator, a statement 
signed by

[[Page 287]]

the CAIR authorized account representative and identifying each account 
into which any transfer of allowances, submitted on or after the date on 
which the Administrator receives such statement, is authorized. Such 
authorization shall be binding on any CAIR authorized account 
representative for such account and shall apply to all transfers into 
the account that are submitted on or after such date of receipt, unless 
and until the Administrator receives a statement signed by the CAIR 
authorized account representative retracting the authorization for the 
account.
    (2) The statement under paragraph (b)(1) of this section shall 
include the following: ``By this signature I authorize any transfer of 
allowances into each account listed herein, except that I do not waive 
any remedies under State or Federal law to obtain correction of any 
erroneous transfers into such accounts. This authorization shall be 
binding on any CAIR authorized account representative for such account 
unless and until a statement signed by the CAIR authorized account 
representative retracting this authorization for the account is received 
by the Administrator.''



Sec. 97.261  EPA recordation.

    (a) Within 5 business days (except as necessary to perform a 
transfer in perpetuity of CAIR SO2 allowances allocated to a 
CAIR SO2 unit or as provided in paragraph (b) of this 
section) of receiving a CAIR SO2 allowance transfer, the 
Administrator will record a CAIR SO2 allowance transfer by 
moving each CAIR SO2 allowance from the transferor account to 
the transferee account as specified by the request, provided that:
    (1) The transfer is correctly submitted under Sec. 97.260;
    (2) The transferor account includes each CAIR SO2 
allowance identified by serial number in the transfer; and
    (3) The transfer is in accordance with the limitation on transfer 
under Sec. 74.42 of this chapter and Sec. 74.47(c) of this chapter, as 
applicable.
    (b) A CAIR SO2 allowance transfer that is submitted for 
recordation after the allowance transfer deadline for a control period 
and that includes any CAIR SO2 allowances allocated for any 
control period before such allowance transfer deadline will not be 
recorded until after the Administrator completes the deductions under 
Sec. 97.254 for the control period immediately before such allowance 
transfer deadline.
    (c) Where a CAIR SO2 allowance transfer submitted for 
recordation fails to meet the requirements of paragraph (a) of this 
section, the Administrator will not record such transfer.



Sec. 97.262  Notification.

    (a) Notification of recordation. Within 5 business days of 
recordation of a CAIR SO2 allowance transfer under Sec. 
97.261, the Administrator will notify the CAIR authorized account 
representatives of both the transferor and transferee accounts.
    (b) Notification of non-recordation. Within 10 business days of 
receipt of a CAIR SO2 allowance transfer that fails to meet 
the requirements of Sec. 97.261(a), the Administrator will notify the 
CAIR authorized account representatives of both accounts subject to the 
transfer of:
    (1) A decision not to record the transfer, and
    (2) The reasons for such non-recordation.
    (c) Nothing in this section shall preclude the submission of a CAIR 
SO2 allowance transfer for recordation following notification 
of non-recordation.



                  Subpart HHH_Monitoring and Reporting



Sec. 97.270  General requirements.

    The owners and operators, and to the extent applicable, the CAIR 
designated representative, of a CAIR SO2 unit, shall comply 
with the monitoring, recordkeeping, and reporting requirements as 
provided in this subpart and in subparts F and G of part 75 of this 
chapter. For purposes of complying with such requirements, the 
definitions in Sec. 97.202 and in Sec. 72.2 of this chapter shall 
apply, and the terms ``affected unit,'' ``designated representative,'' 
and ``continuous emission monitoring system'' (or ``CEMS'') in part 75 
of this chapter shall be deemed to refer to the

[[Page 288]]

terms ``CAIR SO2 unit,'' ``CAIR designated representative,'' 
and ``continuous emission monitoring system'' or (``CEMS'') 
respectively, as defined in Sec. 97.202. The owner or operator of a 
unit that is not a CAIR SO2 unit but that is monitored under 
Sec. 75.16(b)(2) of this chapter shall comply with the same monitoring, 
recordkeeping, and reporting requirements as a CAIR SO2 unit.
    (a) Requirements for installation, certification, and data 
accounting. The owner or operator of each CAIR SO2 unit 
shall:
    (1) Install all monitoring systems required under this subpart for 
monitoring SO2 mass emissions and individual unit heat input 
(including all systems required to monitor SO2 concentration, 
stack gas moisture content, stack gas flow rate, CO2 or 
O2 concentration, and fuel flow rate, as applicable, in 
accordance with Sec. Sec. 75.11 and 75.16 of this chapter);
    (2) Successfully complete all certification tests required under 
Sec. 97.271 and meet all other requirements of this subpart and part 75 
of this chapter applicable to the monitoring systems under paragraph 
(a)(1) of this section; and
    (3) Record, report, and quality-assure the data from the monitoring 
systems under paragraph (a)(1) of this section.
    (b) Compliance deadlines. Except as provided in paragraph (e) of 
this section, the owner or operator shall meet the monitoring system 
certification and other requirements of paragraphs (a)(1) and (2) of 
this section on or before the following dates. The owner or operator 
shall record, report, and quality-assure the data from the monitoring 
systems under paragraph (a)(1) of this section on and after the 
following dates.
    (1) For the owner or operator of a CAIR SO2 unit that 
commences commercial operation before July 1, 2008, by January 1, 2009.
    (2) For the owner or operator of a CAIR SO2 unit that 
commences commercial operation on or after July 1, 2008, by the later of 
the following dates:
    (i) January 1, 2009; or
    (ii) 90 unit operating days or 180 calendar days, whichever occurs 
first, after the date on which the unit commences commercial operation.
    (3) For the owner or operator of a CAIR SO2 unit for 
which construction of a new stack or flue or installation of add-on 
SO2 emission controls is completed after the applicable 
deadline under paragraph (b)(1), (2), (4), or (5) of this section, by 90 
unit operating days or 180 calendar days, whichever occurs first, after 
the date on which emissions first exit to the atmosphere through the new 
stack or flue or add-on SO2 emissions controls.
    (4) Notwithstanding the dates in paragraphs (b)(1) and (2) of this 
section, for the owner or operator of a unit for which a CAIR opt-in 
permit application is submitted and not withdrawn and a CAIR opt-in 
permit is not yet issued or denied under subpart III of this part, by 
the date specified in Sec. 97.284(b).
    (5) Notwithstanding the dates in paragraphs (b)(1) and (2) of this 
section, for the owner or operator of a CAIR SO2 opt-in unit 
under subpart III of this part, by the date on which the CAIR 
SO2 opt-in unit enters the CAIR SO2 Trading 
Program as provided in Sec. 97.284(g).
    (c) Reporting data. The owner or operator of a CAIR SO2 
unit that does not meet the applicable compliance date set forth in 
paragraph (b) of this section for any monitoring system under paragraph 
(a)(1) of this section shall, for each such monitoring system, 
determine, record, and report maximum potential (or, as appropriate, 
minimum potential) values for SO2 concentration, stack gas 
flow rate, stack gas moisture content, fuel flow rate, and any other 
parameters required to determine SO2 mass emissions and heat 
input in accordance with Sec. 75.31(b)(2) or (c)(3) of this chapter or 
section 2.4 of appendix D to part 75 of this chapter, as applicable.
    (d) Prohibitions. (1) No owner or operator of a CAIR SO2 
unit shall use any alternative monitoring system, alternative reference 
method, or any other alternative to any requirement of this subpart 
without having obtained prior written approval in accordance with Sec. 
97.275.
    (2) No owner or operator of a CAIR SO2 unit shall operate 
the unit so as to discharge, or allow to be discharged,

[[Page 289]]

SO2 emissions to the atmosphere without accounting for all 
such emissions in accordance with the applicable provisions of this 
subpart and part 75 of this chapter.
    (3) No owner or operator of a CAIR SO2 unit shall disrupt 
the continuous emission monitoring system, any portion thereof, or any 
other approved emission monitoring method, and thereby avoid monitoring 
and recording SO2 mass emissions discharged into the 
atmosphere or heat input, except for periods of recertification or 
periods when calibration, quality assurance testing, or maintenance is 
performed in accordance with the applicable provisions of this subpart 
and part 75 of this chapter.
    (4) No owner or operator of a CAIR SO2 unit shall retire 
or permanently discontinue use of the continuous emission monitoring 
system, any component thereof, or any other approved monitoring system 
under this subpart, except under any one of the following circumstances:
    (i) During the period that the unit is covered by an exemption under 
Sec. 97.205 that is in effect;
    (ii) The owner or operator is monitoring emissions from the unit 
with another certified monitoring system approved, in accordance with 
the applicable provisions of this subpart and part 75 of this chapter, 
by the Administrator for use at that unit that provides emission data 
for the same pollutant or parameter as the retired or discontinued 
monitoring system; or
    (iii) The CAIR designated representative submits notification of the 
date of certification testing of a replacement monitoring system for the 
retired or discontinued monitoring system in accordance with Sec. 
97.271(d)(3)(i).
    (e) Long-term cold storage. The owner or operator of a CAIR 
SO2 unit is subject to the applicable provisions of part 75 
of this chapter concerning units in long-term cold storage.



Sec. 97.271  Initial certification and recertification procedures.

    (a) The owner or operator of a CAIR SO2 unit shall be 
exempt from the initial certification requirements of this section for a 
monitoring system under Sec. 97.270(a)(1) if the following conditions 
are met:
    (1) The monitoring system has been previously certified in 
accordance with part 75 of this chapter; and
    (2) The applicable quality-assurance and quality-control 
requirements of Sec. 75.21 of this chapter and appendix B and appendix 
D to part 75 of this chapter are fully met for the certified monitoring 
system described in paragraph (a)(1) of this section.
    (b) The recertification provisions of this section shall apply to a 
monitoring system under Sec. 97.270(a)(1) exempt from initial 
certification requirements under paragraph (a) of this section.
    (c) [Reserved]
    (d) Except as provided in paragraph (a) of this section, the owner 
or operator of a CAIR SO2 unit shall comply with the 
following initial certification and recertification procedures, for a 
continuous monitoring system (i.e., a continuous emission monitoring 
system and an excepted monitoring system under appendix D to part 75 of 
this chapter) under Sec. 97.270(a)(1). The owner or operator of a unit 
that qualifies to use the low mass emissions excepted monitoring 
methodology under Sec. 75.19 of this chapter or that qualifies to use 
an alternative monitoring system under subpart E of part 75 of this 
chapter shall comply with the procedures in paragraph (e) or (f) of this 
section respectively.
    (1) Requirements for initial certification. The owner or operator 
shall ensure that each continuous monitoring system under Sec. 
97.270(a)(1) (including the automated data acquisition and handling 
system) successfully completes all of the initial certification testing 
required under Sec. 75.20 of this chapter by the applicable deadline in 
Sec. 97.270(b). In addition, whenever the owner or operator installs a 
monitoring system to meet the requirements of this subpart in a location 
where no such monitoring system was previously installed, initial 
certification in accordance with Sec. 75.20 of this chapter is 
required.
    (2) Requirements for recertification. Whenever the owner or operator 
makes a replacement, modification, or change in any certified continuous 
emission monitoring system under Sec. 97.270(a)(1)

[[Page 290]]

that may significantly affect the ability of the system to accurately 
measure or record SO2 mass emissions or heat input rate or to 
meet the quality-assurance and quality-control requirements of Sec. 
75.21 of this chapter or appendix B to part 75 of this chapter, the 
owner or operator shall recertify the monitoring system in accordance 
with Sec. 75.20(b) of this chapter. Furthermore, whenever the owner or 
operator makes a replacement, modification, or change to the flue gas 
handling system or the unit's operation that may significantly change 
the stack flow or concentration profile, the owner or operator shall 
recertify each continuous emission monitoring system whose accuracy is 
potentially affected by the change, in accordance with Sec. 75.20(b) of 
this chapter. Examples of changes to a continuous emission monitoring 
system that require recertification include: replacement of the 
analyzer, complete replacement of an existing continuous emission 
monitoring system, or change in location or orientation of the sampling 
probe or site. Any fuel flowmeter system under Sec. 97.270(a)(1) is 
subject to the recertification requirements in Sec. 75.20(g)(6) of this 
chapter.
    (3) Approval process for initial certification and recertification. 
Paragraphs (d)(3)(i) through (iv) of this section apply to both initial 
certification and recertification of a continuous monitoring system 
under Sec. 97.270(a)(1). For recertifications, replace the words 
``certification'' and ``initial certification'' with the word 
``recertification'', replace the word ``certified'' with the word 
``recertified,'' and follow the procedures in Sec. Sec. 75.20(b)(5) and 
(g)(7) of this chapter in lieu of the procedures in paragraph (d)(3)(v) 
of this section.
    (i) Notification of certification. The CAIR designated 
representative shall submit to the appropriate EPA Regional Office and 
the Administrator written notice of the dates of certification testing, 
in accordance with Sec. 97.273.
    (ii) Certification application. The CAIR designated representative 
shall submit to the Administrator a certification application for each 
monitoring system. A complete certification application shall include 
the information specified in Sec. 75.63 of this chapter.
    (iii) Provisional certification date. The provisional certification 
date for a monitoring system shall be determined in accordance with 
Sec. 75.20(a)(3) of this chapter. A provisionally certified monitoring 
system may be used under the CAIR SO2 Trading Program for a 
period not to exceed 120 days after receipt by the Administrator of the 
complete certification application for the monitoring system under 
paragraph (d)(3)(ii) of this section. Data measured and recorded by the 
provisionally certified monitoring system, in accordance with the 
requirements of part 75 of this chapter, will be considered valid 
quality-assured data (retroactive to the date and time of provisional 
certification), provided that the Administrator does not invalidate the 
provisional certification by issuing a notice of disapproval within 120 
days of the date of receipt of the complete certification application by 
the Administrator.
    (iv) Certification application approval process. The Administrator 
will issue a written notice of approval or disapproval of the 
certification application to the owner or operator within 120 days of 
receipt of the complete certification application under paragraph 
(d)(3)(ii) of this section. In the event the Administrator does not 
issue such a notice within such 120-day period, each monitoring system 
that meets the applicable performance requirements of part 75 of this 
chapter and is included in the certification application will be deemed 
certified for use under the CAIR SO2 Trading Program.
    (A) Approval notice. If the certification application is complete 
and shows that each monitoring system meets the applicable performance 
requirements of part 75 of this chapter, then the Administrator will 
issue a written notice of approval of the certification application 
within 120 days of receipt.
    (B) Incomplete application notice. If the certification application 
is not complete, then the Administrator will issue a written notice of 
incompleteness that sets a reasonable date by

[[Page 291]]

which the CAIR designated representative must submit the additional 
information required to complete the certification application. If the 
CAIR designated representative does not comply with the notice of 
incompleteness by the specified date, then the Administrator may issue a 
notice of disapproval under paragraph (d)(3)(iv)(C) of this section. The 
120-day review period shall not begin before receipt of a complete 
certification application.
    (C) Disapproval notice. If the certification application shows that 
any monitoring system does not meet the performance requirements of part 
75 of this chapter or if the certification application is incomplete and 
the requirement for disapproval under paragraph (d)(3)(iv)(B) of this 
section is met, then the Administrator will issue a written notice of 
disapproval of the certification application. Upon issuance of such 
notice of disapproval, the provisional certification is invalidated by 
the Administrator and the data measured and recorded by each uncertified 
monitoring system shall not be considered valid quality-assured data 
beginning with the date and hour of provisional certification (as 
defined under Sec. 75.20(a)(3) of this chapter). The owner or operator 
shall follow the procedures for loss of certification in paragraph 
(d)(3)(v) of this section for each monitoring system that is disapproved 
for initial certification.
    (D) Audit decertification. The Administrator may issue a notice of 
disapproval of the certification status of a monitor in accordance with 
Sec. 97.272(b).
    (v) Procedures for loss of certification. If the Administrator 
issues a notice of disapproval of a certification application under 
paragraph (d)(3)(iv)(C) of this section or a notice of disapproval of 
certification status under paragraph (d)(3)(iv)(D) of this section, 
then:
    (A) The owner or operator shall substitute the following values, for 
each disapproved monitoring system, for each hour of unit operation 
during the period of invalid data specified under Sec. 
75.20(a)(4)(iii), Sec. 75.20(g)(7), or Sec. 75.21(e) of this chapter 
and continuing until the applicable date and hour specified under Sec. 
75.20(a)(5)(i) or (g)(7) of this chapter:
    (1) For a disapproved SO2 pollutant concentration monitor 
and disapproved flow monitor, respectively, the maximum potential 
concentration of SO2 and the maximum potential flow rate, as 
defined in sections 2.1.1.1 and 2.1.4.1 of appendix A to part 75 of this 
chapter.
    (2) For a disapproved moisture monitoring system and disapproved 
diluent gas monitoring system, respectively, the minimum potential 
moisture percentage and either the maximum potential CO2 
concentration or the minimum potential O2 concentration (as 
applicable), as defined in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of 
appendix A to part 75 of this chapter.
    (3) For a disapproved fuel flowmeter system, the maximum potential 
fuel flow rate, as defined in section 2.4.2.1 of appendix D to part 75 
of this chapter.
    (B) The CAIR designated representative shall submit a notification 
of certification retest dates and a new certification application in 
accordance with paragraphs (d)(3)(i) and (ii) of this section.
    (C) The owner or operator shall repeat all certification tests or 
other requirements that were failed by the monitoring system, as 
indicated in the Administrator's notice of disapproval, no later than 30 
unit operating days after the date of issuance of the notice of 
disapproval.
    (e) Initial certification and recertification procedures for units 
using the low mass emission excepted methodology under Sec. 75.19 of 
this chapter. The owner or operator of a unit qualified to use the low 
mass emissions (LME) excepted methodology under Sec. 75.19 of this 
chapter shall meet the applicable certification and recertification 
requirements in Sec. Sec. 75.19(a)(2) and 75.20(h) of this chapter. If 
the owner or operator of such a unit elects to certify a fuel flowmeter 
system for heat input determination, the owner or operator shall also 
meet the certification and recertification requirements in Sec. 
75.20(g) of this chapter.
    (f) Certification/recertification procedures for alternative 
monitoring systems. The CAIR designated representative of each unit for 
which the owner or operator intends to use an alternative monitoring 
system approved by the Administrator under subpart E of part 75 of

[[Page 292]]

this chapter shall comply with the applicable notification and 
application procedures of Sec. 75.20(f) of this chapter.



Sec. 97.272  Out of control periods.

    (a) Whenever any monitoring system fails to meet the quality-
assurance and quality-control requirements or data validation 
requirements of part 75 of this chapter, data shall be substituted using 
the applicable missing data procedures in subpart D of appendix D to 
part 75 of this chapter.
    (b) Audit decertification. Whenever both an audit of a monitoring 
system and a review of the initial certification or recertification 
application reveal that any monitoring system should not have been 
certified or recertified because it did not meet a particular 
performance specification or other requirement under Sec. 97.271 or the 
applicable provisions of part 75 of this chapter, both at the time of 
the initial certification or recertification application submission and 
at the time of the audit, the Administrator will issue a notice of 
disapproval of the certification status of such monitoring system. For 
the purposes of this paragraph, an audit shall be either a field audit 
or an audit of any information submitted to the permitting authority or 
the Administrator. By issuing the notice of disapproval, the 
Administrator revokes prospectively the certification status of the 
monitoring system. The data measured and recorded by the monitoring 
system shall not be considered valid quality-assured data from the date 
of issuance of the notification of the revoked certification status 
until the date and time that the owner or operator completes 
subsequently approved initial certification or recertification tests for 
the monitoring system. The owner or operator shall follow the applicable 
initial certification or recertification procedures in Sec. 97.271 for 
each disapproved monitoring system.



Sec. 97.273  Notifications.

    The CAIR designated representative for a CAIR SO2 unit 
shall submit written notice to the Administrator in accordance with 
Sec. 75.61 of this chapter. Sec. 97.274 Recordkeeping and reporting.
    (a) General provisions. The CAIR designated representative shall 
comply with all recordkeeping and reporting requirements in this 
section, the applicable recordkeeping and reporting requirements in 
subparts F and G of part 75 of this chapter, and the requirements of 
Sec. 97.210(e)(1).
    (b) Monitoring Plans. The owner or operator of a CAIR SO2 
unit shall comply with requirements of Sec. 75.62 of this chapter and, 
for a unit for which a CAIR opt-in permit application is submitted and 
not withdrawn and a CAIR opt-in permit is not yet issued or denied under 
subpart III of this part, Sec. Sec. 97.283 and 97.284(a).
    (c) Certification Applications. The CAIR designated representative 
shall submit an application to the Administrator within 45 days after 
completing all initial certification or recertification tests required 
under Sec. 97.271, including the information required under Sec. 75.63 
of this chapter.
    (d) Quarterly reports. The CAIR designated representative shall 
submit quarterly reports, as follows:
    (1) The CAIR designated representative shall report the 
SO2 mass emissions data and heat input data for the CAIR 
SO2 unit, in an electronic quarterly report in a format 
prescribed by the Administrator, for each calendar quarter beginning 
with:
    (i) For a unit that commences commercial operation before July 1, 
2008, the calendar quarter covering January 1, 2009 through March 31, 
2009;
    (ii) For a unit that commences commercial operation on or after July 
1, 2008, the calendar quarter corresponding to the earlier of the date 
of provisional certification or the applicable deadline for initial 
certification under Sec. 97.270(b), unless that quarter is the third or 
fourth quarter of 2008, in which case reporting shall commence in the 
quarter covering January 1, 2009 through March 31, 2009;
    (iii) Notwithstanding paragraphs (d)(1)(i) and (ii) of this section, 
for a unit for which a CAIR opt-in permit application is submitted and 
not withdrawn and a CAIR opt-in permit is not yet issued or denied under 
subpart III of this part, the calendar quarter corresponding to the date 
specified in Sec. 97.284(b); and

[[Page 293]]

    (iv) Notwithstanding paragraphs (d)(1)(i) and (ii) of this section, 
for a CAIR SO2 opt-in unit under subpart III of this part, 
the calendar quarter corresponding to the date on which the CAIR 
SO2 opt-in unit enters the CAIR SO2 Trading 
Program as provided in Sec. 97.284(g).
    (2) The CAIR designated representative shall submit each quarterly 
report to the Administrator within 30 days following the end of the 
calendar quarter covered by the report. Quarterly reports shall be 
submitted in the manner specified in Sec. 75.64 of this chapter.
    (3) For CAIR SO2 units that are also subject to an Acid 
Rain emissions limitation or the CAIR NOX Annual Trading 
Program, CAIR NOX Ozone Season Trading Program, or Hg Budget 
Trading Program, quarterly reports shall include the applicable data and 
information required by subparts F through I of part 75 of this chapter 
as applicable, in addition to the SO2 mass emission data, 
heat input data, and other information required by this subpart.
    (e) Compliance certification. The CAIR designated representative 
shall submit to the Administrator a compliance certification (in a 
format prescribed by the Administrator) in support of each quarterly 
report based on reasonable inquiry of those persons with primary 
responsibility for ensuring that all of the unit's emissions are 
correctly and fully monitored. The certification shall state that:
    (1) The monitoring data submitted were recorded in accordance with 
the applicable requirements of this subpart and part 75 of this chapter, 
including the quality assurance procedures and specifications; and
    (2) For a unit with add-on SO2 emission controls and for 
all hours where SO2 data are substituted in accordance with 
Sec. 75.34(a)(1) of this chapter, the add-on emission controls were 
operating within the range of parameters listed in the quality 
assurance/quality control program under appendix B to part 75 of this 
chapter and the substitute data values do not systematically 
underestimate SO2 emissions.



Sec. 97.275  Petitions.

    The CAIR designated representative of a CAIR SO2 unit may 
submit a petition under Sec. 75.66 of this chapter to the Administrator 
requesting approval to apply an alternative to any requirement of this 
subpart. Application of an alternative to any requirement of this 
subpart is in accordance with this subpart only to the extent that the 
petition is approved in writing by the Administrator, in consultation 
with the permitting authority.



                    Subpart III_CAIR SO2 Opt-in Units



Sec. 97.280  Applicability.

    A CAIR SO2 opt-in unit must be a unit that:
    (a) Is located in a State that submits, and for which the 
Administrator approves, a State implementation plan revision in 
accordance with Sec. 51.124(r)(1), (2), or (3) of this chapter 
establishing procedures concerning CAIR opt-in units;
    (b) Is not a CAIR SO2 unit under Sec. 97.204 and is not 
covered by a retired unit exemption under Sec. 97.205 that is in 
effect;
    (c) Is not covered by a retired unit exemption under Sec. 72.8 of 
this chapter that is in effect and is not an opt-in source under part 74 
of this chapter;
    (d) Has or is required or qualified to have a title V operating 
permit or other federally enforceable permit; and
    (e) Vents all of its emissions to a stack and can meet the 
monitoring, recordkeeping, and reporting requirements of subpart HH of 
this part.



Sec. 97.281  General.

    (a) Except as otherwise provided in Sec. Sec. 97.201 through 
97.204, Sec. Sec. 97.206 through 97.208, and subparts BBB and CCC and 
subparts FFF through HHH of this part, a CAIR SO2 opt-in unit 
shall be treated as a CAIR SO2 unit for purposes of applying 
such sections and subparts of this part.
    (b) Solely for purposes of applying, as provided in this subpart, 
the requirements of subpart HHH of this part to a unit for which a CAIR 
opt-in permit application is submitted and not withdrawn and a CAIR opt-
in permit is not yet issued or denied under this subpart, such unit 
shall be treated as a CAIR SO2 unit before issuance of a CAIR 
opt-in permit for such unit.

[[Page 294]]



Sec. 97.282  CAIR designated representative.

    Any CAIR SO2 opt-in unit, and any unit for which a CAIR 
opt-in permit application is submitted and not withdrawn and a CAIR opt-
in permit is not yet issued or denied under this subpart, located at the 
same source as one or more CAIR SO2 units shall have the same 
CAIR designated representative and alternate CAIR designated 
representative as such CAIR SO2 units.



Sec. 97.283  Applying for CAIR opt-in permit.

    (a) Applying for initial CAIR opt-in permit. The CAIR designated 
representative of a unit meeting the requirements for a CAIR 
SO2 opt-in unit in Sec. 97.280 may apply for an initial CAIR 
opt-in permit at any time, except as provided under Sec. 97.286(f) and 
(g), and, in order to apply, must submit the following:
    (1) A complete CAIR permit application under Sec. 97.222;
    (2) A certification, in a format specified by the permitting 
authority, that the unit:
    (i) Is not a CAIR SO2 unit under Sec. 97.204 and is not 
covered by a retired unit exemption under Sec. 97.205 that is in 
effect;
    (ii) Is not covered by a retired unit exemption under Sec. 72.8 of 
this chapter that is in effect;
    (iii) Is not and, so long as the unit is a CAIR SO2 opt-
in unit, will not become, an opt-in source under part 74 of this 
chapter;
    (iv) Vents all of its emissions to a stack; and
    (v) Has documented heat input for more than 876 hours during the 6 
months immediately preceding submission of the CAIR permit application 
under Sec. 97.222;
    (3) A monitoring plan in accordance with subpart HHH of this part;
    (4) A complete certificate of representation under Sec. 97.213 
consistent with Sec. 97.282, if no CAIR designated representative has 
been previously designated for the source that includes the unit; and
    (5) A statement, in a format specified by the permitting authority, 
whether the CAIR designated representative requests that the unit be 
allocated CAIR SO2 allowances under Sec. 97.288(b) or Sec. 
97.288(c) (subject to the conditions in Sec. Sec. 97.284(h) and 
97.286(g)), to the extent such allocation is provided in a State 
implementation plan revision submitted in accordance with Sec. 
51.124(r)(1), (2), or (3) of this chapter and approved by the 
Administrator. If allocation under Sec. 97.288(c) is requested, this 
statement shall include a statement that the owners and operators of the 
unit intend to repower the unit before January 1, 2015 and that they 
will provide, upon request, documentation demonstrating such intent.
    (b) Duty to reapply. (1) The CAIR designated representative of a 
CAIR SO2 opt-in unit shall submit a complete CAIR permit 
application under Sec. 97.222 to renew the CAIR opt-in unit permit in 
accordance with the permitting authority's regulations for title V 
operating permits, or the permitting authority's regulations for other 
federally enforceable permits if applicable, addressing permit renewal.
    (2) Unless the permitting authority issues a notification of 
acceptance of withdrawal of the CAIR SO2 opt-in unit from the 
CAIR SO2 Trading Program in accordance with Sec. 97.286 or 
the unit becomes a CAIR SO2 unit under Sec. 97.204, the CAIR 
SO2 opt-in unit shall remain subject to the requirements for 
a CAIR SO2 opt-in unit, even if the CAIR designated 
representative for the CAIR SO2 opt-in unit fails to submit a 
CAIR permit application that is required for renewal of the CAIR opt-in 
permit under paragraph (b)(1) of this section.

[65 FR 2727, Jan. 18, 2000, as amended at 71 FR 74795, Dec. 13, 2006]



Sec. 97.284  Opt-in process.

    The permitting authority will issue or deny a CAIR opt-in permit for 
a unit for which an initial application for a CAIR opt-in permit under 
Sec. 97.183 is submitted in accordance with the following, to the 
extent provided in a State implementation plan revision submitted in 
accordance with Sec. 51.124(r)(1), (2), or (3) of this chapter and 
approved by the Administrator:
    (a) Interim review of monitoring plan. The permitting authority and 
the Administrator will determine, on an interim basis, the sufficiency 
of the monitoring plan accompanying the initial application for a CAIR 
opt-in permit

[[Page 295]]

under Sec. 97.283. A monitoring plan is sufficient, for purposes of 
interim review, if the plan appears to contain information demonstrating 
that the SO2 emissions rate and heat input of the unit and 
all other applicable parameters are monitored and reported in accordance 
with subpart HHH of this part. A determination of sufficiency shall not 
be construed as acceptance or approval of the monitoring plan.
    (b) Monitoring and reporting. (1)(i) If the permitting authority and 
the Administrator determine that the monitoring plan is sufficient under 
paragraph (a) of this section, the owner or operator shall monitor and 
report the SO2 emissions rate and the heat input of the unit 
and all other applicable parameters, in accordance with subpart HHH of 
this part, starting on the date of certification of the appropriate 
monitoring systems under subpart HHH of this part and continuing until a 
CAIR opt-in permit is denied under Sec. 97.284(f) or, if a CAIR opt-in 
permit is issued, the date and time when the unit is withdrawn from the 
CAIR SO2 Trading Program in accordance with Sec. 97.286.
    (ii) The monitoring and reporting under paragraph (b)(1)(i) of this 
section shall include the entire control period immediately before the 
date on which the unit enters the CAIR SO2 Trading Program 
under Sec. 97.284(g), during which period monitoring system 
availability must not be less than 90 percent under subpart HHH of this 
part and the unit must be in full compliance with any applicable State 
or Federal emissions or emissions-related requirements.
    (2) To the extent the SO2 emissions rate and the heat 
input of the unit are monitored and reported in accordance with subpart 
HHH of this part for one or more control periods, in addition to the 
control period under paragraph (b)(1)(ii) of this section, during which 
control periods monitoring system availability is not less than 90 
percent under subpart HHH of this part and the unit is in full 
compliance with any applicable State or Federal emissions or emissions-
related requirements and which control periods begin not more than 3 
years before the unit enters the CAIR SO2 Trading Program 
under Sec. 97.284(g), such information shall be used as provided in 
paragraphs (c) and (d) of this section.
    (c) Baseline heat input. The unit's baseline heat input shall equal:
    (1) If the unit's SO2 emissions rate and heat input are 
monitored and reported for only one control period, in accordance with 
paragraph (b)(1) of this section, the unit's total heat input (in mmBtu) 
for the control period; or
    (2) If the unit's SO2 emissions rate and heat input are 
monitored and reported for more than one control period, in accordance 
with paragraphs (b)(1) and (2) of this section, the average of the 
amounts of the unit's total heat input (in mmBtu) for the control 
periods under paragraphs (b)(1)(ii) and (2) of this section.
    (d) Baseline SO2 emission rate. The unit's baseline SO2 
emission rate shall equal:
    (1) If the unit's SO2 emissions rate and heat input are 
monitored and reported for only one control period, in accordance with 
paragraph (b)(1) of this section, the unit's SO2 emissions 
rate (in lb/mmBtu) for the control period;
    (2) If the unit's SO2 emissions rate and heat input are 
monitored and reported for more than one control period, in accordance 
with paragraphs (b)(1) and (2) of this section, and the unit does not 
have add-on SO2 emission controls during any such control 
periods, the average of the amounts of the unit's SO2 
emissions rate (in lb/mmBtu) for the control periods under paragraphs 
(b)(1)(ii) and (2) of this section; or
    (3) If the unit's SO2 emissions rate and heat input are 
monitored and reported for more than one control period, in accordance 
with paragraphs (b)(1) and (2) of this section, and the unit has add-on 
SO2 emission controls during any such control periods, the 
average of the amounts of the unit's SO2 emissions rate (in 
lb/mmBtu) for such control periods during which the unit has add-on 
SO2 emission controls.
    (e) Issuance of CAIR opt-in permit. After calculating the baseline 
heat input and the baseline SO2 emissions rate for the unit 
under paragraphs (c) and (d) of this section and if the permitting 
authority determines that the CAIR designated representative shows

[[Page 296]]

that the unit meets the requirements for a CAIR SO2 opt-in 
unit in Sec. 97.280 and meets the elements certified in Sec. 
97.283(a)(2), the permitting authority will issue a CAIR opt-in permit. 
The permitting authority will provide a copy of the CAIR opt-in permit 
to the Administrator, who will then establish a compliance account for 
the source that includes the CAIR SO2 opt-in unit unless the 
source already has a compliance account.
    (f) Issuance of denial of CAIR opt-in permit. Notwithstanding 
paragraphs (a) through (e) of this section, if at any time before 
issuance of a CAIR opt-in permit for the unit, the permitting authority 
determines that the CAIR designated representative fails to show that 
the unit meets the requirements for a CAIR SO2 opt-in unit in 
Sec. 97.280 or meets the elements certified in Sec. 97.283(a)(2), the 
permitting authority will issue a denial of a CAIR opt-in permit for the 
unit.
    (g) Date of entry into CAIR SO2 Trading Program. A unit for which an 
initial CAIR opt-in permit is issued by the permitting authority shall 
become a CAIR SO2 opt-in unit, and a CAIR SO2 
unit, as of the later of January 1, 2010 or January 1 of the first 
control period during which such CAIR opt-in permit is issued.
    (h) Repowered CAIR SO2 opt-in unit. (1) If CAIR designated 
representative requests, and the permitting authority issues a CAIR opt-
in permit providing for, allocation to a CAIR SO2 opt-in unit 
of CAIR SO2 allowances under Sec. 97.288(c) and such unit is 
repowered after its date of entry into the CAIR SO2 Trading 
Program under paragraph (g) of this section, the repowered unit shall be 
treated as a CAIR SO2 opt-in unit replacing the original CAIR 
SO2 opt-in unit, as of the date of start-up of the repowered 
unit's combustion chamber.
    (2) Notwithstanding paragraphs (c) and (d) of this section, as of 
the date of start-up under paragraph (h)(1) of this section, the 
repowered unit shall be deemed to have the same date of commencement of 
operation, date of commencement of commercial operation, baseline heat 
input, and baseline SO2 emission rate as the original CAIR 
SO2 opt-in unit, and the original CAIR SO2 opt-in 
unit shall no longer be treated as a CAIR SO2 opt-in unit or 
a CAIR SO2 unit.

[65 FR 2727, Jan. 18, 2000, as amended at 71 FR 74795, Dec. 13, 2006]



Sec. 97.285  CAIR opt-in permit contents.

    (a) Each CAIR opt-in permit will contain:
    (1) All elements required for a complete CAIR permit application 
under Sec. 97.222;
    (2) The certification in Sec. 97.283(a)(2);
    (3) The unit's baseline heat input under Sec. 97.284(c);
    (4) The unit's baseline SO2 emission rate under Sec. 
97.284(d);
    (5) A statement whether the unit is to be allocated CAIR 
SO2 allowances under Sec. 97.288(b) or Sec. 97.288(c) 
(subject to the conditions in Sec. Sec. 97.284(h) and 97.286(g));
    (6) A statement that the unit may withdraw from the CAIR 
SO2 Trading Program only in accordance with Sec. 97.286; and
    (7) A statement that the unit is subject to, and the owners and 
operators of the unit must comply with, the requirements of Sec. 
97.287.
    (b) Each CAIR opt-in permit is deemed to incorporate automatically 
the definitions of terms under Sec. 97.202 and, upon recordation by the 
Administrator under subpart FFF or GGG of this part or this subpart, 
every allocation, transfer, or deduction of CAIR SO2 
allowances to or from the compliance account of the source that includes 
a CAIR SO2 opt-in unit covered by the CAIR opt-in permit.
    (c) The CAIR opt-in permit shall be included, in a format specified 
by the permitting authority, in the CAIR permit for the source where the 
CAIR SO2 opt-in unit is located and in a title V operating 
permit or other federally enforceable permit for the source.



Sec. 97.286  Withdrawal from CAIR SO[bdi2] Trading Program.

    Except as provided under paragraph (g) of this section, a CAIR 
SO2 opt-in unit may withdraw from the CAIR SO2 
Trading Program, but only if the permitting authority issues a 
notification to the CAIR designated representative of the CAIR 
SO2 opt-in unit of the acceptance of the withdrawal of the 
CAIR

[[Page 297]]

SO2 opt-in unit in accordance with paragraph (d) of this 
section.
    (a) Requesting withdrawal. In order to withdraw a CAIR 
SO2 opt-in unit from the CAIR SO2 Trading Program, 
the CAIR designated representative of the CAIR SO2 opt-in 
unit shall submit to the permitting authority a request to withdraw 
effective as of midnight of December 31 of a specified calendar year, 
which date must be at least 4 years after December 31 of the year of 
entry into the CAIR SO2 Trading Program under Sec. 
97.284(g). The request must be submitted no later than 90 days before 
the requested effective date of withdrawal.
    (b) Conditions for withdrawal. Before a CAIR SO2 opt-in 
unit covered by a request under paragraph (a) of this section may 
withdraw from the CAIR SO2 Trading Program and the CAIR opt-
in permit may be terminated under paragraph (e) of this section, the 
following conditions must be met:
    (1) For the control period ending on the date on which the 
withdrawal is to be effective, the source that includes the CAIR 
SO2 opt-in unit must meet the requirement to hold CAIR 
SO2 allowances under Sec. 97.206(c) and cannot have any 
excess emissions.
    (2) After the requirement for withdrawal under paragraph (b)(1) of 
this section is met, the Administrator will deduct from the compliance 
account of the source that includes the CAIR SO2 opt-in unit 
CAIR SO2 allowances equal in amount to and allocated for the 
same or a prior control period as any CAIR SO2 allowances 
allocated to the CAIR SO2 opt-in unit under Sec. 97.288 for 
any control period for which the withdrawal is to be effective. If there 
are no remaining CAIR SO2 units at the source, the 
Administrator will close the compliance account, and the owners and 
operators of the CAIR SO2 opt-in unit may submit a CAIR 
SO2 allowance transfer for any remaining CAIR SO2 
allowances to another CAIR SO2 Allowance Tracking System in 
accordance with subpart GGG of this part.
    (c) Notification. (1) After the requirements for withdrawal under 
paragraphs (a) and (b) of this section are met (including deduction of 
the full amount of CAIR SO2 allowances required), the 
permitting authority will issue a notification to the CAIR designated 
representative of the CAIR SO2 opt-in unit of the acceptance 
of the withdrawal of the CAIR SO2 opt-in unit as of midnight 
on December 31 of the calendar year for which the withdrawal was 
requested.
    (2) If the requirements for withdrawal under paragraphs (a) and (b) 
of this section are not met, the permitting authority will issue a 
notification to the CAIR designated representative of the CAIR 
SO2 opt-in unit that the CAIR SO2 opt-in unit's 
request to withdraw is denied. Such CAIR SO2 opt-in unit 
shall continue to be a CAIR SO2 opt-in unit.
    (d) Permit amendment. After the permitting authority issues a 
notification under paragraph (c)(1) of this section that the 
requirements for withdrawal have been met, the permitting authority will 
revise the CAIR permit covering the CAIR SO2 opt-in unit to 
terminate the CAIR opt-in permit for such unit as of the effective date 
specified under paragraph (c)(1) of this section. The unit shall 
continue to be a CAIR SO2 opt-in unit until the effective 
date of the termination and shall comply with all requirements under the 
CAIR SO2 Trading Program concerning any control periods for 
which the unit is a CAIR SO2 opt-in unit, even if such 
requirements arise or must be complied with after the withdrawal takes 
effect.
    (e) Reapplication upon failure to meet conditions of withdrawal. If 
the permitting authority denies the CAIR SO2 opt-in unit's 
request to withdraw, the CAIR designated representative may submit 
another request to withdraw in accordance with paragraphs (a) and (b) of 
this section.
    (f) Ability to reapply to the CAIR SO2 Trading Program. Once a CAIR 
SO2 opt-in unit withdraws from the CAIR SO2 
Trading Program and its CAIR opt-in permit is terminated under this 
section, the CAIR designated representative may not submit another 
application for a CAIR opt-in permit under Sec. 97.283 for such CAIR 
SO2 opt-in unit before the date that is 4 years after the 
date on which the withdrawal became effective. Such new application for 
a CAIR opt-in permit will be treated as an initial application for a 
CAIR opt-in permit under Sec. 97.284.

[[Page 298]]

    (g) Inability to withdraw. Notwithstanding paragraphs (a) through 
(f) of this section, a CAIR SO2 opt-in unit shall not be 
eligible to withdraw from the CAIR SO2 Trading Program if the 
CAIR designated representative of the CAIR SO2 opt-in unit 
requests, and the permitting authority issues a CAIR opt-in permit 
providing for, allocation to the CAIR SO2 opt-in unit of CAIR 
SO2 allowances under Sec. 97.288(c).



Sec. 97.287  Change in regulatory status.

    (a) Notification. If a CAIR SO2 opt-in unit becomes a 
CAIR SO2 unit under Sec. 97.204, then the CAIR designated 
representative shall notify in writing the permitting authority and the 
Administrator of such change in the CAIR SO2 opt-in unit's 
regulatory status, within 30 days of such change.
    (b) Permitting authority's and Administrator's actions. (1) If a 
CAIR SO2 opt-in unit becomes a CAIR SO2 unit under 
Sec. 97.204, the permitting authority will revise the CAIR 
SO2 opt-in unit's CAIR opt-in permit to meet the requirements 
of a CAIR permit under Sec. 97.223, and remove the CAIR opt-in permit 
provisions, as of the date on which the CAIR SO2 opt-in unit 
becomes a CAIR SO2 unit under Sec. 97.204.
    (2)(i) The Administrator will deduct from the compliance account of 
the source that includes the CAIR SO2 opt-in unit that 
becomes a CAIR SO2 unit under Sec. 97.204, CAIR 
SO2 allowances equal in amount to and allocated for the same 
or a prior control period as:
    (A) Any CAIR SO2 allowances allocated to the CAIR 
SO2 opt-in unit under Sec. 97.288 for any control period 
after the date on which the CAIR SO2 opt-in unit becomes a 
CAIR SO2 unit under Sec. 97.204; and
    (B) If the date on which the CAIR SO2 opt-in unit becomes 
a CAIR SO2 unit under Sec. 97.204 is not December 31, the 
CAIR SO2 allowances allocated to the CAIR SO2 opt-
in unit under Sec. 97.288 for the control period that includes the date 
on which the CAIR SO2 opt-in unit becomes a CAIR 
SO2 unit under Sec. 97.204, multiplied by the ratio of the 
number of days, in the control period, starting with the date on which 
the CAIR SO2 opt-in unit becomes a CAIR SO2 unit 
under Sec. 97.204 divided by the total number of days in the control 
period and rounded to the nearest whole allowance as appropriate.
    (ii) The CAIR designated representative shall ensure that the 
compliance account of the source that includes the CAIR SO2 
opt-in unit that becomes a CAIR SO2 unit under Sec. 97.204 
contains the CAIR SO2 allowances necessary for completion of 
the deduction under paragraph (b)(2)(i) of this section.

[65 FR 2727, Jan. 18, 2000, as amended at 71 FR 74795, Dec. 13, 2006]



Sec. 97.288  CAIR SO [bdi2] allowance allocations to CAIR SO
[bdi2] opt-in units.

    (a) Timing requirements. (1) When the CAIR opt-in permit is issued 
under Sec. 97.284(e), the permitting authority will allocate CAIR 
SO2 allowances to the CAIR SO2 opt-in unit, and 
submit to the Administrator the allocation for the control period in 
which a CAIR SO2 opt-in unit enters the CAIR SO2 
Trading Program under Sec. 97.284(g), in accordance with paragraph (b) 
or (c) of this section.
    (2) By no later than October 31 of the control period after the 
control period in which a CAIR SO2 opt-in unit enters the 
CAIR SO2 Trading Program under Sec. 97.284(g) and October 31 
of each year thereafter, the permitting authority will allocate CAIR 
SO2 allowances to the CAIR SO2 opt-in unit, and 
submit to the Administrator the allocation for the control period that 
includes such submission deadline and in which the unit is a CAIR 
SO2 opt-in unit, in accordance with paragraph (b) or (c) of 
this section.
    (b) Calculation of allocation. For each control period for which a 
CAIR SO2 opt-in unit is to be allocated CAIR SO2 
allowances, the permitting authority will allocate in accordance with 
the following procedures, if provided in a State implementation plan 
revision submitted in accordance with Sec. 51.124(r)(1), (2), or (3) of 
this chapter and approved by the Administrator:
    (1) The heat input (in mmBtu) used for calculating the CAIR 
SO2 allowance allocation will be the lesser of:
    (i) The CAIR SO2 opt-in unit's baseline heat input 
determined under Sec. 97.284(c); or
    (ii) The CAIR SO2 opt-in unit's heat input, as determined 
in accordance with subpart HHH of this part, for the

[[Page 299]]

immediately prior control period, except when the allocation is being 
calculated for the control period in which the CAIR SO2 opt-
in unit enters the CAIR SO2 Trading Program under Sec. 
97.284(g).
    (2) The SO2 emission rate (in lb/mmBtu) used for 
calculating CAIR SO2 allowance allocations will be the lesser 
of:
    (i) The CAIR SO2 opt-in unit's baseline SO2 
emissions rate (in lb/mmBtu) determined under Sec. 97.284(d) and 
multiplied by 70 percent; or
    (ii) The most stringent State or Federal SO2 emissions 
limitation applicable to the CAIR SO2 opt-in unit at any time 
during the control period for which CAIR SO2 allowances are 
to be allocated.
    (3) The permitting authority will allocate CAIR SO2 
allowances to the CAIR SO2 opt-in unit with a tonnage 
equivalent equal to, or less than by the smallest possible amount, the 
heat input under paragraph (b)(1) of this section, multiplied by the 
SO2 emission rate under paragraph (b)(2) of this section, and 
divided by 2,000 lb/ton.
    (c) Notwithstanding paragraph (b) of this section and if the CAIR 
designated representative requests, and the permitting authority issues 
a CAIR opt-in permit (based on a demonstration of the intent to repower 
stated under Sec. 97.283(a)(5)) providing for, allocation to a CAIR 
SO2 opt-in unit of CAIR SO2 allowances under this 
paragraph (subject to the conditions in Sec. Sec. 97.284(h) and 
97.286(g)), the permitting authority will allocate to the CAIR 
SO2 opt-in unit as follows, if provided in a State 
implementation plan revision submitted in accordance with Sec. 
51.124(r)(1), (2), or (3) of this chapter and approved by the 
Administrator:
    (1) For each control period in 2010 through 2014 for which the CAIR 
SO2 opt-in unit is to be allocated CAIR SO2 
allowances,
    (i) The heat input (in mmBtu) used for calculating CAIR 
SO2 allowance allocations will be determined as described in 
paragraph (b)(1) of this section.
    (ii) The SO2 emission rate (in lb/mmBtu) used for 
calculating CAIR SO2 allowance allocations will be the lesser 
of:
    (A) The CAIR SO2 opt-in unit's baseline SO2 
emissions rate (in lb/mmBtu) determined under Sec. 97.284(d); or
    (B) The most stringent State or Federal SO2 emissions 
limitation applicable to the CAIR SO2 opt-in unit at any time 
during the control period in which the CAIR SO2 opt-in unit 
enters the CAIR SO2 Trading Program under Sec. 97.284(g).
    (iii) The permitting authority will allocate CAIR SO2 
allowances to the CAIR SO2 opt-in unit with a tonnage 
equivalent equal to, or less than by the smallest possible amount, the 
heat input under paragraph (c)(1)(i) of this section, multiplied by the 
SO2 emission rate under paragraph (c)(1)(ii) of this section, 
and divided by 2,000 lb/ton.
    (2) For each control period in 2015 and thereafter for which the 
CAIR SO2 opt-in unit is to be allocated CAIR SO2 
allowances,
    (i) The heat input (in mmBtu) used for calculating the CAIR 
SO2 allowance allocations will be determined as described in 
paragraph (b)(1) of this section.
    (ii) The SO2 emission rate (in lb/mmBtu) used for 
calculating the CAIR SO2 allowance allocation will be the 
lesser of:
    (A) The CAIR SO2 opt-in unit's baseline SO2 
emissions rate (in lb/mmBtu) determined under Sec. 97.284(d) multiplied 
by 10 percent; or
    (B) The most stringent State or Federal SO2 emissions 
limitation applicable to the CAIR SO2 opt-in unit at any time 
during the control period for which CAIR SO2 allowances are 
to be allocated.
    (iii) The permitting authority will allocate CAIR SO2 
allowances to the CAIR SO2 opt-in unit with a tonnage 
equivalent equal to, or less than by the smallest possible amount, the 
heat input under paragraph (c)(2)(i) of this section, multiplied by the 
SO2 emission rate under paragraph (c)(2)(ii) of this section, 
and divided by 2,000 lb/ton.
    (d) Recordation. If provided in a State implementation plan revision 
submitted in accordance with Sec. 51.124(r)(1), (2), or (3) of this 
chapter and approved by the Administrator:
    (1) The Administrator will record, in the compliance account of the 
source that includes the CAIR SO2 opt-in unit,

[[Page 300]]

the CAIR SO2 allowances allocated by the permitting authority 
to the CAIR SO2 opt-in unit under paragraph (a)(1) of this 
section.
    (2) By December 1 of the control period in which a CAIR 
SO2 opt-in unit enters the CAIR SO2 Trading 
Program under Sec. 97.284(g) and December 1 of each year thereafter, 
the Administrator will record, in the compliance account of the source 
that includes the CAIR SO2 opt-in unit, the CAIR 
SO2 allowances allocated by the permitting authority to the 
CAIR SO2 opt-in unit under paragraph (a)(2) of this section.



 Sec. Appendix A to Subpart III of Part 97--States With Approved State 
  Implementation Plan Revisions Concerning CAIR SO2 Opt-In 
                                  Units

    1. The following States have State Implementation Plan revisions 
under Sec. 51.124(r) of this chapter approved by the Administrator and 
establishing procedures providing for CAIR SO2 opt-in units 
under subpart III of this part and allocation of CAIR SO2 
allowances to such units under Sec. 97.288(b):

Indiana
North Carolina
Ohio
South Carolina
Tennessee

    2. The following States have State Implementation Plan revisions 
under Sec. 51.124(r) of this chapter approved by the Administrator and 
establishing procedures providing for CAIR SO2 opt-in units 
under subpart III of this part and allocation of CAIR SO2 
allowances to such units under Sec. 97.288(c):

Indiana
North Carolina
Ohio
South Carolina
Tennessee

[65 FR 2727, Jan. 18, 2000, as amended at 72 FR 46394, Aug. 20, 2007; 72 
FR 56920, Oct. 5, 2007; 72 FR 57215, Oct. 9, 2007; 72 FR 59487, Oct. 22, 
2007; 73 FR 6041, Feb. 1, 2008]



  Subpart AAAA_CAIR NOX Ozone Season Trading Program General Provisions



Sec. 97.301  Purpose.

This subpart and subparts BBBB through IIII set forth the general 
    provisions and the designated representative, permitting, allowance, 
    monitoring, and opt-in provisions for the Federal Clean Air 
    Interstate Rule (CAIR) NOX Ozone Season Trading Program, 
    under section 110 of the Clean Air Act and Sec. 52.35 of this 
    chapter, as a means of mitigating interstate transport of ozone and 
    nitrogen oxides.



Sec. 97.302  Definitions.

    The terms used in this subpart and subparts BBBB through IIII shall 
have the meanings set forth in this section as follows:
    Account number means the identification number given by the 
Administrator to each CAIR NOX Ozone Season Allowance 
Tracking System account.
    Acid Rain emissions limitation means a limitation on emissions of 
sulfur dioxide or nitrogen oxides under the Acid Rain Program.
    Acid Rain Program means a multi-state sulfur dioxide and nitrogen 
oxides air pollution control and emission reduction program established 
by the Administrator under title IV of the CAA and parts 72 through 78 
of this chapter.
    Administrator means the Administrator of the United States 
Environmental Protection Agency or the Administrator's duly authorized 
representative.
    Allocate or allocation means, with regard to CAIR NOX 
Ozone Season allowances, the determination by a permitting authority or 
the Administrator of the amount of such CAIR NOX Ozone Season 
allowances to be initially credited to a CAIR NOX Ozone 
Season unit, a new unit set-aside, or other entity.
    Allowance transfer deadline means, for a control period, midnight of 
November 30 (if it is a business day), or midnight of the first business 
day thereafter (if November 30 is not a business day), immediately 
following the control period and is the deadline by which a CAIR 
NOX Ozone Season allowance transfer must be submitted for 
recordation in a CAIR NOX Ozone Season source's compliance 
account in order to be used to meet the source's CAIR NOX 
Ozone Season emissions limitation for such control period in accordance 
with Sec. 97.354.
    Alternate CAIR designated representative means, for a CAIR 
NOX Ozone Season source and each CAIR NOX Ozone 
Season unit at the source, the natural

[[Page 301]]

person who is authorized by the owners and operators of the source and 
all such units at the source, in accordance with subparts BBBB and IIII 
of this part, to act on behalf of the CAIR designated representative in 
matters pertaining to the CAIR NOX Ozone Season Trading 
Program. If the CAIR NOX Ozone Season source is also a CAIR 
NOX source, then this natural person shall be the same person 
as the alternate CAIR designated representative under the CAIR 
NOX Annual Trading Program. If the CAIR NOX Ozone 
Season source is also a CAIR SO2 source, then this natural 
person shall be the same person as the alternate CAIR designated 
representative under the CAIR SO2 Trading Program. If the 
CAIR NOX Ozone Season source is also subject to the Acid Rain 
Program, then this natural person shall be the same person as the 
alternate designated representative under the Acid Rain Program. If the 
CAIR NOX Ozone Season source is also subject to the Hg Budget 
Trading Program, then this natural person shall be the same person as 
the alternate Hg designated representative under the Hg Budget Trading 
Program.
    Automated data acquisition and handling system or DAHS means that 
component of the continuous emission monitoring system, or other 
emissions monitoring system approved for use under subpart HHHH of this 
part, designed to interpret and convert individual output signals from 
pollutant concentration monitors, flow monitors, diluent gas monitors, 
and other component parts of the monitoring system to produce a 
continuous record of the measured parameters in the measurement units 
required by subpart HHHH of this part.
    Biomass means--
    (1) Any organic material grown for the purpose of being converted to 
energy;
    (2) Any organic byproduct of agriculture that can be converted into 
energy; or
    (3) Any material that can be converted into energy and is 
nonmerchantable for other purposes, that is segregated from other 
nonmerchantable material, and that is;
    (i) A forest-related organic resource, including mill residues, 
precommercial thinnings, slash, brush, or byproduct from conversion of 
trees to merchantable material; or
    (ii) A wood material, including pallets, crates, dunnage, 
manufacturing and construction materials (other than pressure-treated, 
chemically-treated, or painted wood products), and landscape or right-
of-way tree trimmings.
    Boiler means an enclosed fossil-or other-fuel-fired combustion 
device used to produce heat and to transfer heat to recirculating water, 
steam, or other medium.
    Bottoming-cycle cogeneration unit means a cogeneration unit in which 
the energy input to the unit is first used to produce useful thermal 
energy and at least some of the reject heat from the useful thermal 
energy application or process is then used for electricity production.
    CAIR authorized account representative means, with regard to a 
general account, a responsible natural person who is authorized, in 
accordance with subparts BBBB, FFFF, and IIII of this part, to transfer 
and otherwise dispose of CAIR NOX Ozone Season allowances 
held in the general account and, with regard to a compliance account, 
the CAIR designated representative of the source.
    CAIR designated representative means, for a CAIR NOX 
Ozone Season source and each CAIR NOX Ozone Season unit at 
the source, the natural person who is authorized by the owners and 
operators of the source and all such units at the source, in accordance 
with subparts BBBB and IIII of this part, to represent and legally bind 
each owner and operator in matters pertaining to the CAIR NOX 
Ozone Season Trading Program. If the CAIR NOX Ozone Season 
source is also a CAIR NOX source, then this natural person 
shall be the same person as the CAIR designated representative under the 
CAIR NOX Annual Trading Program. If the CAIR NOX 
Ozone Season source is also a CAIR SO2 source, then this 
natural person shall be the same person as the CAIR designated 
representative under the CAIR SO2 Trading Program. If the 
CAIR NOX Ozone Season source is also subject to the Acid Rain 
Program, then this natural person shall be the same person as the 
designated representative under

[[Page 302]]

the Acid Rain Program. If the CAIR NOX Ozone Season source is 
also subject to the Hg Budget Trading Program, then this natural person 
shall be the same person as the Hg designated representative under the 
Hg Budget Trading Program.
    CAIR NOX Annual Trading Program means a multi-state nitrogen oxides 
air pollution control and emission reduction program established by the 
Administrator in accordance with subparts AA through II of this part and 
Sec. Sec. 51.123(p) and 52.35 of this chapter or approved and 
administered by the Administrator in accordance with subparts AA through 
II of part 96 of this chapter and Sec. 51.123(o)(1) or (2) of this 
chapter, as a means of mitigating interstate transport of fine 
particulates and nitrogen oxides.
    CAIR NOX Ozone Season allowance means a limited authorization issued 
by a permitting authority or the Administrator under subpart EEEE of 
this part, Sec. 97.388, or provisions of a State implementation plan 
that are approved under Sec. 51.123(aa)(1) or (2) (and (bb)(1)), 
(bb)(2), (dd), or (ee) of this chapter, to emit one ton of nitrogen 
oxides during a control period of the specified calendar year for which 
the authorization is allocated or of any calendar year thereafter under 
the CAIR NOX Ozone Season Trading Program or a limited 
authorization issued by a permitting authority for a control period 
during 2003 through 2008 under the NOX Budget Trading Program 
in accordance with Sec. 51.121(p) of this chapter to emit one ton of 
nitrogen oxides during a control period, provided that the provision in 
Sec. 51.121(b)(2)(ii)(E) of this chapter shall not be used in applying 
this definition and the limited authorization shall not have been used 
to meet the allowance-holding requirement under the NOX 
Budget Trading Program. An authorization to emit nitrogen oxides that is 
not issued under subpart EEEE of this part, Sec. 97.388, or provisions 
of a State implementation plan that are approved under Sec. 
51.123(aa)(1) or (2) (and (bb)(1)), (bb)(2), (dd), or (ee) of this 
chapter or under the NOX Budget Trading Program as described 
in the prior sentence shall not be a CAIR NOX Ozone Season 
allowance.
    CAIR NOX Ozone Season allowance deduction or deduct CAIR NOX Ozone 
Season allowances means the permanent withdrawal of CAIR NOX 
Ozone Season allowances by the Administrator from a compliance account, 
e.g., in order to account for a specified number of tons of total 
nitrogen oxides emissions from all CAIR NOX Ozone Season 
units at a CAIR NOX Ozone Season source for a control period, 
determined in accordance with subpart HHHH of this part, or to account 
for excess emissions.
    CAIR NOX Ozone Season Allowance Tracking System means the system by 
which the Administrator records allocations, deductions, and transfers 
of CAIR NOX Ozone Season allowances under the CAIR 
NOX Ozone Season Trading Program. Such allowances will be 
allocated, held, deducted, or transferred only as whole allowances.
    CAIR NOX Ozone Season Allowance Tracking System account means an 
account in the CAIR NOX Ozone Season Allowance Tracking 
System established by the Administrator for purposes of recording the 
allocation, holding, transferring, or deducting of CAIR NOX 
Ozone Season allowances.
    CAIR NOX Ozone Season allowances held or hold CAIR NOX 
Ozone Season allowances means the CAIR NOX Ozone Season 
allowances recorded by the Administrator, or submitted to the 
Administrator for recordation, in accordance with subparts FFFF, GGGG, 
and IIII of this part, in a CAIR NOX Ozone Season Allowance 
Tracking System account.
    CAIR NOX Ozone Season emissions limitation means, for a CAIR 
NOX Ozone Season source, the tonnage equivalent, in 
NOX emissions in a control period, of the CAIR NOX 
Ozone Season allowances available for deduction for the source under 
Sec. 97.354(a) and (b) for the control period.
    CAIR NOX Ozone Season source means a source that includes one or 
more CAIR NOX Ozone Season units.
    CAIR NOX Ozone Season Trading Program means a multi-state nitrogen 
oxides air pollution control and emission reduction program established 
by the Administrator in accordance with subparts AAAA through IIII of 
part 96 of this part and Sec. Sec. 51.123(ee) and 52.35 of

[[Page 303]]

this chapter or approved and administered by the Administrator in 
accordance with under subparts AAAA through IIII and Sec. 51.123(aa)(1) 
or (2) (and (bb)(1)), (bb)(2), or (dd) of this chapter, as a means of 
mitigating interstate transport of ozone and nitrogen oxides.
    CAIR NOX Ozone Season unit means a unit that is subject to the CAIR 
NOX Ozone Season Trading Program under Sec. 97.304 and, 
except for purposes of Sec. 97.305 and subpart EEEE of this part, a 
CAIR NOX Ozone Season opt-in unit under subpart IIII of this 
part.
    CAIR NOX source means a source that is subject to the CAIR 
NOX Annual Trading Program.
    CAIR permit means the legally binding and federally enforceable 
written document, or portion of such document, issued by the permitting 
authority under subpart CCCC of this part, including any permit 
revisions, specifying the CAIR NOX Ozone Season Trading 
Program requirements applicable to a CAIR NOX Ozone Season 
source, to each CAIR NOX Ozone Season unit at the source, and 
to the owners and operators and the CAIR designated representative of 
the source and each such unit.
    CAIR SO2 source means a source that is subject to the CAIR 
SO2 Trading Program.
    CAIR SO2 Trading Program means a multi-state sulfur dioxide air 
pollution control and emission reduction program established by the 
Administrator in accordance with subparts AAA through III of this part 
and Sec. Sec. 51.124(r) and 52.36 of this chapter or approved and 
administered by the Administrator in accordance with subparts AAA 
through III of part 96 of this chapter and Sec. 51.124(o)(1) or (2) of 
this chapter, as a means of mitigating interstate transport of fine 
particulates and sulfur dioxide.
    Certifying official means:
    (1) For a corporation, a president, secretary, treasurer, or vice-
president or the corporation in charge of a principal business function 
or any other person who performs similar policy or decision-making 
functions for the corporation;
    (2) For a partnership or sole proprietorship, a general partner or 
the proprietor respectively; or
    (3) For a local government entity or State, Federal, or other public 
agency, a principal executive officer or ranking elected official.
    Clean Air Act or CAA means the Clean Air Act, 42 U.S.C. 7401, et 
seq.
    Coal means any solid fuel classified as anthracite, bituminous, 
subbituminous, or lignite.
    Coal-derived fuel means any fuel (whether in a solid, liquid, or 
gaseous state) produced by the mechanical, thermal, or chemical 
processing of coal.
    Coal-fired means:
    (1) Except for purposes of subpart EEEE of this part, combusting any 
amount of coal or coal-derived fuel, alone or in combination with any 
amount of any other fuel, during any year; or
    (2) For purposes of subpart EEEE of this part, combusting any amount 
of coal or coal-derived fuel, alone or in combination with any amount of 
any other fuel, during a specified year.
    Cogeneration unit means a stationary, fossil-fuel-fired boiler or 
stationary, fossil-fuel-fired combustion turbine:
    (1) Having equipment used to produce electricity and useful thermal 
energy for industrial, commercial, heating, or cooling purposes through 
the sequential use of energy; and
    (2) Producing during the 12-month period starting on the date the 
unit first produces electricity and during any calendar year after the 
calendar year in which the unit first produces electricity--
    (i) For a topping-cycle cogeneration unit,
    (A) Useful thermal energy not less than 5 percent of total energy 
output; and
    (B) Useful power that, when added to one-half of useful thermal 
energy produced, is not less then 42.5 percent of total energy input, if 
useful thermal energy produced is 15 percent or more of total energy 
output, or not less than 45 percent of total energy input, if useful 
thermal energy produced is less than 15 percent of total energy output.

[[Page 304]]

    (ii) For a bottoming-cycle cogeneration unit, useful power not less 
than 45 percent of total energy input;
    (3) Provided that the total energy input under paragraphs (2)(i)(B) 
and (2)(ii) of this definition shall equal the unit's total energy input 
from all fuel except biomass if the unit is a boiler.
    Combustion turbine means:
    (1) An enclosed device comprising a compressor, a combustor, and a 
turbine and in which the flue gas resulting from the combustion of fuel 
in the combustor passes through the turbine, rotating the turbine; and
    (2) If the enclosed device under paragraph (1) of this definition is 
combined cycle, any associated duct burner, heat recovery steam 
generator, and steam turbine.
    Commence commercial operation means, with regard to a unit:
    (1) To have begun to produce steam, gas, or other heated medium used 
to generate electricity for sale or use, including test generation, 
except as provided in Sec. 97.305 and Sec. 97.384(h).
    (i) For a unit that is a CAIR NOX Ozone Season unit under 
Sec. 97.304 on the later of November 15, 1990 or the date the unit 
commences commercial operation as defined in paragraph (1) of this 
definition and that subsequently undergoes a physical change (other than 
replacement of the unit by a unit at the same source), such date shall 
remain the date of commencement of commercial operation of the unit, 
which shall continue to be treated as the same unit.
    (ii) For a unit that is a CAIR NOX Ozone Season unit 
under Sec. 97.304 on the later of November 15, 1990 or the date the 
unit commences commercial operation as defined in paragraph (1) of this 
definition and that is subsequently replaced by a unit at the same 
source (e.g., repowered), such date shall remain the replaced unit's 
date of commencement of commercial operation, and the replacement unit 
shall be treated as a separate unit with a separate date for 
commencement of commercial operation as defined in paragraph (1), (2), 
or (3) of this definition as appropriate.
    (2) Notwithstanding paragraph (1) of this definition and except as 
provided in Sec. 97.305, for a unit that is not a CAIR NOX 
Ozone Season unit under Sec. 97.304 on the later of November 15, 1990 
or the date the unit commences commercial operation as defined in 
paragraph (1) of this definition, the unit's date for commencement of 
commercial operation shall be the date on which the unit becomes a CAIR 
NOX Ozone Season unit under Sec. 97.304.
    (i) For a unit with a date for commencement of commercial operation 
as defined in paragraph (2) of this definition and that subsequently 
undergoes a physical change (other than replacement of the unit by a 
unit at the same source), such date shall remain the date of 
commencement of commercial operation of the unit, which shall continue 
to be treated as the same unit.
    (ii) For a unit with a date for commencement of commercial operation 
as defined in paragraph (2) of this definition and that is subsequently 
replaced by a unit at the same source (e.g., repowered), such date shall 
remain the replaced unit's date of commencement of commercial operation, 
and the replacement unit shall be treated as a separate unit with a 
separate date for commencement of commercial operation as defined in 
paragraph (1), (2), or (3) of this definition as appropriate.
    (3) Notwithstanding paragraphs (1) and (2) of this definition, for a 
unit not serving a generator producing electricity for sale, the unit's 
date of commencement of operation shall also be the unit's date of 
commencement of commercial operation.
    Commence operation means:
    (1) To have begun any mechanical, chemical, or electronic process, 
including, with regard to a unit, start-up of a unit's combustion 
chamber, except as provided in Sec. 97.384(h).
    (i) For a unit that undergoes a physical change (other than 
replacement of the unit by a unit at the same source) after the date the 
unit commences operation as defined in paragraph (1) of this definition, 
such date shall remain the date of commencement of operation of the 
unit, which shall continue to be treated as the same unit.
    (ii) For a unit that is replaced by a unit at the same source (e.g., 
repowered) after the date the unit commences operation as defined in 
paragraph (1) of this definition, such date

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shall remain the replaced unit's date of commencement of operation, and 
the replacement unit shall be treated as a separate unit with a separate 
date for commencement of operation as defined in paragraph (1) or (2) of 
this definition as appropriate, except as provided in Sec. 97.384(h).
    (2) Notwithstanding paragraph (1) of this definition and solely for 
purposes of subpart HHHH of this part, for a unit that is not a CAIR 
NOX Ozone Season unit under Sec. 97.304(d) on the later of 
November 15, 1990 or the date the unit commences operation as defined in 
paragraph (1) of this definition and subsequently becomes such a CAIR 
NOX Ozone Season unit, the unit's date for commencement of 
operation shall be the date on which the unit becomes a CAIR 
NOX Ozone Season unit under Sec. 97.304(d).
    (i) For a unit with a date for commencement of operation as defined 
in paragraph (2) of this definition and that subsequently undergoes a 
physical change (other than replacement of the unit by a unit at the 
same source), such date shall remain the date of commencement of 
operation of the unit, which shall continue to be treated as the same 
unit.
    (ii) For a unit with a date for commencement of operation as defined 
in paragraph (2) of this definition and that is subsequently replaced by 
a unit at the same source (e.g., repowered), such date shall remain the 
replaced unit's date of commencement of operation, and the replacement 
unit shall be treated as a separate unit with a separate date for 
commencement of operation as defined in paragraph (1) or (2) of this 
definition as appropriate.
    Common stack means a single flue through which emissions from 2 or 
more units are exhausted.
    Compliance account means a CAIR NOX Ozone Season 
Allowance Tracking System account, established by the Administrator for 
a CAIR NOX Ozone Season source under subpart FFFF or IIII of 
this part, in which any CAIR NOX Ozone Season allowance 
allocations for the CAIR NOX Ozone Season units at the source 
are initially recorded and in which are held any CAIR NOX 
Ozone Season allowances available for use for a control period in order 
to meet the source's CAIR NOX Ozone Season emissions 
limitation in accordance with Sec. 97.354.
    Continuous emission monitoring system or CEMS means the equipment 
required under subpart HHHH of this part to sample, analyze, measure, 
and provide, by means of readings recorded at least once every 15 
minutes (using an automated data acquisition and handling system 
(DAHS)), a permanent record of nitrogen oxides emissions, stack gas 
volumetric flow rate, stack gas moisture content, and oxygen or carbon 
dioxide concentration (as applicable), in a manner consistent with part 
75 of this chapter. The following systems are the principal types of 
continuous emission monitoring systems required under subpart HHHH of 
this part:
    (1) A flow monitoring system, consisting of a stack flow rate 
monitor and an automated data acquisition and handling system and 
providing a permanent, continuous record of stack gas volumetric flow 
rate, in standard cubic feet per hour (scfh);
    (2) A nitrogen oxides concentration monitoring system, consisting of 
a NOX pollutant concentration monitor and an automated data 
acquisition and handling system and providing a permanent, continuous 
record of NOX emissions, in parts per million (ppm);
    (3) A nitrogen oxides emission rate (or NOX-diluent) 
monitoring system, consisting of a NOX pollutant 
concentration monitor, a diluent gas (CO2 or O2) 
monitor, and an automated data acquisition and handling system and 
providing a permanent, continuous record of NOX 
concentration, in parts per million (ppm), diluent gas concentration, in 
percent CO2 or O2, and NOX emission 
rate, in pounds per million British thermal units (lb/mmBtu);
    (4) A moisture monitoring system, as defined in Sec. 75.11(b)(2) of 
this chapter and providing a permanent, continuous record of the stack 
gas moisture content, in percent H2O;
    (5) A carbon dioxide monitoring system, consisting of a 
CO2 pollutant concentration monitor (or an oxygen monitor 
plus suitable mathematical equations from which the CO2 
concentration is derived) and an automated data acquisition and handling 
system and providing a permanent, continuous

[[Page 306]]

record of CO2 emissions, in percent CO2; and
    (6) An oxygen monitoring system, consisting of an O2 
concentration monitor and an automated data acquisition and handling 
system and providing a permanent, continuous record of O2, in 
percent O2.
    Control period or ozone season means the period beginning May 1 of a 
calendar year, except as provided in Sec. 97.306(c)(2) and ending on 
September 30 of the same year, inclusive.
    Emissions means air pollutants exhausted from a unit or source into 
the atmosphere, as measured, recorded, and reported to the Administrator 
by the CAIR designated representative and as determined by the 
Administrator in accordance with subpart HHHH of this part.
    Excess emissions means any ton of nitrogen oxides emitted by the 
CAIR NOX Ozone Season units at a CAIR NOX Ozone 
Season source during a control period that exceeds the CAIR 
NOX Ozone Season emissions limitation for the source.
    Fossil fuel means natural gas, petroleum, coal, or any form of 
solid, liquid, or gaseous fuel derived from such material.
    Fossil-fuel-fired means, with regard to a unit, combusting any 
amount of fossil fuel in any calendar year.
    Fuel oil means any petroleum-based fuel (including diesel fuel or 
petroleum derivatives such as oil tar) and any recycled or blended 
petroleum products or petroleum by-products used as a fuel whether in a 
liquid, solid, or gaseous state.
    General account means a CAIR NOX Ozone Season Allowance 
Tracking System account, established under subpart FFFF of this part, 
that is not a compliance account.
    Generator means a device that produces electricity.
    Gross electrical output means, with regard to a cogeneration unit, 
electricity made available for use, including any such electricity used 
in the power production process (which process includes, but is not 
limited to, any on-site processing or treatment of fuel combusted at the 
unit and any on-site emission controls).
    Heat input means, with regard to a specified period of time, the 
product (in mmBtu/time) of the gross calorific value of the fuel (in 
Btu/lb) divided by 1,000,000 Btu/mmBtu and multiplied by the fuel feed 
rate into a combustion device (in lb of fuel/time), as measured, 
recorded, and reported to the Administrator by the CAIR designated 
representative and determined by the Administrator in accordance with 
subpart HHHH of this part and excluding the heat derived from preheated 
combustion air, recirculated flue gases, or exhaust from other sources.
    Heat input rate means the amount of heat input (in mmBtu) divided by 
unit operating time (in hr) or, with regard to a specific fuel, the 
amount of heat input attributed to the fuel (in mmBtu) divided by the 
unit operating time (in hr) during which the unit combusts the fuel.
    Hg Budget Trading Program means a multi-state Hg air pollution 
control and emission reduction program approved and administered by the 
Administrator in accordance subpart HHHH of part 60 of this chapter and 
Sec. 60.24(h)(6), or established by the Administrator under section 111 
of the Clean Air Act, as a means of reducing national Hg emissions.
    Life-of-the-unit, firm power contractual arrangement means a unit 
participation power sales agreement under which a utility or industrial 
customer reserves, or is entitled to receive, a specified amount or 
percentage of nameplate capacity and associated energy generated by any 
specified unit and pays its proportional amount of such unit's total 
costs, pursuant to a contract:
    (1) For the life of the unit;
    (2) For a cumulative term of no less than 30 years, including 
contracts that permit an election for early termination; or
    (3) For a period no less than 25 years or 70 percent of the economic 
useful life of the unit determined as of the time the unit is built, 
with option rights to purchase or release some portion of the nameplate 
capacity and associated energy generated by the unit at the end of the 
period.
    Maximum design heat input means the maximum amount of fuel per hour 
(in

[[Page 307]]

Btu/hr) that a unit is capable of combusting on a steady state basis as 
of the initial installation of the unit as specified by the manufacturer 
of the unit.
    Monitoring system means any monitoring system that meets the 
requirements of subpart HHHH of this part, including a continuous 
emissions monitoring system, an alternative monitoring system, or an 
excepted monitoring system under part 75 of this chapter.
    Most stringent State or Federal NOX emissions limitation means, with 
regard to a unit, the lowest NOX emissions limitation (in 
terms of lb/mmBtu) that is applicable to the unit under State or Federal 
law, regardless of the averaging period to which the emissions 
limitation applies.
    Nameplate capacity means, starting from the initial installation of 
a generator, the maximum electrical generating output (in MWe) that the 
generator is capable of producing on a steady state basis and during 
continuous operation (when not restricted by seasonal or other 
deratings) as of such installation as specified by the manufacturer of 
the generator or, starting from the completion of any subsequent 
physical change in the generator resulting in an increase in the maximum 
electrical generating output (in MWe) that the generator is capable of 
producing on a steady state basis and during continuous operation (when 
not restricted by seasonal or other deratings), such increased maximum 
amount as of such completion as specified by the person conducting the 
physical change.
    Oil-fired means, for purposes of subpart EEEE of this part, 
combusting fuel oil for more than 15.0 percent of the annual heat input 
in a specified year and not qualifying as coal-fired.
    Operator means any person who operates, controls, or supervises a 
CAIR NOX Ozone Season unit or a CAIR NOX Ozone 
Season source and shall include, but not be limited to, any holding 
company, utility system, or plant manager of such a unit or source.
    Owner means any of the following persons:
    (1) With regard to a CAIR NOX Ozone Season source or a 
CAIR NOX Ozone Season unit at a source, respectively:
    (i) Any holder of any portion of the legal or equitable title in a 
CAIR NOX Ozone Season unit at the source or the CAIR 
NOX Ozone Season unit;
    (ii) Any holder of a leasehold interest in a CAIR NOX 
Ozone Season unit at the source or the CAIR NOX Ozone Season 
unit; or
    (iii) Any purchaser of power from a CAIR NOX Ozone Season 
unit at the source or the CAIR NOX Ozone Season unit under a 
life-of-the-unit, firm power contractual arrangement; provided that, 
unless expressly provided for in a leasehold agreement, owner shall not 
include a passive lessor, or a person who has an equitable interest 
through such lessor, whose rental payments are not based (either 
directly or indirectly) on the revenues or income from such CAIR 
NOX Ozone Season unit; or
    (2) With regard to any general account, any person who has an 
ownership interest with respect to the CAIR NOX Ozone Season 
allowances held in the general account and who is subject to the binding 
agreement for the CAIR authorized account representative to represent 
the person's ownership interest with respect to CAIR NOX 
Ozone Season allowances.
    Permitting authority means the State air pollution control agency, 
local agency, other State agency, or other agency authorized by the 
Administrator to issue or revise permits to meet the requirements of the 
CAIR NOX Ozone Season Trading Program or, if no such agency 
has been so authorized, the Administrator.
    Potential electrical output capacity means 33 percent of a unit(s 
maximum design heat input, divided by 3,413 Btu/kWh, divided by 1,000 
kWh/MWh, and multiplied by 8,760 hr/yr.
    Receive or receipt of means, when referring to the permitting 
authority or the Administrator, to come into possession of a document, 
information, or correspondence (whether sent in hard copy or by 
authorized electronic transmission), as indicated in an official log, or 
by a notation made on the document, information, or correspondence,

[[Page 308]]

by the permitting authority or the Administrator in the regular course 
of business.
    Recordation, record, or recorded means, with regard to CAIR 
NOX Ozone Season allowances, the movement of CAIR 
NOX Ozone Season allowances by the Administrator into or 
between CAIR NOX Ozone Season Allowance Tracking System 
accounts, for purposes of allocation, transfer, or deduction.
    Reference method means any direct test method of sampling and 
analyzing for an air pollutant as specified in Sec. 75.22 of this 
chapter.
    Replacement, replace, or replaced means, with regard to a unit, the 
demolishing of a unit, or the permanent shutdown and permanent disabling 
of a unit, and the construction of another unit (the replacement unit) 
to be used instead of the demolished or shutdown unit (the replaced 
unit).
    Repowered means, with regard to a unit, replacement of a coal-fired 
boiler with one of the following coal-fired technologies at the same 
source as the coal-fired boiler:
    (1) Atmospheric or pressurized fluidized bed combustion;
    (2) Integrated gasification combined cycle;
    (3) Magnetohydrodynamics;
    (4) Direct and indirect coal-fired turbines;
    (5) Integrated gasification fuel cells; or
    (6) As determined by the Administrator in consultation with the 
Secretary of Energy, a derivative of one or more of the technologies 
under paragraphs (1) through (5) of this definition and any other coal-
fired technology capable of controlling multiple combustion emissions 
simultaneously with improved boiler or generation efficiency and with 
significantly greater waste reduction relative to the performance of 
technology in widespread commercial use as of January 1, 2005.
    Sequential use of energy means:
    (1) For a topping-cycle cogeneration unit, the use of reject heat 
from electricity production in a useful thermal energy application or 
process; or
    (2) For a bottoming-cycle cogeneration unit, the use of reject heat 
from useful thermal energy application or process in electricity 
production.
    Serial number means, for a CAIR NOX Ozone Season 
allowance, the unique identification number assigned to each CAIR 
NOX Ozone Season allowance by the Administrator.
    Solid waste incineration unit means a stationary, fossil-fuel-fired 
boiler or stationary, fossil-fuel-fired combustion turbine that is a 
``solid waste incineration unit'' as defined in section 129(g)(1) of the 
Clean Air Act.
    Source means all buildings, structures, or installations located in 
one or more contiguous or adjacent properties under common control of 
the same person or persons. For purposes of section 502(c) of the Clean 
Air Act, a ``source,'' including a ``source'' with multiple units, shall 
be considered a single ``facility.''
    State means one of the States or the District of Columbia that is 
subject to the CAIR NOX Ozone Season Trading Program pursuant 
to Sec. 52.35 of this chapter.
    Submit or serve means to send or transmit a document, information, 
or correspondence to the person specified in accordance with the 
applicable regulation:
    (1) In person;
    (2) By United States Postal Service; or
    (3) By other means of dispatch or transmission and delivery. 
Compliance with any ``submission'' or ``service'' deadline shall be 
determined by the date of dispatch, transmission, or mailing and not the 
date of receipt.
    Title V operating permit means a permit issued under title V of the 
Clean Air Act and part 70 or part 71 of this chapter.
    Title V operating permit regulations means the regulations that the 
Administrator has approved or issued as meeting the requirements of 
title V of the Clean Air Act and part 70 or 71 of this chapter.
    Ton means 2,000 pounds. For the purpose of determining compliance 
with the CAIR NOX Ozone Season emissions limitation, total 
tons of nitrogen oxides emissions for a control period shall be 
calculated as the sum of all recorded hourly emissions (or the mass

[[Page 309]]

equivalent of the recorded hourly emission rates) in accordance with 
subpart HHHH of this part, but with any remaining fraction of a ton 
equal to or greater than 0.50 tons deemed to equal one ton and any 
remaining fraction of a ton less than 0.50 tons deemed to equal zero 
tons.
    Topping-cycle cogeneration unit means a cogeneration unit in which 
the energy input to the unit is first used to produce useful power, 
including electricity, and at least some of the reject heat from the 
electricity production is then used to provide useful thermal energy.
    Total energy input means, with regard to a cogeneration unit, total 
energy of all forms supplied to the cogeneration unit, excluding energy 
produced by the cogeneration unit itself. Each form of energy supplied 
shall be measured by the lower heating value of that form of energy 
calculated as follows:

LHV = HHV-10.55(W + 9H)

Where:

LHV = lower heating value of fuel in Btu/lb,
HHV = higher heating value of fuel in Btu/lb,
W = Weight % of moisture in fuel, and
H = Weight % of hydrogen in fuel.

    Total energy output means, with regard to a cogeneration unit, the 
sum of useful power and useful thermal energy produced by the 
cogeneration unit.
    Unit means a stationary, fossil-fuel-fired boiler or combustion 
turbine or other stationary, fossil-fuel-fired combustion device.
    Unit operating day means a calendar day in which a unit combusts any 
fuel.
    Unit operating hour or hour of unit operation means an hour in which 
a unit combusts any fuel.
    Useful power means, with regard to a cogeneration unit, electricity 
or mechanical energy made available for use, excluding any such energy 
used in the power production process (which process includes, but is not 
limited to, any on-site processing or treatment of fuel combusted at the 
unit and any on-site emission controls).
    Useful thermal energy means, with regard to a cogeneration unit, 
thermal energy that is:
    (1) Made available to an industrial or commercial process (not a 
power production process), excluding any heat contained in condensate 
return or makeup water;
    (2) Used in a heating application (e.g., space heating or domestic 
hot water heating); or
    (3) Used in a space cooling application (i.e., thermal energy used 
by an absorption chiller).
    Utility power distribution system means the portion of an 
electricity grid owned or operated by a utility and dedicated to 
delivering electricity to customers.

[65 FR 2727, Jan. 18, 2000, as amended at 71 FR 74795, Dec. 13, 2006; 72 
FR 59207, Oct. 19, 2007]



Sec. 97.303  Measurements, abbreviations, and acronyms.

    Measurements, abbreviations, and acronyms used in this subpart and 
subparts BBBB through IIII are defined as follows:

Btu--British thermal unit.
CO2--carbon dioxide.
H2O--water.
Hg--mercury.
hr--hour.
kW--kilowatt electrical.
kWh--kilowatt hour.
lb--pound.
mmBtu--million Btu.
MWe--megawatt electrical.
MWh--megawatt hour.
NOX--nitrogen oxides.
O2--oxygen.
ppm--parts per million.
scfh--standard cubic feet per hour.
SO2--sulfur dioxide.
yr--year.



Sec. 97.304  Applicability.

    (a) Except as provided in paragraph (b) of this section:
    (1) The following units in a State shall be CAIR NOX 
Ozone Season units, and any source that includes one or more such units 
shall be a CAIR NOX Ozone Season source, subject to the 
requirements of this subpart and subparts BBBB through HHHH of this 
part: any stationary, fossil-fuel-fired boiler or stationary, fossil-
fuel-fired combustion turbine serving at any time, since the later of 
November 15, 1990 or the start-up of the unit(s combustion chamber, a 
generator with nameplate capacity of more than 25 MWe producing 
electricity for sale.

[[Page 310]]

    (2) If a stationary boiler or stationary combustion turbine that, 
under paragraph (a)(1) of this section, is not a CAIR NOX 
Ozone Season unit begins to combust fossil fuel or to serve a generator 
with nameplate capacity of more than 25 MWe producing electricity for 
sale, the unit shall become a CAIR NOX Ozone Season unit as 
provided in paragraph (a)(1) of this section on the first date on which 
it both combusts fossil fuel and serves such generator.
    (b) The units in a State that meet the requirements set forth in 
paragraph (b)(1)(i), (b)(2)(i), or (b)(2)(ii) of this section shall not 
be CAIR NOX Ozone Season units:
    (1)(i) Any unit that is a CAIR NOX Ozone Season unit 
under paragraph (a)(1) or (2) of this section:
    (A) Qualifying as a cogeneration unit during the 12-month period 
starting on the date the unit first produces electricity and continuing 
to qualify as a cogeneration unit; and
    (B) Not serving at any time, since the later of November 15, 1990 or 
the start-up of the unit's combustion chamber, a generator with 
nameplate capacity of more than 25 MWe supplying in any calendar year 
more than one-third of the unit(s potential electric output capacity or 
219,000 MWh, whichever is greater, to any utility power distribution 
system for sale.
    (ii) If a unit qualifies as a cogeneration unit during the 12-month 
period starting on the date the unit first produces electricity and 
meets the requirements of paragraphs (b)(1)(i) of this section for at 
least one calendar year, but subsequently no longer meets all such 
requirements, the unit shall become a CAIR NOX Ozone Season 
unit starting on the earlier of January 1 after the first calendar year 
during which the unit first no longer qualifies as a cogeneration unit 
or January 1 after the first calendar year during which the unit no 
longer meets the requirements of paragraph (b)(1)(i)(B) of this section.
    (2)(i) Any unit that is a CAIR NOX Ozone Season unit 
under paragraph (a)(1) or (2) of this section commencing operation 
before January 1, 1985:
    (A) Qualifying as a solid waste incineration unit; and
    (B) With an average annual fuel consumption of non-fossil fuel for 
1985-1987 exceeding 80 percent (on a Btu basis) and an average annual 
fuel consumption of non-fossil fuel for any 3 consecutive calendar years 
after 1990 exceeding 80 percent (on a Btu basis).
    (ii) Any unit that is a CAIR NOX Ozone Season unit under 
paragraph (a)(1) or (2) of this section commencing operation on or after 
January 1, 1985:
    (A) Qualifying as a solid waste incineration unit; and
    (B) With an average annual fuel consumption of non-fossil fuel for 
the first 3 calendar years of operation exceeding 80 percent (on a Btu 
basis) and an average annual fuel consumption of non-fossil fuel for any 
3 consecutive calendar years after 1990 exceeding 80 percent (on a Btu 
basis).
    (iii) If a unit qualifies as a solid waste incineration unit and 
meets the requirements of paragraph (b)(2)(i) or (ii) of this section 
for at least 3 consecutive calendar years, but subsequently no longer 
meets all such requirements, the unit shall become a CAIR NOX 
Ozone Season unit starting on the earlier of January 1 after the first 
calendar year during which the unit first no longer qualifies as a solid 
waste incineration unit or January 1 after the first 3 consecutive 
calendar years after 1990 for which the unit has an average annual fuel 
consumption of fossil fuel of 20 percent or more.
    (c) A certifying official of an owner or operator of any unit may 
petition the Administrator at any time for a determination concerning 
the applicability, under paragraphs (a) and (b) of this section, of the 
CAIR NOX Ozone Season Trading Program to the unit.
    (1) Petition content. The petition shall be in writing and include 
the identification of the unit and the relevant facts about the unit. 
The petition and any other documents provided to the Administrator in 
connection with the petition shall include the following certification 
statement, signed by the certifying official: ``I am authorized to make 
this submission on behalf of the owners and operators of the unit for 
which the submission is made. I certify under penalty of law that I have 
personally examined, and am familiar with, the statements and 
information

[[Page 311]]

submitted in this document and all its attachments. Based on my inquiry 
of those individuals with primary responsibility for obtaining the 
information, I certify that the statements and information are to the 
best of my knowledge and belief true, accurate, and complete. I am aware 
that there are significant penalties for submitting false statements and 
information or omitting required statements and information, including 
the possibility of fine or imprisonment.''
    (2) Submission. The petition and any other documents provided in 
connection with the petition shall be submitted to the Director of the 
Clean Air Markets Division (or its successor), U.S. Environmental 
Protection Agency, who will act on the petition as the Administrator's 
duly authorized representative.
    (3) Response. The Administrator will issue a written response to the 
petition and may request supplemental information relevant to such 
petition. The Administrator's determination concerning the 
applicability, under paragraphs (a) and (b) of this section, of the CAIR 
NOX Ozone Season Trading Program to the unit shall be binding 
on the permitting authority unless the petition or other information or 
documents provided in connection with the petition are found to have 
contained significant, relevant errors or omissions.
    (d) Notwithstanding paragraphs (a) and (b) of this section, if a 
State submits, and the Administrator approves, a State implementation 
plan revision in accordance with Sec. 51.123(ee)(1) of this chapter 
providing for the inclusion in the CAIR NOX Ozone Season 
Trading Program of all units that are not otherwise CAIR NOX 
Ozone Season units under paragraphs (a) and (b) of this section and that 
are NOX Budget units covered by the State's emissions trading 
program approved under Sec. 51.121(p) of this chapter, such units shall 
be CAIR NOX Ozone Season units as of the first date that they 
are NOX Budget units under the NOX Budget Trading 
Program under Sec. 51.121(p) of this chapter.



Sec. 97.305  Retired unit exemption.

    (a)(1) Any CAIR NOX Ozone Season unit that is permanently 
retired and is not a CAIR NOX Ozone Season opt-in unit under 
subpart IIII of this part shall be exempt from the CAIR NOX 
Ozone Season Trading Program, except for the provisions of this section, 
Sec. Sec. 97.302, 97.303, 97.304, 97.306(c)(4) through (7), 97.307, 
97.308, and subparts BBBB and EEEE through GGGG of this part.
    (2) The exemption under paragraph (a)(1) of this section shall 
become effective the day on which the CAIR NOX Ozone Season 
unit is permanently retired. Within 30 days of the unit's permanent 
retirement, the CAIR designated representative shall submit a statement 
to the permitting authority otherwise responsible for administering any 
CAIR permit for the unit and shall submit a copy of the statement to the 
Administrator. The statement shall state, in a format prescribed by the 
permitting authority, that the unit was permanently retired on a 
specific date and will comply with the requirements of paragraph (b) of 
this section.
    (3) After receipt of the statement under paragraph (a)(2) of this 
section, the permitting authority will amend any permit under subpart 
CCCC of this part covering the source at which the unit is located to 
add the provisions and requirements of the exemption under paragraphs 
(a)(1) and (b) of this section.
    (b) Special provisions. (1) A unit exempt under paragraph (a) of 
this section shall not emit any nitrogen oxides, starting on the date 
that the exemption takes effect.
    (2) The Administrator or the permitting authority will allocate CAIR 
NOX Ozone Season allowances under subpart EEEE of this part 
to a unit exempt under paragraph (a) of this section.
    (3) For a period of 5 years from the date the records are created, 
the owners and operators of a unit exempt under paragraph (a) of this 
section shall retain at the source that includes the unit, records 
demonstrating that the unit is permanently retired. The 5-year period 
for keeping records may be extended for cause, at any time before the 
end of the period, in writing by the

[[Page 312]]

permitting authority or the Administrator. The owners and operators bear 
the burden of proof that the unit is permanently retired.
    (4) The owners and operators and, to the extent applicable, the CAIR 
designated representative of a unit exempt under paragraph (a) of this 
section shall comply with the requirements of the CAIR NOX 
Ozone Season Trading Program concerning all periods for which the 
exemption is not in effect, even if such requirements arise, or must be 
complied with, after the exemption takes effect.
    (5) A unit exempt under paragraph (a) of this section and located at 
a source that is required, or but for this exemption would be required, 
to have a title V operating permit shall not resume operation unless the 
CAIR designated representative of the source submits a complete CAIR 
permit application under Sec. 97.322 for the unit not less than 18 
months (or such lesser time provided by the permitting authority) before 
the later of January 1, 2009 or the date on which the unit resumes 
operation.
    (6) On the earlier of the following dates, a unit exempt under 
paragraph (a) of this section shall lose its exemption:
    (i) The date on which the CAIR designated representative submits a 
CAIR permit application for the unit under paragraph (b)(5) of this 
section;
    (ii) The date on which the CAIR designated representative is 
required under paragraph (b)(5) of this section to submit a CAIR permit 
application for the unit; or
    (iii) The date on which the unit resumes operation, if the CAIR 
designated representative is not required to submit a CAIR permit 
application for the unit.
    (7) For the purpose of applying monitoring, reporting, and 
recordkeeping requirements under subpart HHHH of this part, a unit that 
loses its exemption under paragraph (a) of this section shall be treated 
as a unit that commences commercial operation on the first date on which 
the unit resumes operation.



Sec. 97.306  Standard requirements.

    (a) Permit requirements. (1) The CAIR designated representative of 
each CAIR NOX Ozone Season source required to have a title V 
operating permit and each CAIR NOX Ozone Season unit required 
to have a title V operating permit at the source shall:
    (i) Submit to the permitting authority a complete CAIR permit 
application under Sec. 97.322 in accordance with the deadlines 
specified in Sec. 97.321; and
    (ii) Submit in a timely manner any supplemental information that the 
permitting authority determines is necessary in order to review a CAIR 
permit application and issue or deny a CAIR permit.
    (2) The owners and operators of each CAIR NOX Ozone 
Season source required to have a title V operating permit and each CAIR 
NOX Ozone Season unit required to have a title V operating 
permit at the source shall have a CAIR permit issued by the permitting 
authority under subpart CCCC of this part for the source and operate the 
source and the unit in compliance with such CAIR permit.
    (3) Except as provided in subpart IIII of this part, the owners and 
operators of a CAIR NOX Ozone Season source that is not 
otherwise required to have a title V operating permit and each CAIR 
NOX Ozone Season unit that is not otherwise required to have 
a title V operating permit are not required to submit a CAIR permit 
application, and to have a CAIR permit, under subpart CCCC of this part 
for such CAIR NOX Ozone Season source and such CAIR 
NOX Ozone Season unit.
    (b) Monitoring, reporting, and recordkeeping requirements. (1) The 
owners and operators, and the CAIR designated representative, of each 
CAIR NOX Ozone Season source and each CAIR NOX 
Ozone Season unit at the source shall comply with the monitoring, 
reporting, and recordkeeping requirements of subpart HHHH of this part.
    (2) The emissions measurements recorded and reported in accordance 
with subpart HHHH of this part shall be used to determine compliance by 
each CAIR NOX Ozone Season source with the CAIR 
NOX Ozone Season emissions limitation under paragraph (c) of 
this section.

[[Page 313]]

    (c) Nitrogen oxides ozone season emission requirements. (1) As of 
the allowance transfer deadline for a control period, the owners and 
operators of each CAIR NOX Ozone Season source and each CAIR 
NOX Ozone Season unit at the source shall hold, in the 
source's compliance account, CAIR NOX Ozone Season allowances 
available for compliance deductions for the control period under Sec. 
97.354(a) in an amount not less than the tons of total nitrogen oxides 
emissions for the control period from all CAIR NOX Ozone 
Season units at the source, as determined in accordance with subpart 
HHHH of this part.
    (2) A CAIR NOX Ozone Season unit shall be subject to the 
requirements under paragraph (c)(1) of this section for the control 
period starting on the later of May 1, 2009 or the deadline for meeting 
the unit's monitor certification requirements under Sec. 97.370(b)(1), 
(2), (3), or (7) and for each control period thereafter.
    (3) A CAIR NOX Ozone Season allowance shall not be 
deducted, for compliance with the requirements under paragraph (c)(1) of 
this section, for a control period in a calendar year before the year 
for which the CAIR NOX Ozone Season allowance was allocated.
    (4) CAIR NOX Ozone Season allowances shall be held in, 
deducted from, or transferred into or among CAIR NOX Ozone 
Season Allowance Tracking System accounts in accordance with subparts 
EEEE, FFFF, GGGG, and IIII of this part.
    (5) A CAIR NOX Ozone Season allowance is a limited 
authorization to emit one ton of nitrogen oxides in accordance with the 
CAIR NOX Ozone Season Trading Program. No provision of the 
CAIR NOX Ozone Season Trading Program, the CAIR permit 
application, the CAIR permit, or an exemption under Sec. 97.305 and no 
provision of law shall be construed to limit the authority of the United 
States to terminate or limit such authorization.
    (6) A CAIR NOX Ozone Season allowance does not constitute 
a property right.
    (7) Upon recordation by the Administrator under subpart EEEE, FFFF, 
GGGG, or IIII of this part, every allocation, transfer, or deduction of 
a CAIR NOX Ozone Season allowance to or from a CAIR 
NOX Ozone Season source's compliance account is incorporated 
automatically in any CAIR permit of the source.
    (d) Excess emissions requirements. If a CAIR NOX Ozone 
Season source emits nitrogen oxides during any control period in excess 
of the CAIR NOX Ozone Season emissions limitation, then:
    (1) The owners and operators of the source and each CAIR 
NOX Ozone Season unit at the source shall surrender the CAIR 
NOX Ozone Season allowances required for deduction under 
Sec. 97.354(d)(1) and pay any fine, penalty, or assessment or comply 
with any other remedy imposed, for the same violations, under the Clean 
Air Act or applicable State law; and
    (2) Each ton of such excess emissions and each day of such control 
period shall constitute a separate violation of this subpart, the Clean 
Air Act, and applicable State law.
    (e) Recordkeeping and reporting requirements. (1) Unless otherwise 
provided, the owners and operators of the CAIR NOX Ozone 
Season source and each CAIR NOX Ozone Season unit at the 
source shall keep on site at the source each of the following documents 
for a period of 5 years from the date the document is created. This 
period may be extended for cause, at any time before the end of 5 years, 
in writing by the permitting authority or the Administrator.
    (i) The certificate of representation under Sec. 97.313 for the 
CAIR designated representative for the source and each CAIR 
NOX Ozone Season unit at the source and all documents that 
demonstrate the truth of the statements in the certificate of 
representation; provided that the certificate and documents shall be 
retained on site at the source beyond such 5-year period until such 
documents are superseded because of the submission of a new certificate 
of representation under Sec. 97.313 changing the CAIR designated 
representative.
    (ii) All emissions monitoring information, in accordance with 
subpart HHHH of this part, provided that to the extent that subpart HHHH 
of this part provides for a 3-year period for recordkeeping, the 3-year 
period shall apply.

[[Page 314]]

    (iii) Copies of all reports, compliance certifications, and other 
submissions and all records made or required under the CAIR 
NOX Ozone Season Trading Program.
    (iv) Copies of all documents used to complete a CAIR permit 
application and any other submission under the CAIR NOX Ozone 
Season Trading Program or to demonstrate compliance with the 
requirements of the CAIR NOX Ozone Season Trading Program.
    (2) The CAIR designated representative of a CAIR NOX 
Ozone Season source and each CAIR NOX Ozone Season unit at 
the source shall submit the reports required under the CAIR 
NOX Ozone Season Trading Program, including those under 
subpart HHHH of this part.
    (f) Liability. (1) Each CAIR NOX Ozone Season source and 
each CAIR NOX Ozone Season unit shall meet the requirements 
of the CAIR NOX Ozone Season Trading Program.
    (2) Any provision of the CAIR NOX Ozone Season Trading 
Program that applies to a CAIR NOX Ozone Season source or the 
CAIR designated representative of a CAIR NOX Ozone Season 
source shall also apply to the owners and operators of such source and 
of the CAIR NOX Ozone Season units at the source.
    (3) Any provision of the CAIR NOX Ozone Season Trading 
Program that applies to a CAIR NOX Ozone Season unit or the 
CAIR designated representative of a CAIR NOX Ozone Season 
unit shall also apply to the owners and operators of such unit.
    (g) Effect on other authorities. No provision of the CAIR 
NOX Ozone Season Trading Program, a CAIR permit application, 
a CAIR permit, or an exemption under Sec. 97.305 shall be construed as 
exempting or excluding the owners and operators, and the CAIR designated 
representative, of a CAIR NOX Ozone Season source or CAIR 
NOX Ozone Season unit from compliance with any other 
provision of the applicable, approved State implementation plan, a 
federally enforceable permit, or the Clean Air Act.



Sec. 97.307  Computation of time.

    (a) Unless otherwise stated, any time period scheduled, under the 
CAIR NOX Ozone Season Trading Program, to begin on the 
occurrence of an act or event shall begin on the day the act or event 
occurs.
    (b) Unless otherwise stated, any time period scheduled, under the 
CAIR NOX Ozone Season Trading Program, to begin before the 
occurrence of an act or event shall be computed so that the period ends 
the day before the act or event occurs.
    (c) Unless otherwise stated, if the final day of any time period, 
under the CAIR NOX Ozone Season Trading Program, falls on a 
weekend or a State or Federal holiday, the time period shall be extended 
to the next business day.



Sec. 97.308  Appeal procedures.

    The appeal procedures for decisions of the Administrator under the 
CAIR NOX Ozone Season Trading Program are set forth in part 
78 of this chapter.



 Sec. Appendix A to Subpart AAAA of Part 97--States With Approved State 
         Implementation Plan Revisions Concerning Applicability

    The following States have State Implementation Plan revisions under 
Sec. 51.123(ee)(1) of this chapter approved by the Administrator and 
providing for expansion of the applicability provisions to include all 
non-EGUs subject to the respective State's emission trading program 
approved under Sec. 51.121(p) of this chapter:

Michigan
Tennessee

[65 FR 2727, Jan. 18, 2000, as amended at 72 FR 72262, Dec. 20, 2007; 74 
FR 61537, Nov. 25, 2009]



 Subpart BBBB_CAIR Designated Representative for CAIR NOX Ozone Season 
                                 Sources



Sec. 97.310  Authorization and responsibilities of CAIR designated representative.

    (a) Except as provided under Sec. 97.311, each CAIR NOX 
Ozone Season source, including all CAIR NOX Ozone Season 
units at the source, shall have one and only one CAIR designated 
representative, with regard to all matters under the CAIR NOX 
Ozone Season Trading Program concerning the source or any CAIR 
NOX Ozone Season unit at the source.

[[Page 315]]

    (b) The CAIR designated representative of the CAIR NOX 
Ozone Season source shall be selected by an agreement binding on the 
owners and operators of the source and all CAIR NOX Ozone 
Season units at the source and shall act in accordance with the 
certification statement in Sec. 97.313(a)(4)(iv).
    (c) Upon receipt by the Administrator of a complete certificate of 
representation under Sec. 97.313, the CAIR designated representative of 
the source shall represent and, by his or her representations, actions, 
inactions, or submissions, legally bind each owner and operator of the 
CAIR NOX Ozone Season source represented and each CAIR 
NOX Ozone Season unit at the source in all matters pertaining 
to the CAIR NOX Ozone Season Trading Program, notwithstanding 
any agreement between the CAIR designated representative and such owners 
and operators. The owners and operators shall be bound by any decision 
or order issued to the CAIR designated representative by the permitting 
authority, the Administrator, or a court regarding the source or unit.
    (d) No CAIR permit will be issued, no emissions data reports will be 
accepted, and no CAIR NOX Ozone Season Allowance Tracking 
System account will be established for a CAIR NOX Ozone 
Season unit at a source, until the Administrator has received a complete 
certificate of representation under Sec. 97.313 for a CAIR designated 
representative of the source and the CAIR NOX Ozone Season 
units at the source.
    (e)(1) Each submission under the CAIR NOX Ozone Season 
Trading Program shall be submitted, signed, and certified by the CAIR 
designated representative for each CAIR NOX Ozone Season 
source on behalf of which the submission is made. Each such submission 
shall include the following certification statement by the CAIR 
designated representative: ``I am authorized to make this submission on 
behalf of the owners and operators of the source or units for which the 
submission is made. I certify under penalty of law that I have 
personally examined, and am familiar with, the statements and 
information submitted in this document and all its attachments. Based on 
my inquiry of those individuals with primary responsibility for 
obtaining the information, I certify that the statements and information 
are to the best of my knowledge and belief true, accurate, and complete. 
I am aware that there are significant penalties for submitting false 
statements and information or omitting required statements and 
information, including the possibility of fine or imprisonment.''
    (2) The permitting authority and the Administrator will accept or 
act on a submission made on behalf of owner or operators of a CAIR 
NOX Ozone Season source or a CAIR NOX Ozone Season 
unit only if the submission has been made, signed, and certified in 
accordance with paragraph (e)(1) of this section.



Sec. 97.311  Alternate CAIR designated representative.

    (a) A certificate of representation under Sec. 97.313 may designate 
one and only one alternate CAIR designated representative, who may act 
on behalf of the CAIR designated representative. The agreement by which 
the alternate CAIR designated representative is selected shall include a 
procedure for authorizing the alternate CAIR designated representative 
to act in lieu of the CAIR designated representative.
    (b) Upon receipt by the Administrator of a complete certificate of 
representation under Sec. 97.313, any representation, action, inaction, 
or submission by the alternate CAIR designated representative shall be 
deemed to be a representation, action, inaction, or submission by the 
CAIR designated representative.
    (c) Except in this section and Sec. Sec. 97.302, 97.310(a) and (d), 
97.312, 97.313, 97.315, 97.351, and 97.382, whenever the term ``CAIR 
designated representative'' is used in subparts AAAA through IIII of 
this part, the term shall be construed to include the CAIR designated 
representative or any alternate CAIR designated representative.



Sec. 97.312  Changing CAIR designated representative and alternate
CAIR designated representative; changes in owners and operators.

    (a) Changing CAIR designated representative. The CAIR designated 
representative may be changed at any

[[Page 316]]

time upon receipt by the Administrator of a superseding complete 
certificate of representation under Sec. 97.313. Notwithstanding any 
such change, all representations, actions, inactions, and submissions by 
the previous CAIR designated representative before the time and date 
when the Administrator receives the superseding certificate of 
representation shall be binding on the new CAIR designated 
representative and the owners and operators of the CAIR NOX 
Ozone Season source and the CAIR NOX Ozone Season units at 
the source.
    (b) Changing alternate CAIR designated representative. The alternate 
CAIR designated representative may be changed at any time upon receipt 
by the Administrator of a superseding complete certificate of 
representation under Sec. 97.313. Notwithstanding any such change, all 
representations, actions, inactions, and submissions by the previous 
alternate CAIR designated representative before the time and date when 
the Administrator receives the superseding certificate of representation 
shall be binding on the new alternate CAIR designated representative and 
the owners and operators of the CAIR NOX Ozone Season source 
and the CAIR NOX Ozone Season units at the source.
    (c) Changes in owners and operators. (1) In the event an owner or 
operator of a CAIR NOX Ozone Season source or a CAIR 
NOX Ozone Season unit is not included in the list of owners 
and operators in the certificate of representation under Sec. 97.313, 
such owner or operator shall be deemed to be subject to and bound by the 
certificate of representation, the representations, actions, inactions, 
and submissions of the CAIR designated representative and any alternate 
CAIR designated representative of the source or unit, and the decisions 
and orders of the permitting authority, the Administrator, or a court, 
as if the owner or operator were included in such list.
    (2) Within 30 days following any change in the owners and operators 
of a CAIR NOX Ozone Season source or a CAIR NOX 
Ozone Season unit, including the addition of a new owner or operator, 
the CAIR designated representative or any alternate CAIR designated 
representative shall submit a revision to the certificate of 
representation under Sec. 97.313 amending the list of owners and 
operators to include the change.



Sec. 97.313  Certificate of representation.

    (a) A complete certificate of representation for a CAIR designated 
representative or an alternate CAIR designated representative shall 
include the following elements in a format prescribed by the 
Administrator:
    (1) Identification of the CAIR NOX Ozone Season source, 
and each CAIR NOX Ozone Season unit at the source, for which 
the certificate of representation is submitted, including identification 
and nameplate capacity of each generator served by each such unit.
    (2) The name, address, e-mail address (if any), telephone number, 
and facsimile transmission number (if any) of the CAIR designated 
representative and any alternate CAIR designated representative.
    (3) A list of the owners and operators of the CAIR NOX 
Ozone Season source and of each CAIR NOX Ozone Season unit at 
the source.
    (4) The following certification statements by the CAIR designated 
representative and any alternate CAIR designated representative--
    (i) ``I certify that I was selected as the CAIR designated 
representative or alternate CAIR designated representative, as 
applicable, by an agreement binding on the owners and operators of the 
source and each CAIR NOX Ozone Season unit at the source.''
    (ii) ``I certify that I have all the necessary authority to carry 
out my duties and responsibilities under the CAIR NOX Ozone 
Season Trading Program on behalf of the owners and operators of the 
source and of each CAIR NOX Ozone Season unit at the source 
and that each such owner and operator shall be fully bound by my 
representations, actions, inactions, or submissions.''
    (iii) ``I certify that the owners and operators of the source and of 
each CAIR NOX Ozone Season unit at the source shall be bound 
by any order issued to me by the Administrator, the permitting 
authority, or a court regarding the source or unit.''

[[Page 317]]

    (iv) ``Where there are multiple holders of a legal or equitable 
title to, or a leasehold interest in, a CAIR NOX Ozone Season 
unit, or where a utility or industrial customer purchases power from a 
CAIR NOX Ozone Season unit under a life-of-the-unit, firm 
power contractual arrangement, I certify that: I have given a written 
notice of my selection as the `CAIR designated representative' or 
`alternate CAIR designated representative', as applicable, and of the 
agreement by which I was selected to each owner and operator of the 
source and of each CAIR NOX Ozone Season unit at the source; 
and CAIR NOX Ozone Season allowances and proceeds of 
transactions involving CAIR NOX Ozone Season allowances will 
be deemed to be held or distributed in proportion to each holder's 
legal, equitable, leasehold, or contractual reservation or entitlement, 
except that, if such multiple holders have expressly provided for a 
different distribution of CAIR NOX Ozone Season allowances by 
contract, CAIR NOX Ozone Season allowances and proceeds of 
transactions involving CAIR NOX Ozone Season allowances will 
be deemed to be held or distributed in accordance with the contract.''
    (5) The signature of the CAIR designated representative and any 
alternate CAIR designated representative and the dates signed.
    (b) Unless otherwise required by the permitting authority or the 
Administrator, documents of agreement referred to in the certificate of 
representation shall not be submitted to the permitting authority or the 
Administrator. Neither the permitting authority nor the Administrator 
shall be under any obligation to review or evaluate the sufficiency of 
such documents, if submitted.



Sec. 97.314  Objections concerning CAIR designated representative.

    (a) Once a complete certificate of representation under Sec. 97.313 
has been submitted and received, the permitting authority and the 
Administrator will rely on the certificate of representation unless and 
until a superseding complete certificate of representation under Sec. 
97.313 is received by the Administrator.
    (b) Except as provided in Sec. 97.312(a) or (b), no objection or 
other communication submitted to the permitting authority or the 
Administrator concerning the authorization, or any representation, 
action, inaction, or submission, of the CAIR designated representative 
shall affect any representation, action, inaction, or submission of the 
CAIR designated representative or the finality of any decision or order 
by the permitting authority or the Administrator under the CAIR 
NOX Ozone Season Trading Program.
    (c) Neither the permitting authority nor the Administrator will 
adjudicate any private legal dispute concerning the authorization or any 
representation, action, inaction, or submission of any CAIR designated 
representative, including private legal disputes concerning the proceeds 
of CAIR NOX Ozone Season allowance transfers.



Sec. 97.315  Delegation by CAIR designated representative and 
alternate CAIR designated representative.

    (a) A CAIR designated representative may delegate, to one or more 
natural persons, his or her authority to make an electronic submission 
to the Administrator provided for or required under this part.
    (b) An alternate CAIR designated representative may delegate, to one 
or more natural persons, his or her authority to make an electronic 
submission to the Administrator provided for or required under this 
part.
    (c) In order to delegate authority to make an electronic submission 
to the Administrator in accordance with paragraph (a) or (b) of this 
section, the CAIR designated representative or alternate CAIR designated 
representative, as appropriate, must submit to the Administrator a 
notice of delegation, in a format prescribed by the Administrator, that 
includes the following elements:
    (1) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of such CAIR designated 
representative or alternate CAIR designated representative;
    (2) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of each such

[[Page 318]]

natural person (referred to as an ``agent'');
    (3) For each such natural person, a list of the type or types of 
electronic submissions under paragraph (a) or (b) of this section for 
which authority is delegated to him or her; and
    (4) The following certification statements by such CAIR designated 
representative or alternate CAIR designated representative:
    (i) ``I agree that any electronic submission to the Administrator 
that is by an agent identified in this notice of delegation and of a 
type listed for such agent in this notice of delegation and that is made 
when I am a CAIR designated representative or alternate CAIR designated 
representative, as appropriate, and before this notice of delegation is 
superseded by another notice of delegation under 40 CFR 97.315(d) shall 
be deemed to be an electronic submission by me.''
    (ii) ``Until this notice of delegation is superseded by another 
notice of delegation under 40 CFR 97.315(d), I agree to maintain an e-
mail account and to notify the Administrator immediately of any change 
in my e-mail address unless all delegation of authority by me under 40 
CFR 97.315 is terminated.''.
    (d) A notice of delegation submitted under paragraph (c) of this 
section shall be effective, with regard to the CAIR designated 
representative or alternate CAIR designated representative identified in 
such notice, upon receipt of such notice by the Administrator and until 
receipt by the Administrator of a superseding notice of delegation 
submitted by such CAIR designated representative or alternate CAIR 
designated representative, as appropriate. The superseding notice of 
delegation may replace any previously identified agent, add a new agent, 
or eliminate entirely any delegation of authority.
    (e) Any electronic submission covered by the certification in 
paragraph (c)(4)(i) of this section and made in accordance with a notice 
of delegation effective under paragraph (d) of this section shall be 
deemed to be an electronic submission by the CAIR designated 
representative or alternate CAIR designated representative submitting 
such notice of delegation.



                          Subpart CCCC_Permits



Sec. 97.320  General CAIR NOX Ozone Season Trading Program permit
requirements.

    (a) For each CAIR NOX Ozone Season source required to 
have a title V operating permit or required, under subpart IIII of this 
part, to have a title V operating permit or other federally enforceable 
permit, such permit shall include a CAIR permit administered by the 
permitting authority for the title V operating permit or the federally 
enforceable permit as applicable. The CAIR portion of the title V permit 
or other federally enforceable permit as applicable shall be 
administered in accordance with the permitting authority's title V 
operating permits regulations promulgated under part 70 or 71 of this 
chapter or the permitting authority's regulations for other federally 
enforceable permits as applicable, except as provided otherwise by Sec. 
97.305, this subpart, and subpart IIII of this part.
    (b) Each CAIR permit shall contain, with regard to the CAIR 
NOX Ozone Season source and the CAIR NOX Ozone 
Season units at the source covered by the CAIR permit, all applicable 
CAIR NOX Ozone Season Trading Program, CAIR NOX 
Annual Trading Program, and CAIR SO2 Trading Program 
requirements and shall be a complete and separable portion of the title 
V operating permit or other federally enforceable permit under paragraph 
(a) of this section.



Sec. 97.321  Submission of CAIR permit applications.

    (a) Duty to apply. The CAIR designated representative of any CAIR 
NOX Ozone Season source required to have a title V operating 
permit shall submit to the permitting authority a complete CAIR permit 
application under Sec. 97.322 for the source covering each CAIR 
NOX Ozone Season unit at the source at least 18 months (or 
such lesser time provided by the permitting authority) before the later 
of January 1, 2009 or the date on which the CAIR NOX Ozone 
Season unit commences commercial operation, except as provided in Sec. 
97.383(a).
    (b) Duty to reapply. For a CAIR NOX Ozone Season source 
required to have a

[[Page 319]]

title V operating permit, the CAIR designated representative shall 
submit a complete CAIR permit application under Sec. 97.322 for the 
source covering each CAIR NOX Ozone Season unit at the source 
to renew the CAIR permit in accordance with the permitting authority's 
title V operating permits regulations addressing permit renewal, except 
as provided in Sec. 97.383(b).



Sec. 97.322  Information requirements for CAIR permit applications.

    A complete CAIR permit application shall include the following 
elements concerning the CAIR NOX Ozone Season source for 
which the application is submitted, in a format prescribed by the 
permitting authority:
    (a) Identification of the CAIR NOX Ozone Season source;
    (b) Identification of each CAIR NOX Ozone Season unit at 
the CAIR NOX Ozone Season source; and
    (c) The standard requirements under Sec. 97.306.



Sec. 97.323  CAIR permit contents and term.

    (a) Each CAIR permit will contain, in a format prescribed by the 
permitting authority, all elements required for a complete CAIR permit 
application under Sec. 97.322.
    (b) Each CAIR permit is deemed to incorporate automatically the 
definitions of terms under Sec. 97.302 and, upon recordation by the 
Administrator under subpart EEEE, FFFF, GGGG, or IIII of this part, 
every allocation, transfer, or deduction of a CAIR NOX Ozone 
Season allowance to or from the compliance account of the CAIR 
NOX Ozone Season source covered by the permit.
    (c) The term of the CAIR permit will be set by the permitting 
authority, as necessary to facilitate coordination of the renewal of the 
CAIR permit with issuance, revision, or renewal of the CAIR 
NOX Ozone Season source's title V operating permit or other 
federally enforceable permit as applicable.



Sec. 97.324  CAIR permit revisions.

    Except as provided in Sec. 97.323(b), the permitting authority will 
revise the CAIR permit, as necessary, in accordance with the permitting 
authority's title V operating permits regulations or the permitting 
authority's regulations for other federally enforceable permits as 
applicable addressing permit revisions.

Subpart DDDD [Reserved]



        Subpart EEEE_CAIR NOX Ozone Season Allowance Allocations



Sec. 97.340  State trading budgets.

    (a) Except as provided in paragraph (b) of this section, the State 
trading budgets for annual allocations of CAIR NOX Ozone 
Season allowances for the control periods in 2009 through 2014 and in 
2015 and thereafter are respectively as follows:

------------------------------------------------------------------------
                                                           State trading
                                           State trading    budget for
                  State                     budget for       2015 and
                                             2009-2014      thereafter
                                              (tons)          (tons)
------------------------------------------------------------------------
Alabama.................................          32,182          26,818
Arkansas................................          11,515           9,597
Connecticut.............................           2,559           2,559
Delaware................................           2,226           1,855
District of Columbia....................             112              94
Florida.................................          47,912          39,926
Illinois................................          30,701          28,981
Indiana.................................          45,952          39,273
Iowa....................................          14,263          11,886
Kentucky................................          36,045          30,587
Louisiana...............................          17,085          14,238
Maryland................................          12,834          10,695
Massachusetts...........................           7,551           6,293
Michigan................................          28,971          24,142
Mississippi.............................           8,714           7,262
Missouri................................          26,678          22,231
New Jersey..............................           6,654           5,545
New York................................          20,632          17,193
North Carolina..........................          28,392          23,660
Ohio....................................          45,664          39,945
Pennsylvania............................          42,171          35,143
South Carolina..........................          15,249          12,707
Tennessee...............................          22,842          19,035
Virginia................................          15,994          13,328
West Virginia...........................          26,859          26,525
Wisconsin...............................          17,987          14,989
------------------------------------------------------------------------

    (b) Upon approval by the Administrator of a State's State 
implementation plan revision under Sec. 51.123(ee)(1) of this chapter 
providing for the inclusion in the CAIR NOX Ozone Season 
Trading Program of all units that are not otherwise CAIR NOX 
Ozone Season units under Sec. 97.304(a) and (b) and that are 
NOX Budget units covered by the State's emissions trading 
program approved under Sec. 51.121(p), the amount in the State trading 
budget for a control period in a calendar year will be the sum of the 
amount set forth for the

[[Page 320]]

State and for the year in paragraph (a) of this section and the amount 
of additional CAIR NOX Ozone Season allowance allocations 
issued under Sec. 51.123(ee)(1)(ii)(A) of this chapter for the year.



Sec. 97.341  Timing requirements for CAIR NOX Ozone Season allowance
allocations.

    (a) The Administrator will determine by order the CAIR 
NOX Ozone Season allowance allocations, in accordance with 
Sec. 97.342(a) and (b), for the control periods in 2009, 2010, 2011, 
2012, 2013, and 2014.
    (b) By July 31, 2011 and July 31 of each year thereafter, the 
Administrator will determine by order the CAIR NOX Ozone 
Season allowance allocations, in accordance with Sec. 97.342(a) and 
(b), for the control period in the fourth year after the year of the 
applicable deadline for determination under this paragraph.
    (c) By April 30, 2009 and April 30 of each year thereafter, the 
Administrator will determine by order the CAIR NOX Ozone 
Season allowance allocations, in accordance with Sec. 97.342(a), (c), 
and (d), for the control period in the year of the applicable deadline 
for determination under this paragraph.
    (d) The Administrator will make available to the public each 
determination of CAIR NOX Ozone Season allowances under 
paragraph (a), (b), or (c) of this section and will provide an 
opportunity for submission of objections to the determination. 
Objections shall be limited to addressing whether the determination is 
in accordance with Sec. 97.342. Based on any such objections, the 
Administrator will adjust each determination to the extent necessary to 
ensure that it is in accordance with Sec. 97.342.



Sec. 97.342  CAIR NOX Ozone Season allowance allocations.

    (a)(1) The baseline heat input (in mmBtu) used with respect to CAIR 
NOX Ozone Season allowance allocations under paragraph (b) of 
this section for each CAIR NOX Ozone Season unit will be:
    (i) For units commencing operation before January 1, 2001 the 
average of the 3 highest amounts of the unit's adjusted control period 
heat input for 2000 through 2004, with the adjusted control period heat 
input for each year calculated as follows:
    (A) If the unit is coal-fired during the year, the unit's control 
period heat input for such year is multiplied by 100 percent;
    (B) If the unit is oil-fired during the year, the unit's control 
period heat input for such year is multiplied by 60 percent; and
    (C) If the unit is not subject to paragraph (a)(1)(i)(A) or (B) of 
this section, the unit's control period heat input for such year is 
multiplied by 40 percent.
    (ii) For units commencing operation on or after January 1, 2001 and 
operating each calendar year during a period of 5 or more consecutive 
calendar years, the average of the 3 highest amounts of the unit's total 
converted control period heat input over the first such 5 years.
    (2)(i) A unit's control period heat input, and a unit's status as 
coal-fired or oil-fired, for a calendar year under paragraph (a)(1)(i) 
of this section, and a unit's total tons of NOX emissions 
during a control period in a calendar year under paragraph (c)(3) of 
this section, will be determined in accordance with part 75 of this 
chapter, to the extent the unit was otherwise subject to the 
requirements of part 75 of this chapter for the year, or will be based 
on the best available data reported to the Administrator for the unit 
(in a format prescribed by the Administrator), to the extent the unit 
was not otherwise subject to the requirements of part 75 of this chapter 
for the year.
    (ii) A unit's converted control period heat input for a calendar 
year specified under paragraph (a)(1)(ii) of this section equals:
    (A) Except as provided in paragraph (a)(2)(ii)(B) or (C) of this 
section, the control period gross electrical output of the generator or 
generators served by the unit multiplied by 7,900 Btu/kWh, if the unit 
is coal-fired for the year, or 6,675 Btu/kWh, if the unit is not coal-
fired for the year, and divided by 1,000,000 Btu/mmBtu, provided that if 
a generator is served by 2 or more units, then the gross electrical 
output of the generator will be attributed to

[[Page 321]]

each unit in proportion to the unit's share of the total control period 
heat input of such units for the year;
    (B) For a unit that is a boiler and has equipment used to produce 
electricity and useful thermal energy for industrial, commercial, 
heating, or cooling purposes through the sequential use of energy, the 
total heat energy (in Btu) of the steam produced by the boiler during 
the control period, divided by 0.8 and by 1,000,000 Btu/mmBtu; or
    (C) For a unit that is a combustion turbine and has equipment used 
to produce electricity and useful thermal energy for industrial, 
commercial, heating, or cooling purposes through the sequential use of 
energy, the control period gross electrical output of the enclosed 
device comprising the compressor, combustor, and turbine multiplied by 
3,413 Btu/kWh, plus the total heat energy (in Btu) of the steam produced 
by any associated heat recovery steam generator during the control 
period divided by 0.8, and with the sum divided by 1,000,000 Btu/mmBtu.
    (iii) Gross electrical output and total heat energy under paragraph 
(a)(2)(ii) of this section will be determined based on the best 
available data reported to the Administrator for the unit (in a format 
prescribed by the Administrator).
    (3) The Administrator will determine what data are the best 
available data under paragraph (a)(2) of this section by weighing the 
likelihood that data are accurate and reliable and giving greater weight 
to data submitted to a governmental entity in compliance with legal 
requirements or substantiated by an independent entity.
    (b)(1) For each control period in 2009 and thereafter, the 
Administrator will allocate to all CAIR NOX Ozone Season 
units in a State that have a baseline heat input (as determined under 
paragraph (a) of this section) a total amount of CAIR NOX 
Ozone Season allowances equal to 95 percent for a control period during 
2009 through 2014, and 97 percent for a control period during 2015 and 
thereafter, of the tons of NOX emissions in the applicable 
State trading budget under Sec. 97.340 (except as provided in 
paragraphs (d) and (e) of this section).
    (2) The Administrator will allocate CAIR NOX Ozone Season 
allowances to each CAIR NOX Ozone Season unit under paragraph 
(b)(1) of this section in an amount determined by multiplying the total 
amount of CAIR NOX Ozone Season allowances allocated under 
paragraph (b)(1) of this section by the ratio of the baseline heat input 
of such CAIR NOX Ozone Season unit to the total amount of 
baseline heat input of all such CAIR NOX Ozone Season units 
in the State and rounding to the nearest whole allowance as appropriate.
    (c) For each control period in 2009 and thereafter, the 
Administrator will allocate CAIR NOX Ozone Season allowances 
to CAIR NOX Ozone Season units in a State that are not 
allocated CAIR NOX Ozone Season allowances under paragraph 
(b) of this section because the units do not yet have a baseline heat 
input under paragraph (a) of this section or because the units have a 
baseline heat input but all CAIR NOX Ozone Season allowances 
available under paragraph (b) of this section for the control period are 
already allocated, in accordance with the following procedures:
    (1) The Administrator will establish a separate new unit set-aside 
for each control period. Each new unit set-aside will be allocated CAIR 
NOX Ozone Season allowances equal to 5 percent for a control 
period in 2009 through 2014, and 3 percent for a control period in 2015 
and thereafter, of the amount of tons of NOX emissions in the 
applicable State trading budget under Sec. 97.340.
    (2) The CAIR designated representative of such a CAIR NOX 
Ozone Season unit may submit to the Administrator a request, in a format 
specified by the Administrator, to be allocated CAIR NOX 
Ozone Season allowances, starting with the later of the control period 
in 2009 or the first control period after the control period in which 
the CAIR NOX Ozone Season unit commences commercial operation 
and until the first control period for which the unit is allocated CAIR 
NOX Ozone Season allowances under paragraph (b) of this 
section. A separate CAIR NOX Ozone Season allowance 
allocation request for each control period for which CAIR NOX 
Ozone Season allowances are sought must be submitted on or before

[[Page 322]]

February 1 before such control period and after the date on which the 
CAIR NOX Ozone Season unit commences commercial operation.
    (3) In a CAIR NOX Ozone Season allowance allocation 
request under paragraph (c)(2) of this section, the CAIR designated 
representative may request for a control period CAIR NOX 
Ozone Season allowances in an amount not exceeding the CAIR 
NOX Ozone Season unit(s total tons of NOX 
emissions during the control period immediately before such control 
period.
    (4) The Administrator will review each CAIR NOX Ozone 
Season allowance allocation request under paragraph (c)(2) of this 
section and will allocate CAIR NOX Ozone Season allowances 
for each control period pursuant to such request as follows:
    (i) The Administrator will accept an allowance allocation request 
only if the request meets, or is adjusted by the Administrator as 
necessary to meet, the requirements of paragraphs (c)(2) and (3) of this 
section.
    (ii) On or after February 1 before the control period, the 
Administrator will determine the sum of the CAIR NOX Ozone 
Season allowances requested (as adjusted under paragraph (c)(4)(i) of 
this section) in all allowance allocation requests accepted under 
paragraph (c)(4)(i) of this section for the control period.
    (iii) If the amount of CAIR NOX Ozone Season allowances 
in the new unit set-aside for the control period is greater than or 
equal to the sum under paragraph (c)(4)(ii) of this section, then the 
Administrator will allocate the amount of CAIR NOX Ozone 
Season allowances requested (as adjusted under paragraph (c)(4)(i) of 
this section) to each CAIR NOX Ozone Season unit covered by 
an allowance allocation request accepted under paragraph (c)(4)(i) of 
this section.
    (iv) If the amount of CAIR NOX Ozone Season allowances in 
the new unit set-aside for the control period is less than the sum under 
paragraph (c)(4)(ii) of this section, then the Administrator will 
allocate to each CAIR NOX Ozone Season unit covered by an 
allowance allocation request accepted under paragraph (c)(4)(i) of this 
section the amount of the CAIR NOX Ozone Season allowances 
requested (as adjusted under paragraph (c)(4)(i) of this section), 
multiplied by the amount of CAIR NOX Ozone Season allowances 
in the new unit set-aside for the control period, divided by the sum 
determined under paragraph (c)(4)(ii) of this section, and rounded to 
the nearest whole allowance as appropriate.
    (v) The Administrator will notify each CAIR designated 
representative that submitted an allowance allocation request of the 
amount of CAIR NOX Ozone Season allowances (if any) allocated 
for the control period to the CAIR NOX Ozone Season unit 
covered by the request.
    (d) If, after completion of the procedures under paragraph (c)(4) of 
this section for a control period, any unallocated CAIR NOX 
Ozone Season allowances remain in the new unit set-aside under paragraph 
(c) of this section for a State for the control period, the 
Administrator will allocate to each CAIR NOX Ozone Season 
unit that was allocated CAIR NOX Ozone Season allowances 
under paragraph (b) of this section in the State an amount of CAIR 
NOX Ozone Season allowances equal to the total amount of such 
remaining unallocated CAIR NOX Ozone Season allowances, 
multiplied by the unit's allocation under paragraph (b) of this section, 
divided by 95 percent for a control period during 2009 through 2014, and 
97 percent for a control period during 2015 and thereafter, of the 
amount of tons of NOX emissions in the applicable State 
trading budget under Sec. 97.340, and rounded to the nearest whole 
allowance as appropriate.
    (e) If the Administrator determines that CAIR NOX Ozone 
Season allowances were allocated under paragraphs (a) and (b) of this 
section, paragraphs (a) and (c) of this section, or paragraph (d) of 
this section for a control period and that the recipient of the 
allocation is not actually a CAIR NOX Ozone Season unit under 
Sec. 97.304 in such control period, then the Administrator will notify 
the CAIR designated representative and will act in accordance with the 
following procedures:
    (1) Except as provided in paragraph (e)(2) or (3) of this section, 
the Administrator will not record such CAIR NOX Ozone Season 
allowances under Sec. 97.353.

[[Page 323]]

    (2) If the Administrator already recorded such CAIR NOX 
Ozone Season allowances under Sec. 97.353 and if the Administrator 
makes such determinations before making deductions for the source that 
includes such recipient under Sec. 97.354(b) for the control period, 
then the Administrator will deduct from the account in which such CAIR 
NOX Ozone Season allowances were recorded under Sec. 97.353 
an amount of CAIR NOX Ozone Season allowances allocated for 
the same or a prior control period equal to the amount of such already 
recorded CAIR NOX Ozone Season allowances. The CAIR 
designated representative shall ensure that there are sufficient CAIR 
NOX Ozone Season allowances in such account for completion of 
the deduction.
    (3) If the Administrator already recorded such CAIR NOX 
Ozone Season allowances under Sec. 97.353 and if the Administrator 
makes such determinations after making deductions for the source that 
includes such recipient under Sec. 97.354(b) for the control period, 
then the Administrator will apply paragraph (e)(1) or (2) of this 
section, as appropriate, to any subsequent control period for which CAIR 
NOX Ozone Season allowances were allocated to such recipient.
    (4) The Administrator will transfer the CAIR NOX Ozone 
Season allowances that are not recorded, or that are deducted, in 
accordance with paragraphs (e)(1), (2), and (3) of this section to a new 
unit set-aside for the State in which such recipient is located.



Sec. 97.343  Alternative of allocation of CAIR NOX Ozone Season 
allowances by permitting authority.

    (a) Notwithstanding Sec. Sec. 97.341, 97.342, and 97.353 if a State 
submits, and the Administrator approves, a State implementation plan 
revision in accordance with Sec. 51.123(ee)(2) of this chapter 
providing for allocation of CAIR NOX Ozone Season allowances 
by the permitting authority, then the permitting authority shall make 
such allocations in accordance with such approved State implementation 
plan revision, the Administrator will not make allocations under 
Sec. Sec. 97.341 and 97.342 for the CAIR NOX Ozone Season 
units in the State, and under Sec. 97.353, the Administrator will 
record allocations made under such approved State implementation plan 
revision instead of allocations under Sec. Sec. 97.341 and 97.342.
    (b) In implementing paragraph (a) of this section and Sec. Sec. 
97.341, 97.342, and 97.353, the Administrator will ensure that the total 
amount of CAIR NOX Ozone Season allowances allocated, under 
such provisions and under a State's State implementation plan revision 
approved in accordance with Sec. 51.123(ee)(2) of this chapter, for a 
control period for CAIR NOX Ozone Season sources in the State 
or for other entities specified by the permitting authority will not 
exceed the State's State trading budget for the year of the control 
period.



 Sec. Appendix A to Subpart EEEE of Part 97--States With Approved State 
          Implementation Plan Revisions Concerning Allocations

    The following States have State Implementation Plan revisions under 
Sec. 51.123(ee)(2) of this chapter approved by the Administrator and 
providing for allocation of CAIR NOX Ozone Season allowances 
by the permitting authority under Sec. 97.343(a):

Indiana
Louisiana
Michigan
New Jersey
North Carolina
Ohio
South Carolina
Tennessee
West Virginia (for control periods 2009-2014)
Wisconsin

[65 FR 2727, Jan. 18, 2000, as amended at 72 FR 46394, Aug. 20, 2007; 72 
FR 52293, Sept. 13, 2007; 72 FR 55068, Sept. 28, 2007; 72 FR 55659, 
55672, Oct. 1, 2007; 72 FR 56920, Oct. 5, 2007; 72 FR 57215, Oct. 9, 
2007; 72 FR 58546, Oct. 16, 2007; 72 FR 59487, Oct. 22, 2007; 72 FR 
71579, Dec. 18, 2007; 72 FR 72263, Dec. 20, 2007; 73 FR 6041, Feb. 1, 
2008]



      Subpart FFFF_CAIR NOX Ozone Season Allowance Tracking System



Sec. 97.350  [Reserved]



Sec. 97.351  Establishment of accounts.

    (a) Compliance accounts. Except as provided in Sec. 97.384(e), upon 
receipt of a complete certificate of representation under Sec. 97.313, 
the Administrator will establish a compliance account for the

[[Page 324]]

CAIR NOX Ozone Season source for which the certificate of 
representation was submitted, unless the source already has a compliance 
account.
    (b) General accounts--(1) Application for general account. (i) Any 
person may apply to open a general account for the purpose of holding 
and transferring CAIR NOX Ozone Season allowances. An 
application for a general account may designate one and only one CAIR 
authorized account representative and one and only one alternate CAIR 
authorized account representative who may act on behalf of the CAIR 
authorized account representative. The agreement by which the alternate 
CAIR authorized account representative is selected shall include a 
procedure for authorizing the alternate CAIR authorized account 
representative to act in lieu of the CAIR authorized account 
representative.
    (ii) A complete application for a general account shall be submitted 
to the Administrator and shall include the following elements in a 
format prescribed by the Administrator:
    (A) Name, mailing address, e-mail address (if any), telephone 
number, and facsimile transmission number (if any) of the CAIR 
authorized account representative and any alternate CAIR authorized 
account representative;
    (B) Organization name and type of organization, if applicable;
    (C) A list of all persons subject to a binding agreement for the 
CAIR authorized account representative and any alternate CAIR authorized 
account representative to represent their ownership interest with 
respect to the CAIR NOX Ozone Season allowances held in the 
general account;
    (D) The following certification statement by the CAIR authorized 
account representative and any alternate CAIR authorized account 
representative: ``I certify that I was selected as the CAIR authorized 
account representative or the alternate CAIR authorized account 
representative, as applicable, by an agreement that is binding on all 
persons who have an ownership interest with respect to CAIR 
NOX Ozone Season allowances held in the general account. I 
certify that I have all the necessary authority to carry out my duties 
and responsibilities under the CAIR NOX Ozone Season Trading 
Program on behalf of such persons and that each such person shall be 
fully bound by my representations, actions, inactions, or submissions 
and by any order or decision issued to me by the Administrator or a 
court regarding the general account.''
    (E) The signature of the CAIR authorized account representative and 
any alternate CAIR authorized account representative and the dates 
signed.
    (iii) Unless otherwise required by the permitting authority or the 
Administrator, documents of agreement referred to in the application for 
a general account shall not be submitted to the permitting authority or 
the Administrator. Neither the permitting authority nor the 
Administrator shall be under any obligation to review or evaluate the 
sufficiency of such documents, if submitted.
    (2) Authorization of CAIR authorized account representative and 
alternate CAIR authorized account representative. (i) Upon receipt by 
the Administrator of a complete application for a general account under 
paragraph (b)(1) of this section:
    (A) The Administrator will establish a general account for the 
person or persons for whom the application is submitted.
    (B) The CAIR authorized account representative and any alternate 
CAIR authorized account representative for the general account shall 
represent and, by his or her representations, actions, inactions, or 
submissions, legally bind each person who has an ownership interest with 
respect to CAIR NOX Ozone Season allowances held in the 
general account in all matters pertaining to the CAIR NOX 
Ozone Season Trading Program, notwithstanding any agreement between the 
CAIR authorized account representative or any alternate CAIR authorized 
account representative and such person. Any such person shall be bound 
by any order or decision issued to the CAIR authorized account 
representative or any alternate CAIR authorized account representative 
by the Administrator or a court regarding the general account.
    (C) Any representation, action, inaction, or submission by any 
alternate

[[Page 325]]

CAIR authorized account representative shall be deemed to be a 
representation, action, inaction, or submission by the CAIR authorized 
account representative.
    (ii) Each submission concerning the general account shall be 
submitted, signed, and certified by the CAIR authorized account 
representative or any alternate CAIR authorized account representative 
for the persons having an ownership interest with respect to CAIR 
NOX Ozone Season allowances held in the general account. Each 
such submission shall include the following certification statement by 
the CAIR authorized account representative or any alternate CAIR 
authorized account representative: ``I am authorized to make this 
submission on behalf of the persons having an ownership interest with 
respect to the CAIR NOX Ozone Season allowances held in the 
general account. I certify under penalty of law that I have personally 
examined, and am familiar with, the statements and information submitted 
in this document and all its attachments. Based on my inquiry of those 
individuals with primary responsibility for obtaining the information, I 
certify that the statements and information are to the best of my 
knowledge and belief true, accurate, and complete. I am aware that there 
are significant penalties for submitting false statements and 
information or omitting required statements and information, including 
the possibility of fine or imprisonment.''
    (iii) The Administrator will accept or act on a submission 
concerning the general account only if the submission has been made, 
signed, and certified in accordance with paragraph (b)(2)(ii) of this 
section.
    (3) Changing CAIR authorized account representative and alternate 
CAIR authorized account representative; changes in persons with 
ownership interest. (i) The CAIR authorized account representative for a 
general account may be changed at any time upon receipt by the 
Administrator of a superseding complete application for a general 
account under paragraph (b)(1) of this section. Notwithstanding any such 
change, all representations, actions, inactions, and submissions by the 
previous CAIR authorized account representative before the time and date 
when the Administrator receives the superseding application for a 
general account shall be binding on the new CAIR authorized account 
representative and the persons with an ownership interest with respect 
to the CAIR NOX Ozone Season allowances in the general 
account.
    (ii) The alternate CAIR authorized account representative for a 
general account may be changed at any time upon receipt by the 
Administrator of a superseding complete application for a general 
account under paragraph (b)(1) of this section. Notwithstanding any such 
change, all representations, actions, inactions, and submissions by the 
previous alternate CAIR authorized account representative before the 
time and date when the Administrator receives the superseding 
application for a general account shall be binding on the new alternate 
CAIR authorized account representative and the persons with an ownership 
interest with respect to the CAIR NOX Ozone Season allowances 
in the general account.
    (iii)(A) In the event a person having an ownership interest with 
respect to CAIR NOX Ozone Season allowances in the general 
account is not included in the list of such persons in the application 
for a general account, such person shall be deemed to be subject to and 
bound by the application for a general account, the representation, 
actions, inactions, and submissions of the CAIR authorized account 
representative and any alternate CAIR authorized account representative 
of the account, and the decisions and orders of the Administrator or a 
court, as if the person were included in such list.
    (B) Within 30 days following any change in the persons having an 
ownership interest with respect to CAIR NOX Ozone Season 
allowances in the general account, including the addition of a new 
person, the CAIR authorized account representative or any alternate CAIR 
authorized account representative shall submit a revision to the 
application for a general account amending the list of persons having an 
ownership interest with respect to the CAIR NOX Ozone Season 
allowances in the general account to include the change.

[[Page 326]]

    (4) Objections concerning CAIR authorized account representative and 
alternate CAIR authorized account representative. (i) Once a complete 
application for a general account under paragraph (b)(1) of this section 
has been submitted and received, the Administrator will rely on the 
application unless and until a superseding complete application for a 
general account under paragraph (b)(1) of this section is received by 
the Administrator.
    (ii) Except as provided in paragraph (b)(3)(i) or (ii) of this 
section, no objection or other communication submitted to the 
Administrator concerning the authorization, or any representation, 
action, inaction, or submission of the CAIR authorized account 
representative or any alternate CAIR authorized account representative 
for a general account shall affect any representation, action, inaction, 
or submission of the CAIR authorized account representative or any 
alternate CAIR authorized account representative or the finality of any 
decision or order by the Administrator under the CAIR NOX 
Ozone Season Trading Program.
    (iii) The Administrator will not adjudicate any private legal 
dispute concerning the authorization or any representation, action, 
inaction, or submission of the CAIR authorized account representative or 
any alternate CAIR authorized account representative for a general 
account, including private legal disputes concerning the proceeds of 
CAIR NOX Ozone Season allowance transfers.
    (5) Delegation by CAIR authorized account representative and 
alternate CAIR authorized account representative. (i) A CAIR authorized 
account representative may delegate, to one or more natural persons, his 
or her authority to make an electronic submission to the Administrator 
provided for or required under subparts FFFF and GGGG of this part.
    (ii) An alternate CAIR authorized account representative may 
delegate, to one or more natural persons, his or her authority to make 
an electronic submission to the Administrator provided for or required 
under subparts FFFF and GGGG of this part.
    (iii) In order to delegate authority to make an electronic 
submission to the Administrator in accordance with paragraph (b)(5)(i) 
or (ii) of this section, the CAIR authorized account representative or 
alternate CAIR authorized account representative, as appropriate, must 
submit to the Administrator a notice of delegation, in a format 
prescribed by the Administrator, that includes the following elements:
    (A) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of such CAIR authorized account 
representative or alternate CAIR authorized account representative;
    (B) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of each such natural person 
(referred to as an ``agent'');
    (C) For each such natural person, a list of the type or types of 
electronic submissions under paragraph (b)(5)(i) or (ii) of this section 
for which authority is delegated to him or her;
    (D) The following certification statement by such CAIR authorized 
account representative or alternate CAIR authorized account 
representative: ``I agree that any electronic submission to the 
Administrator that is by an agent identified in this notice of 
delegation and of a type listed for such agent in this notice of 
delegation and that is made when I am a CAIR authorized account 
representative or alternate CAIR authorized representative, as 
appropriate, and before this notice of delegation is superseded by 
another notice of delegation under 40 CFR 97.351(b)(5)(iv) shall be 
deemed to be an electronic submission by me.''; and
    (E) The following certification statement by such CAIR authorized 
account representative or alternate CAIR authorized account 
representative: Until this notice of delegation is superseded by another 
notice of delegation under 40 CFR 97.351(b)(5)(iv), I agree to maintain 
an e-mail account and to notify the Administrator immediately of any 
change in my e-mail address unless all delegation of authority by me 
under 40 CFR 97.351(b)(5) is terminated.''.
    (iv) A notice of delegation submitted under paragraph (b)(5)(iii) of 
this section shall be effective, with regard to

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the CAIR authorized account representative or alternate CAIR authorized 
account representative identified in such notice, upon receipt of such 
notice by the Administrator and until receipt by the Administrator of a 
superseding notice of delegation submitted by such CAIR authorized 
account representative or alternate CAIR authorized account 
representative, as appropriate. The superseding notice of delegation may 
replace any previously identified agent, add a new agent, or eliminate 
entirely any delegation of authority.
    (v) Any electronic submission covered by the certification in 
paragraph (b)(5)(iii)(D) of this section and made in accordance with a 
notice of delegation effective under paragraph (b)(5)(iv) of this 
section shall be deemed to be an electronic submission by the CAIR 
designated representative or alternate CAIR designated representative 
submitting such notice of delegation.
    (c) Account identification. The Administrator will assign a unique 
identifying number to each account established under paragraph (a) or 
(b) of this section.



Sec. 97.352  Responsibilities of CAIR authorized account representative.

    Following the establishment of a CAIR NOX Ozone Season 
Allowance Tracking System account, all submissions to the Administrator 
pertaining to the account, including, but not limited to, submissions 
concerning the deduction or transfer of CAIR NOX Ozone Season 
allowances in the account, shall be made only by the CAIR authorized 
account representative for the account.



Sec. 97.353  Recordation of CAIR NOX Ozone Season allowance allocations.

    (a) By September 30, 2007, the Administrator will record in the CAIR 
NOX Ozone Season sources compliance account the CAIR 
NOX Ozone Season allowances allocated for the CAIR 
NOX Ozone Season units at the source in accordance with Sec. 
97.342(a) and (b) for the control period in 2009.
    (b) By September 30, 2008, the Administrator will record in the CAIR 
NOX Ozone Season source's compliance account the CAIR 
NOX Ozone Season allowances allocated for the CAIR 
NOX Ozone Season units at the source in accordance with Sec. 
97.342(a) and (b) for the control period in 2010.
    (c) By September 30, 2009, the Administrator will record in the CAIR 
NOX Ozone Season source's compliance account the CAIR Ozone 
Season NOX allowances allocated for the CAIR NOX 
Ozone Season units at the source in accordance with Sec. 97.342(a) and 
(b) for the control periods in 2011, 2012, and 2013.
    (d) By December 1, 2010 and December 1 of each year thereafter, the 
Administrator will record in the CAIR NOX Ozone Season 
source's compliance account the CAIR NOX Ozone Season 
allowances allocated for the CAIR NOX Ozone Season units at 
the source in accordance with Sec. 97.342(a) and (b) for the control 
period in the fourth year after the year of the applicable deadline for 
recordation under this paragraph.
    (e) By September 1, 2009 and September 1 of each year thereafter, 
the Administrator will record in the CAIR NOX Ozone Season 
source's compliance account the CAIR NOX Ozone Season 
allowances allocated for the CAIR NOX Ozone Season units at 
the source in accordance with Sec. 97.342(a) and (c) for the control 
period in the year of the applicable deadline for recordation under this 
paragraph.
    (f) Serial numbers for allocated CAIR NOX Ozone Season allowances. 
When recording the allocation of CAIR NOX Ozone Season 
allowances for a CAIR NOX Ozone Season unit in a compliance 
account, the Administrator will assign each CAIR NOX Ozone 
Season allowance a unique identification number that will include digits 
identifying the year of the control period for which the CAIR 
NOX Ozone Season allowance is allocated.



Sec. 97.354  Compliance with CAIR NOX emissions limitation.

    (a) Allowance transfer deadline. The CAIR NOX Ozone 
Season allowances are available to be deducted for compliance with a 
source's CAIR NOX Ozone Season emissions limitation for a 
control period in a given calendar year only if the CAIR NOX 
Ozone Season allowances:
    (1) Were allocated for the control period in the year or a prior 
year; and

[[Page 328]]

    (2) Are held in the compliance account as of the allowance transfer 
deadline for the control period or are transferred into the compliance 
account by a CAIR NOX Ozone Season allowance transfer 
correctly submitted for recordation under Sec. Sec. 97.360 and 97.361 
by the allowance transfer deadline for the control period.
    (b) Deductions for compliance. Following the recordation, in 
accordance with Sec. 97.361, of CAIR NOX Ozone Season 
allowance transfers submitted for recordation in a source's compliance 
account by the allowance transfer deadline for a control period, the 
Administrator will deduct from the compliance account CAIR 
NOX Ozone Season allowances available under paragraph (a) of 
this section in order to determine whether the source meets the CAIR 
NOX Ozone Season emissions limitation for the control period, 
as follows:
    (1) Until the amount of CAIR NOX Ozone Season allowances 
deducted equals the number of tons of total nitrogen oxides emissions, 
determined in accordance with subpart HHHH of this part, from all CAIR 
NOX Ozone Season units at the source for the control period; 
or
    (2) If there are insufficient CAIR NOX Ozone Season 
allowances to complete the deductions in paragraph (b)(1) of this 
section, until no more CAIR NOX Ozone Season allowances 
available under paragraph (a) of this section remain in the compliance 
account.
    (c)(1) Identification of CAIR NOX Ozone Season allowances by serial 
number. The CAIR authorized account representative for a source's 
compliance account may request that specific CAIR NOX Ozone 
Season allowances, identified by serial number, in the compliance 
account be deducted for emissions or excess emissions for a control 
period in accordance with paragraph (b) or (d) of this section. Such 
request shall be submitted to the Administrator by the allowance 
transfer deadline for the control period and include, in a format 
prescribed by the Administrator, the identification of the CAIR 
NOX Ozone Season source and the appropriate serial numbers.
    (2) First-in, first-out. The Administrator will deduct CAIR 
NOX Ozone Season allowances under paragraph (b) or (d) of 
this section from the source's compliance account, in the absence of an 
identification or in the case of a partial identification of CAIR 
NOX Ozone Season allowances by serial number under paragraph 
(c)(1) of this section, on a first-in, first-out (FIFO) accounting basis 
in the following order:
    (i) Any CAIR NOX Ozone Season allowances that were 
allocated to the units at the source, in the order of recordation; and 
then
    (ii) Any CAIR NOX Ozone Season allowances that were 
allocated to any entity and transferred and recorded in the compliance 
account pursuant to subpart GGGG of this part, in the order of 
recordation.
    (d) Deductions for excess emissions. (1) After making the deductions 
for compliance under paragraph (b) of this section for a control period 
in a calendar year in which the CAIR NOX Ozone Season source 
has excess emissions, the Administrator will deduct from the source's 
compliance account an amount of CAIR NOX Ozone Season 
allowances, allocated for the control period in the immediately 
following calendar year, equal to 3 times the number of tons of the 
source's excess emissions.
    (2) Any allowance deduction required under paragraph (d)(1) of this 
section shall not affect the liability of the owners and operators of 
the CAIR NOX Ozone Season source or the CAIR NOX 
Ozone Season units at the source for any fine, penalty, or assessment, 
or their obligation to comply with any other remedy, for the same 
violations, as ordered under the Clean Air Act or applicable State law.
    (e) Recordation of deductions. The Administrator will record in the 
appropriate compliance account all deductions from such an account under 
paragraphs (b) and (d) of this section and subpart IIII.
    (f) Administrator(s action on submissions. (1) The Administrator may 
review and conduct independent audits concerning any submission under 
the CAIR NOX Ozone Season Trading Program and make 
appropriate adjustments of the information in the submissions.
    (2) The Administrator may deduct CAIR NOX Ozone Season 
allowances

[[Page 329]]

from or transfer CAIR NOX Ozone Season allowances to a 
source's compliance account based on the information in the submissions, 
as adjusted under paragraph (f)(1) of this section, and record such 
deductions and transfers.



Sec. 97.355  Banking.

    (a) CAIR NOX Ozone Season allowances may be banked for 
future use or transfer in a compliance account or a general account in 
accordance with paragraph (b) of this section.
    (b) Any CAIR NOX Ozone Season allowance that is held in a 
compliance account or a general account will remain in such account 
unless and until the CAIR NOX Ozone Season allowance is 
deducted or transferred under Sec. 97.342, Sec. 97.354, Sec. 97.356, 
or subpart GGGG or IIII of this part.



Sec. 97.356  Account error.

    The Administrator may, at his or her sole discretion and on his or 
her own motion, correct any error in any CAIR NOX Ozone 
Season Allowance Tracking System account. Within 10 business days of 
making such correction, the Administrator will notify the CAIR 
authorized account representative for the account.



Sec. 97.357  Closing of general accounts.

    (a) The CAIR authorized account representative of a general account 
may submit to the Administrator a request to close the account, which 
shall include a correctly submitted allowance transfer under Sec. Sec. 
97.360 and 97.361 for any CAIR NOX Ozone Season allowances in 
the account to one or more other CAIR NOX Ozone Season 
Allowance Tracking System accounts.
    (b) If a general account has no allowance transfers in or out of the 
account for a 12-month period or longer and does not contain any CAIR 
NOX Ozone Season allowances, the Administrator may notify the 
CAIR authorized account representative for the account that the account 
will be closed following 20 business days after the notice is sent. The 
account will be closed after the 20-day period unless, before the end of 
the 20-day period, the Administrator receives a correctly submitted 
transfer of CAIR NOX Ozone Season allowances into the account 
under Sec. Sec. 97.360 and 97.361 or a statement submitted by the CAIR 
authorized account representative demonstrating to the satisfaction of 
the Administrator good cause as to why the account should not be closed.



         Subpart GGGG_CAIR NOX Ozone Season Allowance Transfers



Sec. 97.360  Submission of CAIR NOX Ozone Season allowance transfers.

    A CAIR authorized account representative seeking recordation of a 
CAIR NOX Ozone Season allowance transfer shall submit the 
transfer to the Administrator. To be considered correctly submitted, the 
CAIR NOX Ozone Season allowance transfer shall include the 
following elements, in a format specified by the Administrator:
    (a) The account numbers for both the transferor and transferee 
accounts;
    (b) The serial number of each CAIR NOX Ozone Season 
allowance that is in the transferor account and is to be transferred; 
and
    (c) The name and signature of the CAIR authorized account 
representative of the transferor account and the date signed.



Sec. 97.361  EPA recordation.

    (a) Within 5 business days (except as provided in paragraph (b) of 
this section) of receiving a CAIR NOX Ozone Season allowance 
transfer, the Administrator will record a CAIR NOX Ozone 
Season allowance transfer by moving each CAIR NOX Ozone 
Season allowance from the transferor account to the transferee account 
as specified by the request, provided that:
    (1) The transfer is correctly submitted under Sec. 97.360; and
    (2) The transferor account includes each CAIR NOX Ozone 
Season allowance identified by serial number in the transfer.
    (b) A CAIR NOX Ozone Season allowance transfer that is 
submitted for recordation after the allowance transfer deadline for a 
control period and that includes any CAIR NOX Ozone Season 
allowances allocated for any control period before such allowance 
transfer deadline will not be recorded until after the Administrator 
completes the deductions under Sec. 97.354 for the control

[[Page 330]]

period immediately before such allowance transfer deadline.
    (c) Where a CAIR NOX Ozone Season allowance transfer 
submitted for recordation fails to meet the requirements of paragraph 
(a) of this section, the Administrator will not record such transfer.



Sec. 97.362  Notification.

    (a) Notification of recordation. Within 5 business days of 
recordation of a CAIR NOX Ozone Season allowance transfer 
under Sec. 97.361, the Administrator will notify the CAIR authorized 
account representatives of both the transferor and transferee accounts.
    (b) Notification of non-recordation. Within 10 business days of 
receipt of a CAIR NOX Ozone Season allowance transfer that 
fails to meet the requirements of Sec. 97.361(a), the Administrator 
will notify the CAIR authorized account representatives of both accounts 
subject to the transfer of:
    (1) A decision not to record the transfer, and
    (2) The reasons for such non-recordation.
    (c) Nothing in this section shall preclude the submission of a CAIR 
NOX Ozone Season allowance transfer for recordation following 
notification of non-recordation.



                  Subpart HHHH_Monitoring and Reporting



Sec. 97.370  General requirements.

    The owners and operators, and to the extent applicable, the CAIR 
designated representative, of a CAIR NOX Ozone Season unit, 
shall comply with the monitoring, recordkeeping, and reporting 
requirements as provided in this subpart and in subpart H of part 75 of 
this chapter. For purposes of complying with such requirements, the 
definitions in Sec. 97.302 and in Sec. 72.2 of this chapter shall 
apply, and the terms ``affected unit,'' ``designated representative,'' 
and ``continuous emission monitoring system'' (or ``CEMS'') in part 75 
of this chapter shall be deemed to refer to the terms ``CAIR 
NOX Ozone Season unit,'' ``CAIR designated representative,'' 
and ``continuous emission monitoring system'' (or ``CEMS'') 
respectively, as defined in Sec. 97.302. The owner or operator of a 
unit that is not a CAIR NOX Ozone Season unit but that is 
monitored under Sec. 75.72(b)(2)(ii) of this chapter shall comply with 
the same monitoring, recordkeeping, and reporting requirements as a CAIR 
NOX Ozone Season unit.
    (a) Requirements for installation, certification, and data 
accounting. The owner or operator of each CAIR NOX Ozone 
Season unit shall:
    (1) Install all monitoring systems required under this subpart for 
monitoring NOX mass emissions and individual unit heat input 
(including all systems required to monitor NOX emission rate, 
NOX concentration, stack gas moisture content, stack gas flow 
rate, CO2 or O2 concentration, and fuel flow rate, 
as applicable, in accordance with Sec. Sec. 75.71 and 75.72 of this 
chapter);
    (2) Successfully complete all certification tests required under 
Sec. 97.371 and meet all other requirements of this subpart and part 75 
of this chapter applicable to the monitoring systems under paragraph 
(a)(1) of this section; and
    (3) Record, report, and quality-assure the data from the monitoring 
systems under paragraph (a)(1) of this section.
    (b) Compliance deadlines. Except as provided in paragraph (e) of 
this section, the owner or operator shall meet the monitoring system 
certification and other requirements of paragraphs (a)(1) and (2) of 
this section on or before the following dates. The owner or operator 
shall record, report, and quality-assure the data from the monitoring 
systems under paragraph (a)(1) of this section on and after the 
following dates.
    (1) For the owner or operator of a CAIR NOX Ozone Season 
unit that commences commercial operation before July 1, 2007, by May 1, 
2008.
    (2) For the owner or operator of a CAIR NOX Ozone Season 
unit that commences commercial operation on or after July 1, 2007 and 
that reports on an annual basis under Sec. 97.374(d), by the later of 
the following dates:
    (i) 90 unit operating days or 180 calendar days, whichever occurs 
first, after the date on which the unit commences commercial operation; 
or
    (ii) May 1, 2008.

[[Page 331]]

    (3) For the owner or operator of a CAIR NOX Ozone Season 
unit that commences commercial operation on or after July 1, 2007 and 
that reports on a control period basis under Sec. 97.374(d)(2)(ii), by 
the later of the following dates:
    (i) 90 unit operating days or 180 calendar days, whichever occurs 
first, after the date on which the unit commences commercial operation; 
or
    (ii) If the compliance date under paragraph (b)(3)(i) of this 
section is not during a control period, May 1 immediately following the 
compliance date under paragraph (b)(3)(i) of this section.
    (4) For the owner or operator of a CAIR NOX Ozone Season 
unit for which construction of a new stack or flue or installation of 
add-on NOX emission controls is completed after the 
applicable deadline under paragraph (b)(1), (2), (6), or (7) of this 
section and that reports on an annual basis under Sec. 97.374(d), by 90 
unit operating days or 180 calendar days, whichever occurs first, after 
the date on which emissions first exit to the atmosphere through the new 
stack or flue or add-on NOX emissions controls.
    (5) For the owner or operator of a CAIR NOX Ozone Season 
unit for which construction of a new stack or flue or installation of 
add-on NOX emission controls is completed after the 
applicable deadline under paragraph (b)(1), (3), (6), or (7) of this 
section and that reports on a control period basis under Sec. 
97.374(d)(2)(ii), by the later of the following dates:
    (i) 90 unit operating days or 180 calendar days, whichever occurs 
first, after the date on which emissions first exit to the atmosphere 
through the new stack or flue or add-on NOX emissions 
controls; or
    (ii) If the compliance date under paragraph (b)(5)(i) of this 
section is not during a control period, May 1 immediately following the 
compliance date under paragraph (b)(5)(i) of this section.
    (6) Notwithstanding the dates in paragraphs (b)(1), (2), and (3) of 
this section, for the owner or operator of a unit for which a CAIR 
NOX Ozone Season opt-in permit application is submitted and 
not withdrawn and a CAIR opt-in permit is not yet issued or denied under 
subpart IIII of this part, by the date specified in Sec. 97.384(b).
    (7) Notwithstanding the dates in paragraphs (b)(1), (2), and (3) of 
this section, for the owner or operator of a CAIR NOX Ozone 
Season opt-in unit under subpart IIII of this part, by the date on which 
the CAIR NOX Ozone Season opt-in unit enters the CAIR 
NOX Ozone Season Trading Program as provided in Sec. 
97.384(g).
    (c) Reporting data. The owner or operator of a CAIR NOX 
Ozone Season unit that does not meet the applicable compliance date set 
forth in paragraph (b) of this section for any monitoring system under 
paragraph (a)(1) of this section shall, for each such monitoring system, 
determine, record, and report maximum potential (or, as appropriate, 
minimum potential) values for NOX concentration, 
NOX emission rate, stack gas flow rate, stack gas moisture 
content, fuel flow rate, and any other parameters required to determine 
NOX mass emissions and heat input in accordance with Sec. 
75.31(b)(2) or (c)(3) of this chapter, section 2.4 of appendix D to part 
75 of this chapter, or section 2.5 of appendix E to part 75 of this 
chapter, as applicable.
    (d) Prohibitions. (1) No owner or operator of a CAIR NOX 
Ozone Season unit shall use any alternative monitoring system, 
alternative reference method, or any other alternative to any 
requirement of this subpart without having obtained prior written 
approval in accordance with Sec. 97.375.
    (2) No owner or operator of a CAIR NOX Ozone Season unit 
shall operate the unit so as to discharge, or allow to be discharged, 
NOX emissions to the atmosphere without accounting for all 
such emissions in accordance with the applicable provisions of this 
subpart and part 75 of this chapter.
    (3) No owner or operator of a CAIR NOX Ozone Season unit 
shall disrupt the continuous emission monitoring system, any portion 
thereof, or any other approved emission monitoring method, and thereby 
avoid monitoring and recording NOX mass emissions discharged 
into the atmosphere or heat input, except for periods of recertification 
or periods when calibration,

[[Page 332]]

quality assurance testing, or maintenance is performed in accordance 
with the applicable provisions of this subpart and part 75 of this 
chapter.
    (4) No owner or operator of a CAIR NOX Ozone Season unit 
shall retire or permanently discontinue use of the continuous emission 
monitoring system, any component thereof, or any other approved 
monitoring system under this subpart, except under any one of the 
following circumstances:
    (i) During the period that the unit is covered by an exemption under 
Sec. 97.305 that is in effect;
    (ii) The owner or operator is monitoring emissions from the unit 
with another certified monitoring system approved, in accordance with 
the applicable provisions of this subpart and part 75 of this chapter, 
by the Administrator for use at that unit that provides emission data 
for the same pollutant or parameter as the retired or discontinued 
monitoring system; or
    (iii) The CAIR designated representative submits notification of the 
date of certification testing of a replacement monitoring system for the 
retired or discontinued monitoring system in accordance with Sec. 
97.371(d)(3)(i).
    (e) Long-term cold storage. The owner or operator of a CAIR 
NOX Ozone Season unit is subject to the applicable provisions 
of part 75 of this chapter concerning units in long-term cold storage.



Sec. 97.371  Initial certification and recertification procedures.

    (a) The owner or operator of a CAIR NOX Ozone Season unit 
shall be exempt from the initial certification requirements of this 
section for a monitoring system under Sec. 97.370(a)(1) if the 
following conditions are met:
    (1) The monitoring system has been previously certified in 
accordance with part 75 of this chapter; and
    (2) The applicable quality-assurance and quality-control 
requirements of Sec. 75.21 of this chapter and appendix B, appendix D, 
and appendix E to part 75 of this chapter are fully met for the 
certified monitoring system described in paragraph (a)(1) of this 
section.
    (b) The recertification provisions of this section shall apply to a 
monitoring system under Sec. 97.370(a)(1) exempt from initial 
certification requirements under paragraph (a) of this section.
    (c) If the Administrator has previously approved a petition under 
Sec. 75.17(a) or (b) of this chapter for apportioning the 
NOX emission rate measured in a common stack or a petition 
under Sec. 75.66 of this chapter for an alternative to a requirement in 
Sec. 75.12 or Sec. 75.17 of this chapter, the CAIR designated 
representative shall resubmit the petition to the Administrator under 
Sec. 97.375 to determine whether the approval applies under the CAIR 
NOX Ozone Season Trading Program.
    (d) Except as provided in paragraph (a) of this section, the owner 
or operator of a CAIR NOX Ozone Season unit shall comply with 
the following initial certification and recertification procedures for a 
continuous monitoring system (i.e., a continuous emission monitoring 
system and an excepted monitoring system under appendices D and E to 
part 75 of this chapter) under Sec. 97.370(a)(1). The owner or operator 
of a unit that qualifies to use the low mass emissions excepted 
monitoring methodology under Sec. 75.19 of this chapter or that 
qualifies to use an alternative monitoring system under subpart E of 
part 75 of this chapter shall comply with the procedures in paragraph 
(e) or (f) of this section respectively.
    (1) Requirements for initial certification. The owner or operator 
shall ensure that each continuous monitoring system under Sec. 
97.370(a)(1) (including the automated data acquisition and handling 
system) successfully completes all of the initial certification testing 
required under Sec. 75.20 of this chapter by the applicable deadline in 
Sec. 97.370(b). In addition, whenever the owner or operator installs a 
monitoring system to meet the requirements of this subpart in a location 
where no such monitoring system was previously installed, initial 
certification in accordance with Sec. 75.20 of this chapter is 
required.
    (2) Requirements for recertification. Whenever the owner or operator 
makes a replacement, modification, or change in any certified continuous 
emission monitoring system under Sec. 97.370(a)(1) that may 
significantly affect the ability of the system to accurately measure or 
record NOX mass emissions or

[[Page 333]]

heat input rate or to meet the quality-assurance and quality-control 
requirements of Sec. 75.21 of this chapter or appendix B to part 75 of 
this chapter, the owner or operator shall recertify the monitoring 
system in accordance with Sec. 75.20(b) of this chapter. Furthermore, 
whenever the owner or operator makes a replacement, modification, or 
change to the flue gas handling system or the unit's operation that may 
significantly change the stack flow or concentration profile, the owner 
or operator shall recertify each continuous emission monitoring system 
whose accuracy is potentially affected by the change, in accordance with 
Sec. 75.20(b) of this chapter. Examples of changes to a continuous 
emission monitoring system that require recertification include: 
replacement of the analyzer, complete replacement of an existing 
continuous emission monitoring system, or change in location or 
orientation of the sampling probe or site. Any fuel flowmeter systems, 
and any excepted NOX monitoring system under appendix E to 
part 75 of this chapter, under Sec. 97.370(a)(1) are subject to the 
recertification requirements in Sec. 75.20(g)(6) of this chapter.
    (3) Approval process for initial certification and recertification. 
Paragraphs (d)(3)(i) through (iv) of this section apply to both initial 
certification and recertification of a continuous monitoring system 
under Sec. 97.370(a)(1). For recertifications, replace the words 
``certification'' and ``initial certification'' with the word 
``recertification'', replace the word ``certified'' with the word 
``recertified,'' and follow the procedures in Sec. Sec. 75.20(b)(5) and 
(g)(7) of this chapter in lieu of the procedures in paragraph (d)(3)(v) 
of this section.
    (i) Notification of certification. The CAIR designated 
representative shall submit to the appropriate EPA Regional Office and 
the Administrator written notice of the dates of certification testing, 
in accordance with Sec. 97.373.
    (ii) Certification application. The CAIR designated representative 
shall submit to the Administrator a certification application for each 
monitoring system. A complete certification application shall include 
the information specified in Sec. 75.63 of this chapter.
    (iii) Provisional certification date. The provisional certification 
date for a monitoring system shall be determined in accordance with 
Sec. 75.20(a)(3) of this chapter. A provisionally certified monitoring 
system may be used under the CAIR NOX Ozone Season Trading 
Program for a period not to exceed 120 days after receipt by the 
Administrator of the complete certification application for the 
monitoring system under paragraph (d)(3)(ii) of this section. Data 
measured and recorded by the provisionally certified monitoring system, 
in accordance with the requirements of part 75 of this chapter, will be 
considered valid quality-assured data (retroactive to the date and time 
of provisional certification), provided that the Administrator does not 
invalidate the provisional certification by issuing a notice of 
disapproval within 120 days of the date of receipt of the complete 
certification application by the Administrator.
    (iv) Certification application approval process. The Administrator 
will issue a written notice of approval or disapproval of the 
certification application to the owner or operator within 120 days of 
receipt of the complete certification application under paragraph 
(d)(3)(ii) of this section. In the event the Administrator does not 
issue such a notice within such 120-day period, each monitoring system 
that meets the applicable performance requirements of part 75 of this 
chapter and is included in the certification application will be deemed 
certified for use under the CAIR NOX Ozone Season Trading 
Program.
    (A) Approval notice. If the certification application is complete 
and shows that each monitoring system meets the applicable performance 
requirements of part 75 of this chapter, then the Administrator will 
issue a written notice of approval of the certification application 
within 120 days of receipt.
    (B) Incomplete application notice. If the certification application 
is not complete, then the Administrator will issue a written notice of 
incompleteness that sets a reasonable date by

[[Page 334]]

which the CAIR designated representative must submit the additional 
information required to complete the certification application. If the 
CAIR designated representative does not comply with the notice of 
incompleteness by the specified date, then the Administrator may issue a 
notice of disapproval under paragraph (d)(3)(iv)(C) of this section. The 
120-day review period shall not begin before receipt of a complete 
certification application.
    (C) Disapproval notice. If the certification application shows that 
any monitoring system does not meet the performance requirements of part 
75 of this chapter or if the certification application is incomplete and 
the requirement for disapproval under paragraph (d)(3)(iv)(B) of this 
section is met, then the Administrator will issue a written notice of 
disapproval of the certification application. Upon issuance of such 
notice of disapproval, the provisional certification is invalidated by 
the Administrator and the data measured and recorded by each uncertified 
monitoring system shall not be considered valid quality-assured data 
beginning with the date and hour of provisional certification (as 
defined under Sec. 75.20(a)(3) of this chapter). The owner or operator 
shall follow the procedures for loss of certification in paragraph 
(d)(3)(v) of this section for each monitoring system that is disapproved 
for initial certification.
    (D) Audit decertification. The Administrator may issue a notice of 
disapproval of the certification status of a monitor in accordance with 
Sec. 97.372(b).
    (v) Procedures for loss of certification. If the Administrator 
issues a notice of disapproval of a certification application under 
paragraph (d)(3)(iv)(C) of this section or a notice of disapproval of 
certification status under paragraph (d)(3)(iv)(D) of this section, 
then:
    (A) The owner or operator shall substitute the following values, for 
each disapproved monitoring system, for each hour of unit operation 
during the period of invalid data specified under Sec. 
75.20(a)(4)(iii), Sec. 75.20(g)(7), or Sec. 75.21(e) of this chapter 
and continuing until the applicable date and hour specified under Sec. 
75.20(a)(5)(i) or (g)(7) of this chapter:
    (1) For a disapproved NOX emission rate (i.e., 
NOX-diluent) system, the maximum potential NOX 
emission rate, as defined in (72.2 of this chapter.
    (2) For a disapproved NOX pollutant concentration monitor 
and disapproved flow monitor, respectively, the maximum potential 
concentration of NOX and the maximum potential flow rate, as 
defined in sections 2.1.2.1 and 2.1.4.1 of appendix A to part 75 of this 
chapter.
    (3) For a disapproved moisture monitoring system and disapproved 
diluent gas monitoring system, respectively, the minimum potential 
moisture percentage and either the maximum potential CO2 
concentration or the minimum potential O2 concentration (as 
applicable), as defined in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of 
appendix A to part 75 of this chapter.
    (4) For a disapproved fuel flowmeter system, the maximum potential 
fuel flow rate, as defined in section 2.4.2.1 of appendix D to part 75 
of this chapter.
    (5) For a disapproved excepted NOX monitoring system 
under appendix E to part 75 of this chapter, the fuel-specific maximum 
potential NOX emission rate, as defined in (72.2 of this 
chapter.
    (B) The CAIR designated representative shall submit a notification 
of certification retest dates and a new certification application in 
accordance with paragraphs (d)(3)(i) and (ii) of this section.
    (C) The owner or operator shall repeat all certification tests or 
other requirements that were failed by the monitoring system, as 
indicated in the Administrator's notice of disapproval, no later than 30 
unit operating days after the date of issuance of the notice of 
disapproval.
    (e) Initial certification and recertification procedures for units 
using the low mass emission excepted methodology under Sec. 75.19 of 
this chapter. The owner or operator of a unit qualified to use the low 
mass emissions (LME) excepted methodology under Sec. 75.19 of this 
chapter shall meet the applicable certification and recertification 
requirements in Sec. Sec. 75.19(a)(2) and 75.20(h) of this chapter. If 
the owner or operator of such a unit elects to certify a fuel flowmeter 
system for heat input determination, the owner or operator shall

[[Page 335]]

also meet the certification and recertification requirements in Sec. 
75.20(g) of this chapter.
    (f) Certification/recertification procedures for alternative 
monitoring systems. The CAIR designated representative of each unit for 
which the owner or operator intends to use an alternative monitoring 
system approved by the Administrator under subpart E of part 75 of this 
chapter shall comply with the applicable notification and application 
procedures of Sec. 75.20(f) of this chapter.

[65 FR 2727, Jan. 18, 2000, as amended at 71 FR 74795, Dec. 13, 2006]



Sec. 97.372  Out of control periods.

    (a) Whenever any monitoring system fails to meet the quality-
assurance and quality-control requirements or data validation 
requirements of part 75 of this chapter, data shall be substituted using 
the applicable missing data procedures in subpart D or subpart H of, or 
appendix D or appendix E to, part 75 of this chapter.
    (b) Audit decertification. Whenever both an audit of a monitoring 
system and a review of the initial certification or recertification 
application reveal that any monitoring system should not have been 
certified or recertified because it did not meet a particular 
performance specification or other requirement under Sec. 97.371 or the 
applicable provisions of part 75 of this chapter, both at the time of 
the initial certification or recertification application submission and 
at the time of the audit, the Administrator will issue a notice of 
disapproval of the certification status of such monitoring system. For 
the purposes of this paragraph, an audit shall be either a field audit 
or an audit of any information submitted to the permitting authority or 
the Administrator. By issuing the notice of disapproval, the 
Administrator revokes prospectively the certification status of the 
monitoring system. The data measured and recorded by the monitoring 
system shall not be considered valid quality-assured data from the date 
of issuance of the notification of the revoked certification status 
until the date and time that the owner or operator completes 
subsequently approved initial certification or recertification tests for 
the monitoring system. The owner or operator shall follow the applicable 
initial certification or recertification procedures in Sec. 97.371 for 
each disapproved monitoring system.



Sec. 97.373  Notifications.

    The CAIR designated representative for a CAIR NOX Ozone 
Season unit shall submit written notice to the Administrator in 
accordance with Sec. 75.61 of this chapter.



Sec. 97.374  Recordkeeping and reporting.

    (a) General provisions. The CAIR designated representative shall 
comply with all recordkeeping and reporting requirements in this 
section, the applicable recordkeeping and reporting requirements under 
Sec. 75.73 of this chapter, and the requirements of Sec. 97.310(e)(1).
    (b) Monitoring Plans. The owner or operator of a CAIR NOX 
Ozone Season unit shall comply with requirements of Sec. 75.73 (c) and 
(e) of this chapter and, for a unit for which a CAIR opt-in permit 
application is submitted and not withdrawn and a CAIR opt-in permit is 
not yet issued or denied under subpart IIII of this part, Sec. Sec. 
97.383 and 97.384(a).
    (c) Certification Applications. The CAIR designated representative 
shall submit an application to the Administrator within 45 days after 
completing all initial certification or recertification tests required 
under Sec. 97.371, including the information required under Sec. 75.63 
of this chapter.
    (d) Quarterly reports. The CAIR designated representative shall 
submit quarterly reports, as follows:
    (1) If the CAIR NOX Ozone Season unit is subject to an 
Acid Rain emissions limitation or a CAIR NOX emissions 
limitation or if the owner or operator of such unit chooses to report on 
an annual basis under this subpart, the CAIR designated representative 
shall meet the requirements of subpart H of part 75 of this chapter 
(concerning monitoring of NOX mass emissions) for such unit 
for the entire year and shall report the NOX mass emissions 
data and heat input data for such unit, in an electronic quarterly 
report in a format prescribed by the Administrator, for each calendar 
quarter beginning with:

[[Page 336]]

    (i) For a unit that commences commercial operation before July 1, 
2007, the calendar quarter covering May 1, 2008 through June 30, 2008;
    (ii) For a unit that commences commercial operation on or after July 
1, 2007, the calendar quarter corresponding to the earlier of the date 
of provisional certification or the applicable deadline for initial 
certification under Sec. 97.370(b), unless that quarter is the third or 
fourth quarter of 2007 or the first quarter of 2008, in which case 
reporting shall commence in the quarter covering May 1, 2008 through 
June 30, 2008;
    (iii) Notwithstanding paragraphs (d)(1) (i) and (ii) of this 
section, for a unit for which a CAIR opt-in permit application is 
submitted and not withdrawn and a CAIR opt-in permit is not yet issued 
or denied under subpart IIII of this part, the calendar quarter 
corresponding to the date specified in Sec. 97.384(b); and
    (iv) Notwithstanding paragraphs (d)(1) (i) and (ii) of this section, 
for a CAIR NOX Ozone Season opt-in unit under subpart IIII of 
this part, the calendar quarter corresponding to the date on which the 
CAIR NOX Ozone Season opt-in unit enters the CAIR 
NOX Ozone Season Trading Program as provided in Sec. 
97.384(g).
    (2) If the CAIR NOX Ozone Season unit is not subject to 
an Acid Rain emissions limitation or a CAIR NOX emissions 
limitation, then the CAIR designated representative shall either:
    (i) Meet the requirements of subpart H of part 75 (concerning 
monitoring of NOX mass emissions) for such unit for the 
entire year and report the NOX mass emissions data and heat 
input data for such unit in accordance with paragraph (d)(1) of this 
section; or
    (ii) Meet the requirements of subpart H of part 75 for the control 
period (including the requirements in Sec. 75.74(c) of this chapter) 
and report NOX mass emissions data and heat input data 
(including the data described in Sec. 75.74(c)(6) of this chapter) for 
such unit only for the control period of each year and report, in an 
electronic quarterly report in a format prescribed by the Administrator, 
for each calendar quarter beginning with:
    (A) For a unit that commences commercial operation before July 1, 
2007, the calendar quarter covering May 1, 2008 through June 30, 2008;
    (B) For a unit that commences commercial operation on or after July 
1, 2007, the calendar quarter corresponding to the earlier of the date 
of provisional certification or the applicable deadline for initial 
certification under Sec. 97.370(b), unless that date is not during a 
control period, in which case reporting shall commence in the quarter 
that includes May 1 through June 30 of the first control period after 
such date;
    (C) Notwithstanding paragraphs (d)(2)(ii)(A) and (2)(ii)(B) of this 
section, for a unit for which a CAIR opt-in permit application is 
submitted and not withdrawn and a CAIR opt-in permit is not yet issued 
or denied under subpart IIII of this part, the calendar quarter 
corresponding to the date specified in Sec. 97.384(b); and
    (D) Notwithstanding paragraphs (d)(2)(ii)(A) and (2)(ii)(B) of this 
section, for a CAIR NOX Ozone Season opt-in unit under 
subpart IIII of this part, the calendar quarter corresponding to the 
date on which the CAIR NOX Ozone Season opt-in unit enters 
the CAIR NOX Ozone Season Trading Program as provided in 
Sec. 97.384(g).
    (3) The CAIR designated representative shall submit each quarterly 
report to the Administrator within 30 days following the end of the 
calendar quarter covered by the report. Quarterly reports shall be 
submitted in the manner specified in Sec. 75.73(f) of this chapter.
    (4) For CAIR NOX Ozone Season units that are also subject 
to an Acid Rain emissions limitation or the CAIR NOX Annual 
Trading Program, CAIR SO2 Trading Program, or Hg Budget 
Trading Program, quarterly reports shall include the applicable data and 
information required by subparts F through I of part 75 of this chapter 
as applicable, in addition to the NOX mass emission data, 
heat input data, and other information required by this subpart.
    (e) Compliance certification. The CAIR designated representative 
shall submit to the Administrator a compliance certification (in a 
format prescribed by the Administrator) in support of each quarterly 
report based on reasonable

[[Page 337]]

inquiry of those persons with primary responsibility for ensuring that 
all of the unit's emissions are correctly and fully monitored. The 
certification shall state that:
    (1) The monitoring data submitted were recorded in accordance with 
the applicable requirements of this subpart and part 75 of this chapter, 
including the quality assurance procedures and specifications;
    (2) For a unit with add-on NOX emission controls and for 
all hours where NOX data are substituted in accordance with 
Sec. 75.34(a)(1) of this chapter, the add-on emission controls were 
operating within the range of parameters listed in the quality 
assurance/quality control program under appendix B to part 75 of this 
chapter and the substitute data values do not systematically 
underestimate NOX emissions; and
    (3) For a unit that is reporting on a control period basis under 
paragraph (d)(2)(ii) of this section, the NOX emission rate 
and NOX concentration values substituted for missing data 
under subpart D of part 75 of this chapter are calculated using only 
values from a control period and do not systematically underestimate 
NOX emissions.



Sec. 97.375  Petitions.

    The CAIR designated representative of a CAIR NOX Ozone 
Season unit may submit a petition under Sec. 75.66 of this chapter to 
the Administrator requesting approval to apply an alternative to any 
requirement of this subpart. Application of an alternative to any 
requirement of this subpart is in accordance with this subpart only to 
the extent that the petition is approved in writing by the 
Administrator, in consultation with the permitting authority.



             Subpart IIII_CAIR NOX Ozone Season Opt-in Units



Sec. 97.380  Applicability.

    A CAIR NOX Ozone Season opt-in unit must be a unit that:
    (a) Is located in a State that submits, and for which the 
Administrator approves, a State implementation plan revision in 
accordance with Sec. 51.123(ee)(3) (i), (ii), or (iii) of this chapter 
establishing procedures concerning CAIR Ozone Season opt-in units;
    (b) Is not a CAIR NOX Ozone Season unit under Sec. 
97.304 and is not covered by a retired unit exemption under Sec. 97.305 
that is in effect;
    (c) Is not covered by a retired unit exemption under Sec. 72.8 of 
this chapter that is in effect;
    (d) Has or is required or qualified to have a title V operating 
permit or other federally enforceable permit; and
    (e) Vents all of its emissions to a stack and can meet the 
monitoring, recordkeeping, and reporting requirements of subpart HHHH of 
this part.



Sec. 97.381  General.

    (a) Except as otherwise provided in Sec. Sec. 97.301 through 
97.304, Sec. Sec. 97.306 through 97.308, and subparts BBBB and CCCC and 
subparts FFFF through HHHH of this part, a CAIR NOX Ozone 
Season opt-in unit shall be treated as a CAIR NOX Ozone 
Season unit for purposes of applying such sections and subparts of this 
part.
    (b) Solely for purposes of applying, as provided in this subpart, 
the requirements of subpart HHHH of this part to a unit for which a CAIR 
opt-in permit application is submitted and not withdrawn and a CAIR opt-
in permit is not yet issued or denied under this subpart, such unit 
shall be treated as a CAIR NOX Ozone Season unit before 
issuance of a CAIR opt-in permit for such unit.



Sec. 97.382  CAIR designated representative.

    Any CAIR NOX Ozone Season opt-in unit, and any unit for 
which a CAIR opt-in permit application is submitted and not withdrawn 
and a CAIR opt-in permit is not yet issued or denied under this subpart, 
located at the same source as one or more CAIR NOX Ozone 
Season units shall have the same CAIR designated representative and 
alternate CAIR designated representative as such CAIR NOX 
Ozone Season units.



Sec. 97.383  Applying for CAIR opt-in permit.

    (a) Applying for initial CAIR opt-in permit. The CAIR designated 
representative of a unit meeting the requirements for a CAIR 
NOX Ozone Season opt-in unit in Sec. 97.380 may apply for an 
initial

[[Page 338]]

CAIR opt-in permit at any time, except as provided under Sec. 97.386 
(f) and (g), and, in order to apply, must submit the following:
    (1) A complete CAIR permit application under Sec. 97.322;
    (2) A certification, in a format specified by the permitting 
authority, that the unit:
    (i) Is not a CAIR NOX Ozone Season unit under Sec. 
97.304 and is not covered by a retired unit exemption under Sec. 97.305 
that is in effect;
    (ii) Is not covered by a retired unit exemption under Sec. 72.8 of 
this chapter that is in effect;
    (iii) Vents all of its emissions to a stack; and
    (iv) Has documented heat input for more than 876 hours during the 6 
months immediately preceding submission of the CAIR permit application 
under Sec. 97.322;
    (3) A monitoring plan in accordance with subpart HHHH of this part;
    (4) A complete certificate of representation under Sec. 97.313 
consistent with Sec. 97.382, if no CAIR designated representative has 
been previously designated for the source that includes the unit; and
    (5) A statement, in a format specified by the permitting authority, 
whether the CAIR designated representative requests that the unit be 
allocated CAIR NOX Ozone Season allowances under Sec. 
97.380(b) or Sec. 97.388(c) (subject to the conditions in Sec. Sec. 
97.384(h) and 97.386(g)), to the extent such allocation is provided in a 
State implementation plan revision submitted in accordance with Sec. 
51.123(ee)(3)(i), (ii), or (iii) of this chapter and approved by the 
Administrator. If allocation under Sec. 97.388(c) is requested, this 
statement shall include a statement that the owners and operators intend 
to repower the unit before January 1, 2015 and that they will provide, 
upon request, documentation demonstrating such intent.
    (b) Duty to reapply. (1) The CAIR designated representative of a 
CAIR NOX Ozone Season opt-in unit shall submit a complete 
CAIR permit application under Sec. 97.322 to renew the CAIR opt-in unit 
permit in accordance with the permitting authority's regulations for 
title V operating permits, or the permitting authority's regulations for 
other federally enforceable permits if applicable, addressing permit 
renewal.
    (2) Unless the permitting authority issues a notification of 
acceptance of withdrawal of the CAIR NOX Ozone Season opt-in 
unit from the CAIR NOX Ozone Season Trading Program in 
accordance with Sec. 97.386 or the unit becomes a CAIR NOX 
Ozone Season unit under Sec. 97.304, the CAIR NOX Ozone 
Season opt-in unit shall remain subject to the requirements for a CAIR 
NOX Ozone Season opt-in unit, even if the CAIR designated 
representative for the CAIR NOX Ozone Season opt-in unit 
fails to submit a CAIR permit application that is required for renewal 
of the CAIR opt-in permit under paragraph (b)(1) of this section.



Sec. 97.384  Opt-in process.

    The permitting authority will issue or deny a CAIR opt-in permit for 
a unit for which an initial application for a CAIR opt-in permit under 
Sec. 97.383 is submitted in accordance with the following, to the 
extent provided in a State implementation plan revision submitted in 
accordance with Sec. 51.123(ee)(3)(i), (ii), or (iii) of this chapter 
and approved by the Administrator:
    (a) Interim review of monitoring plan. The permitting authority and 
the Administrator will determine, on an interim basis, the sufficiency 
of the monitoring plan accompanying the initial application for a CAIR 
opt-in permit under Sec. 97.383. A monitoring plan is sufficient, for 
purposes of interim review, if the plan appears to contain information 
demonstrating that the NOX emissions rate and heat input of 
the unit and all other applicable parameters are monitored and reported 
in accordance with subpart HHHH of this part. A determination of 
sufficiency shall not be construed as acceptance or approval of the 
monitoring plan.
    (b) Monitoring and reporting. (1)(i) If the permitting authority and 
the Administrator determine that the monitoring plan is sufficient under 
paragraph (a) of this section, the owner or operator shall monitor and 
report the NOX emissions rate and the heat input of the unit 
and all other applicable parameters, in accordance with subpart HHHH of 
this part, starting on the date

[[Page 339]]

of certification of the appropriate monitoring systems under subpart 
HHHH of this part and continuing until a CAIR opt-in permit is denied 
under Sec. 97.384(f) or, if a CAIR opt-in permit is issued, the date 
and time when the unit is withdrawn from the CAIR NOX Ozone 
Season Trading Program in accordance with Sec. 97.386.
    (ii) The monitoring and reporting under paragraph (b)(1)(i) of this 
section shall include the entire control period immediately before the 
date on which the unit enters the CAIR NOX Ozone Season 
Trading Program under Sec. 97.384(g), during which period monitoring 
system availability must not be less than 90 percent under subpart HHHH 
of this part and the unit must be in full compliance with any applicable 
State or Federal emissions or emissions-related requirements.
    (2) To the extent the NOX emissions rate and the heat 
input of the unit are monitored and reported in accordance with subpart 
HHHH of this part for one or more control periods, in addition to the 
control period under paragraph (b)(1)(ii) of this section, during which 
control periods monitoring system availability is not less than 90 
percent under subpart HHHH of this part and the unit is in full 
compliance with any applicable State or Federal emissions or emissions-
related requirements and which control periods begin not more than 3 
years before the unit enters the CAIR NOX Ozone Season 
Trading Program under Sec. 97.384(g), such information shall be used as 
provided in paragraphs (c) and (d) of this section.
    (c) Baseline heat input. The unit's baseline heat input shall equal:
    (1) If the unit's NOX emissions rate and heat input are 
monitored and reported for only one control period, in accordance with 
paragraph (b)(1) of this section, the unit's total heat input (in mmBtu) 
for the control period; or
    (2) If the unit's NOX emissions rate and heat input are 
monitored and reported for more than one control period, in accordance 
with paragraphs (b)(1) and (2) of this section, the average of the 
amounts of the unit's total heat input (in mmBtu) for the control 
periods under paragraphs (b)(1)(ii) and (2) of this section.
    (d) Baseline NOX emission rate. The unit's baseline NOX 
emission rate shall equal:
    (1) If the unit's NOX emissions rate and heat input are 
monitored and reported for only one control period, in accordance with 
paragraph (b)(1) of this section, the unit's NOX emissions 
rate (in lb/mmBtu) for the control period;
    (2) If the unit's NOX emissions rate and heat input are 
monitored and reported for more than one control period, in accordance 
with paragraphs (b)(1) and (2) of this section, and the unit does not 
have add-on NOX emission controls during any such control 
periods, the average of the amounts of the unit's NOX 
emissions rate (in lb/mmBtu) for the control periods under paragraphs 
(b)(1)(ii) and (2) of this section; or
    (3) If the unit's NOX emissions rate and heat input are 
monitored and reported for more than one control period, in accordance 
with paragraphs (b)(1) and (2) of this section, and the unit has add-on 
NOX emission controls during any such control periods, the 
average of the amounts of the unit's NOX emissions rate (in 
lb/mmBtu) for such control periods during which the unit has add-on 
NOX emission controls.
    (e) Issuance of CAIR opt-in permit. After calculating the baseline 
heat input and the baseline NOX emissions rate for the unit 
under paragraphs (c) and (d) of this section and if the permitting 
authority determines that the CAIR designated representative shows that 
the unit meets the requirements for a CAIR NOX Ozone Season 
opt-in unit in Sec. 97.380 and meets the elements certified in Sec. 
97.383(a)(2), the permitting authority will issue a CAIR opt-in permit. 
The permitting authority will provide a copy of the CAIR opt-in permit 
to the Administrator, who will then establish a compliance account for 
the source that includes the CAIR NOX Ozone Season opt-in 
unit unless the source already has a compliance account.
    (f) Issuance of denial of CAIR opt-in permit. Notwithstanding 
paragraphs (a) through (e) of this section, if at any time before 
issuance of a CAIR opt-in

[[Page 340]]

permit for the unit, the permitting authority determines that the CAIR 
designated representative fails to show that the unit meets the 
requirements for a CAIR NOX Ozone Season opt-in unit in Sec. 
97.380 or meets the elements certified in Sec. 97.383(a)(2), the 
permitting authority will issue a denial of a CAIR opt-in permit for the 
unit.
    (g) Date of entry into CAIR NOX Ozone Season Trading 
Program. A unit for which an initial CAIR opt-in permit is issued by the 
permitting authority shall become a CAIR NOX Ozone Season 
opt-in unit, and a CAIR NOX Ozone Season unit, as of the 
later of May 1, 2009 or May 1 of the first control period during which 
such CAIR opt-in permit is issued.
    (h) Repowered CAIR NOX Ozone Season opt-in unit. (1) If 
CAIR designated representative requests, and the permitting authority 
issues a CAIR opt-in permit providing for, allocation to a CAIR 
NOX Ozone Season opt-in unit of CAIR NOX Ozone 
Season allowances under Sec. 97.388(c) and such unit is repowered after 
its date of entry into the CAIR NOX Ozone Season Trading 
Program under paragraph (g) of this section, the repowered unit shall be 
treated as a CAIR NOX Ozone Season opt-in unit replacing the 
original CAIR NOX Ozone Season opt-in unit, as of the date of 
start-up of the repowered unit's combustion chamber.
    (2) Notwithstanding paragraphs (c) and (d) of this section, as of 
the date of start-up under paragraph (h)(1) of this section, the 
repowered unit shall be deemed to have the same date of commencement of 
operation, date of commencement of commercial operation, baseline heat 
input, and baseline NOX emission rate as the original CAIR 
NOX Ozone Season opt-in unit, and the original CAIR 
NOX Ozone Season opt-in unit shall no longer be treated as a 
CAIR NOX Ozone Season opt-in unit or a CAIR NOX 
Ozone Season unit.

[65 FR 2727, Jan. 18, 2000, as amended at 71 FR 74795, Dec. 13, 2006]



Sec. 97.385  CAIR opt-in permit contents.

    (a) Each CAIR opt-in permit will contain:
    (1) All elements required for a complete CAIR permit application 
under Sec. 97.322;
    (2) The certification in Sec. 97.383(a)(2);
    (3) The unit's baseline heat input under Sec. 97.384(c);
    (4) The unit's baseline NOX emission rate under Sec. 
97.384(d);
    (5) A statement whether the unit is to be allocated CAIR 
NOX Ozone Season allowances under Sec. 97.388(b) or Sec. 
97.388(c) (subject to the conditions in Sec. Sec. 97.384(h) and 
97.386(g));
    (6) A statement that the unit may withdraw from the CAIR 
NOX Ozone Season Trading Program only in accordance with 
Sec. 97.386; and
    (7) A statement that the unit is subject to, and the owners and 
operators of the unit must comply with, the requirements of Sec. 
97.387.
    (b) Each CAIR opt-in permit is deemed to incorporate automatically 
the definitions of terms under Sec. 97.302 and, upon recordation by the 
Administrator under subpart FFFF or GGGG of this part or this subpart, 
every allocation, transfer, or deduction of CAIR NOX Ozone 
Season allowances to or from the compliance account of the source that 
includes a CAIR NOX Ozone Season opt-in unit covered by the 
CAIR opt-in permit.
    (c) The CAIR opt-in permit shall be included, in a format specified 
by the permitting authority, in the CAIR permit for the source where the 
CAIR NOX Ozone Season opt-in unit is located and in a title V 
operating permit or other federally enforceable permit for the source.



Sec. 97.386  Withdrawal from CAIR NOX Ozone Season Trading Program.

    Except as provided under paragraph (g) of this section, a CAIR 
NOX Ozone Season opt-in unit may withdraw from the CAIR 
NOX Ozone Season Trading Program, but only if the permitting 
authority issues a notification to the CAIR designated representative of 
the CAIR NOX Ozone Season opt-in unit of the acceptance of 
the withdrawal of the CAIR NOX Ozone Season opt-in unit in 
accordance with paragraph (d) of this section.
    (a) Requesting withdrawal. In order to withdraw a CAIR 
NOX Ozone Season opt-in unit from the CAIR NOX 
Ozone Season Trading Program, the CAIR designated representative of the 
CAIR NOX Ozone Season opt-in unit shall

[[Page 341]]

submit to the permitting authority a request to withdraw effective as of 
midnight of September 30 of a specified calendar year, which date must 
be at least 4 years after September 30 of the year of entry into the 
CAIR NOX Ozone Season Trading Program under Sec. 97.384(g). 
The request must be submitted no later than 90 days before the requested 
effective date of withdrawal.
    (b) Conditions for withdrawal. Before a CAIR NOX Ozone 
Season opt-in unit covered by a request under paragraph (a) of this 
section may withdraw from the CAIR NOX Ozone Season Trading 
Program and the CAIR opt-in permit may be terminated under paragraph (e) 
of this section, the following conditions must be met:
    (1) For the control period ending on the date on which the 
withdrawal is to be effective, the source that includes the CAIR 
NOX Ozone Season opt-in unit must meet the requirement to 
hold CAIR NOX Ozone Season allowances under Sec. 97.306(c) 
and cannot have any excess emissions.
    (2) After the requirement for withdrawal under paragraph (b)(1) of 
this section is met, the Administrator will deduct from the compliance 
account of the source that includes the CAIR NOX Ozone Season 
opt-in unit CAIR NOX Ozone Season allowances equal in amount 
to and allocated for the same or a prior control period as any CAIR 
NOX Ozone Season allowances allocated to the CAIR 
NOX Ozone Season opt-in unit under Sec. 97.388 for any 
control period for which the withdrawal is to be effective. If there are 
no remaining CAIR NOX Ozone Season units at the source, the 
Administrator will close the compliance account, and the owners and 
operators of the CAIR NOX Ozone Season opt-in unit may submit 
a CAIR NOX Ozone Season allowance transfer for any remaining 
CAIR NOX Ozone Season allowances to another CAIR 
NOX Ozone Season Allowance Tracking System in accordance with 
subpart GGGG of this part.
    (c) Notification. (1) After the requirements for withdrawal under 
paragraphs (a) and (b) of this section are met (including deduction of 
the full amount of CAIR NOX Ozone Season allowances 
required), the permitting authority will issue a notification to the 
CAIR designated representative of the CAIR NOX Ozone Season 
opt-in unit of the acceptance of the withdrawal of the CAIR 
NOX Ozone Season opt-in unit as of midnight on September 30 
of the calendar year for which the withdrawal was requested.
    (2) If the requirements for withdrawal under paragraphs (a) and (b) 
of this section are not met, the permitting authority will issue a 
notification to the CAIR designated representative of the CAIR 
NOX Ozone Season opt-in unit that the CAIR NOX 
Ozone Season opt-in unit's request to withdraw is denied. Such CAIR 
NOX Ozone Season opt-in unit shall continue to be a CAIR 
NOX Ozone Season opt-in unit.
    (d) Permit amendment. After the permitting authority issues a 
notification under paragraph (c)(1) of this section that the 
requirements for withdrawal have been met, the permitting authority will 
revise the CAIR permit covering the CAIR NOX Ozone Season 
opt-in unit to terminate the CAIR opt-in permit for such unit as of the 
effective date specified under paragraph (c)(1) of this section. The 
unit shall continue to be a CAIR NOX Ozone Season opt-in unit 
until the effective date of the termination and shall comply with all 
requirements under the CAIR NOX Ozone Season Trading Program 
concerning any control periods for which the unit is a CAIR 
NOX Ozone Season opt-in unit, even if such requirements arise 
or must be complied with after the withdrawal takes effect.
    (e) Reapplication upon failure to meet conditions of withdrawal. If 
the permitting authority denies the CAIR NOX Ozone Season 
opt-in unit's request to withdraw, the CAIR designated representative 
may submit another request to withdraw in accordance with paragraphs (a) 
and (b) of this section.
    (f) Ability to reapply to the CAIR NOX Ozone Season Trading Program. 
Once a CAIR NOX Ozone Season opt-in unit withdraws from the 
CAIR NOX Ozone Season Trading Program and its CAIR opt-in 
permit is terminated under this section, the CAIR designated 
representative may not submit another application for a CAIR opt-in 
permit under Sec. 97.383 for such CAIR NOX Ozone Season opt-
in unit before the date that is 4 years after the date on which the

[[Page 342]]

withdrawal became effective. Such new application for a CAIR opt-in 
permit will be treated as an initial application for a CAIR opt-in 
permit under Sec. 97.384.
    (g) Inability to withdraw. Notwithstanding paragraphs (a) through 
(f) of this section, a CAIR NOX Ozone Season opt-in unit 
shall not be eligible to withdraw from the CAIR NOX Ozone 
Season Trading Program if the CAIR designated representative of the CAIR 
NOX Ozone Season opt-in unit requests, and the permitting 
authority issues a CAIR opt-in permit providing for, allocation to the 
CAIR NOX Ozone Season opt-in unit of CAIR NOX 
Ozone Season allowances under Sec. 97.388(c).



Sec. 97.387  Change in regulatory status.

    (a) Notification. If a CAIR NOX Ozone Season opt-in unit 
becomes a CAIR NOX Ozone Season unit under Sec. 97.304, then 
the CAIR designated representative shall notify in writing the 
permitting authority and the Administrator of such change in the CAIR 
NOX Ozone Season opt-in unit's regulatory status, within 30 
days of such change.
    (b) Permitting authority's and Administrator's actions. (1) If a 
CAIR NOX Ozone Season opt-in unit becomes a CAIR 
NOX Ozone Season unit under Sec. 97.304, the permitting 
authority will revise the CAIR NOX Ozone Season opt-in unit's 
CAIR opt-in permit to meet the requirements of a CAIR permit under Sec. 
97.323, and remove the CAIR opt-in permit provisions, as of the date on 
which the CAIR NOX Ozone Season opt-in unit becomes a CAIR 
NOX Ozone Season unit under Sec. 97.304.
    (2)(i) The Administrator will deduct from the compliance account of 
the source that includes the CAIR NOX Ozone Season opt-in 
unit that becomes a CAIR NOX Ozone Season unit under Sec. 
97.304, CAIR NOX Ozone Season allowances equal in amount to 
and allocated for the same or a prior control period as:
    (A) Any CAIR NOX Ozone Season allowances allocated to the 
CAIR NOX Ozone Season opt-in unit under Sec. 97.388 for any 
control period after the date on which the CAIR NOX Ozone 
Season opt-in unit becomes a CAIR NOX Ozone Season unit under 
Sec. 97.304; and
    (B) If the date on which the CAIR NOX Ozone Season opt-in 
unit becomes a CAIR NOX Ozone Season unit under Sec. 97.304 
is not September 30, the CAIR NOX Ozone Season allowances 
allocated to the CAIR NOX Ozone Season opt-in unit under 
Sec. 97.388 for the control period that includes the date on which the 
CAIR NOX Ozone Season opt-in unit becomes a CAIR 
NOX Ozone Season unit under Sec. 97.304, multiplied by the 
ratio of the number of days, in the control period, starting with the 
date on which the CAIR NOX Ozone Season opt-in unit becomes a 
CAIR NOX Ozone Season unit under Sec. 97.304 divided by the 
total number of days in the control period and rounded to the nearest 
whole allowance as appropriate.
    (ii) The CAIR designated representative shall ensure that the 
compliance account of the source that includes the CAIR NOX 
Ozone Season opt-in unit that becomes a CAIR NOX Ozone Season 
unit under Sec. 97.304 contains the CAIR NOX Ozone Season 
allowances necessary for completion of the deduction under paragraph 
(b)(2)(i) of this section.
    (3)(i) For every control period after the date on which the CAIR 
NOX Ozone Season opt-in unit becomes a CAIR NOX 
Ozone Season unit under Sec. 97.304, the CAIR NOX Ozone 
Season opt-in unit will be allocated CAIR NOX Ozone Season 
allowances under Sec. 97.342.
    (ii) If the date on which the CAIR NOX Ozone Season opt-
in unit becomes a CAIR NOX Ozone Season unit under Sec. 
97.304 is not September 30, the following amount of CAIR NOX 
Ozone Season allowances will be allocated to the CAIR NOX 
Ozone Season opt-in unit (as a CAIR NOX Ozone Season unit) 
under Sec. 97.342 for the control period that includes the date on 
which the CAIR NOX Ozone Season opt-in unit becomes a CAIR 
NOX Ozone Season unit under Sec. 97.304:
    (A) The amount of CAIR NOX Ozone Season allowances 
otherwise allocated to the CAIR NOX Ozone Season opt-in unit 
(as a CAIR NOX Ozone Season unit) under Sec. 97.342 for the 
control period multiplied by;
    (B) The ratio of the number of days, in the control period, starting 
with the date on which the CAIR NOX Ozone Season opt-in unit 
becomes a CAIR NOX Ozone Season unit under Sec. 97.304,

[[Page 343]]

divided by the total number of days in the control period; and
    (C) Rounded to the nearest whole allowance as appropriate.

[65 FR 2727, Jan. 18, 2000, as amended at 71 FR 74795, Dec. 13, 2006]



Sec. 97.388  CAIR NOX Ozone Season allowance allocations to CAIR NOX
Ozone Season opt-in units.

    (a) Timing requirements. (1) When the CAIR opt-in permit is issued 
under Sec. 97.384(e), the permitting authority will allocate CAIR 
NOX Ozone Season allowances to the CAIR NOX Ozone 
Season opt-in unit, and submit to the Administrator the allocation for 
the control period in which a CAIR NOX Ozone Season opt-in 
unit enters the CAIR NOX Ozone Season Trading Program under 
Sec. 97.384(g), in accordance with paragraph (b) or (c) of this 
section.
    (2) By no later than July 31 of the control period after the control 
period in which a CAIR NOX Ozone Season opt-in unit enters 
the CAIR NOX Ozone Season Trading Program under Sec. 
97.384(g) and July 31 of each year thereafter, the permitting authority 
will allocate CAIR NOX Ozone Season allowances to the CAIR 
NOX Ozone Season opt-in unit, and submit to the Administrator 
the allocation for the control period that includes such submission 
deadline and in which the unit is a CAIR NOX Ozone Season 
opt-in unit, in accordance with paragraph (b) or (c) of this section.
    (b) Calculation of allocation. For each control period for which a 
CAIR NOX Ozone Season opt-in unit is to be allocated CAIR 
NOX Ozone Season allowances, the permitting authority will 
allocate in accordance with the following procedures, if provided in a 
State implementation plan revision submitted in accordance with Sec. 
51.123(ee)(3)(i), (ii), or (iii) of this chapter and approved by the 
Administrator:
    (1) The heat input (in mmBtu) used for calculating the CAIR 
NOX Ozone Season allowance allocation will be the lesser of:
    (i) The CAIR NOX Ozone Season opt-in unit's baseline heat 
input determined under Sec. 97.384(c); or
    (ii) The CAIR NOX Ozone Season opt-in unit's heat input, 
as determined in accordance with subpart HHHH of this part, for the 
immediately prior control period, except when the allocation is being 
calculated for the control period in which the CAIR NOX Ozone 
Season opt-in unit enters the CAIR NOX Ozone Season Trading 
Program under Sec. 97.384(g).
    (2) The NOX emission rate (in lb/mmBtu) used for 
calculating CAIR NOX Ozone Season allowance allocations will 
be the lesser of:
    (i) The CAIR NOX Ozone Season opt-in unit's baseline 
NOX emissions rate (in lb/mmBtu) determined under Sec. 
97.384(d) and multiplied by 70 percent; or
    (ii) The most stringent State or Federal NOX emissions 
limitation applicable to the CAIR NOX Ozone Season opt-in 
unit at any time during the control period for which CAIR NOX 
Ozone Season allowances are to be allocated.
    (3) The permitting authority will allocate CAIR NOX Ozone 
Season allowances to the CAIR NOX Ozone Season opt-in unit in 
an amount equaling the heat input under paragraph (b)(1) of this 
section, multiplied by the NOX emission rate under paragraph 
(b)(2) of this section, divided by 2,000 lb/ton, and rounded to the 
nearest whole allowance as appropriate.
    (c) Notwithstanding paragraph (b) of this section and if the CAIR 
designated representative requests, and the permitting authority issues 
a CAIR opt-in permit (based on a demonstration of the intent to repower 
stated under Sec. 97.383 (a)(5)) providing for, allocation to a CAIR 
NOX Ozone Season opt-in unit of CAIR NOX Ozone 
Season allowances under this paragraph (subject to the conditions in 
Sec. Sec. 97.384(h) and 97.386(g)), the permitting authority will 
allocate to the CAIR NOX Ozone Season opt-in unit as follows, 
if provided in a State implementation plan revision submitted in 
accordance with Sec. 51.123(ee)(3)(i), (ii), or (iii) of this chapter 
and approved by the Administrator:
    (1) For each control period in 2009 through 2014 for which the CAIR 
NOX Ozone Season opt-in unit is to be allocated CAIR 
NOX Ozone Season allowances,
    (i) The heat input (in mmBtu) used for calculating CAIR 
NOX Ozone Season

[[Page 344]]

allowance allocations will be determined as described in paragraph 
(b)(1) of this section.
    (ii) The NOX emission rate (in lb/mmBtu) used for 
calculating CAIR NOX Ozone Season allowance allocations will 
be the lesser of:
    (A) The CAIR NOX Ozone Season opt-in unit's baseline 
NOX emissions rate (in lb/mmBtu) determined under Sec. 
97.384(d); or
    (B) The most stringent State or Federal NOX emissions 
limitation applicable to the CAIR NOX Ozone Season opt-in 
unit at any time during the control period in which the CAIR 
NOX Ozone Season opt-in unit enters the CAIR NOX 
Ozone Season Trading Program under Sec. 97.384(g).
    (iii) The permitting authority will allocate CAIR NOX 
Ozone Season allowances to the CAIR NOX Ozone Season opt-in 
unit in an amount equaling the heat input under paragraph (c)(1)(i) of 
this section, multiplied by the NOX emission rate under 
paragraph (c)(1)(ii) of this section, divided by 2,000 lb/ton, and 
rounded to the nearest whole allowance as appropriate.
    (2) For each control period in 2015 and thereafter for which the 
CAIR NOX Ozone Season opt-in unit is to be allocated CAIR 
NOX Ozone Season allowances,
    (i) The heat input (in mmBtu) used for calculating the CAIR 
NOX Ozone Season allowance allocations will be determined as 
described in paragraph (b)(1) of this section.
    (ii) The NOX emission rate (in lb/mmBtu) used for 
calculating the CAIR NOX Ozone Season allowance allocation 
will be the lesser of:
    (A) 0.15 lb/mmBtu;
    (B) The CAIR NOX Ozone Season opt-in unit's baseline 
NOX emissions rate (in lb/mmBtu) determined under Sec. 
97.384(d); or
    (C) The most stringent State or Federal NOX emissions 
limitation applicable to the CAIR NOX Ozone Season opt-in 
unit at any time during the control period for which CAIR NOX 
Ozone Season allowances are to be allocated.
    (iii) The permitting authority will allocate CAIR NOX 
Ozone Season allowances to the CAIR NOX Ozone Season opt-in 
unit in an amount equaling the heat input under paragraph (c)(2)(i) of 
this section, multiplied by the NOX emission rate under 
paragraph (c)(2)(ii) of this section, divided by 2,000 lb/ton, and 
rounded to the nearest whole allowance as appropriate.
    (d) Recordation. If provided in a State implementation plan revision 
submitted in accordance with Sec. 51.123(ee)(3)(i), (ii), or (iii) of 
this chapter and approved by the Administrator:
    (1) The Administrator will record, in the compliance account of the 
source that includes the CAIR NOX Ozone Season opt-in unit, 
the CAIR NOX Ozone Season allowances allocated by the 
permitting authority to the CAIR NOX Ozone Season opt-in unit 
under paragraph (a)(1) of this section.
    (2) By September 1 of the control period in which a CAIR 
NOX Ozone Season opt-in unit enters the CAIR NOX 
Ozone Season Trading Program under Sec. 97.384(g) and September 1 of 
each year thereafter, the Administrator will record, in the compliance 
account of the source that includes the CAIR NOX Ozone Season 
opt-in unit, the CAIR NOX Ozone Season allowances allocated 
by the permitting authority to the CAIR NOX Ozone Season opt-
in unit under paragraph (a)(2) of this section.



 Sec. Appendix A to Subpart IIII of Part 97--States With Approved State 
   Implementation Plan Revisions Concerning CAIR NOX Ozone 
                           Season Opt-in Units

    1. The following States have State Implementation Plan revisions 
under Sec. 51.123(ee)(3) of this chapter approved by the Administrator 
and establishing procedures providing for CAIR NOX Ozone 
Season opt-in units under subpart IIII of this part and allocation of 
CAIR NOX Ozone Season allowances to such units under Sec. 
97.388(b):

Indiana
Michigan
North Carolina
Ohio
South Carolina
Tennessee

    2. The following States have State Implementation Plan revisions 
under Sec. 51.123(ee)(3) of this chapter approved by the Administrator 
and establishing procedures providing for CAIR NOX Ozone 
Season opt-in units under subpart IIII of this part and allocation of 
CAIR NOX Ozone Season allowances to such units under Sec. 
97.388(c):

Indiana

[[Page 345]]

Michigan
North Carolina
Ohio
South Carolina
Tennessee

[65 FR 2727, Jan. 18, 2000, as amended at 72 FR 46394, Aug. 20, 2007; 72 
FR 56920, Oct. 5, 2007; 72 FR 57215, Oct. 9, 2007; 72 FR 59487, Oct. 22, 
2007; 72 FR 72263, Dec. 20, 2007; 73 FR 6041, Feb. 1, 2008]



               Subpart AAAAA_TR NOX Annual Trading Program

    Source: 76 FR 48379, Aug. 8, 2011, unless otherwise noted.



Sec. 97.401  Purpose.

    This subpart sets forth the general, designated representative, 
allowance, and monitoring provisions for the Transport Rule (TR) 
NOX Annual Trading Program, under section 110 of the Clean 
Air Act and Sec. 52.38 of this chapter, as a means of mitigating 
interstate transport of fine particulates and nitrogen oxides.



Sec. 97.402  Definitions.

    The terms used in this subpart shall have the meanings set forth in 
this section as follows:
    Acid Rain Program means a multi-state SO2 and 
NOX air pollution control and emission reduction program 
established by the Administrator under title IV of the Clean Air Act and 
parts 72 through 78 of this chapter.
    Administrator means the Administrator of the United States 
Environmental Protection Agency or the Director of the Clean Air Markets 
Division (or its successor determined by the Administrator) of the 
United States Environmental Protection Agency, the Administrator's duly 
authorized representative under this subpart.
    Allocate or allocation means, with regard to TR NOX 
Annual allowances, the determination by the Administrator, State, or 
permitting authority, in accordance with this subpart and any SIP 
revision submitted by the State and approved by the Administrator under 
Sec. 52.38(a)(3), (4), or (5) of this chapter, of the amount of such TR 
NOX Annual allowances to be initially credited, at no cost to 
the recipient, to:
    (1) A TR NOX Annual unit;
    (2) A new unit set-aside;
    (3) An Indian country new unit set-aside; or
    (4) An entity not listed in paragraphs (1) through (3) of this 
definition;
    (5) Provided that, if the Administrator, State, or permitting 
authority initially credits, to a TR NOX Annual unit 
qualifying for an initial credit, a credit in the amount of zero TR 
NOX Annual allowances, the TR NOX Annual unit will 
be treated as being allocated an amount (i.e., zero) of TR 
NOX Annual allowances.
    Allowable NOX emission rate means, for a unit, the most 
stringent State or federal NOX emission rate limit (in lb/
MWhr or, if in lb/mmBtu, converted to lb/MWhr by multiplying it by the 
unit's heat rate in mmBtu/MWhr) that is applicable to the unit and 
covers the longest averaging period not exceeding one year.
    Allowance Management System means the system by which the 
Administrator records allocations, deductions, and transfers of TR 
NOX Annual allowances under the TR NOX Annual 
Trading Program. Such allowances are allocated, recorded, held, 
deducted, or transferred only as whole allowances.
    Allowance Management System account means an account in the 
Allowance Management System established by the Administrator for 
purposes of recording the allocation, holding, transfer, or deduction of 
TR NOX Annual allowances.
    Allowance transfer deadline means, for a control period in a given 
year, midnight of March 1 (if it is a business day), or midnight of the 
first business day thereafter (if March 1 is not a business day), 
immediately after such control period and is the deadline by which a TR 
NOX Annual allowance transfer must be submitted for 
recordation in a TR NOX Annual source's compliance account in 
order to be available for use in complying with the source's TR 
NOX Annual emissions limitation for such control period in 
accordance with Sec. Sec. 97.406 and 97.424.
    Alternate designated representative means, for a TR NOX 
Annual source and each TR NOX Annual unit at the source, the 
natural person who is authorized by the owners and operators of

[[Page 346]]

the source and all such units at the source, in accordance with this 
subpart, to act on behalf of the designated representative in matters 
pertaining to the TR NOX Annual Trading Program. If the TR 
NOX Annual source is also subject to the Acid Rain Program, 
TR NOX Ozone Season Trading Program, TR SO2 Group 
1 Trading Program, or TR SO2 Group 2 Trading Program, then 
this natural person shall be the same natural person as the alternate 
designated representative, as defined in the respective program.
    Assurance account means an Allowance Management System account, 
established by the Administrator under Sec. 97.425(b)(3) for certain 
owners and operators of a group of one or more TR NOX Annual 
sources and units in a given State (and Indian country within the 
borders of such State), in which are held TR NOX Annual 
allowances available for use for a control period in a given year in 
complying with the TR NOX Annual assurance provisions in 
accordance with Sec. Sec. 97.406 and 97.425.
    Authorized account representative means, for a general account, the 
natural person who is authorized, in accordance with this subpart, to 
transfer and otherwise dispose of TR NOX Annual allowances 
held in the general account and, for a TR NOX Annual source's 
compliance account, the designated representative of the source.
    Automated data acquisition and handling system or DAHS means the 
component of the continuous emission monitoring system, or other 
emissions monitoring system approved for use under this subpart, 
designed to interpret and convert individual output signals from 
pollutant concentration monitors, flow monitors, diluent gas monitors, 
and other component parts of the monitoring system to produce a 
continuous record of the measured parameters in the measurement units 
required by this subpart.
    Biomass means--
    (1) Any organic material grown for the purpose of being converted to 
energy;
    (2) Any organic byproduct of agriculture that can be converted into 
energy; or
    (3) Any material that can be converted into energy and is 
nonmerchantable for other purposes, that is segregated from other 
material that is nonmerchantable for other purposes, and that is;
    (i) A forest-related organic resource, including mill residues, 
precommercial thinnings, slash, brush, or byproduct from conversion of 
trees to merchantable material; or
    (ii) A wood material, including pallets, crates, dunnage, 
manufacturing and construction materials (other than pressure-treated, 
chemically-treated, or painted wood products), and landscape or right-
of-way tree trimmings.
    Boiler means an enclosed fossil- or other-fuel-fired combustion 
device used to produce heat and to transfer heat to recirculating water, 
steam, or other medium.
    Bottoming-cycle unit means a unit in which the energy input to the 
unit is first used to produce useful thermal energy, where at least some 
of the reject heat from the useful thermal energy application or process 
is then used for electricity production.
    Business day means a day that does not fall on a weekend or a 
federal holiday.
    Certifying official means a natural person who is:
    (1) For a corporation, a president, secretary, treasurer, or vice-
president of the corporation in charge of a principal business function 
or any other person who performs similar policy- or decision-making 
functions for the corporation;
    (2) For a partnership or sole proprietorship, a general partner or 
the proprietor respectively; or
    (3) For a local government entity or State, federal, or other public 
agency, a principal executive officer or ranking elected official.
    Clean Air Act means the Clean Air Act, 42 U.S.C. 7401, et seq.
    Coal means ``coal'' as defined in Sec. 72.2 of this chapter.
    Coal-derived fuel means any fuel (whether in a solid, liquid, or 
gaseous state) produced by the mechanical, thermal, or chemical 
processing of coal.
    Cogeneration system means an integrated group, at a source, of 
equipment (including a boiler, or combustion turbine, and a steam 
turbine generator)

[[Page 347]]

designed to produce useful thermal energy for industrial, commercial, 
heating, or cooling purposes and electricity through the sequential use 
of energy.
    Cogeneration unit means a stationary, fossil-fuel-fired boiler or 
stationary, fossil-fuel-fired combustion turbine that is a topping-cycle 
unit or a bottoming-cycle unit:
    (1) Operating as part of a cogeneration system; and
    (2) Producing on an annual average basis--
    (i) For a topping-cycle unit,
    (A) Useful thermal energy not less than 5 percent of total energy 
output; and
    (B) Useful power that, when added to one-half of useful thermal 
energy produced, is not less than 42.5 percent of total energy input, if 
useful thermal energy produced is 15 percent or more of total energy 
output, or not less than 45 percent of total energy input, if useful 
thermal energy produced is less than 15 percent of total energy output.
    (ii) For a bottoming-cycle unit, useful power not less than 45 
percent of total energy input;
    (3) Provided that the requirements in paragraph (2) of this 
definition shall not apply to a calendar year referenced in paragraph 
(2) of this definition during which the unit did not operate at all;
    (4) Provided that the total energy input under paragraphs (2)(i)(B) 
and (2)(ii) of this definition shall equal the unit's total energy input 
from all fuel, except biomass if the unit is a boiler; and
    (5) Provided that, if, throughout its operation during the 12-month 
period or a calendar year referenced in paragraph (2) of this 
definition, a unit is operated as part of a cogeneration system and the 
cogeneration system meets on a system-wide basis the requirement in 
paragraph (2)(i)(B) or (2)(ii) of this definition, the unit shall be 
deemed to meet such requirement during that 12-month period or calendar 
year.
    Combustion turbine means an enclosed device comprising:
    (1) If the device is simple cycle, a compressor, a combustor, and a 
turbine and in which the flue gas resulting from the combustion of fuel 
in the combustor passes through the turbine, rotating the turbine; and
    (2) If the device is combined cycle, the equipment described in 
paragraph (1) of this definition and any associated duct burner, heat 
recovery steam generator, and steam turbine.
    Commence commercial operation means, with regard to a unit:
    (1) To have begun to produce steam, gas, or other heated medium used 
to generate electricity for sale or use, including test generation, 
except as provided in Sec. 97.405.
    (i) For a unit that is a TR NOX Annual unit under Sec. 
97.404 on the later of January 1, 2005 or the date the unit commences 
commercial operation as defined in the introductory text of paragraph 
(1) of this definition and that subsequently undergoes a physical change 
or is moved to a new location or source, such date shall remain the date 
of commencement of commercial operation of the unit, which shall 
continue to be treated as the same unit.
    (ii) For a unit that is a TR NOX Annual unit under Sec. 
97.404 on the later of January 1, 2005 or the date the unit commences 
commercial operation as defined in the introductory text of paragraph 
(1) of this definition and that is subsequently replaced by a unit at 
the same or a different source, such date shall remain the replaced 
unit's date of commencement of commercial operation, and the replacement 
unit shall be treated as a separate unit with a separate date for 
commencement of commercial operation as defined in paragraph (1) or (2) 
of this definition as appropriate.
    (2) Notwithstanding paragraph (1) of this definition and except as 
provided in Sec. 97.405, for a unit that is not a TR NOX 
Annual unit under Sec. 97.404 on the later of January 1, 2005 or the 
date the unit commences commercial operation as defined in introductory 
text of paragraph (1) of this definition, the unit's date for 
commencement of commercial operation shall be the date on which the unit 
becomes a TR NOX Annual unit under Sec. 97.404.
    (i) For a unit with a date for commencement of commercial operation 
as defined in the introductory text of paragraph (2) of this definition 
and that subsequently undergoes a physical

[[Page 348]]

change or is moved to a different location or source, such date shall 
remain the date of commencement of commercial operation of the unit, 
which shall continue to be treated as the same unit.
    (ii) For a unit with a date for commencement of commercial operation 
as defined in the introductory text of paragraph (2) of this definition 
and that is subsequently replaced by a unit at the same or a different 
source, such date shall remain the replaced unit's date of commencement 
of commercial operation, and the replacement unit shall be treated as a 
separate unit with a separate date for commencement of commercial 
operation as defined in paragraph (1) or (2) of this definition as 
appropriate.
    Common designated representative means, with regard to a control 
period in a given year, a designated representative where, as of April 1 
immediately after the allowance transfer deadline for such control 
period, the same natural person is authorized under Sec. Sec. 97.413(a) 
and 97.415(a) as the designated representative for a group of one or 
more TR NOX Annual sources and units located in a State (and 
Indian country within the borders of such State).
    Common designated representative's assurance level means, with 
regard to a specific common designated representative and a State (and 
Indian country within the borders of such State) and control period in a 
given year for which the State assurance level is exceeded as described 
in Sec. 97.406(c)(2)(iii), the common designated representative's share 
of the State NOX Annual trading budget with the variability 
limit for the State for such control period.
    Common designated representative's share means, with regard to a 
specific common designated representative for a control period in a 
given year:
    (1) With regard to a total amount of NOX emissions from 
all TR NOX Annual units in a State (and Indian country within 
the borders of such State) during such control period, the total tonnage 
of NOX emissions during such control period from a group of 
one or more TR NOX Annual units located in such State (and 
such Indian country) and having the common designated representative for 
such control period;
    (2) With regard to a State NOX Annual trading budget with 
the variability limit for such control period, the amount (rounded to 
the nearest allowance) equal to the sum of the total amount of TR 
NOX Annual allowances allocated for such control period to a 
group of one or more TR NOX Annual units located in the State 
(and Indian country within the borders of such State) and having the 
common designated representative for such control period and of the 
total amount of TR NOX Annual allowances purchased by an 
owner or operator of such TR NOX Annual units in an auction 
for such control period and submitted by the State or the permitting 
authority to the Administrator for recordation in the compliance 
accounts for such TR NOX Annual units in accordance with the 
TR NOX Annual allowance auction provisions in a SIP revision 
approved by the Administrator under Sec. 52.38(a)(4) or (5) of this 
chapter, multiplied by the sum of the State NOX Annual 
trading budget under Sec. 97.410(a) and the State's variability limit 
under Sec. 97.410(b) for such control period and divided by such State 
NOX Annual trading budget;
    (3) Provided that, in the case of a unit that operates during, but 
has no amount of TR NOX Annual allowances allocated under 
Sec. Sec. 97.411 and 97.412 for, such control period, the unit shall be 
treated, solely for purposes of this definition, as being allocated an 
amount (rounded to the nearest allowance) of TR NOX Annual 
allowances for such control period equal to the unit's allowable 
NOX emission rate applicable to such control period, 
multiplied by a capacity factor of 0.85 (if the unit is a boiler 
combusting any amount of coal or coal-derived fuel during such control 
period), 0.24 (if the unit is a simple combustion turbine during such 
control period), 0.67 (if the unit is a combined cycle turbine during 
such control period), 0.74 (if the unit is an integrated coal 
gasification combined cycle unit during such control period), or 0.36 
(for any other unit), multiplied by the unit's maximum hourly load as 
reported in accordance with this subpart and by 8,760 hours/control 
period, and divided by 2,000 lb/ton.

[[Page 349]]

    Common stack means a single flue through which emissions from 2 or 
more units are exhausted.
    Compliance account means an Allowance Management System account, 
established by the Administrator for a TR NOX Annual source 
under this subpart, in which any TR NOX Annual allowance 
allocations to the TR NOX Annual units at the source are 
recorded and in which are held any TR NOX Annual allowances 
available for use for a control period in a given year in complying with 
the source's TR NOX Annual emissions limitation in accordance 
with Sec. Sec. 97.406 and 97.424.
    Continuous emission monitoring system or CEMS means the equipment 
required under this subpart to sample, analyze, measure, and provide, by 
means of readings recorded at least once every 15 minutes and using an 
automated data acquisition and handling system (DAHS), a permanent 
record of NOX emissions, stack gas volumetric flow rate, 
stack gas moisture content, and O2 or CO2 
concentration (as applicable), in a manner consistent with part 75 of 
this chapter and Sec. Sec. 97.430 through 97.435. The following systems 
are the principal types of continuous emission monitoring systems:
    (1) A flow monitoring system, consisting of a stack flow rate 
monitor and an automated data acquisition and handling system and 
providing a permanent, continuous record of stack gas volumetric flow 
rate, in standard cubic feet per hour (scfh);
    (2) A NOX concentration monitoring system, consisting of 
a NOX pollutant concentration monitor and an automated data 
acquisition and handling system and providing a permanent, continuous 
record of NOX emissions, in parts per million (ppm);
    (3) A NOX emission rate (or NOX-diluent) 
monitoring system, consisting of a NOX pollutant 
concentration monitor, a diluent gas (CO2 or O2) 
monitor, and an automated data acquisition and handling system and 
providing a permanent, continuous record of NOX 
concentration, in parts per million (ppm), diluent gas concentration, in 
percent CO2 or O2, and NOX emission 
rate, in pounds per million British thermal units (lb/mmBtu);
    (4) A moisture monitoring system, as defined in Sec. 75.11(b)(2) of 
this chapter and providing a permanent, continuous record of the stack 
gas moisture content, in percent H2O;
    (5) A CO2 monitoring system, consisting of a 
CO2 pollutant concentration monitor (or an O2 
monitor plus suitable mathematical equations from which the 
CO2 concentration is derived) and an automated data 
acquisition and handling system and providing a permanent, continuous 
record of CO2 emissions, in percent CO2; and
    (6) An O2 monitoring system, consisting of an 
O2 concentration monitor and an automated data acquisition 
and handling system and providing a permanent, continuous record of 
O2, in percent O2.
    Control period means the period starting January 1 of a calendar 
year, except as provided in Sec. 97.406(c)(3), and ending on December 
31 of the same year, inclusive.
    Designated representative means, for a TR NOX Annual 
source and each TR NOX Annual unit at the source, the natural 
person who is authorized by the owners and operators of the source and 
all such units at the source, in accordance with this subpart, to 
represent and legally bind each owner and operator in matters pertaining 
to the TR NOX Annual Trading Program. If the TR 
NOX Annual source is also subject to the Acid Rain Program, 
TR NOX Ozone Season Trading Program, TR SO2 Group 
1 Trading Program, or TR SO2 Group 2 Trading Program, then 
this natural person shall be the same natural person as the designated 
representative, as defined in the respective program.
    Emissions means air pollutants exhausted from a unit or source into 
the atmosphere, as measured, recorded, and reported to the Administrator 
by the designated representative, and as modified by the Administrator:
    (1) In accordance with this subpart; and
    (2) With regard to a period before the unit or source is required to 
measure, record, and report such air pollutants in accordance with this 
subpart, in accordance with part 75 of this chapter.
    Excess emissions means any ton of emissions from the TR 
NOX Annual

[[Page 350]]

units at a TR NOX Annual source during a control period in a 
given year that exceeds the TR NOX Annual emissions 
limitation for the source for such control period.
    Fossil fuel means--
    (1) Natural gas, petroleum, coal, or any form of solid, liquid, or 
gaseous fuel derived from such material; or
    (2) For purposes of applying the limitation on ``average annual fuel 
consumption of fossil fuel'' in Sec. Sec. 97.404(b)(2)(i)(B) and (ii), 
natural gas, petroleum, coal, or any form of solid, liquid, or gaseous 
fuel derived from such material for the purpose of creating useful heat.
    Fossil-fuel-fired means, with regard to a unit, combusting any 
amount of fossil fuel in 2005 or any calendar year thereafter.
    General account means an Allowance Management System account, 
established under this subpart, that is not a compliance account or an 
assurance account.
    Generator means a device that produces electricity.
    Gross electrical output means, for a unit, electricity made 
available for use, including any such electricity used in the power 
production process (which process includes, but is not limited to, any 
on-site processing or treatment of fuel combusted at the unit and any 
on-site emission controls).
    Heat input means, for a unit for a specified period of time, the 
product (in mmBtu/time) of the gross calorific value of the fuel (in 
mmBtu/lb) fed into the unit multiplied by the fuel feed rate (in lb of 
fuel/time), as measured, recorded, and reported to the Administrator by 
the designated representative and as modified by the Administrator in 
accordance with this subpart and excluding the heat derived from 
preheated combustion air, recirculated flue gases, or exhaust.
    Heat input rate means, for a unit, the amount of heat input (in 
mmBtu) divided by unit operating time (in hr) or, for a unit and a 
specific fuel, the amount of heat input attributed to the fuel (in 
mmBtu) divided by the unit operating time (in hr) during which the unit 
combusts the fuel.
    Heat rate means, for a unit, the unit's maximum design heat input 
(in Btu/hr), divided by the product of 1,000,000 Btu/mmBtu and the 
unit's maximum hourly load.
    Indian country means ``Indian country'' as defined in 18 U.S.C. 
1151.
    Life-of-the-unit, firm power contractual arrangement means a unit 
participation power sales agreement under which a utility or industrial 
customer reserves, or is entitled to receive, a specified amount or 
percentage of nameplate capacity and associated energy generated by any 
specified unit and pays its proportional amount of such unit's total 
costs, pursuant to a contract:
    (1) For the life of the unit;
    (2) For a cumulative term of no less than 30 years, including 
contracts that permit an election for early termination; or
    (3) For a period no less than 25 years or 70 percent of the economic 
useful life of the unit determined as of the time the unit is built, 
with option rights to purchase or release some portion of the nameplate 
capacity and associated energy generated by the unit at the end of the 
period.
    Maximum design heat input means, for a unit, the maximum amount of 
fuel per hour (in Btu/hr) that the unit is capable of combusting on a 
steady state basis as of the initial installation of the unit as 
specified by the manufacturer of the unit.
    Monitoring system means any monitoring system that meets the 
requirements of this subpart, including a continuous emission monitoring 
system, an alternative monitoring system, or an excepted monitoring 
system under part 75 of this chapter.
    Nameplate capacity means, starting from the initial installation of 
a generator, the maximum electrical generating output (in MWe, rounded 
to the nearest tenth) that the generator is capable of producing on a 
steady state basis and during continuous operation (when not restricted 
by seasonal or other deratings) as of such installation as specified by 
the manufacturer of the generator or, starting from the completion of 
any subsequent physical change in the generator resulting in an increase 
in the maximum electrical generating output that the generator is 
capable of producing on a steady state basis and during continuous 
operation

[[Page 351]]

(when not restricted by seasonal or other deratings), such increased 
maximum amount (in MWe, rounded to the nearest tenth) as of such 
completion as specified by the person conducting the physical change.
    Natural gas means ``natural gas'' as defined in Sec. 72.2 of this 
chapter.
    Newly affected TR NOX Annual unit means a unit that was 
not a TR NOX Annual unit when it began operating but that 
thereafter becomes a TR NOX Annual unit.
    Operate or operation means, with regard to a unit, to combust fuel.
    Operator means, for a TR NOX Annual source or a TR 
NOX Annual unit at a source respectively, any person who 
operates, controls, or supervises a TR NOX Annual unit at the 
source or the TR NOX Annual unit and shall include, but not 
be limited to, any holding company, utility system, or plant manager of 
such source or unit.
    Owner means, for a TR NOX Annual source or a TR 
NOX Annual unit at a source respectively, any of the 
following persons:
    (1) Any holder of any portion of the legal or equitable title in a 
TR NOX Annual unit at the source or the TR NOX 
Annual unit;
    (2) Any holder of a leasehold interest in a TR NOX Annual 
unit at the source or the TR NOX Annual unit, provided that, 
unless expressly provided for in a leasehold agreement, ``owner'' shall 
not include a passive lessor, or a person who has an equitable interest 
through such lessor, whose rental payments are not based (either 
directly or indirectly) on the revenues or income from such TR 
NOX Annual unit; and 3) Any purchaser of power from a TR 
NOX Annual unit at the source or the TR NOX Annual 
unit under a life-of-the-unit, firm power contractual arrangement.
    Permanently retired means, with regard to a unit, a unit that is 
unavailable for service and that the unit's owners and operators do not 
expect to return to service in the future.
    Permitting authority means ``permitting authority'' as defined in 
Sec. Sec. 70.2 and 71.2 of this chapter.
    Potential electrical output capacity means, for a unit, 33 percent 
of the unit's maximum design heat input, divided by 3,413 Btu/kWh, 
divided by 1,000 kWh/MWh, and multiplied by 8,760 hr/yr.
    Receive or receipt of means, when referring to the Administrator, to 
come into possession of a document, information, or correspondence 
(whether sent in hard copy or by authorized electronic transmission), as 
indicated in an official log, or by a notation made on the document, 
information, or correspondence, by the Administrator in the regular 
course of business.
    Recordation, record, or recorded means, with regard to TR 
NOX Annual allowances, the moving of TR NOX Annual 
allowances by the Administrator into, out of, or between Allowance 
Management System accounts, for purposes of allocation, auction, 
transfer, or deduction.
    Reference method means any direct test method of sampling and 
analyzing for an air pollutant as specified in Sec. 75.22 of this 
chapter.
    Replacement, replace, or replaced means, with regard to a unit, the 
demolishing of a unit, or the permanent retirement and permanent 
disabling of a unit, and the construction of another unit (the 
replacement unit) to be used instead of the demolished or retired unit 
(the replaced unit).
    Sequential use of energy means:
    (1) The use of reject heat from electricity production in a useful 
thermal energy application or process; or
    (2) The use of reject heat from useful thermal energy application or 
process in electricity production.
    Serial number means, for a TR NOX Annual allowance, the 
unique identification number assigned to each TR NOX Annual 
allowance by the Administrator.
    Solid waste incineration unit means a stationary, fossil-fuel-fired 
boiler or stationary, fossil-fuel-fired combustion turbine that is a 
``solid waste incineration unit'' as defined in section 129(g)(1) of the 
Clean Air Act.
    Source means all buildings, structures, or installations located in 
one or more contiguous or adjacent properties under common control of 
the same person or persons. This definition does not change or otherwise 
affect the definition of ``major source'', ``stationary source'', or 
``source'' as set forth and

[[Page 352]]

implemented in a title V operating permit program or any other program 
under the Clean Air Act.
    State means one of the States that is subject to the TR 
NOX Annual Trading Program pursuant to Sec. 52.38(a) of this 
chapter.
    Submit or serve means to send or transmit a document, information, 
or correspondence to the person specified in accordance with the 
applicable regulation:
    (1) In person;
    (2) By United States Postal Service; or
    (3) By other means of dispatch or transmission and delivery;
    (4) Provided that compliance with any ``submission'' or ``service'' 
deadline shall be determined by the date of dispatch, transmission, or 
mailing and not the date of receipt.
    Topping-cycle unit means a unit in which the energy input to the 
unit is first used to produce useful power, including electricity, where 
at least some of the reject heat from the electricity production is then 
used to provide useful thermal energy.
    Total energy input means, for a unit, total energy of all forms 
supplied to the unit, excluding energy produced by the unit. Each form 
of energy supplied shall be measured by the lower heating value of that 
form of energy calculated as follows:


LHV = HHV - 10.55(W + 9H)

where:

LHV = lower heating value of the form of energy in Btu/lb,
HHV = higher heating value of the form of energy in Btu/lb,
W = weight % of moisture in the form of energy, and
H = weight % of hydrogen in the form of energy.

    Total energy output means, for a unit, the sum of useful power and 
useful thermal energy produced by the unit.
    TR NOX Annual allowance means a limited authorization issued and 
allocated or auctioned by the Administrator under this subpart, or by a 
State or permitting authority under a SIP revision approved by the 
Administrator under Sec. 52.38(a)(3), (4), or (5) of this chapter, to 
emit one ton of NOX during a control period of the specified 
calendar year for which the authorization is allocated or auctioned or 
of any calendar year thereafter under the TR NOX Annual 
Trading Program.
    TR NOX Annual allowance deduction or deduct TR NOX Annual allowances 
means the permanent withdrawal of TR NOX Annual allowances by 
the Administrator from a compliance account (e.g., in order to account 
for compliance with the TR NOX Annual emissions limitation) 
or from an assurance account (e.g., in order to account for compliance 
with the assurance provisions under Sec. Sec. 97.406 and 97.425).
    TR NOX Annual allowances held or hold TR NO4 Annual allowances means 
the TR NOX Annual allowances treated as included in an 
Allowance Management System account as of a specified point in time 
because at that time they:
    (1) Have been recorded by the Administrator in the account or 
transferred into the account by a correctly submitted, but not yet 
recorded, TR NOX Annual allowance transfer in accordance with 
this subpart; and
    (2) Have not been transferred out of the account by a correctly 
submitted, but not yet recorded, TR NOX Annual allowance 
transfer in accordance with this subpart.
    TR NOX Annual emissions limitation means, for a TR NOX 
Annual source, the tonnage of NOX emissions authorized in a 
control period in a given year by the TR NOX Annual 
allowances available for deduction for the source under Sec. 97.424(a) 
for such control period.
    TR NOX Annual source means a source that includes one or more TR 
NOX Annual units.
    TR NOX Annual Trading Program means a multi-state NOX air 
pollution control and emission reduction program established in 
accordance with this subpart and Sec. 52.38(a) of this chapter 
(including such a program that is revised in a SIP revision approved by 
the Administrator under Sec. 52.38(a)(3) or (4) of this chapter or that 
is established in a SIP revision approved by the Administrator under 
Sec. 52.38(a)(5) of this chapter), as a means of mitigating interstate 
transport of fine particulates and NOX.
    TR NOX Annual unit means a unit that is subject to the TR 
NOX Annual Trading Program.

[[Page 353]]

    TR NOX Ozone Season Trading Program means a multi-state 
NOX air pollution control and emission reduction program 
established in accordance with subpart BBBBB of this part and Sec. 
52.38(b) of this chapter (including such a program that is revised in a 
SIP revision approved by the Administrator under Sec. 52.38(b)(3) or 
(4) of this chapter or that is established in a SIP revision approved by 
the Administrator under Sec. 52.38(b)(5) of this chapter), as a means 
of mitigating interstate transport of ozone and NOX.
    TR SO2 Group 1 Trading Program means a multi-state SO2 
air pollution control and emission reduction program established in 
accordance with subpart CCCCC of this part and Sec. 52.39(a), (b), (d) 
through (f), (j), and (k) of this chapter (including such a program that 
is revised in a SIP revision approved by the Administrator under Sec. 
52.39(d) or (e) of this chapter or that is established in a SIP revision 
approved by the Administrator under Sec. 52.39(f) of this chapter), as 
a means of mitigating interstate transport of fine particulates and 
SO2.
    TR SO2 Group 2 Trading Program means a multi-state SO2 air pollution 
control and emission reduction program established in accordance with 
subpart DDDDD of this part and 52.39(a), (c), and (g) through (k) of 
this chapter (including such a program that is revised in a SIP revision 
approved by the Administrator under Sec. 52.39(g) or (h) of this 
chapter or that is established in a SIP revision approved by the 
Administrator under Sec. 52.39(i) of this chapter), as a means of 
mitigating interstate transport of fine particulates and SO2.
    Unit means a stationary, fossil-fuel-fired boiler, stationary, 
fossil-fuel-fired combustion turbine, or other stationary, fossil-fuel-
fired combustion device. A unit that undergoes a physical change or is 
moved to a different location or source shall continue to be treated as 
the same unit. A unit (the replaced unit) that is replaced by another 
unit (the replacement unit) at the same or a different source shall 
continue to be treated as the same unit, and the replacement unit shall 
be treated as a separate unit.
    Unit operating day means, with regard to a unit, a calendar day in 
which the unit combusts any fuel.
    Unit operating hour or hour of unit operation means, with regard to 
a unit, an hour in which the unit combusts any fuel.
    Useful power means, with regard to a unit, electricity or mechanical 
energy that the unit makes available for use, excluding any such energy 
used in the power production process (which process includes, but is not 
limited to, any on-site processing or treatment of fuel combusted at the 
unit and any on-site emission controls).
    Useful thermal energy means thermal energy that is:
    (1) Made available to an industrial or commercial process (not a 
power production process), excluding any heat contained in condensate 
return or makeup water;
    (2) Used in a heating application (e.g., space heating or domestic 
hot water heating); or
    (3) Used in a space cooling application (i.e., in an absorption 
chiller).
    Utility power distribution system means the portion of an 
electricity grid owned or operated by a utility and dedicated to 
delivering electricity to customers.



Sec. 97.403  Measurements, abbreviations, and acronyms.

    Measurements, abbreviations, and acronyms used in this subpart are 
defined as follows:

Btu--British thermal unit
CO2--carbon dioxide
H2O--water
hr--hour
kW--kilowatt electrical
kWh--kilowatt hour
lb--pound
mmBtu--million Btu
MWe--megawatt electrical
MWh--megawatt hour
NOX--nitrogen oxides
O2--oxygen
ppm--parts per million
scfh--standard cubic feet per hour
SO2--sulfur dioxide
yr--year



Sec. 97.404  Applicability.

    (a) Except as provided in paragraph (b) of this section:
    (1) The following units in a State (and Indian country within the 
borders of such State) shall be TR NOX Annual

[[Page 354]]

units, and any source that includes one or more such units shall be a TR 
NOX Annual source, subject to the requirements of this 
subpart: any stationary, fossil-fuel-fired boiler or stationary, fossil-
fuel-fired combustion turbine serving at any time, on or after January 
1, 2005, a generator with nameplate capacity of more than 25 MWe 
producing electricity for sale.
    (2) If a stationary boiler or stationary combustion turbine that, 
under paragraph (a)(1) of this section, is not a TR NOX 
Annual unit begins to combust fossil fuel or to serve a generator with 
nameplate capacity of more than 25 MWe producing electricity for sale, 
the unit shall become a TR NOX Annual unit as provided in 
paragraph (a)(1) of this section on the first date on which it both 
combusts fossil fuel and serves such generator.
    (b) Any unit in a State (and Indian country within the borders of 
such State) that otherwise is a TR NOX Annual unit under 
paragraph (a) of this section and that meets the requirements set forth 
in paragraph (b)(1)(i) or (2)(i) of this section shall not be a TR 
NOX Annual unit:
    (1)(i) Any unit:
    (A) Qualifying as a cogeneration unit throughout the later of 2005 
or the 12-month period starting on the date the unit first produces 
electricity and continuing to qualify as a cogeneration unit throughout 
each calendar year ending after the later of 2005 or such 12-month 
period; and
    (B) Not supplying in 2005 or any calendar year thereafter more than 
one-third of the unit's potential electric output capacity or 219,000 
MWh, whichever is greater, to any utility power distribution system for 
sale.
    (ii) If, after qualifying under paragraph (b)(1)(i) of this section 
as not being a TR NOX Annual unit, a unit subsequently no 
longer meets all the requirements of paragraph (b)(1)(i) of this 
section, the unit shall become a TR NOX Annual unit starting 
on the earlier of January 1 after the first calendar year during which 
the unit first no longer qualifies as a cogeneration unit or January 1 
after the first calendar year during which the unit no longer meets the 
requirements of paragraph (b)(1)(i)(B) of this section. The unit shall 
thereafter continue to be a TR NOX Annual unit.
    (2)(i) Any unit:
    (A) Qualifying as a solid waste incineration unit throughout the 
later of 2005 or the 12-month period starting on the date the unit first 
produces electricity and continuing to qualify as a solid waste 
incineration unit throughout each calendar year ending after the later 
of 2005 or such 12-month period; and
    (B) With an average annual fuel consumption of fossil fuel for the 
first 3 consecutive calendar years of operation starting no earlier than 
2005 of less than 20 percent (on a Btu basis) and an average annual fuel 
consumption of fossil fuel for any 3 consecutive calendar years 
thereafter of less than 20 percent (on a Btu basis).
    (ii) If, after qualifying under paragraph (b)(2)(i) of this section 
as not being a TR NOX Annual unit, a unit subsequently no 
longer meets all the requirements of paragraph (b)(1)(i) of this 
section, the unit shall become a TR NOX Annual unit starting 
on the earlier of January 1 after the first calendar year during which 
the unit first no longer qualifies as a solid waste incineration unit or 
January 1 after the first 3 consecutive calendar years after 2005 for 
which the unit has an average annual fuel consumption of fossil fuel of 
20 percent or more. The unit shall thereafter continue to be a TR 
NOX Annual unit.
    (c) A certifying official of an owner or operator of any unit or 
other equipment may submit a petition (including any supporting 
documents) to the Administrator at any time for a determination 
concerning the applicability, under paragraphs (a) and (b) of this 
section or a SIP revision approved under Sec. 52.38(a)(4) or (5) of 
this chapter, of the TR NOX Annual Trading Program to the 
unit or other equipment.
    (1) Petition content. The petition shall be in writing and include 
the identification of the unit or other equipment and the relevant facts 
about the unit or other equipment. The petition and any other documents 
provided to the Administrator in connection with the petition shall 
include the following certification statement, signed

[[Page 355]]

by the certifying official: ``I am authorized to make this submission on 
behalf of the owners and operators of the unit or other equipment for 
which the submission is made. I certify under penalty of law that I have 
personally examined, and am familiar with, the statements and 
information submitted in this document and all its attachments. Based on 
my inquiry of those individuals with primary responsibility for 
obtaining the information, I certify that the statements and information 
are to the best of my knowledge and belief true, accurate, and complete. 
I am aware that there are significant penalties for submitting false 
statements and information or omitting required statements and 
information, including the possibility of fine or imprisonment.''
    (2) Response. The Administrator will issue a written response to the 
petition and may request supplemental information determined by the 
Administrator to be relevant to such petition. The Administrator's 
determination concerning the applicability, under paragraphs (a) and (b) 
of this section, of the TR NOX Annual Trading Program to the 
unit or other equipment shall be binding on any State or permitting 
authority unless the Administrator determines that the petition or other 
documents or information provided in connection with the petition 
contained significant, relevant errors or omissions.



Sec. 97.405  Retired unit exemption.

    (a)(1) Any TR NOX Annual unit that is permanently retired 
shall be exempt from Sec. 97.406(b) and (c)(1), Sec. 97.424, and 
Sec. Sec. 97.430 through 97.435.
    (2) The exemption under paragraph (a)(1) of this section shall 
become effective the day on which the TR NOX Annual unit is 
permanently retired. Within 30 days of the unit's permanent retirement, 
the designated representative shall submit a statement to the 
Administrator. The statement shall state, in a format prescribed by the 
Administrator, that the unit was permanently retired on a specified date 
and will comply with the requirements of paragraph (b) of this section.
    (b) Special provisions. (1) A unit exempt under paragraph (a) of 
this section shall not emit any NOX, starting on the date 
that the exemption takes effect.
    (2) For a period of 5 years from the date the records are created, 
the owners and operators of a unit exempt under paragraph (a) of this 
section shall retain, at the source that includes the unit, records 
demonstrating that the unit is permanently retired. The 5-year period 
for keeping records may be extended for cause, at any time before the 
end of the period, in writing by the Administrator. The owners and 
operators bear the burden of proof that the unit is permanently retired.
    (3) The owners and operators and, to the extent applicable, the 
designated representative of a unit exempt under paragraph (a) of this 
section shall comply with the requirements of the TR NOX 
Annual Trading Program concerning all periods for which the exemption is 
not in effect, even if such requirements arise, or must be complied 
with, after the exemption takes effect.
    (4) A unit exempt under paragraph (a) of this section shall lose its 
exemption on the first date on which the unit resumes operation. Such 
unit shall be treated, for purposes of applying allocation, monitoring, 
reporting, and recordkeeping requirements under this subpart, as a unit 
that commences commercial operation on the first date on which the unit 
resumes operation.



Sec. 97.406  Standard requirements.

    (a) Designated representative requirements. The owners and operators 
shall comply with the requirement to have a designated representative, 
and may have an alternate designated representative, in accordance with 
Sec. Sec. 97.413 through 97.418.
    (b) Emissions monitoring, reporting, and recordkeeping requirements. 
(1) The owners and operators, and the designated representative, of each 
TR NOX Annual source and each TR NOX Annual unit 
at the source shall comply with the monitoring, reporting, and 
recordkeeping requirements of Sec. Sec. 97.430 through 97.435.
    (2) The emissions data determined in accordance with Sec. Sec. 
97.430 through 97.435 shall be used to calculate allocations of TR 
NOX Annual allowances under Sec. Sec. 97.411(a)(2) and (b) 
and 97.412 and to

[[Page 356]]

determine compliance with the TR NOX Annual emissions 
limitation and assurance provisions under paragraph (c) of this section, 
provided that, for each monitoring location from which mass emissions 
are reported, the mass emissions amount used in calculating such 
allocations and determining such compliance shall be the mass emissions 
amount for the monitoring location determined in accordance with 
Sec. Sec. 97.430 through 97.435 and rounded to the nearest ton, with 
any fraction of a ton less than 0.50 being deemed to be zero.
    (c) NOX emissions requirements. (1) TR NOX Annual 
emissions limitation. (i) As of the allowance transfer deadline for a 
control period in a given year, the owners and operators of each TR 
NOX Annual source and each TR NOX Annual unit at 
the source shall hold, in the source's compliance account, TR 
NOX Annual allowances available for deduction for such 
control period under Sec. 97.424(a) in an amount not less than the tons 
of total NOX emissions for such control period from all TR 
NOX Annual units at the source.
    (ii) If total NOX emissions during a control period in a 
given year from the TR NOX Annual units at a TR 
NOX Annual source are in excess of the TR NOX 
Annual emissions limitation set forth in paragraph (c)(1)(i) of this 
section, then:
    (A) The owners and operators of the source and each TR 
NOX Annual unit at the source shall hold the TR 
NOX Annual allowances required for deduction under Sec. 
97.424(d); and
    (B) The owners and operators of the source and each TR 
NOX Annual unit at the source shall pay any fine, penalty, or 
assessment or comply with any other remedy imposed, for the same 
violations, under the Clean Air Act, and each ton of such excess 
emissions and each day of such control period shall constitute a 
separate violation of this subpart and the Clean Air Act.
    (2) TR NOX Annual assurance provisions. (i) If total 
NOX emissions during a control period in a given year from 
all TR NOX Annual units at TR NOX Annual sources 
in a State (and Indian country within the borders of such State) exceed 
the State assurance level, then the owners and operators of such sources 
and units in each group of one or more sources and units having a common 
designated representative for such control period, where the common 
designated representative's share of such NOX emissions 
during such control period exceeds the common designated 
representative's assurance level for the State and such control period, 
shall hold (in the assurance account established for the owners and 
operators of such group) TR NOX Annual allowances available 
for deduction for such control period under Sec. 97.425(a) in an amount 
equal to two times the product (rounded to the nearest whole number), as 
determined by the Administrator in accordance with Sec. 97.425(b), of 
multiplying--
    (A) The quotient of the amount by which the common designated 
representative's share of such NOX emissions exceeds the 
common designated representative's assurance level divided by the sum of 
the amounts, determined for all common designated representatives for 
such sources and units in the State (and Indian country within the 
borders of such State) for such control period, by which each common 
designated representative's share of such NOX emissions 
exceeds the respective common designated representative's assurance 
level; and
    (B) The amount by which total NOX emissions from all TR 
NOX Annual units at TR NOX Annual sources in the 
State (and Indian country within the borders of such State) for such 
control period exceed the State assurance level.
    (ii) The owners and operators shall hold the TR NOX 
Annual allowances required under paragraph (c)(2)(i) of this section, as 
of midnight of November 1 (if it is a business day), or midnight of the 
first business day thereafter (if November 1 is not a business day), 
immediately after such control period.
    (iii) Total NOX emissions from all TR NOX 
Annual units at TR NOX Annual sources in a State (and Indian 
country within the borders of such State) during a control period in a 
given year exceed the State assurance level if such total NOX 
emissions exceed the sum, for such control period, of the State 
NOX Annual trading budget under Sec. 97.410(a) and the 
State's variability limit under Sec. 97.410(b).

[[Page 357]]

    (iv) It shall not be a violation of this subpart or of the Clean Air 
Act if total NOX emissions from all TR NOX Annual 
units at TR NOX Annual sources in a State (and Indian country 
within the borders of such State) during a control period exceed the 
State assurance level or if a common designated representative's share 
of total NOX emissions from the TR NOX Annual 
units at TR NOX Annual sources in a State (and Indian country 
within the borders of such State) during a control period exceeds the 
common designated representative's assurance level.
    (v) To the extent the owners and operators fail to hold TR 
NOX Annual allowances for a control period in a given year in 
accordance with paragraphs (c)(2)(i) through (iii) of this section,
    (A) The owners and operators shall pay any fine, penalty, or 
assessment or comply with any other remedy imposed under the Clean Air 
Act; and
    (B) Each TR NOX Annual allowance that the owners and 
operators fail to hold for such control period in accordance with 
paragraphs (c)(2)(i) through (iii) of this section and each day of such 
control period shall constitute a separate violation of this subpart and 
the Clean Air Act.
    (3) Compliance periods. (i) A TR NOX Annual unit shall be 
subject to the requirements under paragraph (c)(1) of this section for 
the control period starting on the later of January 1, 2015 or the 
deadline for meeting the unit's monitor certification requirements under 
Sec. 97.430(b) and for each control period thereafter.
    (ii) A TR NOX Annual unit shall be subject to the 
requirements under paragraph (c)(2) of this section for the control 
period starting on the later of January 1, 2017 or the deadline for 
meeting the unit's monitor certification requirements under Sec. 
97.430(b) and for each control period thereafter.
    (4) Vintage of allowances held for compliance. (i) A TR 
NOX Annual allowance held for compliance with the 
requirements under paragraph (c)(1)(i) of this section for a control 
period in a given year must be a TR NOX Annual allowance that 
was allocated for such control period or a control period in a prior 
year.
    (ii) A TR NOX Annual allowance held for compliance with 
the requirements under paragraphs (c)(1)(ii)(A) and (2)(i) through (iii) 
of this section for a control period in a given year must be a TR 
NOX Annual allowance that was allocated for a control period 
in a prior year or the control period in the given year or in the 
immediately following year.
    (5) Allowance Management System requirements. Each TR NOX 
Annual allowance shall be held in, deducted from, or transferred into, 
out of, or between Allowance Management System accounts in accordance 
with this subpart.
    (6) Limited authorization. A TR NOX Annual allowance is a 
limited authorization to emit one ton of NOX during the 
control period in one year. Such authorization is limited in its use and 
duration as follows:
    (i) Such authorization shall only be used in accordance with the TR 
NOX Annual Trading Program; and
    (ii) Notwithstanding any other provision of this subpart, the 
Administrator has the authority to terminate or limit the use and 
duration of such authorization to the extent the Administrator 
determines is necessary or appropriate to implement any provision of the 
Clean Air Act.
    (7) Property right. A TR NOX Annual allowance does not 
constitute a property right.
    (d) Title V permit requirements. (1) No title V permit revision 
shall be required for any allocation, holding, deduction, or transfer of 
TR NOX Annual allowances in accordance with this subpart.
    (2) A description of whether a unit is required to monitor and 
report NOX emissions using a continuous emission monitoring 
system (under subpart H of part 75 of this chapter), an excepted 
monitoring system (under appendices D and E to part 75 of this chapter), 
a low mass emissions excepted monitoring methodology (under Sec. 75.19 
of this chapter), or an alternative monitoring system (under subpart E 
of part 75 of this chapter) in accordance with Sec. Sec. 97.430 through 
97.435 may be added to, or changed in, a title V permit using minor 
permit modification procedures in accordance with Sec. Sec. 70.7(e)(2) 
and

[[Page 358]]

71.7(e)(1) of this chapter, provided that the requirements applicable to 
the described monitoring and reporting (as added or changed, 
respectively) are already incorporated in such permit. This paragraph 
explicitly provides that the addition of, or change to, a unit's 
description as described in the prior sentence is eligible for minor 
permit modification procedures in accordance with Sec. Sec. 
70.7(e)(2)(i)(B) and 71.7(e)(1)(i)(B) of this chapter.
    (e) Additional recordkeeping and reporting requirements. (1) Unless 
otherwise provided, the owners and operators of each TR NOX 
Annual source and each TR NOX Annual unit at the source shall 
keep on site at the source each of the following documents (in hardcopy 
or electronic format) for a period of 5 years from the date the document 
is created. This period may be extended for cause, at any time before 
the end of 5 years, in writing by the Administrator.
    (i) The certificate of representation under Sec. 97.416 for the 
designated representative for the source and each TR NOX 
Annual unit at the source and all documents that demonstrate the truth 
of the statements in the certificate of representation; provided that 
the certificate and documents shall be retained on site at the source 
beyond such 5-year period until such certificate of representation and 
documents are superseded because of the submission of a new certificate 
of representation under Sec. 97.416 changing the designated 
representative.
    (ii) All emissions monitoring information, in accordance with this 
subpart.
    (iii) Copies of all reports, compliance certifications, and other 
submissions and all records made or required under, or to demonstrate 
compliance with the requirements of, the TR NOX Annual 
Trading Program.
    (2) The designated representative of a TR NOX Annual 
source and each TR NOX Annual unit at the source shall make 
all submissions required under the TR NOX Annual Trading 
Program, except as provided in Sec. 97.418. This requirement does not 
change, create an exemption from, or otherwise affect the responsible 
official submission requirements under a title V operating permit 
program in parts 70 and 71 of this chapter.
    (f) Liability. (1) Any provision of the TR NOX Annual 
Trading Program that applies to a TR NOX Annual source or the 
designated representative of a TR NOX Annual source shall 
also apply to the owners and operators of such source and of the TR 
NOX Annual units at the source.
    (2) Any provision of the TR NOX Annual Trading Program 
that applies to a TR NOX Annual unit or the designated 
representative of a TR NOX Annual unit shall also apply to 
the owners and operators of such unit.
    (g) Effect on other authorities. No provision of the TR 
NOX Annual Trading Program or exemption under Sec. 97.405 
shall be construed as exempting or excluding the owners and operators, 
and the designated representative, of a TR NOX Annual source 
or TR NOX Annual unit from compliance with any other 
provision of the applicable, approved State implementation plan, a 
federally enforceable permit, or the Clean Air Act.

[76 FR 48379, Aug. 8, 2011, as amended at 77 FR 10334, Feb. 21, 2012; 79 
FR 71672, Dec. 3, 2014]



Sec. 97.407  Computation of time.

    (a) Unless otherwise stated, any time period scheduled, under the TR 
NOX Annual Trading Program, to begin on the occurrence of an 
act or event shall begin on the day the act or event occurs.
    (b) Unless otherwise stated, any time period scheduled, under the TR 
NOX Annual Trading Program, to begin before the occurrence of 
an act or event shall be computed so that the period ends the day before 
the act or event occurs.
    (c) Unless otherwise stated, if the final day of any time period, 
under the TR NOX Annual Trading Program, is not a business 
day, the time period shall be extended to the next business day.

[[Page 359]]



Sec. 97.408  Administrative appeal procedures.

    The administrative appeal procedures for decisions of the 
Administrator under the TR NOX Annual Trading Program are set 
forth in part 78 of this chapter.



Sec. 97.409  [Reserved]



Sec. 97.410  State NOX Annual trading budgets, new unit set-asides,
Indian country new unit set-aside, and variability limits.

    (a) The State NOX Annual trading budgets, new unit set-
asides, and Indian country new unit-set asides for allocations of TR 
NOX Annual allowances for the control periods in 2015 and 
thereafter are as follows:
    (1) Alabama. (i) The NOX annual trading budget for 2015 
and 2016 is 72,691 tons.
    (ii) The NOX annual new unit set-aside for 2015 and 2016 
is 1,454 tons.
    (iii) [Reserved]
    (iv) The NOX annual trading budget for 2017 and 
thereafter is 71,962 tons.
    (v) The NOX annual new unit set-aside for 2017 and 
thereafter is 1,439 tons.
    (vi) [Reserved]
    (2) Georgia. (i) The NOX annual trading budget for 2015 
and 2016 is 62,010 tons.
    (ii) The NOX annual new unit set-aside for 2015 and 2016 
is 1,240 tons.
    (iii) [Reserved]
    (iv) The NOX annual trading budget for 2017 and 
thereafter is 53,738 tons.
    (v) The NOX annual new unit set-aside for 2017 and 
thereafter is 1,075 tons.
    (vi) [Reserved]
    (3) Illinois. (i) The NOX annual trading budget for 2015 
and 2016 is 47,872 tons.
    (ii) The NOX annual new unit set-aside for 2015 and 2016 
is 3,830 tons.
    (iii) [Reserved]
    (iv) The NOX annual trading budget for 2017 and 
thereafter is 47,872 tons.
    (v) The NOX annual new unit set-aside for 2017 and 
thereafter is 3,830 tons.
    (vi) [Reserved]
    (4) Indiana. (i) The NOX annual trading budget for 2015 
and 2016 is 109,726 tons.
    (ii) The NOX annual new unit set-aside for 2015 and 2016 
is 3,292 tons.
    (iii) [Reserved]
    (iv) The NOX annual trading budget for 2017 and 
thereafter is 108,424 tons.
    (v) The NOX annual new unit set-aside for 2017 and 
thereafter is 3,253 tons.
    (vi) [Reserved]
    (5) Iowa. (i) The NOX annual trading budget for 2015 and 
2016 is 38,335 tons.
    (ii) The NOX annual new unit set-aside for 2015 and 2016 
is 729 tons.
    (iii) The NOX annual Indian country new unit set-aside 
for 2015 and 2016 is 38 tons.
    (iv) The NOX annual trading budget for 2017 and 
thereafter is 37,498 tons.
    (v) The NOX annual new unit set-aside for 2017 and 
thereafter is 712 tons.
    (vi) The NOX annual Indian country new unit set-aside for 
2017 and thereafter is 38 tons.
    (6) Kansas. (i) The NOX annual trading budget for 2015 
and 2016 is 31,354 tons.
    (ii) The NOX annual new unit set-aside for 2015 and 2016 
is 596 tons.
    (iii) The NOX annual Indian country new unit set-aside 
for 2015 and 2016 is 31 tons.
    (iv) The NOX annual trading budget for 2017 and 
thereafter is 31,354 tons.
    (v) The NOX annual new unit set-aside for 2017 and 
thereafter is 596 tons.
    (vi) The NOX annual Indian country new unit set-aside for 
2017 and thereafter is 31 tons.
    (7) Kentucky. (i) The NOX annual trading budget for 2015 
and 2016 is 85,086 tons.
    (ii) The NOX annual new unit set-aside for 2015 and 2016 
is 3,403 tons.
    (iii) [Reserved]
    (iv) The NOX annual trading budget for 2017 and 
thereafter is 77,238 tons.
    (v) The NOX annual new unit set-aside for 2017 and 
thereafter is 3,090 tons.
    (vi) [Reserved]
    (8) Maryland. (i) The NOX annual trading budget for 2015 
and 2016 is 16,633 tons.
    (ii) The NOX annual new unit set-aside for 2015 and 2016 
is 333 tons.
    (iii) [Reserved]
    (iv) The NOX annual trading budget for 2017 and 
thereafter is 16,574 tons.
    (v) The NOX annual new unit set-aside for 2017 and 
thereafter is 331 tons.
    (vi) [Reserved]

[[Page 360]]

    (9) Michigan. (i) The NOX annual trading budget for 2015 
and 2016 is 65,421 tons.
    (ii) The NOX annual new unit set-aside for 2015 and 2016 
is 1,243 tons.
    (iii) The NOX annual Indian country new unit set-aside 
for 2015 and 2016 is 65 tons.
    (iv) The NOX annual trading budget for 2017 and 
thereafter is 63,040 tons.
    (v) The NOX annual new unit set-aside for 2017 and 
thereafter is 1,198 tons.
    (vi) The NOX annual Indian country new unit set-aside for 
2017 and thereafter is 63 tons.
    (10) Minnesota. (i) The NOX annual trading budget for 
2015 and 2016 is 29,572 tons.
    (ii) The NOX annual new unit set-aside for 2015 and 2016 
is 561 tons.
    (iii) The NOX annual Indian country new unit set-aside 
for 2015 and 2016 is 30 tons.
    (iv) The NOX annual trading budget for 2017 and 
thereafter is 29,572 tons.
    (v) The NOX annual new unit set-aside for 2017 and 
thereafter is 561 tons.
    (vi) The NOX annual Indian country new unit set-aside for 
2017 and thereafter is 30 tons.
    (11) Missouri. (i) The NOX annual trading budget for 2015 
and 2016 is 52,400 tons.
    (ii) The NOX annual new unit set-aside for 2015 is 1,572 
tons and for 2016 is 3,144 tons.
    (iii) [Reserved]
    (iv) The NOX annual trading budget for 2017 and 
thereafter is 48,743 tons.
    (v) The NOX annual new unit set-aside for 2017 and 
thereafter is 2,925 tons.
    (12) Nebraska. (i) The NOX annual trading budget for 2015 
and 2016 is 30,039 tons.
    (ii) The NOX annual new unit set-aside for 2015 and 2016 
is 1,772 tons.
    (iii) The NOX annual Indian country new unit set-aside 
for 2015 and 2016 is 30 tons.
    (iv) The NOX annual trading budget for 2017 and 
thereafter is 30,039 tons.
    (v) The NOX annual new unit set-aside for 2017 and 
thereafter is 1,772 tons.
    (vi) The NOX annual Indian country new unit set-aside for 
2017 and thereafter is 30 tons.
    (13) New Jersey. (i) The NOX annual trading budget for 
2015 and 2016 is 8,218 tons.
    (ii) The NOX annual new unit set-aside for 2015 and 2016 
is 164 tons.
    (iii) [Reserved]
    (iv) The NOX annual trading budget for 2017 and 
thereafter is 7,945 tons.
    (v) The NOX annual new unit set-aside for 2017 and 
thereafter is 159 tons.
    (vi) [Reserved]
    (14) New York. (i) The NOX annual trading budget for 2015 
and 2016 is 21,722 tons.
    (ii) The NOX annual new unit set-aside for 2015 and 2016 
is 412 tons.
    (iii) The NOX annual Indian country new unit set-aside 
for 2015 and 2016 is 22 tons.
    (iv) The NOX annual trading budget for 2017 and 
thereafter is 21,722 tons.
    (v) The NOX annual new unit set-aside for 2017 and 
thereafter is 412 tons.
    (vi) The NOX annual Indian country new unit set-aside for 
2017 and thereafter is 22 tons.
    (15) North Carolina. (i) The NOX annual trading budget 
for 2015 and 2016 is 50,587 tons.
    (ii) The NOX annual new unit set-aside for 2015 and 2016 
is 2,984 tons.
    (iii) The NOX annual Indian country new unit set-aside 
for 2015 and 2016 is 51 tons.
    (iv) The NOX annual trading budget for 2017 and 
thereafter is 41,553 tons.
    (v) The NOX annual new unit set-aside for 2017 and 
thereafter is 2,451 tons.
    (vi) The NOX annual Indian country new unit set-aside for 
2017 and thereafter is 42 tons.
    (16) Ohio. (i) The NOX annual trading budget for 2015 and 
2016 is 95,468 tons.
    (ii) The NOX annual new unit set-aside for 2015 and 2016 
is 1,909 tons.
    (iii) [Reserved]
    (iv) The NOX annual trading budget for 2017 and 
thereafter is 90,258 tons.
    (v) The NOX annual new unit set-aside for 2017 and 
thereafter is 1,805 tons.
    (17) Pennsylvania. (i) The NOX annual trading budget for 
2015 and 2016 is 119,986 tons.
    (ii) The NOX annual new unit set-aside for 2015 and 2016 
is 2,400 tons.
    (iii) [Reserved]

[[Page 361]]

    (iv) The NOX annual trading budget for 2017 and 
thereafter is 119,194 tons.
    (v) The NOX annual new unit set-aside for 2017 and 
thereafter is 2,384 tons.
    (vi) [Reserved]
    (18) South Carolina. (i) The NOX annual trading budget 
for 2015 and 2016 is 32,498 tons.
    (ii) The NOX annual new unit set-aside for 2015 and 2016 
is 617 tons.
    (iii) The NOX annual Indian country new unit set-aside 
for 2015 and 2016 is 33 tons.
    (iv) The NOX annual trading budget for 2017 and 
thereafter is 32,498 tons.
    (v) The NOX annual new unit set-aside for 2017 and 
thereafter is 617 tons.
    (vi) The NOX annual Indian country new unit set-aside for 
2017 and thereafter is 33 tons.
    (19) Tennessee. (i) The NOX annual trading budget for 
2015 and 2016 is 35,703 tons.
    (ii) The NOX annual new unit set-aside for 2015 and 2016 
is 714 tons.
    (iii) [Reserved]
    (iv) The NOX annual trading budget for 2017 and 
thereafter is 19,337 tons.
    (v) The NOX annual new unit set-aside for 2017 and 
thereafter is 387 tons.
    (vi) [Reserved]
    (20) Texas. (i) The NOX annual trading budget for 2015 
and 2016 is 137,701 tons.
    (ii) The NOX annual new unit set-aside for 2015 and 2016 
is 5,370 tons.
    (iii) The NOX annual Indian country new unit set-aside 
for 2015 and 2016 is 138 tons.
    (iv) The NOX annual trading budget for 2017 and 
thereafter is 137,701 tons.
    (v) The NOX annual new unit set-aside for 2017 and 
thereafter is 5,370 tons.
    (vi) The NOX annual Indian country new unit set-aside for 
2017 and thereafter is 138 tons.
    (21) Virginia. (i) The NOX annual trading budget for 2015 
and 2016 is 33,242 tons.
    (ii) The NOX annual new unit set-aside for 2015 and 2016 
is 1,662 tons.
    (iii) [Reserved]
    (iv) The NOX annual trading budget for 2017 and 
thereafter is 33,242 tons.
    (v) The NOX annual new unit set-aside for 2017 and 
thereafter is 1,662 tons.
    (vi) [Reserved]
    (22) West Virginia. (i) The NOX annual trading budget for 
2015 and 2016 is 59,472 tons.
    (ii) The NOX annual new unit set-aside for 2015 and 2016 
is 2,974 tons.
    (iii) [Reserved]
    (iv) The NOX annual trading budget for 2017 and 
thereafter is 54,582 tons.
    (v) The NOX annual new unit set-aside for 2017 and 
thereafter is 2,729 tons.
    (vi) [Reserved]
    (23) Wisconsin. (i) The NOX annual trading budget for 
2015 and 2016 is 34,101 tons.
    (ii) The NOX annual new unit set-aside for 2015 and 2016 
is 2,012 tons.
    (iii) The NOX annual Indian country new unit set-aside 
for 2015 and 2016 is 34 tons.
    (iv) The NOX annual trading budget for 2017 and 
thereafter is 32,871 tons.
    (v) The NOX annual new unit set-aside for 2017 and 
thereafter is 1,939 tons.
    (vi) The NOX annual Indian country new unit set-aside for 
2017 and thereafter is 33 tons.
    (b) The States' variability limits for the State NOX 
Annual trading budgets for the control periods in 2017 and thereafter 
are as follows:
    (1) The NOX annual variability limit for Alabama is 
12,953 tons.
    (2) The NOX annual variability limit for Georgia is 9,673 
tons.
    (3) The NOX annual variability limit for Illinois is 
8,617 tons.
    (4) The NOX annual variability limit for Indiana is 
19,516 tons.
    (5) The NOX annual variability limit for Iowa is 6,750 
tons.
    (6) The NOX annual variability limit for Kansas is 5,644 
tons.
    (7) The NOX annual variability limit for Kentucky is 
13,903 tons.
    (8) The NOX annual variability limit for Maryland is 
2,983 tons.
    (9) The NOX annual variability limit for Michigan is 
11,347 tons.
    (10) The NOX annual variability limit for Minnesota is 
5,323 tons.
    (11) The NOX annual variability limit for Missouri is 
8,774 tons.
    (12) The NOX annual variability limit for Nebraska is 
5,407 tons.
    (13) The NOX annual variability limit for New Jersey is 
1,430 tons.

[[Page 362]]

    (14) The NOX annual variability limit for New York is 
3,910 tons.
    (15) The NOX annual variability limit for North Carolina 
is 7,480 tons.
    (16) The NOX annual variability limit for Ohio is 16,246 
tons.
    (17) The NOX annual variability limit for Pennsylvania is 
21,455 tons.
    (18) The NOX annual variability limit for South Carolina 
is 5,850 tons.
    (19) The NOX annual variability limit for Tennessee is 
3,481 tons.
    (20) The NOX annual variability limit for Texas is 24,786 
tons.
    (21) The NOX annual variability limit for Virginia is 
5,984 tons.
    (22) The NOX annual variability limit for West Virginia 
is 9,825 tons.
    (23) The NOX annual variability limit for Wisconsin is 
5,917 tons.
    (c) Each NOX annual trading budget identified in this 
section includes any tons in a new unit set aside or Indian country new 
unit set aside, but does not include any tons in a variability limit.

[77 FR 10334, Feb. 21, 2012, as amended at 77 FR 10347, Feb. 21, 2012; 
77 FR 34844, June 12, 2012; 79 FR 71672, Dec. 3, 2014]



Sec. 97.411  Timing requirements for TR NOX Annual allowance 
allocations.

    (a) Existing units. (1) TR NOX Annual allowances are 
allocated, for the control periods in 2015 and each year thereafter, as 
provided in a notice of data availability issued by the Administrator. 
Providing an allocation to a unit in such notice does not constitute a 
determination that the unit is a TR NOX Annual unit, and not 
providing an allocation to a unit in such notice does not constitute a 
determination that the unit is not a TR NOX Annual unit.
    (2) Notwithstanding paragraph (a)(1) of this section, if a unit 
provided an allocation in the notice of data availability issued under 
paragraph (a)(1) of this section does not operate, starting after 2014, 
during the control period in two consecutive years, such unit will not 
be allocated the TR NOX Annual allowances provided in such 
notice for the unit for the control periods in the fifth year after the 
first such year and in each year after that fifth year. All TR 
NOX Annual allowances that would otherwise have been 
allocated to such unit will be allocated to the new unit set-aside for 
the State where such unit is located and for the respective years 
involved. If such unit resumes operation, the Administrator will 
allocate TR NOX Annual allowances to the unit in accordance 
with paragraph (b) of this section.
    (b) New units. (1) New unit set-asides. (i) By June 1, 2015 and June 
1 of each year thereafter, the Administrator will calculate the TR 
NOX Annual allowance allocation to each TR NOX 
Annual unit in a State, in accordance with Sec. 97.412(a)(2) through 
(7) and (12), for the control period in the year of the applicable 
calculation deadline under this paragraph and will promulgate a notice 
of data availability of the results of the calculations.
    (ii) For each notice of data availability required in paragraph 
(b)(1)(i) of this section, the Administrator will provide an opportunity 
for submission of objections to the calculations referenced in such 
notice.
    (A) Objections shall be submitted by the deadline specified in each 
notice of data availability required in paragraph (b)(1)(i) of this 
section and shall be limited to addressing whether the calculations 
(including the identification of the TR NOX Annual units) are 
in accordance with Sec. 97.412(a)(2) through (7) and (12) and 
Sec. Sec. 97.406(b)(2) and 97.430 through 97.435.
    (B) The Administrator will adjust the calculations to the extent 
necessary to ensure that they are in accordance with the provisions 
referenced in paragraph (b)(1)(ii)(A) of this section. By August 1 
immediately after the promulgation of each notice of data availability 
required in paragraph (b)(1)(i) of this section, the Administrator will 
promulgate a notice of data availability of any adjustments that the 
Administrator determines to be necessary with regard to allocations 
under Sec. 97.412(a)(2) through (7) and (12) and the reasons for 
accepting or rejecting any objections submitted in accordance with 
paragraph (b)(1)(ii)(A) of this section.
    (iii) If the new unit set-aside for such control period contains any 
TR NOX Annual allowances that have not been allocated in the 
applicable notice of data availability required in paragraph

[[Page 363]]

(b)(1)(ii) of this section, the Administrator will promulgate, by 
December 15 immediately after such notice, a notice of data availability 
that identifies any TR NOX Annual units that commenced 
commercial operation during the period starting January 1 of the year 
before the year of such control period and ending November 30 of year of 
such control period.
    (iv) For each notice of data availability required in paragraph 
(b)(1)(iii) of this section, the Administrator will provide an 
opportunity for submission of objections to the identification of TR 
NOX annual units in such notice.
    (A) Objections shall be submitted by the deadline specified in each 
notice of data availability required in paragraph (b)(1)(iii) of this 
section and shall be limited to addressing whether the identification of 
TR NOX annual units in such notice is in accordance with 
paragraph (b)(1)(iii) of this section.
    (B) The Administrator will adjust the identification of TR 
NOX Annual units in the each notice of data availability 
required in paragraph (b)(1)(iii) of this section to the extent 
necessary to ensure that it is in accordance with paragraph (b)(1)(iii) 
of this section and will calculate the TR NOX Annual 
allowance allocation to each TR NOX Annual unit in accordance 
with Sec. 97.412(a)(9), (10), and (12) and Sec. Sec. 97.406(b)(2) and 
97.430 through 97.435. By February 15 immediately after the promulgation 
of each notice of data availability required in paragraph (b)(1)(iii) of 
this section, the Administrator will promulgate a notice of data 
availability of any adjustments of the identification of TR 
NOX Annual units that the Administrator determines to be 
necessary, the reasons for accepting or rejecting any objections 
submitted in accordance with paragraph (b)(1)(iv)(A) of this section, 
and the results of such calculations.
    (v) To the extent any TR NOX Annual allowances are added 
to the new unit set-aside after promulgation of each notice of data 
availability required in paragraph (b)(1)(iv) of this section, the 
Administrator will promulgate additional notices of data availability, 
as deemed appropriate, of the allocation of such TR NOX 
Annual allowances in accordance with Sec. 97.412(a)(10).
    (2) Indian country new unit set-asides. (i) By June 1, 2015 and June 
1 of each year thereafter, the Administrator will calculate the TR 
NOX Annual allowance allocation to each TR NOX 
Annual unit in Indian country within the borders of a State, in 
accordance with Sec. 97.412(b)(2) through (7) and (12), for the control 
period in the year of the applicable calculation deadline under this 
paragraph and will promulgate a notice of data availability of the 
results of the calculations.
    (ii) For each notice of data availability required in paragraph 
(b)(2)(i) of this section, the Administrator will provide an opportunity 
for submission of objections to the calculations referenced in such 
notice.
    (A) Objections shall be submitted by the deadline specified in each 
notice of data availability required in paragraph (b)(2)(i) of this 
section and shall be limited to addressing whether the calculations 
(including the identification of the TR NOX Annual units) are 
in accordance with Sec. 97.412(b)(2) through (7) and (12) and 
Sec. Sec. 97.406(b)(2) and 97.430 through 97.435.
    (B) The Administrator will adjust the calculations to the extent 
necessary to ensure that they are in accordance with the provisions 
referenced in paragraph (b)(2)(ii)(A) of this section. By August 1 
immediately after the promulgation of each notice of data availability 
required in paragraph (b)(2)(i) of this section, the Administrator will 
promulgate a notice of data availability of any adjustments that the 
Administrator determines to be necessary with regard to allocations 
under Sec. 97.412(b)(2) through (7) and (12) and the reasons for 
accepting or rejecting any objections submitted in accordance with 
paragraph (b)(2)(ii)(A) of this section.
    (iii) If the Indian country new unit set-aside for such control 
period contains any TR NOX Annual allowances that have not 
been allocated in the applicable notice of data availability required in 
paragraph (b)(2)(ii) of this section, the Administrator will promulgate, 
by December 15 immediately after such notice, a notice of data 
availability that identifies any TR NOX

[[Page 364]]

Annual units that commenced commercial operation during the period 
starting January 1 of the year before the year of such control period 
and ending November 30 of year of such control period.
    (iv) For each notice of data availability required in paragraph 
(b)(2)(iii) of this section, the Administrator will provide an 
opportunity for submission of objections to the identification of TR 
NOX annual units in such notice.
    (A) Objections shall be submitted by the deadline specified in each 
notice of data availability required in paragraph (b)(2)(iii) of this 
section and shall be limited to addressing whether the identification of 
TR NOX annual units in such notice is in accordance with 
paragraph (b)(2)(iii) of this section.
    (B) The Administrator will adjust the identification of TR 
NOX Annual units in the each notice of data availability 
required in paragraph (b)(2)(iii) of this section to the extent 
necessary to ensure that it is in accordance with paragraph (b)(2)(iii) 
of this section and will calculate the TR NOX Annual 
allowance allocation to each TR NOX Annual unit in accordance 
with Sec. 97.412(b)(9), (10), and (12) and Sec. Sec. 97.406(b)(2) and 
97.430 through 97.435. By February 15 immediately after the promulgation 
of each notice of data availability required in paragraph (b)(2)(iii) of 
this section, the Administrator will promulgate a notice of data 
availability of any adjustments of the identification of TR 
NOX Annual units that the Administrator determines to be 
necessary, the reasons for accepting or rejecting any objections 
submitted in accordance with paragraph (b)(2)(iv)(A) of this section, 
and the results of such calculations.
    (v) To the extent any TR NOX Annual allowances are added 
to the Indian country new unit set-aside after promulgation of each 
notice of data availability required in paragraph (b)(2)(iv) of this 
section, the Administrator will promulgate additional notices of data 
availability, as deemed appropriate, of the allocation of such TR 
NOX Annual allowances in accordance with Sec. 97.412(b)(10).
    (c) Units incorrectly allocated TR NOX Annual allowances. 
(1) For each control period in 2015 and thereafter, if the Administrator 
determines that TR NOX Annual allowances were allocated under 
paragraph (a) of this section, or under a provision of a SIP revision 
approved under Sec. 52.38(a)(3), (4), or (5) of this chapter, where 
such control period and the recipient are covered by the provisions of 
paragraph (c)(1)(i) of this section or were allocated under Sec. 
97.412(a)(2) through (7), (9), and (12) and (b)(2) through (7), (9), and 
(12), or under a provision of a SIP revision approved under Sec. 
52.38(a)(4) or (5) of this chapter, where such control period and the 
recipient are covered by the provisions of paragraph (c)(1)(ii) of this 
section, then the Administrator will notify the designated 
representative of the recipient and will act in accordance with the 
procedures set forth in paragraphs (c)(2) through (5) of this section:
    (i)(A) The recipient is not actually a TR NOX Annual unit 
under Sec. 97.404 as of January 1, 2015 and is allocated TR 
NOX Annual allowances for such control period or, in the case 
of an allocation under a provision of a SIP revision approved under 
Sec. 52.38(a)(3), (4), or (5) of this chapter, the recipient is not 
actually a TR NOX Annual unit as of January 1, 2015 and is 
allocated TR NOX Annual allowances for such control period 
that the SIP revision provides should be allocated only to recipients 
that are TR NOX Annual units as of January 1, 2015; or
    (B) The recipient is not located as of January 1 of the control 
period in the State from whose NOX Annual trading budget the 
TR NOX Annual allowances allocated under paragraph (a) of 
this section, or under a provision of a SIP revision approved under 
Sec. 52.38(a)(3), (4), or (5) of this chapter, were allocated for such 
control period.
    (ii) The recipient is not actually a TR NOX Annual unit 
under Sec. 97.404 as of January 1 of such control period and is 
allocated TR NOX Annual allowances for such control period 
or, in the case of an allocation under a provision of a SIP revision 
approved under Sec. 52.38(a)(3), (4), or (5) of this chapter, the 
recipient is not actually a TR NOX Annual unit as of January 
1 of such control period and is allocated TR NOX Annual 
allowances for such control period that the SIP revision provides

[[Page 365]]

should be allocated only to recipients that are TR NOX Annual 
units as of January 1 of such control period.
    (2) Except as provided in paragraph (c)(3) or (4) of this section, 
the Administrator will not record such TR NOX Annual 
allowances under Sec. 97.421.
    (3) If the Administrator already recorded such TR NOX 
Annual allowances under Sec. 97.421 and if the Administrator makes the 
determination under paragraph (c)(1) of this section before making 
deductions for the source that includes such recipient under Sec. 
97.424(b) for such control period, then the Administrator will deduct 
from the account in which such TR NOX Annual allowances were 
recorded an amount of TR NOX Annual allowances allocated for 
the same or a prior control period equal to the amount of such already 
recorded TR NOX Annual allowances. The authorized account 
representative shall ensure that there are sufficient TR NOX 
Annual allowances in such account for completion of the deduction.
    (4) If the Administrator already recorded such TR NOX 
Annual allowances under Sec. 97.421 and if the Administrator makes the 
determination under paragraph (c)(1) of this section after making 
deductions for the source that includes such recipient under Sec. 
97.424(b) for such control period, then the Administrator will not make 
any deduction to take account of such already recorded TR NOX 
Annual allowances.
    (5)(i) With regard to the TR NOX Annual allowances that 
are not recorded, or that are deducted as an incorrect allocation, in 
accordance with paragraphs (c)(2) and (3) of this section for a 
recipient under paragraph (c)(1)(i) of this section, the Administrator 
will:
    (A) Transfer such TR NOX Annual allowances to the new 
unit set-aside for such control period for the State from whose 
NOX Annual trading budget the TR NOX Annual 
allowances were allocated; or
    (B) If the State has a SIP revision approved under Sec. 52.38(a)(4) 
or (5) covering such control period, include such TR NOX 
Annual allowances in the portion of the State NOX Annual 
trading budget that may be allocated for such control period in 
accordance with such SIP revision.
    (ii) With regard to the TR NOX Annual allowances that 
were not allocated from the Indian country new unit set-aside for such 
control period and that are not recorded, or that are deducted as an 
incorrect allocation, in accordance with paragraphs (c)(2) and (3) of 
this section for a recipient under paragraph (c)(1)(ii) of this 
paragraph, the Administrator will:
    (A) Transfer such TR NOX Annual allowances to the new 
unit set-aside for such control period; or
    (B) If the State has a SIP revision approved under Sec. 52.38(a)(4) 
or (5) covering such control period, include such TR NOX 
Annual allowances in the portion of the State NOX Annual 
trading budget that may be allocated for such control period in 
accordance with such SIP revision.
    (iii) With regard to the TR NOX Annual allowances that 
were allocated from the Indian country new unit set-aside for such 
control period and that are not recorded, or that are deducted as an 
incorrect allocation, in accordance with paragraphs (c)(2) and (3) of 
this section for a recipient under paragraph (c)(1)(ii) of this 
paragraph, the Administrator will transfer such TR NOX Annual 
allowances to the Indian country new unit set-aside for such control 
period.

[76 FR 48379, Aug. 8, 2011, as amended at 79 FR 71672, Dec. 3, 2014]



Sec. 97.412  TR NOX Annual allowance allocations to new units.

    (a) For each control period in 2015 and thereafter and for the TR 
NOX Annual units in each State, the Administrator will 
allocate TR NOX Annual allowances to the TR NOX 
Annual units as follows:
    (1) The TR NOX Annual allowances will be allocated to the 
following TR NOX Annual units, except as provided in 
paragraph (a)(10) of this section:
    (i) TR NOX Annual units that are not allocated an amount 
of TR NOX Annual allowances in the notice of data 
availability issued under Sec. 97.411(a)(1);
    (ii) TR NOX Annual units whose allocation of an amount of 
TR NOX Annual allowances for such control period in the 
notice of data availability issued under Sec. 97.411(a)(1) is covered 
by Sec. 97.411(c)(2) or (3);

[[Page 366]]

    (iii) TR NOX Annual units that are allocated an amount of 
TR NOX Annual allowances for such control period in the 
notice of data availability issued under Sec. 97.411(a)(1), which 
allocation is terminated for such control period pursuant to Sec. 
97.411(a)(2), and that operate during the control period immediately 
preceding such control period; or
    (iv) For purposes of paragraph (a)(9) of this section, TR 
NOX Annual units under Sec. 97.411(c)(1)(ii) whose 
allocation of an amount of TR NOX Annual allowances for such 
control period in the notice of data availability issued under Sec. 
97.411(b)(1)(ii)(B) is covered by Sec. 97.411(c)(2) or (3).
    (2) The Administrator will establish a separate new unit set-aside 
for the State for each such control period. Each such new unit set-aside 
will be allocated TR NOX Annual allowances in an amount equal 
to the applicable amount of tons of NOX emissions as set 
forth in Sec. 97.410(a) and will be allocated additional TR 
NOX Annual allowances (if any) in accordance with Sec. Sec. 
97.411(a)(2) and (c)(5) and paragraph (b)(10) of this section.
    (3) The Administrator will determine, for each TR NOX 
Annual unit described in paragraph (a)(1) of this section, an allocation 
of TR NOX Annual allowances for the later of the following 
control periods and for each subsequent control period:
    (i) The control period in 2015;
    (ii) The first control period after the control period in which the 
TR NOX Annual unit commences commercial operation;
    (iii) For a unit described in paragraph (a)(1)(ii) of this section, 
the first control period in which the TR NOX Annual unit 
operates in the State after operating in another jurisdiction and for 
which the unit is not already allocated one or more TR NOX 
Annual allowances; and
    (iv) For a unit described in paragraph (a)(1)(iii) of this section, 
the first control period after the control period in which the unit 
resumes operation.
    (4)(i) The allocation to each TR NOX annual unit 
described in paragraph (a)(1)(i) through (iii) of this section and for 
each control period described in paragraph (a)(3) of this section will 
be an amount equal to the unit's total tons of NOX emissions 
during the immediately preceding control period.
    (ii) The Administrator will adjust the allocation amount in 
paragraph (a)(4)(i) in accordance with paragraphs (a)(5) through (7) and 
(12) of this section.
    (5) The Administrator will calculate the sum of the TR 
NOX Annual allowances determined for all such TR 
NOX Annual units under paragraph (a)(4)(i) of this section in 
the State for such control period.
    (6) If the amount of TR NOX Annual allowances in the new 
unit set-aside for the State for such control period is greater than or 
equal to the sum under paragraph (a)(5) of this section, then the 
Administrator will allocate the amount of TR NOX Annual 
allowances determined for each such TR NOX Annual unit under 
paragraph (a)(4)(i) of this section.
    (7) If the amount of TR NOX Annual allowances in the new 
unit set-aside for the State for such control period is less than the 
sum under paragraph (a)(5) of this section, then the Administrator will 
allocate to each such TR NOX Annual unit the amount of the TR 
NOX Annual allowances determined under paragraph (a)(4)(i) of 
this section for the unit, multiplied by the amount of TR NOX 
Annual allowances in the new unit set-aside for such control period, 
divided by the sum under paragraph (a)(5) of this section, and rounded 
to the nearest allowance.
    (8) The Administrator will notify the public, through the 
promulgation of the notices of data availability described in Sec. 
97.411(b)(1)(i) and (ii), of the amount of TR NOX Annual 
allowances allocated under paragraphs (a)(2) through (7) and (12) of 
this section for such control period to each TR NOX Annual 
unit eligible for such allocation.
    (9) If, after completion of the procedures under paragraphs (a)(5) 
through (8) of this section for such control period, any unallocated TR 
NOX Annual allowances remain in the new unit set-aside for 
the State for such control period, the Administrator will allocate such 
TR NOX Annual allowances as follows--
    (i) The Administrator will determine, for each unit described in 
paragraph

[[Page 367]]

(a)(1) of this section that commenced commercial operation during the 
period starting January 1 of the year before the year of such control 
period and ending November 30 of year of such control period, the 
positive difference (if any) between the unit's emissions during such 
control period and the amount of TR NOX Annual allowances 
referenced in the notice of data availability required under Sec. 
97.411(b)(1)(ii) for the unit for such control period;
    (ii) The Administrator will determine the sum of the positive 
differences determined under paragraph (a)(9)(i) of this section;
    (iii) If the amount of unallocated TR NOX Annual 
allowances remaining in the new unit set-aside for the State for such 
control period is greater than or equal to the sum determined under 
paragraph (a)(9)(ii) of this section, then the Administrator will 
allocate the amount of TR NOX Annual allowances determined 
for each such TR NOX Annual unit under paragraph (a)(9)(i) of 
this section; and
    (iv) If the amount of unallocated TR NOX Annual 
allowances remaining in the new unit set-aside for the State for such 
control period is less than the sum under paragraph (a)(9)(ii) of this 
section, then the Administrator will allocate to each such TR 
NOX Annual unit the amount of the TR NOX Annual 
allowances determined under paragraph (a)(9)(i) of this section for the 
unit, multiplied by the amount of unallocated TR NOX Annual 
allowances remaining in the new unit set-aside for such control period, 
divided by the sum under paragraph (a)(9)(ii) of this section, and 
rounded to the nearest allowance.
    (10) If, after completion of the procedures under paragraphs (a)(9) 
and (12) of this section for such control period, any unallocated TR 
NOX Annual allowances remain in the new unit set-aside for 
the State for such control period, the Administrator will allocate to 
each TR NOX Annual unit that is in the State, is allocated an 
amount of TR NOX Annual allowances in the notice of data 
availability issued under Sec. 97.411(a)(1), and continues to be 
allocated TR NOX Annual allowances for such control period in 
accordance with Sec. 97.411(a)(2), an amount of TR NOX 
Annual allowances equal to the following: the total amount of such 
remaining unallocated TR NOX Annual allowances in such new 
unit set-aside, multiplied by the unit's allocation under Sec. 
97.411(a) for such control period, divided by the remainder of the 
amount of tons in the applicable State NOX Annual trading 
budget minus the sum of the amounts of tons in such new unit set-aside 
and the Indian country new unit set-aside for the State for such control 
period, and rounded to the nearest allowance.
    (11) The Administrator will notify the public, through the 
promulgation of the notices of data availability described in Sec. 
97.411(b)(1)(iii), (iv), and (v), of the amount of TR NOX 
Annual allowances allocated under paragraphs (a)(9), (10), and (12) of 
this section for such control period to each TR NOX Annual 
unit eligible for such allocation.
    (12)(i) Notwithstanding the requirements of paragraphs (a)(2) 
through (11) of this section, if the calculations of allocations of a 
new unit set-aside for a control period in a given year under paragraph 
(a)(7) of this section, paragraphs (a)(6) and (9)(iv) of this section, 
or paragraphs (a)(6), (9)(iii), and (10) of this section would otherwise 
result in total allocations of such new unit set-aside exceeding the 
total amount of such new unit set-aside, then the Administrator will 
adjust the results of the calculations under paragraph (a)(7), (9)(iv), 
or (10) of this section, as applicable, as follows. The Administrator 
will list the TR NOX Annual units in descending order based 
on the amount of such units' allocations under paragraph (a)(7), 
(9)(iv), or (10) of this section, as applicable, and, in cases of equal 
allocation amounts, in alphabetical order of the relevant source's name 
and numerical order of the relevant unit's identification number, and 
will reduce each unit's allocation under paragraph (a)(7), (9)(iv), or 
(10) of this section, as applicable, by one TR NOX Annual 
allowance (but not below zero) in the order in which the units are 
listed and will repeat this reduction process as necessary, until the 
total allocations of such new unit set-aside equal the total amount of 
such new unit set-aside.

[[Page 368]]

    (ii) Notwithstanding the requirements of paragraphs (a)(10) and (11) 
of this section, if the calculations of allocations of a new unit set-
aside for a control period in a given year under paragraphs (a)(6), 
(9)(iii), and (10) of this section would otherwise result in a total 
allocations of such new unit set-aside less than the total amount of 
such new unit set-aside, then the Administrator will adjust the results 
of the calculations under paragraph (a)(10) of this section, as follows. 
The Administrator will list the TR NOX Annual units in 
descending order based on the amount of such units' allocations under 
paragraph (a)(10) of this section and, in cases of equal allocation 
amounts, in alphabetical order of the relevant source's name and 
numerical order of the relevant unit's identification number, and will 
increase each unit's allocation under paragraph (a)(10) of this section 
by one TR NOX Annual allowance in the order in which the 
units are listed and will repeat this increase process as necessary, 
until the total allocations of such new unit set-aside equal the total 
amount of such new unit set-aside.
    (b) For each control period in 2015 and thereafter and for the TR 
NOX Annual units located in Indian country within the borders 
of each State, the Administrator will allocate TR NOX Annual 
allowances to the TR NOX Annual units as follows:
    (1) The TR NOX Annual allowances will be allocated to the 
following TR NOX Annual units, except as provided in 
paragraph (b)(10) of this section:
    (i) TR NOX Annual units that are not allocated an amount 
of TR NOX Annual allowances in the notice of data 
availability issued under Sec. 97.411(a)(1); or
    (ii) For purposes of paragraph (b)(9) of this section, TR 
NOX Annual units under Sec. 97.411(c)(1)(ii) whose 
allocation of an amount of TR NOX Annual allowances for such 
control period in the notice of data availability issued under Sec. 
97.411(b)(2)(ii)(B) is covered by Sec. 97.411(c)(2) or (3).
    (2) The Administrator will establish a separate Indian country new 
unit set-aside for the State for each such control period. Each such 
Indian country new unit set-aside will be allocated TR NOX 
Annual allowances in an amount equal to the applicable amount of tons of 
NOX emissions as set forth in Sec. 97.410(a) and will be 
allocated additional TR NOX Annual allowances (if any) in 
accordance with Sec. 97.411(c)(5).
    (3) The Administrator will determine, for each TR NOX 
Annual unit described in paragraph (b)(1) of this section, an allocation 
of TR NOX Annual allowances for the later of the following 
control periods and for each subsequent control period:
    (i) The control period in 2015; and
    (ii) The first control period after the control period in which the 
TR NOX Annual unit commences commercial operation.
    (4)(i) The allocation to each TR NOX annual unit 
described in paragraph (b)(1)(i) of this section and for each control 
period described in paragraph (b)(3) of this section will be an amount 
equal to the unit's total tons of NOX emissions during the 
immediately preceding control period.
    (ii) The Administrator will adjust the allocation amount in 
paragraph (b)(4)(i) in accordance with paragraphs (b)(5) through (7) and 
(12) of this section.
    (5) The Administrator will calculate the sum of the TR 
NOX Annual allowances determined for all such TR 
NOX Annual units under paragraph (b)(4)(i) of this section in 
Indian country within the borders of the State for such control period.
    (6) If the amount of TR NOX Annual allowances in the 
Indian country new unit set-aside for the State for such control period 
is greater than or equal to the sum under paragraph (b)(5) of this 
section, then the Administrator will allocate the amount of TR 
NOX Annual allowances determined for each such TR 
NOX Annual unit under paragraph (b)(4)(i) of this section.
    (7) If the amount of TR NOX Annual allowances in the 
Indian country new unit set-aside for the State for such control period 
is less than the sum under paragraph (b)(5) of this section, then the 
Administrator will allocate to each such TR NOX Annual unit 
the amount of the TR NOX Annual allowances determined under 
paragraph (b)(4)(i) of this section for the unit, multiplied by the 
amount of TR NOX

[[Page 369]]

Annual allowances in the Indian country new unit set-aside for such 
control period, divided by the sum under paragraph (b)(5) of this 
section, and rounded to the nearest allowance.
    (8) The Administrator will notify the public, through the 
promulgation of the notices of data availability described in Sec. 
97.411(b)(2)(i) and (ii), of the amount of TR NOX Annual 
allowances allocated under paragraphs (b)(2) through (7) and (12) of 
this section for such control period to each TR NOX Annual 
unit eligible for such allocation.
    (9) If, after completion of the procedures under paragraphs (b)(5) 
through (8) of this section for such control period, any unallocated TR 
NOX Annual allowances remain in the Indian country new unit 
set-aside for the State for such control period, the Administrator will 
allocate such TR NOX Annual allowances as follows--
    (i) The Administrator will determine, for each unit described in 
paragraph (b)(1) of this section that commenced commercial operation 
during the period starting January 1 of the year before the year of such 
control period and ending November 30 of year of such control period, 
the positive difference (if any) between the unit's emissions during 
such control period and the amount of TR NOX Annual 
allowances referenced in the notice of data availability required under 
Sec. 97.411(b)(2)(ii) for the unit for such control period;
    (ii) The Administrator will determine the sum of the positive 
differences determined under paragraph (b)(9)(i) of this section;
    (iii) If the amount of unallocated TR NOX Annual 
allowances remaining in the Indian country new unit set-aside for the 
State for such control period is greater than or equal to the sum 
determined under paragraph (b)(9)(ii) of this section, then the 
Administrator will allocate the amount of TR NOX Annual 
allowances determined for each such TR NOX Annual unit under 
paragraph (b)(9)(i) of this section; and
    (iv) If the amount of unallocated TR NOX Annual 
allowances remaining in the Indian country new unit set-aside for the 
State for such control period is less than the sum under paragraph 
(b)(9)(ii) of this section, then the Administrator will allocate to each 
such TR NOX Annual unit the amount of the TR NOX 
Annual allowances determined under paragraph (b)(9)(i) of this section 
for the unit, multiplied by the amount of unallocated TR NOX 
Annual allowances remaining in the Indian country new unit set-aside for 
such control period, divided by the sum under paragraph (b)(9)(ii) of 
this section, and rounded to the nearest allowance.
    (10) If, after completion of the procedures under paragraphs (b)(9) 
and (12) of this section for such control period, any unallocated TR 
NOX Annual allowances remain in the Indian country new unit 
set-aside for the State for such control period, the Administrator will:
    (i) Transfer such unallocated TR NOX Annual allowances to 
the new unit set-aside for the State for such control period; or
    (ii) If the State has a SIP revision approved under Sec. 
52.38(a)(4) or (5) covering such control period, include such 
unallocated TR NOX Annual allowances in the portion of the 
State NOX Annual trading budget that may be allocated for 
such control period in accordance with such SIP revision.
    (11) The Administrator will notify the public, through the 
promulgation of the notices of data availability described in Sec. 
97.411(b)(2)(iii), (iv), and (v), of the amount of TR NOX 
Annual allowances allocated under paragraphs (b)(9), (10), and (12) of 
this section for such control period to each TR NOX Annual 
unit eligible for such allocation.
    (12)(i) Notwithstanding the requirements of paragraphs (b)(2) 
through (11) of this section, if the calculations of allocations of an 
Indian country new unit set-aside for a control period in a given year 
under paragraph (b)(7) of this section, paragraphs (b)(6) and (9)(iv) of 
this section, or paragraphs (b)(6), (9)(iii), and (10) of this section 
would otherwise result in total allocations of such Indian country new 
unit set-aside exceeding the total amount of such Indian country new 
unit set-aside, then the Administrator will adjust the

[[Page 370]]

results of the calculations under paragraph (b)(7), (9)(iv), or (10) of 
this section, as applicable, as follows. The Administrator will list the 
TR NOX Annual units in descending order based on the amount 
of such units' allocations under paragraph (b)(7), (9)(iv), or (10) of 
this section, as applicable, and, in cases of equal allocation amounts, 
in alphabetical order of the relevant source's name and numerical order 
of the relevant unit's identification number, and will reduce each 
unit's allocation under paragraph (b)(7), (9)(iv), or (10) of this 
section, as applicable, by one TR NOX Annual allowance (but 
not below zero) in the order in which the units are listed and will 
repeat this reduction process as necessary, until the total allocations 
of such Indian country new unit set-aside equal the total amount of such 
Indian country new unit set-aside.
    (ii) Notwithstanding the requirements of paragraphs (b)(10) and (11) 
of this section, if the calculations of allocations of an Indian country 
new unit set-aside for a control period in a given year under paragraphs 
(b)(6), (9)(iii), and (10) of this section would otherwise result in a 
total allocations of such Indian country new unit set-aside less than 
the total amount of such Indian country new unit set-aside, then the 
Administrator will adjust the results of the calculations under 
paragraph (b)(10) of this section, as follows. The Administrator will 
list the TR NOX Annual units in descending order based on the 
amount of such units' allocations under paragraph (b)(10) of this 
section and, in cases of equal allocation amounts, in alphabetical order 
of the relevant source's name and numerical order of the relevant unit's 
identification number, and will increase each unit's allocation under 
paragraph (b)(10) of this section by one TR NOX Annual 
allowance in the order in which the units are listed and will repeat 
this increase process as necessary, until the total allocations of such 
Indian country new unit set-aside equal the total amount of such Indian 
country new unit set-aside.

[76 FR 48379, Aug. 8, 2011, as amended at 79 FR 71672, Dec. 3, 2014]



Sec. 97.413  Authorization of designated representative and alternate
designated representative.

    (a) Except as provided under Sec. 97.415, each TR NOX 
Annual source, including all TR NOX Annual units at the 
source, shall have one and only one designated representative, with 
regard to all matters under the TR NOX Annual Trading 
Program.
    (1) The designated representative shall be selected by an agreement 
binding on the owners and operators of the source and all TR 
NOX Annual units at the source and shall act in accordance 
with the certification statement in Sec. 97.416(a)(4)(iii).
    (2) Upon and after receipt by the Administrator of a complete 
certificate of representation under Sec. 97.416:
    (i) The designated representative shall be authorized and shall 
represent and, by his or her representations, actions, inactions, or 
submissions, legally bind each owner and operator of the source and each 
TR NOX Annual unit at the source in all matters pertaining to 
the TR NOX Annual Trading Program, notwithstanding any 
agreement between the designated representative and such owners and 
operators; and
    (ii) The owners and operators of the source and each TR 
NOX Annual unit at the source shall be bound by any decision 
or order issued to the designated representative by the Administrator 
regarding the source or any such unit.
    (b) Except as provided under Sec. 97.415, each TR NOX 
Annual source may have one and only one alternate designated 
representative, who may act on behalf of the designated representative. 
The agreement by which the alternate designated representative is 
selected shall include a procedure for authorizing the alternate 
designated representative to act in lieu of the designated 
representative.
    (1) The alternate designated representative shall be selected by an 
agreement binding on the owners and operators of the source and all TR 
NOX Annual units at the source and shall act in accordance 
with the certification statement in Sec. 97.416(a)(4)(iii).
    (2) Upon and after receipt by the Administrator of a complete 
certificate of representation under Sec. 97.416,

[[Page 371]]

    (i) The alternate designated representative shall be authorized;
    (ii) Any representation, action, inaction, or submission by the 
alternate designated representative shall be deemed to be a 
representation, action, inaction, or submission by the designated 
representative; and
    (iii) The owners and operators of the source and each TR 
NOX Annual unit at the source shall be bound by any decision 
or order issued to the alternate designated representative by the 
Administrator regarding the source or any such unit.
    (c) Except in this section, Sec. 97.402, and Sec. Sec. 97.414 
through 97.418, whenever the term ``designated representative'' (as 
distinguished from the term ``common designated representative'') is 
used in this subpart, the term shall be construed to include the 
designated representative or any alternate designated representative.



Sec. 97.414  Responsibilities of designated representative and 
alternate designated representative.

    (a) Except as provided under Sec. 97.418 concerning delegation of 
authority to make submissions, each submission under the TR 
NOX Annual Trading Program shall be made, signed, and 
certified by the designated representative or alternate designated 
representative for each TR NOX Annual source and TR 
NOX Annual unit for which the submission is made. Each such 
submission shall include the following certification statement by the 
designated representative or alternate designated representative: ``I am 
authorized to make this submission on behalf of the owners and operators 
of the source or units for which the submission is made. I certify under 
penalty of law that I have personally examined, and am familiar with, 
the statements and information submitted in this document and all its 
attachments. Based on my inquiry of those individuals with primary 
responsibility for obtaining the information, I certify that the 
statements and information are to the best of my knowledge and belief 
true, accurate, and complete. I am aware that there are significant 
penalties for submitting false statements and information or omitting 
required statements and information, including the possibility of fine 
or imprisonment.''
    (b) The Administrator will accept or act on a submission made for a 
TR NOX Annual source or a TR NOX Annual unit only 
if the submission has been made, signed, and certified in accordance 
with paragraph (a) of this section and Sec. 97.418.



Sec. 97.415  Changing designated representative and alternate
designated representative; changes in owners and operators; 
changes in units at the source.

    (a) Changing designated representative. The designated 
representative may be changed at any time upon receipt by the 
Administrator of a superseding complete certificate of representation 
under Sec. 97.416. Notwithstanding any such change, all 
representations, actions, inactions, and submissions by the previous 
designated representative before the time and date when the 
Administrator receives the superseding certificate of representation 
shall be binding on the new designated representative and the owners and 
operators of the TR NOX Annual source and the TR 
NOX Annual units at the source.
    (b) Changing alternate designated representative. The alternate 
designated representative may be changed at any time upon receipt by the 
Administrator of a superseding complete certificate of representation 
under Sec. 97.416. Notwithstanding any such change, all 
representations, actions, inactions, and submissions by the previous 
alternate designated representative before the time and date when the 
Administrator receives the superseding certificate of representation 
shall be binding on the new alternate designated representative, the 
designated representative, and the owners and operators of the TR 
NOX Annual source and the TR NOX Annual units at 
the source.
    (c) Changes in owners and operators. (1) In the event an owner or 
operator of a TR NOX Annual source or a TR NOX 
Annual unit at the source is not included in the list of owners and 
operators in the certificate of representation under Sec. 97.416, such 
owner or operator shall be deemed to be subject to and

[[Page 372]]

bound by the certificate of representation, the representations, 
actions, inactions, and submissions of the designated representative and 
any alternate designated representative of the source or unit, and the 
decisions and orders of the Administrator, as if the owner or operator 
were included in such list.
    (2) Within 30 days after any change in the owners and operators of a 
TR NOX Annual source or a TR NOX Annual unit at 
the source, including the addition or removal of an owner or operator, 
the designated representative or any alternate designated representative 
shall submit a revision to the certificate of representation under Sec. 
97.416 amending the list of owners and operators to reflect the change.
    (d) Changes in units at the source. Within 30 days of any change in 
which units are located at a TR NOX Annual source (including 
the addition or removal of a unit), the designated representative or any 
alternate designated representative shall submit a certificate of 
representation under Sec. 97.416 amending the list of units to reflect 
the change.
    (1) If the change is the addition of a unit that operated (other 
than for purposes of testing by the manufacturer before initial 
installation) before being located at the source, then the certificate 
of representation shall identify, in a format prescribed by the 
Administrator, the entity from whom the unit was purchased or otherwise 
obtained (including name, address, telephone number, and facsimile 
number (if any)), the date on which the unit was purchased or otherwise 
obtained, and the date on which the unit became located at the source.
    (2) If the change is the removal of a unit, then the certificate of 
representation shall identify, in a format prescribed by the 
Administrator, the entity to which the unit was sold or that otherwise 
obtained the unit (including name, address, telephone number, and 
facsimile number (if any)), the date on which the unit was sold or 
otherwise obtained, and the date on which the unit became no longer 
located at the source.



Sec. 97.416  Certificate of representation.

    (a) A complete certificate of representation for a designated 
representative or an alternate designated representative shall include 
the following elements in a format prescribed by the Administrator:
    (1) Identification of the TR NOX Annual source, and each 
TR NOX Annual unit at the source, for which the certificate 
of representation is submitted, including source name, source category 
and NAICS code (or, in the absence of a NAICS code, an equivalent code), 
State, plant code, county, latitude and longitude, unit identification 
number and type, identification number and nameplate capacity (in MWe, 
rounded to the nearest tenth) of each generator served by each such 
unit, actual or projected date of commencement of commercial operation, 
and a statement of whether such source is located in Indian Country. If 
a projected date of commencement of commercial operation is provided, 
the actual date of commencement of commercial operation shall be 
provided when such information becomes available.
    (2) The name, address, e-mail address (if any), telephone number, 
and facsimile transmission number (if any) of the designated 
representative and any alternate designated representative.
    (3) A list of the owners and operators of the TR NOX 
Annual source and of each TR NOX Annual unit at the source.
    (4) The following certification statements by the designated 
representative and any alternate designated representative--
    (i) ``I certify that I was selected as the designated representative 
or alternate designated representative, as applicable, by an agreement 
binding on the owners and operators of the source and each TR 
NOX Annual unit at the source.''
    (ii) ``I certify that I have all the necessary authority to carry 
out my duties and responsibilities under the TR NOX Annual 
Trading Program on behalf of the owners and operators of the source and 
of each TR NOX Annual unit at the source and that each such 
owner and operator shall be fully bound by my representations, actions, 
inactions, or submissions and by any decision or

[[Page 373]]

order issued to me by the Administrator regarding the source or unit.''
    (iii) ``Where there are multiple holders of a legal or equitable 
title to, or a leasehold interest in, a TR NOX Annual unit, 
or where a utility or industrial customer purchases power from a TR 
NOX Annual unit under a life-of-the-unit, firm power 
contractual arrangement, I certify that: I have given a written notice 
of my selection as the `designated representative' or `alternate 
designated representative', as applicable, and of the agreement by which 
I was selected to each owner and operator of the source and of each TR 
NOX Annual unit at the source; and TR NOX Annual 
allowances and proceeds of transactions involving TR NOX 
Annual allowances will be deemed to be held or distributed in proportion 
to each holder's legal, equitable, leasehold, or contractual reservation 
or entitlement, except that, if such multiple holders have expressly 
provided for a different distribution of TR NOX Annual 
allowances by contract, TR NOX Annual allowances and proceeds 
of transactions involving TR NOX Annual allowances will be 
deemed to be held or distributed in accordance with the contract.''
    (5) The signature of the designated representative and any alternate 
designated representative and the dates signed.
    (b) Unless otherwise required by the Administrator, documents of 
agreement referred to in the certificate of representation shall not be 
submitted to the Administrator. The Administrator shall not be under any 
obligation to review or evaluate the sufficiency of such documents, if 
submitted.



Sec. 97.417  Objections concerning designated representative and
alternate designated representative.

    (a) Once a complete certificate of representation under Sec. 97.416 
has been submitted and received, the Administrator will rely on the 
certificate of representation unless and until a superseding complete 
certificate of representation under Sec. 97.416 is received by the 
Administrator.
    (b) Except as provided in paragraph (a) of this section, no 
objection or other communication submitted to the Administrator 
concerning the authorization, or any representation, action, inaction, 
or submission, of a designated representative or alternate designated 
representative shall affect any representation, action, inaction, or 
submission of the designated representative or alternate designated 
representative or the finality of any decision or order by the 
Administrator under the TR NOX Annual Trading Program.
    (c) The Administrator will not adjudicate any private legal dispute 
concerning the authorization or any representation, action, inaction, or 
submission of any designated representative or alternate designated 
representative, including private legal disputes concerning the proceeds 
of TR NOX Annual allowance transfers.



Sec. 97.418  Delegation by designated representative and alternate
designated representative.

    (a) A designated representative may delegate, to one or more natural 
persons, his or her authority to make an electronic submission to the 
Administrator provided for or required under this subpart.
    (b) An alternate designated representative may delegate, to one or 
more natural persons, his or her authority to make an electronic 
submission to the Administrator provided for or required under this 
subpart.
    (c) In order to delegate authority to a natural person to make an 
electronic submission to the Administrator in accordance with paragraph 
(a) or (b) of this section, the designated representative or alternate 
designated representative, as appropriate, must submit to the 
Administrator a notice of delegation, in a format prescribed by the 
Administrator, that includes the following elements:
    (1) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of such designated representative 
or alternate designated representative;
    (2) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of each such natural person 
(referred to in this section as an ``agent'');
    (3) For each such natural person, a list of the type or types of 
electronic submissions under paragraph (a) or (b)

[[Page 374]]

of this section for which authority is delegated to him or her; and
    (4) The following certification statements by such designated 
representative or alternate designated representative:
    (i) ``I agree that any electronic submission to the Administrator 
that is made by an agent identified in this notice of delegation and of 
a type listed for such agent in this notice of delegation and that is 
made when I am a designated representative or alternate designated 
representative, as appropriate, and before this notice of delegation is 
superseded by another notice of delegation under 40 CFR 97.418(d) shall 
be deemed to be an electronic submission by me.''
    (ii) ``Until this notice of delegation is superseded by another 
notice of delegation under 40 CFR 97.418(d), I agree to maintain an e-
mail account and to notify the Administrator immediately of any change 
in my e-mail address unless all delegation of authority by me under 40 
CFR 97.418 is terminated.''.
    (d) A notice of delegation submitted under paragraph (c) of this 
section shall be effective, with regard to the designated representative 
or alternate designated representative identified in such notice, upon 
receipt of such notice by the Administrator and until receipt by the 
Administrator of a superseding notice of delegation submitted by such 
designated representative or alternate designated representative, as 
appropriate. The superseding notice of delegation may replace any 
previously identified agent, add a new agent, or eliminate entirely any 
delegation of authority.
    (e) Any electronic submission covered by the certification in 
paragraph (c)(4)(i) of this section and made in accordance with a notice 
of delegation effective under paragraph (d) of this section shall be 
deemed to be an electronic submission by the designated representative 
or alternate designated representative submitting such notice of 
delegation.



Sec. 97.419  [Reserved]



Sec. 97.420  Establishment of compliance accounts, assurance accounts,
and general accounts.

    (a) Compliance accounts. Upon receipt of a complete certificate of 
representation under Sec. 97.416, the Administrator will establish a 
compliance account for the TR NOX Annual source for which the 
certificate of representation was submitted, unless the source already 
has a compliance account. The designated representative and any 
alternate designated representative of the source shall be the 
authorized account representative and the alternate authorized account 
representative respectively of the compliance account.
    (b) Assurance accounts. The Administrator will establish assurance 
accounts for certain owners and operators and States in accordance with 
Sec. 97.425(b)(3).
    (c) General accounts. (1) Application for general account. (i) Any 
person may apply to open a general account, for the purpose of holding 
and transferring TR NOX Annual allowances, by submitting to 
the Administrator a complete application for a general account. Such 
application shall designate one and only one authorized account 
representative and may designate one and only one alternate authorized 
account representative who may act on behalf of the authorized account 
representative.
    (A) The authorized account representative and alternate authorized 
account representative shall be selected by an agreement binding on the 
persons who have an ownership interest with respect to TR NOX 
Annual allowances held in the general account.
    (B) The agreement by which the alternate authorized account 
representative is selected shall include a procedure for authorizing the 
alternate authorized account representative to act in lieu of the 
authorized account representative.
    (ii) A complete application for a general account shall include the 
following elements in a format prescribed by the Administrator:
    (A) Name, mailing address, e-mail address (if any), telephone 
number, and facsimile transmission number (if any)

[[Page 375]]

of the authorized account representative and any alternate authorized 
account representative;
    (B) An identifying name for the general account;
    (C) A list of all persons subject to a binding agreement for the 
authorized account representative and any alternate authorized account 
representative to represent their ownership interest with respect to the 
TR NOX Annual allowances held in the general account;
    (D) The following certification statement by the authorized account 
representative and any alternate authorized account representative: ``I 
certify that I was selected as the authorized account representative or 
the alternate authorized account representative, as applicable, by an 
agreement that is binding on all persons who have an ownership interest 
with respect to TR NOX Annual allowances held in the general 
account. I certify that I have all the necessary authority to carry out 
my duties and responsibilities under the TR NOX Annual 
Trading Program on behalf of such persons and that each such person 
shall be fully bound by my representations, actions, inactions, or 
submissions and by any decision or order issued to me by the 
Administrator regarding the general account.''
    (E) The signature of the authorized account representative and any 
alternate authorized account representative and the dates signed.
    (iii) Unless otherwise required by the Administrator, documents of 
agreement referred to in the application for a general account shall not 
be submitted to the Administrator. The Administrator shall not be under 
any obligation to review or evaluate the sufficiency of such documents, 
if submitted.
    (2) Authorization of authorized account representative and alternate 
authorized account representative. (i) Upon receipt by the Administrator 
of a complete application for a general account under paragraph (b)(1) 
of this section, the Administrator will establish a general account for 
the person or persons for whom the application is submitted, and upon 
and after such receipt by the Administrator:
    (A) The authorized account representative of the general account 
shall be authorized and shall represent and, by his or her 
representations, actions, inactions, or submissions, legally bind each 
person who has an ownership interest with respect to TR NOX 
Annual allowances held in the general account in all matters pertaining 
to the TR NOX Annual Trading Program, notwithstanding any 
agreement between the authorized account representative and such person.
    (B) Any alternate authorized account representative shall be 
authorized, and any representation, action, inaction, or submission by 
any alternate authorized account representative shall be deemed to be a 
representation, action, inaction, or submission by the authorized 
account representative.
    (C) Each person who has an ownership interest with respect to TR 
NOX Annual allowances held in the general account shall be 
bound by any decision or order issued to the authorized account 
representative or alternate authorized account representative by the 
Administrator regarding the general account.
    (ii) Except as provided in paragraph (c)(5) of this section 
concerning delegation of authority to make submissions, each submission 
concerning the general account shall be made, signed, and certified by 
the authorized account representative or any alternate authorized 
account representative for the persons having an ownership interest with 
respect to TR NOX Annual allowances held in the general 
account. Each such submission shall include the following certification 
statement by the authorized account representative or any alternate 
authorized account representative: ``I am authorized to make this 
submission on behalf of the persons having an ownership interest with 
respect to the TR NOX Annual allowances held in the general 
account. I certify under penalty of law that I have personally examined, 
and am familiar with, the statements and information submitted in this 
document and all its attachments. Based on my inquiry of those 
individuals with primary responsibility for obtaining the information, I 
certify that the statements and information are to the best of my 
knowledge and belief true, accurate, and complete. I am aware that there 
are

[[Page 376]]

significant penalties for submitting false statements and information or 
omitting required statements and information, including the possibility 
of fine or imprisonment.''
    (iii) Except in this section, whenever the term ``authorized account 
representative'' is used in this subpart, the term shall be construed to 
include the authorized account representative or any alternate 
authorized account representative.
    (3) Changing authorized account representative and alternate 
authorized account representative; changes in persons with ownership 
interest. (i) The authorized account representative of a general account 
may be changed at any time upon receipt by the Administrator of a 
superseding complete application for a general account under paragraph 
(c)(1) of this section. Notwithstanding any such change, all 
representations, actions, inactions, and submissions by the previous 
authorized account representative before the time and date when the 
Administrator receives the superseding application for a general account 
shall be binding on the new authorized account representative and the 
persons with an ownership interest with respect to the TR NOX 
Annual allowances in the general account.
    (ii) The alternate authorized account representative of a general 
account may be changed at any time upon receipt by the Administrator of 
a superseding complete application for a general account under paragraph 
(c)(1) of this section. Notwithstanding any such change, all 
representations, actions, inactions, and submissions by the previous 
alternate authorized account representative before the time and date 
when the Administrator receives the superseding application for a 
general account shall be binding on the new alternate authorized account 
representative, the authorized account representative, and the persons 
with an ownership interest with respect to the TR NOX Annual 
allowances in the general account.
    (iii)(A) In the event a person having an ownership interest with 
respect to TR NOX Annual allowances in the general account is 
not included in the list of such persons in the application for a 
general account, such person shall be deemed to be subject to and bound 
by the application for a general account, the representation, actions, 
inactions, and submissions of the authorized account representative and 
any alternate authorized account representative of the account, and the 
decisions and orders of the Administrator, as if the person were 
included in such list.
    (B) Within 30 days after any change in the persons having an 
ownership interest with respect to NOX Annual allowances in 
the general account, including the addition or removal of a person, the 
authorized account representative or any alternate authorized account 
representative shall submit a revision to the application for a general 
account amending the list of persons having an ownership interest with 
respect to the TR NOX Annual allowances in the general 
account to include the change.
    (4) Objections concerning authorized account representative and 
alternate authorized account representative. (i) Once a complete 
application for a general account under paragraph (c)(1) of this section 
has been submitted and received, the Administrator will rely on the 
application unless and until a superseding complete application for a 
general account under paragraph (b)(1) of this section is received by 
the Administrator.
    (ii) Except as provided in paragraph (c)(4)(i) of this section, no 
objection or other communication submitted to the Administrator 
concerning the authorization, or any representation, action, inaction, 
or submission of the authorized account representative or any alternate 
authorized account representative of a general account shall affect any 
representation, action, inaction, or submission of the authorized 
account representative or any alternate authorized account 
representative or the finality of any decision or order by the 
Administrator under the TR NOX Annual Trading Program.
    (iii) The Administrator will not adjudicate any private legal 
dispute concerning the authorization or any representation, action, 
inaction, or submission of the authorized account representative or any 
alternate authorized account representative of a general account, 
including private legal disputes

[[Page 377]]

concerning the proceeds of TR NOX Annual allowance transfers.
    (5) Delegation by authorized account representative and alternate 
authorized account representative. (i) An authorized account 
representative of a general account may delegate, to one or more natural 
persons, his or her authority to make an electronic submission to the 
Administrator provided for or required under this subpart.
    (ii) An alternate authorized account representative of a general 
account may delegate, to one or more natural persons, his or her 
authority to make an electronic submission to the Administrator provided 
for or required under this subpart.
    (iii) In order to delegate authority to a natural person to make an 
electronic submission to the Administrator in accordance with paragraph 
(c)(5)(i) or (ii) of this section, the authorized account representative 
or alternate authorized account representative, as appropriate, must 
submit to the Administrator a notice of delegation, in a format 
prescribed by the Administrator, that includes the following elements:
    (A) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of such authorized account 
representative or alternate authorized account representative;
    (B) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of each such natural person 
(referred to in this section as an ``agent'');
    (C) For each such natural person, a list of the type or types of 
electronic submissions under paragraph (c)(5)(i) or (ii) of this section 
for which authority is delegated to him or her;
    (D) The following certification statement by such authorized account 
representative or alternate authorized account representative: ``I agree 
that any electronic submission to the Administrator that is made by an 
agent identified in this notice of delegation and of a type listed for 
such agent in this notice of delegation and that is made when I am an 
authorized account representative or alternate authorized 
representative, as appropriate, and before this notice of delegation is 
superseded by another notice of delegation under 40 CFR 97.420(c)(5)(iv) 
shall be deemed to be an electronic submission by me.''; and
    (E) The following certification statement by such authorized account 
representative or alternate authorized account representative: ``Until 
this notice of delegation is superseded by another notice of delegation 
under 40 CFR 97.420(c)(5)(iv), I agree to maintain an e-mail account and 
to notify the Administrator immediately of any change in my e-mail 
address unless all delegation of authority by me under 40 CFR 
97.420(c)(5) is terminated.''.
    (iv) A notice of delegation submitted under paragraph (c)(5)(iii) of 
this section shall be effective, with regard to the authorized account 
representative or alternate authorized account representative identified 
in such notice, upon receipt of such notice by the Administrator and 
until receipt by the Administrator of a superseding notice of delegation 
submitted by such authorized account representative or alternate 
authorized account representative, as appropriate. The superseding 
notice of delegation may replace any previously identified agent, add a 
new agent, or eliminate entirely any delegation of authority.
    (v) Any electronic submission covered by the certification in 
paragraph (c)(5)(iii)(D) of this section and made in accordance with a 
notice of delegation effective under paragraph (c)(5)(iv) of this 
section shall be deemed to be an electronic submission by the designated 
representative or alternate designated representative submitting such 
notice of delegation.
    (6) Closing a general account. (i) The authorized account 
representative or alternate authorized account representative of a 
general account may submit to the Administrator a request to close the 
account. Such request shall include a correctly submitted TR 
NOX Annual allowance transfer under Sec. 97.422 for any TR 
NOX Annual allowances in the account to one or more other 
Allowance Management System accounts.
    (ii) If a general account has no TR NOX Annual allowance 
transfers to or from the account for a 12-month period or longer and 
does not contain any TR

[[Page 378]]

NOX Annual allowances, the Administrator may notify the 
authorized account representative for the account that the account will 
be closed after 30 days after the notice is sent. The account will be 
closed after the 30-day period unless, before the end of the 30-day 
period, the Administrator receives a correctly submitted TR 
NOX Annual allowance transfer under Sec. 97.422 to the 
account or a statement submitted by the authorized account 
representative or alternate authorized account representative 
demonstrating to the satisfaction of the Administrator good cause as to 
why the account should not be closed.
    (d) Account identification. The Administrator will assign a unique 
identifying number to each account established under paragraph (a), (b), 
or (c) of this section.
    (e) Responsibilities of authorized account representative and 
alternate authorized account representative. After the establishment of 
a compliance account or general account, the Administrator will accept 
or act on a submission pertaining to the account, including, but not 
limited to, submissions concerning the deduction or transfer of TR 
NOX Annual allowances in the account, only if the submission 
has been made, signed, and certified in accordance with Sec. Sec. 
97.414(a) and 97.418 or paragraphs (c)(2)(ii) and (c)(5) of this 
section.



Sec. 97.421  Recordation of TR NOX Annual allowance allocations 
and auction results.

    (a) By November 7, 2011, the Administrator will record in each TR 
NOX Annual source's compliance account the TR NOX 
Annual allowances allocated to the TR NOX Annual units at the 
source in accordance with Sec. 97.411(a) for the control period in 
2015.
    (b) By November 7, 2011, the Administrator will record in each TR 
NOX Annual source's compliance account the TR NOX 
Annual allowances allocated to the TR NOX Annual units at the 
source in accordance with Sec. 97.411(a) for the control period in 
2016, unless the State in which the source is located notifies the 
Administrator in writing by October 17, 2011 of the State's intent to 
submit to the Administrator a complete SIP revision by April 1, 2015 
meeting the requirements of Sec. 52.38(a)(3)(i) through (iv) of this 
chapter.
    (1) If, by April 1, 2015, the State does not submit to the 
Administrator such complete SIP revision, the Administrator will record 
by April 15, 2015 in each TR NOX Annual source's compliance 
account the TR NOX Annual allowances allocated to the TR 
NOX Annual units at the source in accordance with Sec. 
97.411(a) for the control period in 2016.
    (2) If the State submits to the Administrator by April 1, 2015, and 
the Administrator approves by October 1, 2015, such complete SIP 
revision, the Administrator will record by October 1, 2015 in each TR 
NOX Annual source's compliance account the TR NOX 
Annual allowances allocated to the TR NOX Annual units at the 
source as provided in such approved, complete SIP revision for the 
control period in 2016.
    (3) If the State submits to the Administrator by April 1, 2015, and 
the Administrator does not approve by October 1, 2015, such complete SIP 
revision, the Administrator will record by October 1, 2015 in each TR 
NOX Annual source's compliance account the TR NOX 
Annual allowances allocated to the TR NOX Annual units at the 
source in accordance with Sec. 97.411(a) for the control period in 
2016.
    (c) By July 1, 2016, the Administrator will record in each TR 
NOX Annual source's compliance account the TR NOX 
Annual allowances allocated to the TR NOX Annual units at the 
source, or in each appropriate Allowance Management System account the 
TR NOX Annual allowances auctioned to TR NOX 
Annual units, in accordance with Sec. 97.411(a), or with a SIP revision 
approved under Sec. 52.38(a)(4) or (5) of this chapter, for the control 
period in 2017 and 2018.
    (d) By July 1, 2017, the Administrator will record in each TR 
NOX Annual source's compliance account the TR NOX 
Annual allowances allocated to the TR NOX Annual units at the 
source, or in each appropriate Allowance Management System account the 
TR NOX Annual allowances auctioned to TR NOX 
Annual units, in accordance with

[[Page 379]]

Sec. 97.411(a), or with a SIP revision approved under Sec. 52.38(a)(4) 
or (5) of this chapter, for the control period in 2019 and 2020.
    (e) By July 1, 2018, the Administrator will record in each TR 
NOX Annual source's compliance account the TR NOX 
Annual allowances allocated to the TR NOX Annual units at the 
source, or in each appropriate Allowance Management System account the 
TR NOX Annual allowances auctioned to TR NOX 
Annual units, in accordance with Sec. 97.411(a), or with a SIP revision 
approved under Sec. 52.38(a)(4) or (5) of this chapter, for the control 
period in 2021 and 2022.
    (f) By July 1, 2019 and July 1 of each year thereafter, the 
Administrator will record in each TR NOX Annual source's 
compliance account the TR NOX Annual allowances allocated to 
the TR NOX Annual units at the source, or in each appropriate 
Allowance Management System account the TR NOX Annual 
allowances auctioned to TR NOX Annual units, in accordance 
with Sec. 97.411(a), or with a SIP revision approved under Sec. 
52.38(a)(4) or (5) of this chapter, for the control period in the fourth 
year after the year of the applicable recordation deadline under this 
paragraph.
    (g) By August 1, 2015 and August 1 of each year thereafter, the 
Administrator will record in each TR NOX Annual source's 
compliance account the TR NOX Annual allowances allocated to 
the TR NOX Annual units at the source, or in each appropriate 
Allowance Management System account the TR NOX Annual 
allowances auctioned to TR NOX Annual units, in accordance 
with Sec. 97.412(a)(2) through (8) and (12), or with a SIP revision 
approved under Sec. 52.38(a)(4) or (5) of this chapter, for the control 
period in the year of the applicable recordation deadline under this 
paragraph.
    (h) By August 1, 2015 and August 1 of each year thereafter, the 
Administrator will record in each TR NOX Annual source's 
compliance account the TR NOX Annual allowances allocated to 
the TR NOX Annual units at the source in accordance with 
Sec. 97.412(b)(2) through (8) and (12) for the control period in the 
year of the applicable recordation deadline under this paragraph.
    (i) By February 15, 2016 and February 15 of each year thereafter, 
the Administrator will record in each TR NOX Annual source's 
compliance account the TR NOX Annual allowances allocated to 
the TR NOX Annual units at the source in accordance with 
Sec. 97.412(a)(9) through (12), for the control period in the year 
before the year of the applicable recordation deadline under this 
paragraph.
    (j) By the date on which any allocation or auction results, other 
than an allocation or auction results described in paragraphs (a) 
through (i) of this section, of TR NOX Annual allowances to a 
recipient is made by or are submitted to the Administrator in accordance 
with Sec. 97.411 or Sec. 97.412 or with a SIP revision approved under 
Sec. 52.38(a)(4) or (5) of this chapter, the Administrator will record 
such allocation or auction results in the appropriate Allowance 
Management System account.
    (k) When recording the allocation or auction of TR NOX 
Annual allowances to a TR NOX Annual unit or other entity in 
an Allowance Management System account, the Administrator will assign 
each TR NOX Annual allowance a unique identification number 
that will include digits identifying the year of the control period for 
which the TR NOX Annual allowance is allocated or auctioned.

[76 FR 48379, Aug. 8, 2011, as amended at 79 FR 71672, Dec. 3, 2014]



Sec. 97.422  Submission of TR NOX Annual allowance transfers.

    (a) An authorized account representative seeking recordation of a TR 
NOX Annual allowance transfer shall submit the transfer to 
the Administrator.
    (b) A TR NOX Annual allowance transfer shall be correctly 
submitted if:
    (1) The transfer includes the following elements, in a format 
prescribed by the Administrator:
    (i) The account numbers established by the Administrator for both 
the transferor and transferee accounts;
    (ii) The serial number of each TR NOX Annual allowance 
that is in the transferor account and is to be transferred; and

[[Page 380]]

    (iii) The name and signature of the authorized account 
representative of the transferor account and the date signed; and
    (2) When the Administrator attempts to record the transfer, the 
transferor account includes each TR NOX Annual allowance 
identified by serial number in the transfer.



Sec. 97.423  Recordation of TR NOX Annual allowance transfers.

    (a) Within 5 business days (except as provided in paragraph (b) of 
this section) of receiving a TR NOX Annual allowance transfer 
that is correctly submitted under Sec. 97.422, the Administrator will 
record a TR NOX Annual allowance transfer by moving each TR 
NOX Annual allowance from the transferor account to the 
transferee account as specified in the transfer.
    (b) A TR NOX Annual allowance transfer to or from a 
compliance account that is submitted for recordation after the allowance 
transfer deadline for a control period and that includes any TR 
NOX Annual allowances allocated for any control period before 
such allowance transfer deadline will not be recorded until after the 
Administrator completes the deductions from such compliance account 
under Sec. 97.424 for the control period immediately before such 
allowance transfer deadline.
    (c) Where a TR NOX Annual allowance transfer is not 
correctly submitted under Sec. 97.422, the Administrator will not 
record such transfer.
    (d) Within 5 business days of recordation of a TR NOX 
Annual allowance transfer under paragraphs (a) and (b) of the section, 
the Administrator will notify the authorized account representatives of 
both the transferor and transferee accounts.
    (e) Within 10 business days of receipt of a TR NOX Annual 
allowance transfer that is not correctly submitted under Sec. 97.422, 
the Administrator will notify the authorized account representatives of 
both accounts subject to the transfer of:
    (1) A decision not to record the transfer, and
    (2) The reasons for such non-recordation.



Sec. 97.424  Compliance with TR NOX Annual emissions limitation.

    (a) Availability for deduction for compliance. TR NOX 
Annual allowances are available to be deducted for compliance with a 
source's TR NOX Annual emissions limitation for a control 
period in a given year only if the TR NOX Annual allowances:
    (1) Were allocated for such control period or a control period in a 
prior year; and
    (2) Are held in the source's compliance account as of the allowance 
transfer deadline for such control period.
    (b) Deductions for compliance. After the recordation, in accordance 
with Sec. 97.423, of TR NOX Annual allowance transfers 
submitted by the allowance transfer deadline for a control period in a 
given year, the Administrator will deduct from each source's compliance 
account TR NOX Annual allowances available under paragraph 
(a) of this section in order to determine whether the source meets the 
TR NOX Annual emissions limitation for such control period, 
as follows:
    (1) Until the amount of TR NOX Annual allowances deducted 
equals the number of tons of total NOX emissions from all TR 
NOX Annual units at the source for such control period; or
    (2) If there are insufficient TR NOX Annual allowances to 
complete the deductions in paragraph (b)(1) of this section, until no 
more TR NOX Annual allowances available under paragraph (a) 
of this section remain in the compliance account.
    (c)(1) Identification of TR NOX Annual allowances by serial number. 
The authorized account representative for a source's compliance account 
may request that specific TR NOX Annual allowances, 
identified by serial number, in the compliance account be deducted for 
emissions or excess emissions for a control period in a given year in 
accordance with paragraph (b) or (d) of this section. In order to be 
complete, such request shall be submitted to the Administrator by the 
allowance transfer deadline for such control period and include, in a 
format prescribed by the Administrator, the identification of the TR 
NOX Annual source and the appropriate serial numbers.

[[Page 381]]

    (2) First-in, first-out. The Administrator will deduct TR 
NOX Annual allowances under paragraph (b) or (d) of this 
section from the source's compliance account in accordance with a 
complete request under paragraph (c)(1) of this section or, in the 
absence of such request or in the case of identification of an 
insufficient amount of TR NOX Annual allowances in such 
request, on a first-in, first-out accounting basis in the following 
order:
    (i) Any TR NOX Annual allowances that were allocated to 
the units at the source and not transferred out of the compliance 
account, in the order of recordation; and then
    (ii) Any TR NOX Annual allowances that were allocated to 
any unit and transferred to and recorded in the compliance account 
pursuant to this subpart, in the order of recordation.
    (d) Deductions for excess emissions. After making the deductions for 
compliance under paragraph (b) of this section for a control period in a 
year in which the TR NOX Annual source has excess emissions, 
the Administrator will deduct from the source's compliance account an 
amount of TR NOX Annual allowances, allocated for a control 
period in a prior year or the control period in the year of the excess 
emissions or in the immediately following year, equal to two times the 
number of tons of the source's excess emissions.
    (e) Recordation of deductions. The Administrator will record in the 
appropriate compliance account all deductions from such an account under 
paragraphs (b) and (d) of this section.



Sec. 97.425  Compliance with TR NOX Annual assurance provisions.

    (a) Availability for deduction. TR NOX Annual allowances 
are available to be deducted for compliance with the TR NOX 
Annual assurance provisions for a control period in a given year by the 
owners and operators of a group of one or more TR NOX Annual 
sources and units in a State (and Indian country within the borders of 
such State) only if the TR NOX Annual allowances:
    (1) Were allocated for a control period in a prior year or the 
control period in the given year or in the immediately following year; 
and
    (2) Are held in the assurance account, established by the 
Administrator for such owners and operators of such group of TR 
NOX Annual sources and units in such State (and Indian 
country within the borders of such State) under paragraph (b)(3) of this 
section, as of the deadline established in paragraph (b)(4) of this 
section.
    (b) Deductions for compliance. The Administrator will deduct TR 
NOX Annual allowances available under paragraph (a) of this 
section for compliance with the TR NOX Annual assurance 
provisions for a State for a control period in a given year in 
accordance with the following procedures:
    (1) By June 1, 2018 and June 1 of each year thereafter, the 
Administrator will:
    (i) Calculate, for each State (and Indian country within the borders 
of such State), the total NOX emissions from all TR 
NOX Annual units at TR NOX Annual sources in the 
State (and Indian country within the borders of such State) during the 
control period in the year before the year of this calculation deadline 
and the amount, if any, by which such total NOX emissions 
exceed the State assurance level as described in Sec. 
97.406(c)(2)(iii); and
    (ii) Promulgate a notice of data availability of the results of the 
calculations required in paragraph (b)(1)(i) of this section, including 
separate calculations of the NOX emissions from each TR 
NOX Annual source.
    (2) For each notice of data availability required in paragraph 
(b)(1)(ii) of this section and for any State (and Indian country within 
the borders of such State) identified in such notice as having TR 
NOX Annual units with total NOX emissions 
exceeding the State assurance level for a control period in a given 
year, as described in Sec. 97.406(c)(2)(iii):
    (i) By July 1 immediately after the promulgation of such notice, the 
designated representative of each TR NOX Annual source in 
each such State (and Indian country within the borders of such State) 
shall submit a statement, in a format prescribed by the Administrator, 
providing for each TR NOX Annual unit (if any) at the source 
that operates during, but is not allocated an amount of TR 
NOX Annual allowances

[[Page 382]]

for, such control period, the unit's allowable NOX emission 
rate for such control period and, if such rate is expressed in lb per 
mmBtu, the unit's heat rate.
    (ii) By August 1 immediately after the promulgation of such notice, 
the Administrator will calculate, for each such State (and Indian 
country within the borders of such State) and such control period and 
each common designated representative for such control period for a 
group of one or more TR NOX Annual sources and units in the 
State (and Indian country within the borders of such State), the common 
designated representative's share of the total NOX emissions 
from all TR NOX Annual units at TR NOX Annual 
sources in the State (and Indian country within the borders of such 
State), the common designated representative's assurance level, and the 
amount (if any) of TR NOX Annual allowances that the owners 
and operators of such group of sources and units must hold in accordance 
with the calculation formula in Sec. 97.406(c)(2)(i) and will 
promulgate a notice of data availability of the results of these 
calculations.
    (iii) The Administrator will provide an opportunity for submission 
of objections to the calculations referenced by the notice of data 
availability required in paragraph (b)(2)(ii) of this section and the 
calculations referenced by the relevant notice of data availability 
required in paragraph (b)(1)(i) of this section.
    (A) Objections shall be submitted by the deadline specified in such 
notice and shall be limited to addressing whether the calculations 
referenced in the relevant notice required under paragraph (b)(1)(ii) of 
this section and referenced in the notice required under paragraph 
(b)(2)(ii) of this section are in accordance with Sec. 
97.406(c)(2)(iii), Sec. Sec. 97.406(b) and 97.430 through 97.435, the 
definitions of ``common designated representative'', ``common designated 
representative's assurance level'', and ``common designated 
representative's share'' in Sec. 97.402, and the calculation formula in 
Sec. 97.406(c)(2)(i).
    (B) The Administrator will adjust the calculations to the extent 
necessary to ensure that they are in accordance with the provisions 
referenced in paragraph (b)(2)(iii)(A) of this section. By October 1 
immediately after the promulgation of such notice, the Administrator 
will promulgate a notice of data availability of any adjustments that 
the Administrator determines to be necessary and the reasons for 
accepting or rejecting any objections submitted in accordance with 
paragraph (b)(2)(iii)(A) of this section.
    (3) For any State (and Indian country within the borders of such 
State) referenced in each notice of data availability required in 
paragraph (b)(2)(iii)(B) of this section as having TR NOX 
Annual units with total NOX emissions exceeding the State 
assurance level for a control period in a given year, the Administrator 
will establish one assurance account for each set of owners and 
operators referenced, in the notice of data availability required under 
paragraph (b)(2)(iii)(B) of this section, as all of the owners and 
operators of a group of TR NOX Annual sources and units in 
the State (and Indian country within the borders of such State) having a 
common designated representative for such control period and as being 
required to hold TR NOX Annual allowances.
    (4)(i) As of midnight of November 1 immediately after the 
promulgation of each notice of data availability required in paragraph 
(b)(2)(iii)(B) of this section, the owners and operators described in 
paragraph (b)(3) of this section shall hold in the assurance account 
established for the them and for the appropriate TR NOX 
Annual sources, TR NOX Annual units, and State (and Indian 
country within the borders of such State) under paragraph (b)(3) of this 
section a total amount of TR NOX Annual allowances, available 
for deduction under paragraph (a) of this section, equal to the amount 
such owners and operators are required to hold with regard to such 
sources, units and State (and Indian country within the borders of such 
State) as calculated by the Administrator and referenced in such notice.
    (ii) Notwithstanding the allowance-holding deadline specified in 
paragraph (b)(4)(i) of this section, if November 1 is

[[Page 383]]

not a business day, then such allowance-holding deadline shall be 
midnight of the first business day thereafter.
    (5) After November 1 (or the date described in paragraph (b)(4)(ii) 
of this section) immediately after the promulgation of each notice of 
data availability required in paragraph (b)(2)(iii)(B) of this section 
and after the recordation, in accordance with Sec. 97.423, of TR 
NOX Annual allowance transfers submitted by midnight of such 
date, the Administrator will determine whether the owners and operators 
described in paragraph (b)(3) of this section hold, in the assurance 
account for the appropriate TR NOX Annual sources, TR 
NOX Annual units, and State (and Indian country within the 
borders of such State) established under paragraph (b)(3) of this 
section, the amount of TR NOX Annual allowances available 
under paragraph (a) of this section that the owners and operators are 
required to hold with regard to such sources, units, and State (and 
Indian country within the borders of such State) as calculated by the 
Administrator and referenced in the notice required in paragraph 
(b)(2)(iii)(B) of this section.
    (6) Notwithstanding any other provision of this subpart and any 
revision, made by or submitted to the Administrator after the 
promulgation of the notice of data availability required in paragraph 
(b)(2)(iii)(B) of this section for a control period in a given year, of 
any data used in making the calculations referenced in such notice, the 
amounts of TR NOX Annual allowances that the owners and 
operators are required to hold in accordance with Sec. 97.406(c)(2)(i) 
for such control period shall continue to be such amounts as calculated 
by the Administrator and referenced in such notice required in paragraph 
(b)(2)(iii)(B) of this section, except as follows:
    (i) If any such data are revised by the Administrator as a result of 
a decision in or settlement of litigation concerning such data on appeal 
under part 78 of this chapter of such notice, or on appeal under section 
307 of the Clean Air Act of a decision rendered under part 78 of this 
chapter on appeal of such notice, then the Administrator will use the 
data as so revised to recalculate the amounts of TR NOX 
Annual allowances that owners and operators are required to hold in 
accordance with the calculation formula in Sec. 97.406(c)(2)(i) for 
such control period with regard to the TR NOX Annual sources, 
TR NOX Annual units, and State (and Indian country within the 
borders of such State) involved, provided that such litigation under 
part 78 of this chapter, or the proceeding under part 78 of this chapter 
that resulted in the decision appealed in such litigation under section 
307 of the Clean Air Act, was initiated no later than 30 days after 
promulgation of such notice required in paragraph (b)(2)(iii)(B) of this 
section.
    (ii) If any such data are revised by the owners and operators of a 
TR NOX Annual source and TR NOX Annual unit whose 
designated representative submitted such data under paragraph (b)(2)(i) 
of this section, as a result of a decision in or settlement of 
litigation concerning such submission, then the Administrator will use 
the data as so revised to recalculate the amounts of TR NOX 
Annual allowances that owners and operators are required to hold in 
accordance with the calculation formula in Sec. 97.406(c)(2)(i) for 
such control period with regard to the TR NOX Annual sources, 
TR NOX Annual units, and State (and Indian country within the 
borders of such State) involved, provided that such litigation was 
initiated no later than 30 days after promulgation of such notice 
required in paragraph (b)(2)(iii)(B) of this section.
    (iii) If the revised data are used to recalculate, in accordance 
with paragraphs (b)(6)(i) and (ii) of this section, the amount of TR 
NOX Annual allowances that the owners and operators are 
required to hold for such control period with regard to the TR 
NOX Annual sources, TR NOX Annual units, and State 
(and Indian country within the borders of such State) involved--
    (A) Where the amount of TR NOX Annual allowances that the 
owners and operators are required to hold increases as a result of the 
use of all such revised data, the Administrator will establish a new, 
reasonable deadline on which the owners and operators shall hold the 
additional amount of TR NOX

[[Page 384]]

Annual allowances in the assurance account established by the 
Administrator for the appropriate TR NOX Annual sources, TR 
NOX Annual units, and State (and Indian country within the 
borders of such State) under paragraph (b)(3) of this section. The 
owners' and operators' failure to hold such additional amount, as 
required, before the new deadline shall not be a violation of the Clean 
Air Act. The owners' and operators' failure to hold such additional 
amount, as required, as of the new deadline shall be a violation of the 
Clean Air Act. Each TR NOX Annual allowance that the owners 
and operators fail to hold as required as of the new deadline, and each 
day in such control period, shall be a separate violation of the Clean 
Air Act.
    (B) For the owners and operators for which the amount of TR 
NOX Annual allowances required to be held decreases as a 
result of the use of all such revised data, the Administrator will 
record, in all accounts from which TR NOX Annual allowances 
were transferred by such owners and operators for such control period to 
the assurance account established by the Administrator for the 
appropriate at TR NOX Annual sources, TR NOX 
Annual units, and State (and Indian country within the borders of such 
State) under paragraph (b)(3) of this section, a total amount of the TR 
NOX Annual allowances held in such assurance account equal to 
the amount of the decrease. If TR NOX Annual allowances were 
transferred to such assurance account from more than one account, the 
amount of TR NOX Annual allowances recorded in each such 
transferor account will be in proportion to the percentage of the total 
amount of TR NOX Annual allowances transferred to such 
assurance account for such control period from such transferor account.
    (C) Each TR NOX Annual allowance held under paragraph 
(b)(6)(iii)(A) of this section as a result of recalculation of 
requirements under the TR NOX Annual assurance provisions for 
such control period must be a TR NOX Annual allowance 
allocated for a control period in a year before or the year immediately 
following, or in the same year as, the year of such control period.

[76 FR 48379, Aug. 8, 2011, as amended at 77 FR 10336, Feb. 21, 2012; 79 
FR 71672, Dec. 3, 2014]



Sec. 97.426  Banking.

    (a) A TR NOX Annual allowance may be banked for future 
use or transfer in a compliance account or a general account in 
accordance with paragraph (b) of this section.
    (b) Any TR NOX Annual allowance that is held in a 
compliance account or a general account will remain in such account 
unless and until the TR NOX Annual allowance is deducted or 
transferred under Sec. 97.411(c), Sec. 97.423, Sec. 97.424, Sec. 
97.425, 97.427, or 97.428.



Sec. 97.427  Account error.

    The Administrator may, at his or her sole discretion and on his or 
her own motion, correct any error in any Allowance Management System 
account. Within 10 business days of making such correction, the 
Administrator will notify the authorized account representative for the 
account.



Sec. 97.428  Administrator's action on submissions.

    (a) The Administrator may review and conduct independent audits 
concerning any submission under the TR NOX Annual Trading 
Program and make appropriate adjustments of the information in the 
submission.
    (b) The Administrator may deduct TR NOX Annual allowances 
from or transfer TR NOX Annual allowances to a compliance 
account or an assurance account, based on the information in a 
submission, as adjusted under paragraph (a)(1) of this section, and 
record such deductions and transfers.



Sec. 97.429  [Reserved]



Sec. 97.430  General monitoring, recordkeeping, and reporting 
requirements.

    The owners and operators, and to the extent applicable, the 
designated representative, of a TR NOX Annual unit, shall 
comply with the monitoring, recordkeeping, and reporting requirements as 
provided in this subpart and subpart H of part 75 of this chapter.

[[Page 385]]

For purposes of applying such requirements, the definitions in Sec. 
97.402 and in Sec. 72.2 of this chapter shall apply, the terms 
``affected unit,'' ``designated representative,'' and ``continuous 
emission monitoring system'' (or ``CEMS'') in part 75 of this chapter 
shall be deemed to refer to the terms ``TR NOX Annual unit,'' 
``designated representative,'' and ``continuous emission monitoring 
system'' (or ``CEMS'') respectively as defined in Sec. 97.402, and the 
term ``newly affected unit'' shall be deemed to mean ``newly affected TR 
NOX Annual unit''. The owner or operator of a unit that is 
not a TR NOX Annual unit but that is monitored under Sec. 
75.72(b)(2)(ii) of this chapter shall comply with the same monitoring, 
recordkeeping, and reporting requirements as a TR NOX Annual 
unit.
    (a) Requirements for installation, certification, and data 
accounting. The owner or operator of each TR NOX Annual unit 
shall:
    (1) Install all monitoring systems required under this subpart for 
monitoring NOX mass emissions and individual unit heat input 
(including all systems required to monitor NOX emission rate, 
NOX concentration, stack gas moisture content, stack gas flow 
rate, CO2 or O2 concentration, and fuel flow rate, 
as applicable, in accordance with Sec. Sec. 75.71 and 75.72 of this 
chapter);
    (2) Successfully complete all certification tests required under 
Sec. 97.431 and meet all other requirements of this subpart and part 75 
of this chapter applicable to the monitoring systems under paragraph 
(a)(1) of this section; and
    (3) Record, report, and quality-assure the data from the monitoring 
systems under paragraph (a)(1) of this section.
    (b) Compliance deadlines. Except as provided in paragraph (e) of 
this section, the owner or operator shall meet the monitoring system 
certification and other requirements of paragraphs (a)(1) and (2) of 
this section on or before the following dates and shall record, report, 
and quality-assure the data from the monitoring systems under paragraph 
(a)(1) of this section on and after the following dates.
    (1) For the owner or operator of a TR NOX Annual unit 
that commences commercial operation before July 1, 2014, January 1, 
2015;
    (2) For the owner or operator of a TR NOX Annual unit 
that commences commercial operation on or after July 1, 2014, the later 
of the following:
    (i) January 1, 2015; or
    (ii) 180 calendar days after the date on which the unit commences 
commercial operation;
    (3) The owner or operator of a TR NOX Annual unit for 
which construction of a new stack or flue or installation of add-on 
NOX emission controls is completed after the applicable 
deadline under paragraph (b)(1) or (2) of this section shall meet the 
requirements of Sec. Sec. 75.4(e)(1) through (e)(4) of this chapter, 
except that:
    (i) Such requirements shall apply to the monitoring systems required 
under Sec. 97.430 through Sec. 97.435, rather than the monitoring 
systems required under part 75 of this chapter;
    (ii) NOX emission rate, NOX concentration, 
stack gas moisture content, stack gas volumetric flow rate, and 
O2 or CO2 concentration data shall be determined 
and reported, rather than the data listed in Sec. 75.4(e)(2) of this 
chapter; and
    (iii) Any petition for another procedure under Sec. 75.4(e)(2) of 
this chapter shall be submitted under Sec. 97.435, rather than Sec. 
75.66.
    (c) Reporting data. The owner or operator of a TR NOX 
Annual unit that does not meet the applicable compliance date set forth 
in paragraph (b) of this section for any monitoring system under 
paragraph (a)(1) of this section shall, for each such monitoring system, 
determine, record, and report maximum potential (or, as appropriate, 
minimum potential) values for NOX concentration, 
NOX emission rate, stack gas flow rate, stack gas moisture 
content, fuel flow rate, and any other parameters required to determine 
NOX mass emissions and heat input in accordance with Sec. 
75.31(b)(2) or (c)(3) of this chapter, section 2.4 of appendix D to part 
75 of this chapter, or section 2.5 of appendix E to part 75 of this 
chapter, as applicable.
    (d) Prohibitions. (1) No owner or operator of a TR NOX 
Annual unit shall use any alternative monitoring system, alternative 
reference method, or any

[[Page 386]]

other alternative to any requirement of this subpart without having 
obtained prior written approval in accordance with Sec. 97.435.
    (2) No owner or operator of a TR NOX Annual unit shall 
operate the unit so as to discharge, or allow to be discharged, 
NOX to the atmosphere without accounting for all such 
NOX in accordance with the applicable provisions of this 
subpart and part 75 of this chapter.
    (3) No owner or operator of a TR NOX Annual unit shall 
disrupt the continuous emission monitoring system, any portion thereof, 
or any other approved emission monitoring method, and thereby avoid 
monitoring and recording NOX mass discharged into the 
atmosphere or heat input, except for periods of recertification or 
periods when calibration, quality assurance testing, or maintenance is 
performed in accordance with the applicable provisions of this subpart 
and part 75 of this chapter.
    (4) No owner or operator of a TR NOX Annual unit shall 
retire or permanently discontinue use of the continuous emission 
monitoring system, any component thereof, or any other approved 
monitoring system under this subpart, except under any one of the 
following circumstances:
    (i) During the period that the unit is covered by an exemption under 
Sec. 97.405 that is in effect;
    (ii) The owner or operator is monitoring emissions from the unit 
with another certified monitoring system approved, in accordance with 
the applicable provisions of this subpart and part 75 of this chapter, 
by the Administrator for use at that unit that provides emission data 
for the same pollutant or parameter as the retired or discontinued 
monitoring system; or
    (iii) The designated representative submits notification of the date 
of certification testing of a replacement monitoring system for the 
retired or discontinued monitoring system in accordance with Sec. 
97.431(d)(3)(i).
    (e) Long-term cold storage. The owner or operator of a TR 
NOX Annual unit is subject to the applicable provisions of 
Sec. 75.4(d) of this chapter concerning units in long-term cold 
storage.

[76 FR 48379, Aug. 8, 2011, as amended at 79 FR 71672, Dec. 3, 2014]



Sec. 97.431  Initial monitoring system certification and 
recertification procedures.

    (a) The owner or operator of a TR NOX Annual unit shall 
be exempt from the initial certification requirements of this section 
for a monitoring system under Sec. 97.430(a)(1) if the following 
conditions are met:
    (1) The monitoring system has been previously certified in 
accordance with part 75 of this chapter; and
    (2) The applicable quality-assurance and quality-control 
requirements of Sec. 75.21 of this chapter and appendices B, D, and E 
to part 75 of this chapter are fully met for the certified monitoring 
system described in paragraph (a)(1) of this section.
    (b) The recertification provisions of this section shall apply to a 
monitoring system under Sec. 97.430(a)(1) that is exempt from initial 
certification requirements under paragraph (a) of this section.
    (c) If the Administrator has previously approved a petition under 
Sec. 75.17(a) or (b) of this chapter for apportioning the 
NOX emission rate measured in a common stack or a petition 
under Sec. 75.66 of this chapter for an alternative to a requirement in 
Sec. 75.12 or Sec. 75.17 of this chapter, the designated 
representative shall resubmit the petition to the Administrator under 
Sec. 97.435 to determine whether the approval applies under the TR 
NOX Annual Trading Program.
    (d) Except as provided in paragraph (a) of this section, the owner 
or operator of a TR NOX Annual unit shall comply with the 
following initial certification and recertification procedures for a 
continuous monitoring system (i.e., a continuous emission monitoring 
system and an excepted monitoring system under appendices D and E to 
part 75 of this chapter) under Sec. 97.430(a)(1). The owner or operator 
of a unit that qualifies to use the low mass emissions excepted 
monitoring methodology under Sec. 75.19 of this chapter or that 
qualifies to use an alternative monitoring system under subpart E of 
part 75 of this chapter shall comply with the procedures in paragraph 
(e) or (f) of this section respectively.

[[Page 387]]

    (1) Requirements for initial certification. The owner or operator 
shall ensure that each continuous monitoring system under Sec. 
97.430(a)(1) (including the automated data acquisition and handling 
system) successfully completes all of the initial certification testing 
required under Sec. 75.20 of this chapter by the applicable deadline in 
Sec. 97.430(b). In addition, whenever the owner or operator installs a 
monitoring system to meet the requirements of this subpart in a location 
where no such monitoring system was previously installed, initial 
certification in accordance with Sec. 75.20 of this chapter is 
required.
    (2) Requirements for recertification. Whenever the owner or operator 
makes a replacement, modification, or change in any certified continuous 
emission monitoring system under Sec. 97.430(a)(1) that may 
significantly affect the ability of the system to accurately measure or 
record NOX mass emissions or heat input rate or to meet the 
quality-assurance and quality-control requirements of Sec. 75.21 of 
this chapter or appendix B to part 75 of this chapter, the owner or 
operator shall recertify the monitoring system in accordance with Sec. 
75.20(b) of this chapter. Furthermore, whenever the owner or operator 
makes a replacement, modification, or change to the flue gas handling 
system or the unit's operation that may significantly change the stack 
flow or concentration profile, the owner or operator shall recertify 
each continuous emission monitoring system whose accuracy is potentially 
affected by the change, in accordance with Sec. 75.20(b) of this 
chapter. Examples of changes to a continuous emission monitoring system 
that require recertification include replacement of the analyzer, 
complete replacement of an existing continuous emission monitoring 
system, or change in location or orientation of the sampling probe or 
site. Any fuel flowmeter system, and any excepted NOX 
monitoring system under appendix E to part 75 of this chapter, under 
Sec. 97.430(a)(1) are subject to the recertification requirements in 
Sec. 75.20(g)(6) of this chapter.
    (3) Approval process for initial certification and recertification. 
For initial certification of a continuous monitoring system under Sec. 
97.430(a)(1), paragraphs (d)(3)(i) through (v) of this section apply. 
For recertifications of such monitoring systems, paragraphs (d)(3)(i) 
through (iv) of this section and the procedures in Sec. Sec. 
75.20(b)(5) and (g)(7) of this chapter (in lieu of the procedures in 
paragraph (d)(3)(v) of this section) apply, provided that in applying 
paragraphs (d)(3)(i) through (iv) of this section, the words 
``certification'' and ``initial certification'' are replaced by the word 
``recertification'' and the word ``certified'' is replaced by with the 
word ``recertified''.
    (i) Notification of certification. The designated representative 
shall submit to the appropriate EPA Regional Office and the 
Administrator written notice of the dates of certification testing, in 
accordance with Sec. 97.433.
    (ii) Certification application. The designated representative shall 
submit to the Administrator a certification application for each 
monitoring system. A complete certification application shall include 
the information specified in Sec. 75.63 of this chapter.
    (iii) Provisional certification date. The provisional certification 
date for a monitoring system shall be determined in accordance with 
Sec. 75.20(a)(3) of this chapter. A provisionally certified monitoring 
system may be used under the TR NOX Annual Trading Program 
for a period not to exceed 120 days after receipt by the Administrator 
of the complete certification application for the monitoring system 
under paragraph (d)(3)(ii) of this section. Data measured and recorded 
by the provisionally certified monitoring system, in accordance with the 
requirements of part 75 of this chapter, will be considered valid 
quality-assured data (retroactive to the date and time of provisional 
certification), provided that the Administrator does not invalidate the 
provisional certification by issuing a notice of disapproval within 120 
days of the date of receipt of the complete certification application by 
the Administrator.
    (iv) Certification application approval process. The Administrator 
will issue a written notice of approval or disapproval of the 
certification application to the owner or operator within

[[Page 388]]

120 days of receipt of the complete certification application under 
paragraph (d)(3)(ii) of this section. In the event the Administrator 
does not issue such a notice within such 120-day period, each monitoring 
system that meets the applicable performance requirements of part 75 of 
this chapter and is included in the certification application will be 
deemed certified for use under the TR NOX Annual Trading 
Program.
    (A) Approval notice. If the certification application is complete 
and shows that each monitoring system meets the applicable performance 
requirements of part 75 of this chapter, then the Administrator will 
issue a written notice of approval of the certification application 
within 120 days of receipt.
    (B) Incomplete application notice. If the certification application 
is not complete, then the Administrator will issue a written notice of 
incompleteness that sets a reasonable date by which the designated 
representative must submit the additional information required to 
complete the certification application. If the designated representative 
does not comply with the notice of incompleteness by the specified date, 
then the Administrator may issue a notice of disapproval under paragraph 
(d)(3)(iv)(C) of this section.
    (C) Disapproval notice. If the certification application shows that 
any monitoring system does not meet the performance requirements of part 
75 of this chapter or if the certification application is incomplete and 
the requirement for disapproval under paragraph (d)(3)(iv)(B) of this 
section is met, then the Administrator will issue a written notice of 
disapproval of the certification application. Upon issuance of such 
notice of disapproval, the provisional certification is invalidated by 
the Administrator and the data measured and recorded by each uncertified 
monitoring system shall not be considered valid quality-assured data 
beginning with the date and hour of provisional certification (as 
defined under Sec. 75.20(a)(3) of this chapter).
    (D) Audit decertification. The Administrator may issue a notice of 
disapproval of the certification status of a monitor in accordance with 
Sec. 97.432(b).
    (v) Procedures for loss of certification. If the Administrator 
issues a notice of disapproval of a certification application under 
paragraph (d)(3)(iv)(C) of this section or a notice of disapproval of 
certification status under paragraph (d)(3)(iv)(D) of this section, 
then:
    (A) The owner or operator shall substitute the following values, for 
each disapproved monitoring system, for each hour of unit operation 
during the period of invalid data specified under Sec. 
75.20(a)(4)(iii), Sec. 75.20(g)(7), or Sec. 75.21(e) of this chapter 
and continuing until the applicable date and hour specified under Sec. 
75.20(a)(5)(i) or (g)(7) of this chapter:
    (1) For a disapproved NOX emission rate (i.e., 
NOX-diluent) system, the maximum potential NOX 
emission rate, as defined in Sec. 72.2 of this chapter.
    (2) For a disapproved NOX pollutant concentration monitor 
and disapproved flow monitor, respectively, the maximum potential 
concentration of NOX and the maximum potential flow rate, as 
defined in sections 2.1.2.1 and 2.1.4.1 of appendix A to part 75 of this 
chapter.
    (3) For a disapproved moisture monitoring system and disapproved 
diluent gas monitoring system, respectively, the minimum potential 
moisture percentage and either the maximum potential CO2 
concentration or the minimum potential O2 concentration (as 
applicable), as defined in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of 
appendix A to part 75 of this chapter.
    (4) For a disapproved fuel flowmeter system, the maximum potential 
fuel flow rate, as defined in section 2.4.2.1 of appendix D to part 75 
of this chapter.
    (5) For a disapproved excepted NOX monitoring system 
under appendix E to part 75 of this chapter, the fuel-specific maximum 
potential NOX emission rate, as defined in Sec. 72.2 of this 
chapter.
    (B) The designated representative shall submit a notification of 
certification retest dates and a new certification application in 
accordance with paragraphs (d)(3)(i) and (ii) of this section.
    (C) The owner or operator shall repeat all certification tests or 
other requirements that were failed by the monitoring system, as 
indicated in the Administrator's notice of disapproval,

[[Page 389]]

no later than 30 unit operating days after the date of issuance of the 
notice of disapproval.
    (e) The owner or operator of a unit qualified to use the low mass 
emissions (LME) excepted methodology under Sec. 75.19 of this chapter 
shall meet the applicable certification and recertification requirements 
in Sec. Sec. 75.19(a)(2) and 75.20(h) of this chapter. If the owner or 
operator of such a unit elects to certify a fuel flowmeter system for 
heat input determination, the owner or operator shall also meet the 
certification and recertification requirements in Sec. 75.20(g) of this 
chapter.
    (f) The designated representative of each unit for which the owner 
or operator intends to use an alternative monitoring system approved by 
the Administrator under subpart E of part 75 of this chapter shall 
comply with the applicable notification and application procedures of 
Sec. 75.20(f) of this chapter.



Sec. 97.432  Monitoring system out-of-control periods.

    (a) General provisions. Whenever any monitoring system fails to meet 
the quality-assurance and quality-control requirements or data 
validation requirements of part 75 of this chapter, data shall be 
substituted using the applicable missing data procedures in subpart D or 
subpart H of, or appendix D or appendix E to, part 75 of this chapter.
    (b) Audit decertification. Whenever both an audit of a monitoring 
system and a review of the initial certification or recertification 
application reveal that any monitoring system should not have been 
certified or recertified because it did not meet a particular 
performance specification or other requirement under Sec. 97.431 or the 
applicable provisions of part 75 of this chapter, both at the time of 
the initial certification or recertification application submission and 
at the time of the audit, the Administrator will issue a notice of 
disapproval of the certification status of such monitoring system. For 
the purposes of this paragraph, an audit shall be either a field audit 
or an audit of any information submitted to the Administrator or any 
State or permitting authority. By issuing the notice of disapproval, the 
Administrator revokes prospectively the certification status of the 
monitoring system. The data measured and recorded by the monitoring 
system shall not be considered valid quality-assured data from the date 
of issuance of the notification of the revoked certification status 
until the date and time that the owner or operator completes 
subsequently approved initial certification or recertification tests for 
the monitoring system. The owner or operator shall follow the applicable 
initial certification or recertification procedures in Sec. 97.431 for 
each disapproved monitoring system.



Sec. 97.433  Notifications concerning monitoring.

    The designated representative of a TR NOX Annual unit 
shall submit written notice to the Administrator in accordance with 
Sec. 75.61 of this chapter.



Sec. 97.434  Recordkeeping and reporting.

    (a) General provisions. The designated representative shall comply 
with all recordkeeping and reporting requirements in paragraphs (b) 
through (e) of this section, the applicable recordkeeping and reporting 
requirements under Sec. 75.73 of this chapter, and the requirements of 
Sec. 97.414(a).
    (b) Monitoring plans. The owner or operator of a TR NOX 
Annual unit shall comply with requirements of Sec. 75.73(c) and (e) of 
this chapter.
    (c) Certification applications. The designated representative shall 
submit an application to the Administrator within 45 days after 
completing all initial certification or recertification tests required 
under Sec. 97.431, including the information required under Sec. 75.63 
of this chapter.
    (d) Quarterly reports. The designated representative shall submit 
quarterly reports, as follows:
    (1) The designated representative shall report the NOX 
mass emissions data and heat input data for the TR NOX Annual 
unit, in an electronic quarterly report in a format prescribed by the 
Administrator, for each calendar quarter beginning with:
    (i) For a unit that commences commercial operation before July 1, 
2014, the calendar quarter covering January 1, 2015 through March 31, 
2015; or

[[Page 390]]

    (ii) For a unit that commences commercial operation on or after July 
1, 2014, the calendar quarter corresponding to the earlier of the date 
of provisional certification or the applicable deadline for initial 
certification under Sec. 97.430(b), unless that quarter is the third or 
fourth quarter of 2014, in which case reporting shall commence in the 
quarter covering January 1, 2015 through March 31, 2015.
    (2) The designated representative shall submit each quarterly report 
to the Administrator within 30 days after the end of the calendar 
quarter covered by the report. Quarterly reports shall be submitted in 
the manner specified in Sec. 75.73(f) of this chapter.
    (3) For TR NOX Annual units that are also subject to the 
Acid Rain Program, TR NOX Ozone Season Trading Program, TR 
SO2 Group 1 Trading Program, or TR SO2 Group 2 
Trading Program, quarterly reports shall include the applicable data and 
information required by subparts F through H of part 75 of this chapter 
as applicable, in addition to the NOX mass emission data, 
heat input data, and other information required by this subpart.
    (4) The Administrator may review and conduct independent audits of 
any quarterly report in order to determine whether the quarterly report 
meets the requirements of this subpart and part 75 of this chapter, 
including the requirement to use substitute data.
    (i) The Administrator will notify the designated representative of 
any determination that the quarterly report fails to meet any such 
requirements and specify in such notification any corrections that the 
Administrator believes are necessary to make through resubmission of the 
quarterly report and a reasonable time period within which the 
designated representative must respond. Upon request by the designated 
representative, the Administrator may specify reasonable extensions of 
such time period. Within the time period (including any such extensions) 
specified by the Administrator, the designated representative shall 
resubmit the quarterly report with the corrections specified by the 
Administrator, except to the extent the designated representative 
provides information demonstrating that a specified correction is not 
necessary because the quarterly report already meets the requirements of 
this subpart and part 75 of this chapter that are relevant to the 
specified correction.
    (ii) Any resubmission of a quarterly report shall meet the 
requirements applicable to the submission of a quarterly report under 
this subpart and part 75 of this chapter, except for the deadline set 
forth in paragraph (d)(2) of this section.
    (e) Compliance certification. The designated representative shall 
submit to the Administrator a compliance certification (in a format 
prescribed by the Administrator) in support of each quarterly report 
based on reasonable inquiry of those persons with primary responsibility 
for ensuring that all of the unit's emissions are correctly and fully 
monitored. The certification shall state that:
    (1) The monitoring data submitted were recorded in accordance with 
the applicable requirements of this subpart and part 75 of this chapter, 
including the quality assurance procedures and specifications; and
    (2) For a unit with add-on NOX emission controls and for 
all hours where NOX data are substituted in accordance with 
Sec. 75.34(a)(1) of this chapter, the add-on emission controls were 
operating within the range of parameters listed in the quality 
assurance/quality control program under appendix B to part 75 of this 
chapter and the substitute data values do not systematically 
underestimate NOX emissions.

[76 FR 48379, Aug. 8, 2011, as amended at 79 FR 71672, Dec. 3, 2014]



Sec. 97.435  Petitions for alternatives to monitoring, recordkeeping,
or reporting requirements.

    (a) The designated representative of a TR NOX Annual unit 
may submit a petition under Sec. 75.66 of this chapter to the 
Administrator, requesting approval to apply an alternative to any 
requirement of Sec. Sec. 97.430 through 97.434.
    (b) A petition submitted under paragraph (a) of this section shall 
include sufficient information for the evaluation of the petition, 
including, at a minimum, the following information:
    (i) Identification of each unit and source covered by the petition;

[[Page 391]]

    (ii) A detailed explanation of why the proposed alternative is being 
suggested in lieu of the requirement;
    (iii) A description and diagram of any equipment and procedures used 
in the proposed alternative;
    (iv) A demonstration that the proposed alternative is consistent 
with the purposes of the requirement for which the alternative is 
proposed and with the purposes of this subpart and part 75 of this 
chapter and that any adverse effect of approving the alternative will be 
de minimis; and
    (v) Any other relevant information that the Administrator may 
require.
    (c) Use of an alternative to any requirement referenced in paragraph 
(a) of this section is in accordance with this subpart only to the 
extent that the petition is approved in writing by the Administrator and 
that such use is in accordance with such approval.



            Subpart BBBBB_TR NOX Ozone Season Trading Program

    Source: 76 FR 48406, Aug. 8, 2011, unless otherwise noted.



Sec. 97.501  Purpose.

    This subpart sets forth the general, designated representative, 
allowance, and monitoring provisions for the Transport Rule (TR) 
NOX Ozone Season Trading Program, under section 110 of the 
Clean Air Act and Sec. 52.38 of this chapter, as a means of mitigating 
interstate transport of ozone and nitrogen oxides.



Sec. 97.502  Definitions.

    The terms used in this subpart shall have the meanings set forth in 
this section as follows:
    Acid Rain Program means a multi-state SO2 and 
NOX air pollution control and emission reduction program 
established by the Administrator under title IV of the Clean Air Act and 
parts 72 through 78 of this chapter.
    Administrator means the Administrator of the United States 
Environmental Protection Agency or the Director of the Clean Air Markets 
Division (or its successor determined by the Administrator) of the 
United States Environmental Protection Agency, the Administrator's duly 
authorized representative under this subpart.
    Allocate or allocation means, with regard to TR NOX Ozone 
Season allowances, the determination by the Administrator, State, or 
permitting authority, in accordance with this subpart and any SIP 
revision submitted by the State and approved by the Administrator under 
Sec. 52.38(b)(3), (4), or (5) of this chapter, of the amount of such TR 
NOX Ozone Season allowances to be initially credited, at no 
cost to the recipient, to:
    (1) A TR NOX Ozone Season unit;
    (2) A new unit set-aside;
    (3) An Indian country new unit set-aside; or
    (4) An entity not listed in paragraphs (1) through (3) of this 
definition;
    (5) Provided that, if the Administrator, State, or permitting 
authority initially credits, to a TR NOX Ozone Season unit 
qualifying for an initial credit, a credit in the amount of zero TR 
NOX Ozone Season allowances, the TR NOX Ozone 
Season unit will be treated as being allocated an amount (i.e., zero) of 
TR NOX Ozone Season allowances.
    Allowable NOX emission rate means, for a unit, the most stringent 
State or federal NOX emission rate limit (in lb/MWhr or, if 
in lb/mmBtu, converted to lb/MWhr by multiplying it by the unit's heat 
rate in mmBtu/MWhr) that is applicable to the unit and covers the 
longest averaging period not exceeding one year.
    Allowance Management System means the system by which the 
Administrator records allocations, deductions, and transfers of TR 
NOX Ozone Season allowances under the TR NOX Ozone 
Season Trading Program. Such allowances are allocated, recorded, held, 
deducted, or transferred only as whole allowances.
    Allowance Management System account means an account in the 
Allowance Management System established by the Administrator for 
purposes of recording the allocation, holding, transfer, or deduction of 
TR NOX Ozone Season allowances.
    Allowance transfer deadline means, for a control period in a given 
year, midnight of December 1 (if it is a business day), or midnight of 
the first business

[[Page 392]]

day thereafter (if December 1 is not a business day), immediately after 
such control period and is the deadline by which a TR NOX 
Ozone Season allowance transfer must be submitted for recordation in a 
TR NOX Ozone Season source's compliance account in order to 
be available for use in complying with the source's TR NOX 
Ozone Season emissions limitation for such control period in accordance 
with Sec. Sec. 97.506 and 97.524.
    Alternate designated representative means, for a TR NOX 
Ozone Season source and each TR NOX Ozone Season unit at the 
source, the natural person who is authorized by the owners and operators 
of the source and all such units at the source, in accordance with this 
subpart, to act on behalf of the designated representative in matters 
pertaining to the TR NOX Ozone Season Trading Program. If the 
TR NOX Ozone Season source is also subject to the Acid Rain 
Program, TR NOX Annual Trading Program, TR SO2 
Group 1 Trading Program, or TR SO2 Group 2 Trading Program, 
then this natural person shall be the same natural person as the 
alternate designated representative, as defined in the respective 
program.
    Assurance account means an Allowance Management System account, 
established by the Administrator under Sec. 97.525(b)(3) for certain 
owners and operators of a group of one or more TR NOX Ozone 
Season sources and units in a given State (and Indian country within the 
borders of such State), in which are held TR NOX Ozone Season 
allowances available for use for a control period in a given year in 
complying with the TR NOX Ozone Season assurance provisions 
in accordance with Sec. Sec. 97.506 and 97.525.
    Authorized account representative means, for a general account, the 
natural person who is authorized, in accordance with this subpart, to 
transfer and otherwise dispose of TR NOX Ozone Season 
allowances held in the general account and, for a TR NOX 
Ozone Season source's compliance account, the designated representative 
of the source.
    Automated data acquisition and handling system or DAHS means the 
component of the continuous emission monitoring system, or other 
emissions monitoring system approved for use under this subpart, 
designed to interpret and convert individual output signals from 
pollutant concentration monitors, flow monitors, diluent gas monitors, 
and other component parts of the monitoring system to produce a 
continuous record of the measured parameters in the measurement units 
required by this subpart.
    Biomass means--
    (1) Any organic material grown for the purpose of being converted to 
energy;
    (2) Any organic byproduct of agriculture that can be converted into 
energy; or
    (3) Any material that can be converted into energy and is 
nonmerchantable for other purposes, that is segregated from other 
material that is nonmerchantable for other purposes, and that is;
    (i) A forest-related organic resource, including mill residues, 
precommercial thinnings, slash, brush, or byproduct from conversion of 
trees to merchantable material; or
    (ii) A wood material, including pallets, crates, dunnage, 
manufacturing and construction materials (other than pressure-treated, 
chemically-treated, or painted wood products), and landscape or right-
of-way tree trimmings.
    Boiler means an enclosed fossil- or other-fuel-fired combustion 
device used to produce heat and to transfer heat to recirculating water, 
steam, or other medium.
    Bottoming-cycle unit means a unit in which the energy input to the 
unit is first used to produce useful thermal energy, where at least some 
of the reject heat from the useful thermal energy application or process 
is then used for electricity production.
    Business day means a day that does not fall on a weekend or a 
federal holiday.
    Certifying official means a natural person who is:
    (1) For a corporation, a president, secretary, treasurer, or vice-
president of the corporation in charge of a principal business function 
or any other person who performs similar policy- or decision-making 
functions for the corporation;

[[Page 393]]

    (2) For a partnership or sole proprietorship, a general partner or 
the proprietor respectively; or
    (3) For a local government entity or State, federal, or other public 
agency, a principal executive officer or ranking elected official.
    Clean Air Act means the Clean Air Act, 42 U.S.C. 7401, et seq.
    Coal means ``coal'' as defined in Sec. 72.2 of this chapter.
    Coal-derived fuel means any fuel (whether in a solid, liquid, or 
gaseous state) produced by the mechanical, thermal, or chemical 
processing of coal.
    Cogeneration system means an integrated group, at a source, of 
equipment (including a boiler, or combustion turbine, and a steam 
turbine generator) designed to produce useful thermal energy for 
industrial, commercial, heating, or cooling purposes and electricity 
through the sequential use of energy.
    Cogeneration unit means a stationary, fossil-fuel-fired boiler or 
stationary, fossil-fuel-fired combustion turbine that is a topping-cycle 
unit or a bottoming-cycle unit:
    (1) Operating as part of a cogeneration system; and
    (2) Producing on an annual average basis--
    (i) For a topping-cycle unit,
    (A) Useful thermal energy not less than 5 percent of total energy 
output; and
    (B) Useful power that, when added to one-half of useful thermal 
energy produced, is not less than 42.5 percent of total energy input, if 
useful thermal energy produced is 15 percent or more of total energy 
output, or not less than 45 percent of total energy input, if useful 
thermal energy produced is less than 15 percent of total energy output.
    (ii) For a bottoming-cycle unit, useful power not less than 45 
percent of total energy input;
    (3) Provided that the requirements in paragraph (2) of this 
definition shall not apply to a calendar year referenced in paragraph 
(2) of this definition during which the unit did not operate at all;
    (4) Provided that the total energy input under paragraphs (2)(i)(B) 
and (2)(ii) of this definition shall equal the unit's total energy input 
from all fuel, except biomass if the unit is a boiler; and
    (5) Provided that, if, throughout its operation during the 12-month 
period or a calendar year referenced in paragraph (2) of this 
definition, a unit is operated as part of a cogeneration system and the 
cogeneration system meets on a system-wide basis the requirement in 
paragraph (2)(i)(B) or (2)(ii) of this definition, the unit shall be 
deemed to meet such requirement during that 12-month period or calendar 
year.
    Combustion turbine means an enclosed device comprising:
    (1) If the device is simple cycle, a compressor, a combustor, and a 
turbine and in which the flue gas resulting from the combustion of fuel 
in the combustor passes through the turbine, rotating the turbine; and
    (2) If the device is combined cycle, the equipment described in 
paragraph (1) of this definition and any associated duct burner, heat 
recovery steam generator, and steam turbine.
    Commence commercial operation means, with regard to a unit:
    (1) To have begun to produce steam, gas, or other heated medium used 
to generate electricity for sale or use, including test generation, 
except as provided in Sec. 97.505.
    (i) For a unit that is a TR NOX Ozone Season unit under 
Sec. 97.504 on the later of January 1, 2005 or the date the unit 
commences commercial operation as defined in the introductory text of 
paragraph (1) of this definition and that subsequently undergoes a 
physical change or is moved to a new location or source, such date shall 
remain the date of commencement of commercial operation of the unit, 
which shall continue to be treated as the same unit.
    (ii) For a unit that is a TR NOX Ozone Season unit under 
Sec. 97.504 on the later of January 1, 2005 or the date the unit 
commences commercial operation as defined in the introductory text of 
paragraph (1) of this definition and that is subsequently replaced by a 
unit at the same or a different source, such date shall remain the 
replaced unit's date of commencement of commercial operation, and the 
replacement unit shall be treated as a separate unit with a separate 
date for commencement of commercial operation as defined in

[[Page 394]]

paragraph (1) or (2) of this definition as appropriate.
    (2) Notwithstanding paragraph (1) of this definition and except as 
provided in Sec. 97.505, for a unit that is not a TR NOX 
Ozone Season unit under Sec. 97.504 on the later of January 1, 2005 or 
the date the unit commences commercial operation as defined in 
introductory text of paragraph (1) of this definition, the unit's date 
for commencement of commercial operation shall be the date on which the 
unit becomes a TR NOX Ozone Season unit under Sec. 97.504.
    (i) For a unit with a date for commencement of commercial operation 
as defined in the introductory text of paragraph (2) of this definition 
and that subsequently undergoes a physical change or is moved to a 
different location or source, such date shall remain the date of 
commencement of commercial operation of the unit, which shall continue 
to be treated as the same unit.
    (ii) For a unit with a date for commencement of commercial operation 
as defined in the introductory text of paragraph (2) of this definition 
and that is subsequently replaced by a unit at the same or a different 
source, such date shall remain the replaced unit's date of commencement 
of commercial operation, and the replacement unit shall be treated as a 
separate unit with a separate date for commencement of commercial 
operation as defined in paragraph (1) or (2) of this definition as 
appropriate.
    Common designated representative means, with regard to a control 
period in a given year, a designated representative where, as of April 1 
immediately after the allowance transfer deadline for such control 
period, the same natural person is authorized under Sec. Sec. 97.513(a) 
and 97.515(a) as the designated representative for a group of one or 
more TR NOX Ozone Season sources and units located in a State 
(and Indian country within the borders of such State).
    Common designated representative's assurance level means, with 
regard to a specific common designated representative and a State (and 
Indian country within the borders of such State) and control period in a 
given year for which the State assurance level is exceeded as described 
in Sec. 97.506(c)(2)(iii), the common designated representative's share 
of the State NOX Ozone Season trading budget with the 
variability limit for the State for such control period.
    Common designated representative's share means, with regard to a 
specific common designated representative for a control period in a 
given year:
    (1) With regard to a total amount of NOX emissions from 
all TR NOX Ozone Season units in a State (and Indian country 
within the borders of such State) during such control period, the total 
tonnage of NOX emissions during such control period from a 
group of one or more TR NOX Ozone Season units located in 
such State (and such Indian country) and having the common designated 
representative for such control period;
    (2) With regard to a State NOX Ozone Season trading 
budget with the variability limit for such control period, the amount 
(rounded to the nearest allowance) equal to the sum of the total amount 
of TR NOX Ozone Season allowances allocated for such control 
period to a group of one or more TR NOX Ozone Season units 
located in the State (and Indian country within the borders of such 
State) and having the common designated representative for such control 
period and of the total amount of TR NOX Ozone Season 
allowances purchased by an owner or operator of such TR NOX 
Ozone Season units in an auction for such control period and submitted 
by the State or the permitting authority to the Administrator for 
recordation in the compliance accounts for such TR NOX Ozone 
Season units in accordance with the TR NOX Ozone Season 
allowance auction provisions in a SIP revision approved by the 
Administrator under Sec. 52.38(b)(4) or (5) of this chapter, multiplied 
by the sum of the State NOX Ozone Season trading budget under 
Sec. 97.510(a) and the State's variability limit under Sec. 97.510(b) 
for such control period and divided by such State NOX Ozone 
Season trading budget;
    (3) Provided that, in the case of a unit that operates during, but 
has no amount of TR NOX Ozone Season allowances allocated 
under Sec. Sec. 97.511 and 97.512 for, such control period, the unit

[[Page 395]]

shall be treated, solely for purposes of this definition, as being 
allocated an amount (rounded to the nearest allowance) of TR 
NOX Ozone Season allowances for such control period equal to 
the unit's allowable NOX emission rate applicable to such 
control period, multiplied by a capacity factor of 0.92 (if the unit is 
a boiler combusting any amount of coal or coal-derived fuel during such 
control period), 0.32 (if the unit is a simple combustion turbine during 
such control period), 0.71 (if the unit is a combined cycle turbine 
during such control period), 0.73 (if the unit is an integrated coal 
gasification combined cycle unit during such control period), or 0.44 
(for any other unit), multiplied by the unit's maximum hourly load as 
reported in accordance with this subpart and by 3,672 hours/control 
period, and divided by 2,000 lb/ton.
    Common stack means a single flue through which emissions from 2 or 
more units are exhausted.
    Compliance account means an Allowance Management System account, 
established by the Administrator for a TR NOX Ozone Season 
source under this subpart, in which any TR NOX Ozone Season 
allowance allocations to the TR NOX Ozone Season units at the 
source are recorded and in which are held any TR NOX Ozone 
Season allowances available for use for a control period in a given year 
in complying with the source's TR NOX Ozone Season emissions 
limitation in accordance with Sec. Sec. 97.506 and 97.524.
    Continuous emission monitoring system or CEMS means the equipment 
required under this subpart to sample, analyze, measure, and provide, by 
means of readings recorded at least once every 15 minutes and using an 
automated data acquisition and handling system (DAHS), a permanent 
record of NOX emissions, stack gas volumetric flow rate, 
stack gas moisture content, and O2 or CO2 
concentration (as applicable), in a manner consistent with part 75 of 
this chapter and Sec. Sec. 97.530 through 97.535. The following systems 
are the principal types of continuous emission monitoring systems:
    (1) A flow monitoring system, consisting of a stack flow rate 
monitor and an automated data acquisition and handling system and 
providing a permanent, continuous record of stack gas volumetric flow 
rate, in standard cubic feet per hour (scfh);
    (2) A NOX concentration monitoring system, consisting of 
a NOX pollutant concentration monitor and an automated data 
acquisition and handling system and providing a permanent, continuous 
record of NOX emissions, in parts per million (ppm);
    (3) A NOX emission rate (or NOX-diluent) 
monitoring system, consisting of a NOX pollutant 
concentration monitor, a diluent gas (CO2 or O2) 
monitor, and an automated data acquisition and handling system and 
providing a permanent, continuous record of NOX 
concentration, in parts per million (ppm), diluent gas concentration, in 
percent CO2 or O2, and NOX emission 
rate, in pounds per million British thermal units (lb/mmBtu);
    (4) A moisture monitoring system, as defined in Sec. 75.11(b)(2) of 
this chapter and providing a permanent, continuous record of the stack 
gas moisture content, in percent H2O;
    (5) A CO2 monitoring system, consisting of a 
CO2 pollutant concentration monitor (or an O2 
monitor plus suitable mathematical equations from which the 
CO2 concentration is derived) and an automated data 
acquisition and handling system and providing a permanent, continuous 
record of CO2 emissions, in percent CO2; and
    (6) An O2 monitoring system, consisting of an 
O2 concentration monitor and an automated data acquisition 
and handling system and providing a permanent, continuous record of 
O2, in percent O2.
    Control period means the period starting May 1 of a calendar year, 
except as provided in Sec. 97.506(c)(3), and ending on September 30 of 
the same year, inclusive.
    Designated representative means, for a TR NOX Ozone 
Season source and each TR NOX Ozone Season unit at the 
source, the natural person who is authorized by the owners and operators 
of the source and all such units at the source, in accordance with this 
subpart, to represent and legally bind each owner and operator in 
matters pertaining to the TR NOX Ozone Season Trading 
Program. If the TR NOX Ozone

[[Page 396]]

Season source is also subject to the Acid Rain Program, TR 
NOX Annual Trading Program, TR SO2 Group 1 Trading 
Program, or TR SO2 Group 2 Trading Program, then this natural 
person shall be the same natural person as the designated 
representative, as defined in the respective program.
    Emissions means air pollutants exhausted from a unit or source into 
the atmosphere, as measured, recorded, and reported to the Administrator 
by the designated representative, and as modified by the Administrator:
    (1) In accordance with this subpart; and
    (2) With regard to a period before the unit or source is required to 
measure, record, and report such air pollutants in accordance with this 
subpart, in accordance with part 75 of this chapter.
    Excess emissions means any ton of emissions from the TR 
NOX Ozone Season units at a TR NOX Ozone Season 
source during a control period in a given year that exceeds the TR 
NOX Ozone Season emissions limitation for the source for such 
control period.
    Fossil fuel means--
    (1) Natural gas, petroleum, coal, or any form of solid, liquid, or 
gaseous fuel derived from such material; or
    (2) For purposes of applying the limitation on ``average annual fuel 
consumption of fossil fuel'' in Sec. Sec. 97.504(b)(2)(i)(B) and (ii), 
natural gas, petroleum, coal, or any form of solid, liquid, or gaseous 
fuel derived from such material for the purpose of creating useful heat.
    Fossil-fuel-fired means, with regard to a unit, combusting any 
amount of fossil fuel in 2005 or any calendar year thereafter.
    General account means an Allowance Management System account, 
established under this subpart, that is not a compliance account or an 
assurance account.
    Generator means a device that produces electricity.
    Gross electrical output means, for a unit, electricity made 
available for use, including any such electricity used in the power 
production process (which process includes, but is not limited to, any 
on-site processing or treatment of fuel combusted at the unit and any 
on-site emission controls).
    Heat input means, for a unit for a specified period of time, the 
product (in mmBtu/time) of the gross calorific value of the fuel (in 
mmBtu/lb) fed into the unit multiplied by the fuel feed rate (in lb of 
fuel/time), as measured, recorded, and reported to the Administrator by 
the designated representative and as modified by the Administrator in 
accordance with this subpart and excluding the heat derived from 
preheated combustion air, recirculated flue gases, or exhaust.
    Heat input rate means, for a unit, the amount of heat input (in 
mmBtu) divided by unit operating time (in hr) or, for a unit and a 
specific fuel, the amount of heat input attributed to the fuel (in 
mmBtu) divided by the unit operating time (in hr) during which the unit 
combusts the fuel.
    Heat rate means, for a unit, the unit's maximum design heat input 
(in Btu/hr), divided by the product of 1,000,000 Btu/mmBtu and the 
unit's maximum hourly load.
    Indian country means ``Indian country'' as defined in 18 U.S.C. 
1151.
    Life-of-the-unit, firm power contractual arrangement means a unit 
participation power sales agreement under which a utility or industrial 
customer reserves, or is entitled to receive, a specified amount or 
percentage of nameplate capacity and associated energy generated by any 
specified unit and pays its proportional amount of such unit's total 
costs, pursuant to a contract:
    (1) For the life of the unit;
    (2) For a cumulative term of no less than 30 years, including 
contracts that permit an election for early termination; or
    (3) For a period no less than 25 years or 70 percent of the economic 
useful life of the unit determined as of the time the unit is built, 
with option rights to purchase or release some portion of the nameplate 
capacity and associated energy generated by the unit at the end of the 
period.
    Maximum design heat input means, for a unit, the maximum amount of 
fuel per hour (in Btu/hr) that the unit is capable of combusting on a 
steady state basis as of the initial installation of the unit as 
specified by the manufacturer of the unit.

[[Page 397]]

    Monitoring system means any monitoring system that meets the 
requirements of this subpart, including a continuous emission monitoring 
system, an alternative monitoring system, or an excepted monitoring 
system under part 75 of this chapter.
    Nameplate capacity means, starting from the initial installation of 
a generator, the maximum electrical generating output (in MWe, rounded 
to the nearest tenth) that the generator is capable of producing on a 
steady state basis and during continuous operation (when not restricted 
by seasonal or other deratings) as of such installation as specified by 
the manufacturer of the generator or, starting from the completion of 
any subsequent physical change in the generator resulting in an increase 
in the maximum electrical generating output that the generator is 
capable of producing on a steady state basis and during continuous 
operation (when not restricted by seasonal or other deratings), such 
increased maximum amount (in MWe, rounded to the nearest tenth) as of 
such completion as specified by the person conducting the physical 
change.
    Natural gas means ``natural gas'' as defined in Sec. 72.2 of this 
chapter.
    Newly affected TR NOX Ozone Season unit means a unit that was not a 
TR NOX Ozone Season unit when it began operating but that 
thereafter becomes a TR NOX Ozone Season unit.
    Operate or operation means, with regard to a unit, to combust fuel.
    Operator means, for a TR NOX Ozone Season source or a TR 
NOX Ozone Season unit at a source respectively, any person 
who operates, controls, or supervises a TR NOX Ozone Season 
unit at the source or the TR NOX Ozone Season unit and shall 
include, but not be limited to, any holding company, utility system, or 
plant manager of such source or unit.
    Owner means, for a TR NOX Ozone Season source or a TR 
NOX Ozone Season unit at a source respectively, any of the 
following persons:
    (1) Any holder of any portion of the legal or equitable title in a 
TR NOX Ozone Season unit at the source or the TR 
NOX Ozone Season unit;
    (2) Any holder of a leasehold interest in a TR NOX Ozone 
Season unit at the source or the TR NOX Ozone Season unit, 
provided that, unless expressly provided for in a leasehold agreement, 
``owner'' shall not include a passive lessor, or a person who has an 
equitable interest through such lessor, whose rental payments are not 
based (either directly or indirectly) on the revenues or income from 
such TR NOX Ozone Season unit; and
    (3) Any purchaser of power from a TR NOX Ozone Season 
unit at the source or the TR NOX Ozone Season unit under a 
life-of-the-unit, firm power contractual arrangement.
    Permanently retired means, with regard to a unit, a unit that is 
unavailable for service and that the unit's owners and operators do not 
expect to return to service in the future.
    Permitting authority means ``permitting authority'' as defined in 
Sec. Sec. 70.2 and 71.2 of this chapter.
    Potential electrical output capacity means, for a unit, 33 percent 
of the unit's maximum design heat input, divided by 3,413 Btu/kWh, 
divided by 1,000 kWh/MWh, and multiplied by 8,760 hr/yr.
    Receive or receipt of means, when referring to the Administrator, to 
come into possession of a document, information, or correspondence 
(whether sent in hard copy or by authorized electronic transmission), as 
indicated in an official log, or by a notation made on the document, 
information, or correspondence, by the Administrator in the regular 
course of business.
    Recordation, record, or recorded means, with regard to TR 
NOX Ozone Season allowances, the moving of TR NOX 
Ozone Season allowances by the Administrator into, out of, or between 
Allowance Management System accounts, for purposes of allocation, 
auction, transfer, or deduction.
    Reference method means any direct test method of sampling and 
analyzing for an air pollutant as specified in Sec. 75.22 of this 
chapter.
    Replacement, replace, or replaced means, with regard to a unit, the 
demolishing of a unit, or the permanent retirement and permanent 
disabling of a unit, and the construction of another unit (the 
replacement unit) to be used instead of the demolished or retired unit 
(the replaced unit).

[[Page 398]]

    Sequential use of energy means:
    (1) The use of reject heat from electricity production in a useful 
thermal energy application or process; or
    (2) The use of reject heat from useful thermal energy application or 
process in electricity production.
    Serial number means, for a TR NOX Ozone Season allowance, 
the unique identification number assigned to each TR NOX 
Ozone Season allowance by the Administrator.
    Solid waste incineration unit means a stationary, fossil-fuel-fired 
boiler or stationary, fossil-fuel-fired combustion turbine that is a 
``solid waste incineration unit'' as defined in section 129(g)(1) of the 
Clean Air Act.
    Source means all buildings, structures, or installations located in 
one or more contiguous or adjacent properties under common control of 
the same person or persons. This definition does not change or otherwise 
affect the definition of ``major source'', ``stationary source'', or 
``source'' as set forth and implemented in a title V operating permit 
program or any other program under the Clean Air Act.
    State means one of the States that is subject to the TR 
NOX Ozone Season Trading Program pursuant to Sec. 52.38(b) 
of this chapter.
    Submit or serve means to send or transmit a document, information, 
or correspondence to the person specified in accordance with the 
applicable regulation:
    (1) In person;
    (2) By United States Postal Service; or
    (3) By other means of dispatch or transmission and delivery;
    (4) Provided that compliance with any ``submission'' or ``service'' 
deadline shall be determined by the date of dispatch, transmission, or 
mailing and not the date of receipt.
    Topping-cycle unit means a unit in which the energy input to the 
unit is first used to produce useful power, including electricity, where 
at least some of the reject heat from the electricity production is then 
used to provide useful thermal energy.
    Total energy input means, for a unit, total energy of all forms 
supplied to the unit, excluding energy produced by the unit. Each form 
of energy supplied shall be measured by the lower heating value of that 
form of energy calculated as follows:


LHV = HHV - 10.55 (W + 9H)

where:

LHV = lower heating value of the form of energy in Btu/lb,
HHV = higher heating value of the form of energy in Btu/lb,
W = weight % of moisture in the form of energy, and
H = weight % of hydrogen in the form of energy.

    Total energy output means, for a unit, the sum of useful power and 
useful thermal energy produced by the unit.
    TR NOX Annual Trading Program means a multi-state NOX air 
pollution control and emission reduction program established in 
accordance with subpart AAAAA of this part and Sec. 52.38(a) of this 
chapter (including such a program that is revised in a SIP revision 
approved by the Administrator under Sec. 52.38(a)(3) or (4) of this 
chapter or that is established in a SIP revision approved by the 
Administrator under Sec. 52.38(a)(5) of this chapter), as a means of 
mitigating interstate transport of fine particulates and NOX.
    TR NOX Ozone Season allowance means a limited authorization issued 
and allocated or auctioned by the Administrator under this subpart, or 
by a State or permitting authority under a SIP revision approved by the 
Administrator under Sec. 52.38(b)(3), (4), or (5) of this chapter, to 
emit one ton of NOX during a control period of the specified 
calendar year for which the authorization is allocated or auctioned or 
of any calendar year thereafter under the TR NOX Ozone Season 
Trading Program.
    TR NOX Ozone Season allowance deduction or deduct TR NOX Ozone 
Season allowances means the permanent withdrawal of TR NOX 
Ozone Season allowances by the Administrator from a compliance account 
(e.g., in order to account for compliance with the TR NOX 
Ozone Season emissions limitation) or from an assurance account (e.g., 
in order to account for compliance with the assurance provisions under 
Sec. Sec. 97.506 and 97.525).
    TR NOX Ozone Season allowances held or hold TR NOX Ozone Season 
allowances

[[Page 399]]

means the TR NOX Ozone Season allowances treated as included 
in an Allowance Management System account as of a specified point in 
time because at that time they:
    (1) Have been recorded by the Administrator in the account or 
transferred into the account by a correctly submitted, but not yet 
recorded, TR NOX Ozone Season allowance transfer in 
accordance with this subpart; and
    (2) Have not been transferred out of the account by a correctly 
submitted, but not yet recorded, TR NOX Ozone Season 
allowance transfer in accordance with this subpart.
    TR NOX Ozone Season emissions limitation means, for a TR 
NOX Ozone Season source, the tonnage of NOX 
emissions authorized in a control period in a given year by the TR 
NOX Ozone Season allowances available for deduction for the 
source under Sec. 97.524(a) for such control period.
    TR NOX Ozone Season source means a source that includes one or more 
TR NOX Ozone Season units.
    TR NOX Ozone Season Trading Program means a multi-state 
NOX air pollution control and emission reduction program 
established in accordance with this subpart and Sec. 52.38(b) of this 
chapter (including such a program that is revised in a SIP revision 
approved by the Administrator under Sec. 52.38(b)(3) or (4) of this 
chapter or that is established in a SIP revision approved by the 
Administrator under Sec. 52.38(b)(5) of this chapter), as a means of 
mitigating interstate transport of ozone and NOX.
    TR NOX Ozone Season unit means a unit that is subject to the TR 
NOX Ozone Season Trading Program.
    TR SO2 Group 1 Trading Program means a multi-state SO2 
air pollution control and emission reduction program established in 
accordance with subpart CCCCC of this part and 52.39(a), (b), (d) 
through (f), (j), and (k) of this chapter (including such a program that 
is revised in a SIP revision approved by the Administrator under Sec. 
52.39(d) or (e) of this chapter or that is established in a SIP revision 
approved by the Administrator under Sec. 52.39(f) of this chapter), as 
a means of mitigating interstate transport of fine particulates and 
SO2.
    TR SO2 Group 2 Trading Program means a multi-state SO2 
air pollution control and emission reduction program established in 
accordance with subpart DDDDD of this part and 52.39(a), (c), and (g) 
through (k) of this chapter (including such a program that is revised in 
a SIP revision approved by the Administrator under Sec. 52.39(g) or (h) 
of this chapter or that is established in a SIP revision approved by the 
Administrator under Sec. 52.39(i) of this chapter), as a means of 
mitigating interstate transport of fine particulates and SO2.
    Unit means a stationary, fossil-fuel-fired boiler, stationary, 
fossil-fuel-fired combustion turbine, or other stationary, fossil-fuel-
fired combustion device. A unit that undergoes a physical change or is 
moved to a different location or source shall continue to be treated as 
the same unit. A unit (the replaced unit) that is replaced by another 
unit (the replacement unit) at the same or a different source shall 
continue to be treated as the same unit, and the replacement unit shall 
be treated as a separate unit.
    Unit operating day means, with regard to a unit, a calendar day in 
which the unit combusts any fuel.
    Unit operating hour or hour of unit operation means, with regard to 
a unit, an hour in which the unit combusts any fuel.
    Useful power means, with regard to a unit, electricity or mechanical 
energy that the unit makes available for use, excluding any such energy 
used in the power production process (which process includes, but is not 
limited to, any on-site processing or treatment of fuel combusted at the 
unit and any on-site emission controls).
    Useful thermal energy means thermal energy that is:
    (1) Made available to an industrial or commercial process (not a 
power production process), excluding any heat contained in condensate 
return or makeup water;
    (2) Used in a heating application (e.g., space heating or domestic 
hot water heating); or
    (3) Used in a space cooling application (i.e., in an absorption 
chiller).
    Utility power distribution system means the portion of an 
electricity grid owned or operated by a utility and dedicated to 
delivering electricity to customers.

[[Page 400]]



Sec. 97.503  Measurements, abbreviations, and acronyms.

    Measurements, abbreviations, and acronyms used in this subpart are 
defined as follows:

Btu--British thermal unit
CO2--carbon dioxide
H2O--water
hr--hour
kW--kilowatt electrical
kWh--kilowatt hour
lb--pound
mmBtu--million Btu
MWe--megawatt electrical
MWh--megawatt hour
NOX--nitrogen oxides
O2--oxygen
ppm--parts per million
scfh--standard cubic feet per hour
SO2--sulfur dioxide
yr--year



Sec. 97.504  Applicability.

    (a) Except as provided in paragraph (b) of this section:
    (1) The following units in a State (and Indian country within the 
borders of such State) shall be TR NOX Ozone Season units, 
and any source that includes one or more such units shall be a TR 
NOX Ozone Season source, subject to the requirements of this 
subpart: any stationary, fossil-fuel-fired boiler or stationary, fossil-
fuel-fired combustion turbine serving at any time, on or after January 
1, 2005, a generator with nameplate capacity of more than 25 MWe 
producing electricity for sale.
    (2) If a stationary boiler or stationary combustion turbine that, 
under paragraph (a)(1) of this section, is not a TR NOX Ozone 
Season unit begins to combust fossil fuel or to serve a generator with 
nameplate capacity of more than 25 MWe producing electricity for sale, 
the unit shall become a TR NOX Ozone Season unit as provided 
in paragraph (a)(1) of this section on the first date on which it both 
combusts fossil fuel and serves such generator.
    (b) Any unit in a State (and Indian country within the borders of 
such State) that otherwise is a TR NOX Ozone Season unit 
under paragraph (a) of this section and that meets the requirements set 
forth in paragraph (b)(1)(i) or (2)(i) of this section shall not be a TR 
NOX Ozone Season unit:
    (1)(i) Any unit:
    (A) Qualifying as a cogeneration unit throughout the later of 2005 
or the 12-month period starting on the date the unit first produces 
electricity and continuing to qualify as a cogeneration unit throughout 
each calendar year ending after the later of 2005 or such 12-month 
period; and
    (B) Not supplying in 2005 or any calendar year thereafter more than 
one-third of the unit's potential electric output capacity or 219,000 
MWh, whichever is greater, to any utility power distribution system for 
sale.
    (ii) If, after qualifying under paragraph (b)(1)(i) of this section 
as not being a TR NOX Ozone Season unit, a unit subsequently 
no longer meets all the requirements of paragraph (b)(1)(i) of this 
section, the unit shall become a TR NOX Ozone Season unit 
starting on the earlier of January 1 after the first calendar year 
during which the unit first no longer qualifies as a cogeneration unit 
or January 1 after the first calendar year during which the unit no 
longer meets the requirements of paragraph (b)(1)(i)(B) of this section. 
The unit shall thereafter continue to be a TR NOX Ozone 
Season unit.
    (2)(i) Any unit:
    (A) Qualifying as a solid waste incineration unit throughout the 
later of 2005 or the 12-month period starting on the date the unit first 
produces electricity and continuing to qualify as a solid waste 
incineration unit throughout each calendar year ending after the later 
of 2005 or such 12-month period; and
    (B) With an average annual fuel consumption of fossil fuel for the 
first 3 consecutive calendar years of operation starting no earlier than 
2005 of less than 20 percent (on a Btu basis) and an average annual fuel 
consumption of fossil fuel for any 3 consecutive calendar years 
thereafter of less than 20 percent (on a Btu basis).
    (ii) If, after qualifying under paragraph (b)(2)(i) of this section 
as not being a TR NOX Ozone Season unit, a unit subsequently 
no longer meets all the requirements of paragraph (b)(1)(i) of this 
section, the unit shall become a TR NOX Ozone Season unit 
starting on the earlier of January 1 after the first calendar year 
during which the unit first no longer qualifies as a solid

[[Page 401]]

waste incineration unit or January 1 after the first 3 consecutive 
calendar years after 2005 for which the unit has an average annual fuel 
consumption of fossil fuel of 20 percent or more. The unit shall 
thereafter continue to be a TR NOX Ozone Season unit.
    (c) A certifying official of an owner or operator of any unit or 
other equipment may submit a petition (including any supporting 
documents) to the Administrator at any time for a determination 
concerning the applicability, under paragraphs (a) and (b) of this 
section or a SIP revision approved under Sec. 52.38(b)(4) or (5) of 
this chapter, of the TR NOX Ozone Season Trading Program to 
the unit or other equipment.
    (1) Petition content. The petition shall be in writing and include 
the identification of the unit or other equipment and the relevant facts 
about the unit or other equipment. The petition and any other documents 
provided to the Administrator in connection with the petition shall 
include the following certification statement, signed by the certifying 
official: ``I am authorized to make this submission on behalf of the 
owners and operators of the unit or other equipment for which the 
submission is made. I certify under penalty of law that I have 
personally examined, and am familiar with, the statements and 
information submitted in this document and all its attachments. Based on 
my inquiry of those individuals with primary responsibility for 
obtaining the information, I certify that the statements and information 
are to the best of my knowledge and belief true, accurate, and complete. 
I am aware that there are significant penalties for submitting false 
statements and information or omitting required statements and 
information, including the possibility of fine or imprisonment.''
    (2) Response. The Administrator will issue a written response to the 
petition and may request supplemental information determined by the 
Administrator to be relevant to such petition. The Administrator's 
determination concerning the applicability, under paragraphs (a) and (b) 
of this section, of the TR NOX Ozone Season Trading Program 
to the unit or other equipment shall be binding on any State or 
permitting authority unless the Administrator determines that the 
petition or other documents or information provided in connection with 
the petition contained significant, relevant errors or omissions.



Sec. 97.505  Retired unit exemption.

    (a)(1) Any TR NOX Ozone Season unit that is permanently 
retired shall be exempt from Sec. 97.506(b) and (c)(1), Sec. 97.524, 
and Sec. Sec. 97.530 through 97.535.
    (2) The exemption under paragraph (a)(1) of this section shall 
become effective the day on which the TR NOX Ozone Season 
unit is permanently retired. Within 30 days of the unit's permanent 
retirement, the designated representative shall submit a statement to 
the Administrator. The statement shall state, in a format prescribed by 
the Administrator, that the unit was permanently retired on a specified 
date and will comply with the requirements of paragraph (b) of this 
section.
    (b) Special provisions. (1) A unit exempt under paragraph (a) of 
this section shall not emit any NOX, starting on the date 
that the exemption takes effect.
    (2) For a period of 5 years from the date the records are created, 
the owners and operators of a unit exempt under paragraph (a) of this 
section shall retain, at the source that includes the unit, records 
demonstrating that the unit is permanently retired. The 5-year period 
for keeping records may be extended for cause, at any time before the 
end of the period, in writing by the Administrator. The owners and 
operators bear the burden of proof that the unit is permanently retired.
    (3) The owners and operators and, to the extent applicable, the 
designated representative of a unit exempt under paragraph (a) of this 
section shall comply with the requirements of the TR NOX 
Ozone Season Trading Program concerning all periods for which the 
exemption is not in effect, even if such requirements arise, or must be 
complied with, after the exemption takes effect.
    (4) A unit exempt under paragraph (a) of this section shall lose its 
exemption on the first date on which the unit resumes operation. Such 
unit shall be

[[Page 402]]

treated, for purposes of applying allocation, monitoring, reporting, and 
recordkeeping requirements under this subpart, as a unit that commences 
commercial operation on the first date on which the unit resumes 
operation.



Sec. 97.506  Standard requirements.

    (a) Designated representative requirements. The owners and operators 
shall comply with the requirement to have a designated representative, 
and may have an alternate designated representative, in accordance with 
Sec. Sec. 97.513 through 97.518.
    (b) Emissions monitoring, reporting, and recordkeeping requirements. 
(1) The owners and operators, and the designated representative, of each 
TR NOX Ozone Season source and each TR NOX Ozone 
Season unit at the source shall comply with the monitoring, reporting, 
and recordkeeping requirements of Sec. Sec. 97.530 through 97.535.
    (2) The emissions data determined in accordance with Sec. Sec. 
97.530 through 97.535 shall be used to calculate allocations of TR 
NOX Ozone Season allowances under Sec. Sec. 97.511(a)(2) and 
(b) and 97.512 and to determine compliance with the TR NOX 
Ozone Season emissions limitation and assurance provisions under 
paragraph (c) of this section, provided that, for each monitoring 
location from which mass emissions are reported, the mass emissions 
amount used in calculating such allocations and determining such 
compliance shall be the mass emissions amount for the monitoring 
location determined in accordance with Sec. Sec. 97.530 through 97.535 
and rounded to the nearest ton, with any fraction of a ton less than 
0.50 being deemed to be zero.
    (c) NOX emissions requirements. (1) TR NOX 
Ozone Season emissions limitation. (i) As of the allowance transfer 
deadline for a control period in a given year, the owners and operators 
of each TR NOX Ozone Season source and each TR NOX 
Ozone Season unit at the source shall hold, in the source's compliance 
account, TR NOX Ozone Season allowances available for 
deduction for such control period under Sec. 97.524(a) in an amount not 
less than the tons of total NOX emissions for such control 
period from all TR NOX Ozone Season units at the source.
    (ii) If total NOX emissions during a control period in a 
given year from the TR NOX Ozone Season units at a TR 
NOX Ozone Season source are in excess of the TR 
NOX Ozone Season emissions limitation set forth in paragraph 
(c)(1)(i) of this section, then:
    (A) The owners and operators of the source and each TR 
NOX Ozone Season unit at the source shall hold the TR 
NOX Ozone Season allowances required for deduction under 
Sec. 97.524(d); and
    (B) The owners and operators of the source and each TR 
NOX Ozone Season unit at the source shall pay any fine, 
penalty, or assessment or comply with any other remedy imposed, for the 
same violations, under the Clean Air Act, and each ton of such excess 
emissions and each day of such control period shall constitute a 
separate violation of this subpart and the Clean Air Act.
    (2) TR NOX Ozone Season assurance provisions. (i) If 
total NOX emissions during a control period in a given year 
from all TR NOX Ozone Season units at TR NOX Ozone 
Season sources in a State (and Indian country within the borders of such 
State) exceed the State assurance level, then the owners and operators 
of such sources and units in each group of one or more sources and units 
having a common designated representative for such control period, where 
the common designated representative's share of such NOX 
emissions during such control period exceeds the common designated 
representative's assurance level for the State and such control period, 
shall hold (in the assurance account established for the owners and 
operators of such group) TR NOX Ozone Season allowances 
available for deduction for such control period under Sec. 97.525(a) in 
an amount equal to two times the product (rounded to the nearest whole 
number), as determined by the Administrator in accordance with Sec. 
97.525(b), of multiplying--
    (A) The quotient of the amount by which the common designated 
representative's share of such NOX emissions exceeds the 
common designated representative's assurance level divided by the sum of 
the amounts, determined for all common designated representatives for 
such sources and

[[Page 403]]

units in the State (and Indian country within the borders of such State) 
for such control period, by which each common designated 
representative's share of such NOX emissions exceeds the 
respective common designated representative's assurance level; and
    (B) The amount by which total NOX emissions from all TR 
NOX Ozone Season units at TR NOX Ozone Season 
sources in the State (and Indian country within the borders of such 
State) for such control period exceed the State assurance level.
    (ii) The owners and operators shall hold the TR NOX Ozone 
Season allowances required under paragraph (c)(2)(i) of this section, as 
of midnight of November 1 (if it is a business day), or midnight of the 
first business day thereafter (if November 1 is not a business day), 
immediately after such control period.
    (iii) Total NOX emissions from all TR NOX 
Ozone Season units at TR NOX Ozone Season sources in a State 
(and Indian country within the borders of such State) during a control 
period in a given year exceed the State assurance level if such total 
NOX emissions exceed the sum, for such control period, of the 
State NOX Ozone Season trading budget under Sec. 97.510(a) 
and the State's variability limit under Sec. 97.510(b).
    (iv) It shall not be a violation of this subpart or of the Clean Air 
Act if total NOX emissions from all TR NOX Ozone 
Season units at TR NOX Ozone Season sources in a State (and 
Indian country within the borders of such State) during a control period 
exceed the State assurance level or if a common designated 
representative's share of total NOX emissions from the TR 
NOX Ozone Season units at TR NOX Ozone Season 
sources in a State (and Indian country within the borders of such State) 
during a control period exceeds the common designated representative's 
assurance level.
    (v) To the extent the owners and operators fail to hold TR 
NOX Ozone Season allowances for a control period in a given 
year in accordance with paragraphs (c)(2)(i) through (iii) of this 
section,
    (A) The owners and operators shall pay any fine, penalty, or 
assessment or comply with any other remedy imposed under the Clean Air 
Act; and
    (B) Each TR NOX Ozone Season allowance that the owners 
and operators fail to hold for such control period in accordance with 
paragraphs (c)(2)(i) through (iii) of this section and each day of such 
control period shall constitute a separate violation of this subpart and 
the Clean Air Act.
    (3) Compliance periods. (i)A TR NOX Ozone Season unit 
shall be subject to the requirements under paragraph (c)(1) of this 
section for the control period starting on the later of May 1, 2015 or 
the deadline for meeting the unit's monitor certification requirements 
under Sec. 97.530(b) and for each control period thereafter.
    (ii) A TR NOX Ozone Season unit shall be subject to the 
requirements under paragraph (c)(2) of this section for the control 
period starting on the later of May 1, 2017 or the deadline for meeting 
the unit's monitor certification requirements under Sec. 97.530(b) and 
for each control period thereafter.
    (4) Vintage of allowances held for compliance. (i) A TR 
NOX Ozone Season allowance held for compliance with the 
requirements under paragraph (c)(1)(i) of this section for a control 
period in a given year must be a TR NOX Ozone Season 
allowance that was allocated for such control period or a control period 
in a prior year.
    (ii) A TR NOX Ozone Season allowance held for compliance 
with the requirements under paragraphs (c)(1)(ii)(A) and (2)(i) through 
(iii) of this section for a control period in a given year must be a TR 
NOX Ozone Season allowance that was allocated for a control 
period in a prior year or the control period in the given year or in the 
immediately following year.
    (5) Allowance Management System requirements. Each TR NOX 
Ozone Season allowance shall be held in, deducted from, or transferred 
into, out of, or between Allowance Management System accounts in 
accordance with this subpart.
    (6) Limited authorization. A TR NOX Ozone Season 
allowance is a limited authorization to emit one ton of NOX 
during the control period in one year. Such authorization is limited in 
its use and duration as follows:

[[Page 404]]

    (i) Such authorization shall only be used in accordance with the TR 
NOX Ozone Season Trading Program; and
    (ii) Notwithstanding any other provision of this subpart, the 
Administrator has the authority to terminate or limit the use and 
duration of such authorization to the extent the Administrator 
determines is necessary or appropriate to implement any provision of the 
Clean Air Act.
    (7) Property right. A TR NOX Ozone Season allowance does 
not constitute a property right.
    (d) Title V permit requirements. (1) No title V permit revision 
shall be required for any allocation, holding, deduction, or transfer of 
TR NOX Ozone Season allowances in accordance with this 
subpart.
    (2) A description of whether a unit is required to monitor and 
report NOX emissions using a continuous emission monitoring 
system (under subpart H of part 75 of this chapter), an excepted 
monitoring system (under appendices D and E to part 75 of this chapter), 
a low mass emissions excepted monitoring methodology (under Sec. 75.19 
of this chapter), or an alternative monitoring system (under subpart E 
of part 75 of this chapter) in accordance with Sec. Sec. 97.530 through 
97.535 may be added to, or changed in, a title V permit using minor 
permit modification procedures in accordance with Sec. Sec. 70.7(e)(2) 
and 71.7(e)(1) of this chapter, provided that the requirements 
applicable to the described monitoring and reporting (as added or 
changed, respectively) are already incorporated in such permit. This 
paragraph explicitly provides that the addition of, or change to, a 
unit's description as described in the prior sentence is eligible for 
minor permit modification procedures in accordance with Sec. Sec. 
70.7(e)(2)(i)(B) and 71.7(e)(1)(i)(B) of this chapter.
    (e) Additional recordkeeping and reporting requirements. (1) Unless 
otherwise provided, the owners and operators of each TR NOX 
Ozone Season source and each TR NOX Ozone Season unit at the 
source shall keep on site at the source each of the following documents 
(in hardcopy or electronic format) for a period of 5 years from the date 
the document is created. This period may be extended for cause, at any 
time before the end of 5 years, in writing by the Administrator.
    (i) The certificate of representation under Sec. 97.516 for the 
designated representative for the source and each TR NOX 
Ozone Season unit at the source and all documents that demonstrate the 
truth of the statements in the certificate of representation; provided 
that the certificate and documents shall be retained on site at the 
source beyond such 5-year period until such certificate of 
representation and documents are superseded because of the submission of 
a new certificate of representation under Sec. 97.516 changing the 
designated representative.
    (ii) All emissions monitoring information, in accordance with this 
subpart.
    (iii) Copies of all reports, compliance certifications, and other 
submissions and all records made or required under, or to demonstrate 
compliance with the requirements of, the TR NOX Ozone Season 
Trading Program.
    (2) The designated representative of a TR NOX Ozone 
Season source and each TR NOX Ozone Season unit at the source 
shall make all submissions required under the TR NOX Ozone 
Season Trading Program, except as provided in Sec. 97.518. This 
requirement does not change, create an exemption from, or otherwise 
affect the responsible official submission requirements under a title V 
operating permit program in parts 70 and 71 of this chapter.
    (f) Liability. (1) Any provision of the TR NOX Ozone 
Season Trading Program that applies to a TR NOX Ozone Season 
source or the designated representative of a TR NOX Ozone 
Season source shall also apply to the owners and operators of such 
source and of the TR NOX Ozone Season units at the source.
    (2) Any provision of the TR NOX Ozone Season Trading 
Program that applies to a TR NOX Ozone Season unit or the 
designated representative of a TR NOX Ozone Season unit shall 
also apply to the owners and operators of such unit.
    (g) Effect on other authorities. No provision of the TR 
NOX Ozone Season Trading Program or exemption under Sec. 
97.505 shall be construed as exempting or excluding the owners and 
operators,

[[Page 405]]

and the designated representative, of a TR NOX Ozone Season 
source or TR NOX Ozone Season unit from compliance with any 
other provision of the applicable, approved State implementation plan, a 
federally enforceable permit, or the Clean Air Act.

[76 FR 48406, Aug. 8, 2011, as amended at 77 FR 10336, Feb. 21, 2012; 79 
FR 71672, Dec. 3, 2014]



Sec. 97.507  Computation of time.

    (a) Unless otherwise stated, any time period scheduled, under the TR 
NOX Ozone Season Trading Program, to begin on the occurrence 
of an act or event shall begin on the day the act or event occurs.
    (b) Unless otherwise stated, any time period scheduled, under the TR 
NOX Ozone Season Trading Program, to begin before the 
occurrence of an act or event shall be computed so that the period ends 
the day before the act or event occurs.
    (c) Unless otherwise stated, if the final day of any time period, 
under the TR NOX Ozone Season Trading Program, is not a 
business day, the time period shall be extended to the next business 
day.



Sec. 97.508  Administrative appeal procedures.

    The administrative appeal procedures for decisions of the 
Administrator under the TR NOX Ozone Season Trading Program 
are set forth in part 78 of this chapter.



Sec. 97.509  [Reserved]



Sec. 97.510  State NOX Ozone Season trading budgets, new unit set-
asides, Indian country new unit set-aside, and variability limits.

    (a) The State NOX ozone season trading budgets, new unit 
set-asides, and Indian country new unit-set asides for allocations of TR 
NOX Ozone Season allowances for the control periods in 2015 
and thereafter are as follows:
    (1) Alabama. (i) The NOX ozone season trading budget for 
2015 and 2016 is 31,746 tons.
    (ii) The NOX ozone season new unit set-aside for 2015 and 
2016 is 635 tons.
    (iii) [Reserved]
    (iv) The NOX ozone season trading budget for 2017 and 
thereafter is 31,499 tons.
    (v) The NOX ozone season new unit set-aside for 2017 and 
thereafter is 630 tons.
    (vi) [Reserved]
    (2) Arkansas. (i) The NOX ozone season trading budget for 
2015 and 2016 is 15,110 tons.
    (ii) The NOX ozone season new unit set-aside for 2015 and 
2016 is 756 tons.
    (iii) [Reserved]
    (iv) The NOX ozone season trading budget for 2017 and 
thereafter is 15,110 tons.
    (v) The NOX ozone season new unit set-aside for 2017 and 
thereafter is 1,209 tons.
    (3) Florida. (i) The NOX ozone season trading budget for 
2015 and 2016 is 28,644 tons.
    (ii) The NOX ozone season new unit set-aside for 2015 and 
2016 is 544 tons.
    (iii) The NOX ozone season Indian country new unit set-
aside for 2015 and 2016 is 29 tons.
    (iv) The NOX ozone season trading budget for 2017 and 
thereafter is 27,825 tons.
    (v) The NOX ozone season new unit set-aside for 2017 and 
thereafter is 529 tons.
    (vi) The NOX ozone season Indian country new unit set-
aside for 2017 and thereafter is 28 tons.
    (4) Georgia. (i) The NOX ozone season trading budget for 
2015 and 2016 is 27,944 tons.
    (ii) The NOX ozone season new unit set-aside for 2015 and 
2016 is 559 tons.
    (iii) [Reserved]
    (iv) The NOX ozone season trading budget for 2017 and 
thereafter is 24,041 tons.
    (v) The NOX ozone season new unit set-aside for 2017 and 
thereafter is 481 tons.
    (vi) [Reserved]
    (5) Illinois. (i) The NOX ozone season trading budget for 
2015 and 2016 is 21,208 tons.
    (ii) The NOX ozone season new unit set-aside for 2015 and 
2016 is 1,697 tons.
    (iii) [Reserved]
    (iv) The NOX ozone season trading budget for 2017 and 
thereafter is 21,208 tons.

[[Page 406]]

    (v) The NOX ozone season new unit set-aside for 2017 and 
thereafter is 1,697 tons.
    (vi) [Reserved]
    (6) Indiana. (i) The NOX ozone season trading budget for 
2015 and 2016 is 46,876 tons.
    (ii) The NOX ozone season new unit set-aside for 2015 and 
2016 is 1,406 tons.
    (iii) [Reserved]
    (iv) The NOX ozone season trading budget for 2017 and 
thereafter is 46,175 tons.
    (v) The NOX ozone season new unit set-aside for 2017 and 
thereafter is 1,385 tons.
    (vi) [Reserved]
    (7) Iowa. (i) The NOX ozone season trading budget for 
2015 and 2016 is 16,532 tons.
    (ii) The NOX ozone season new unit set-aside for 2015 and 
2016 is 314 tons.
    (iii) The NOX ozone season Indian country new unit set-
aside for 2015 and 2016 is 17 tons.
    (iv) The NOX ozone season trading budget for 2017 and 
thereafter is 16,207 tons.
    (v) The NOX ozone season new unit set-aside for 2017 and 
thereafter is 308 tons.
    (vi) The NOX ozone season Indian country new unit set-
aside for 2017 and thereafter is 16 tons.
    (8) Kentucky. (i) The NOX ozone season trading budget for 
2015 and 2016 is 36,167 tons.
    (ii) The NOX ozone season new unit set-aside for 2015 and 
2016 is 1,447 tons.
    (iii) [Reserved]
    (iv) The NOX ozone season trading budget for 2017 and 
thereafter is 32,674 tons.
    (v) The NOX ozone season new unit set-aside for 2017 and 
thereafter is 1,307 tons.
    (vi) [Reserved]
    (9) Louisiana. (i) The NOX ozone season trading budget 
for 2015 and 2016 is 18,115 tons.
    (ii) The NOX ozone season new unit set-aside for 2015 and 
2016 is 344 tons.
    (iii) The NOX ozone season Indian country new unit set-
aside for 2015 and 2016 is 18 tons.
    (iv) The NOX ozone season trading budget for 2017 and 
thereafter is 18,115 tons.
    (v) The NOX ozone season new unit set-aside for 2017 and 
thereafter is 344 tons.
    (vi) The NOX ozone season Indian country new unit set-
aside for 2017 and thereafter is 18 tons.
    (10) Maryland. (i) The NOX ozone season trading budget 
for 2015 and 2016 is 7,179 tons.
    (ii) The NOX ozone season new unit set-aside for 2015 and 
2016 is 144 tons.
    (iii) [Reserved]
    (iv) The NOX ozone season trading budget for 2017 and 
thereafter is 7,179 tons.
    (v) The NOX ozone season new unit set-aside for 2017 and 
thereafter is 144 tons.
    (vi) [Reserved]
    (11) Michigan. (i) The NOX ozone season trading budget 
for 2015 and 2016 is 28,041 tons.
    (ii) The NOX ozone season new unit set-aside for 2015 and 
2016 is 533 tons.
    (iii) The NOX ozone season Indian country new unit set-
aside for 2015 and 2016 is 28 tons.
    (iv) The NOX ozone season trading budget for 2017 and 
thereafter is 27,016 tons.
    (v) The NOX ozone season new unit set-aside for 2017 and 
thereafter is 513 tons.
    (vi) The NOX ozone season Indian country new unit set-
aside for 2017 and thereafter is 27 tons.
    (12) Mississippi. (i) The NOX ozone season trading budget 
for 2015 and 2016 is 12,429 tons.
    (ii) The NOX ozone season new unit set-aside for 2015 and 
2016 is 237 tons.
    (iii) The NOX ozone season Indian country new unit set-
aside for 2015 and 2016 is 12 tons.
    (iv) The NOX ozone season trading budget for 2017 and 
thereafter is 12,429 tons.
    (v) The NOX ozone season new unit set-aside for 2017 and 
thereafter is 237 tons.
    (vi) The NOX ozone season Indian country new unit set-
aside for 2017 and thereafter is 12 tons.
    (13) Missouri. (i) The NOX ozone season trading budget 
for 2015 and 2016 is 22,788 tons.
    (ii) The NOX ozone season new unit set-aside for 2015 is 
684 tons and for 2016 is 1,367 tons.

[[Page 407]]

    (iii) [Reserved]
    (iv) The NOX ozone season trading budget for 2017 and 
thereafter is 21,099 tons.
    (v) The NOX ozone season new unit set-aside for 2017 and 
thereafter is 1,266 tons.
    (14) New Jersey. (i) The NOX ozone season trading budget 
for 2015 and 2016 is 4,128 tons.
    (ii) The NOX ozone season new unit set-aside for 2015 and 
2016 is 83 tons.
    (iii) [Reserved]
    (iv) The NOX ozone season trading budget for 2017 and 
thereafter is 3,731 tons.
    (v) The NOX ozone season new unit set-aside for 2017 and 
thereafter is 75 tons.
    (vi) [Reserved]
    (15) New York. (i) The NOX ozone season trading budget 
for 2015 and 2016 is 10,369 tons.
    (ii) The NOX ozone season new unit set-aside for 2015 and 
2016 is 197 tons.
    (iii) The NOX ozone season Indian country new unit set-
aside for 2015 and 2016 is 10 tons.
    (iv) The NOX ozone season trading budget for 2017 and 
thereafter is 10,369 tons.
    (v) The NOX ozone season new unit set-aside for 2017 and 
thereafter is 197 tons.
    (vi) The NOX ozone season Indian country new unit set-
aside for 2017 and thereafter is 10 tons.
    (16) North Carolina. (i) The NOX ozone season trading 
budget for 2015 and 2016 is 22,168 tons.
    (ii) The NOX ozone season new unit set-aside for 2015 and 
2016 is 1,308 tons.
    (iii) The NOX ozone season Indian country new unit set-
aside for 2015 and 2016 is 22 tons.
    (iv) The NOX ozone season trading budget for 2017 and 
thereafter is 18,455 tons.
    (v) The NOX ozone season new unit set-aside for 2017 and 
thereafter is 1,089 tons.
    (vi) The NOX ozone season Indian country new unit set-
aside for 2017 and thereafter is 18 tons.
    (17) Ohio. (i) The NOX ozone season trading budget for 
2015 and 2016 is 41,284 tons.
    (ii) The NOX ozone season new unit set-aside for 2015 and 
2016 is 826 tons.
    (iii) [Reserved]
    (iv) The NOX ozone season trading budget for 2017 and 
thereafter is 39,013 tons.
    (v) The NOX ozone season new unit set-aside for 2017 and 
thereafter is 780 tons.
    (18) Oklahoma. (i) The NOX ozone season trading budget 
for 2015 is 36,567 tons and for 2016 is 22,694 tons.
    (ii) The NOX ozone season new unit set-aside for 2015 is 
731 tons and for 2016 is 454 tons.
    (iii) [Reserved]
    (iv) The NOX ozone season trading budget for 2017 and 
thereafter is 22,694 tons.
    (v) The NOX ozone season new unit set-aside for 2017 and 
thereafter is 454 tons.
    (19) Pennsylvania. (i) The NOX ozone season trading 
budget for 2015 and 2016 is 52,201 tons.
    (ii) The NOX ozone season new unit set-aside for 2015 and 
2016 is 1,044 tons.
    (iii) [Reserved]
    (iv) The NOX ozone season trading budget for 2017 and 
thereafter is 51,912 tons.
    (v) The NOX ozone season new unit set-aside for 2017 and 
thereafter is 1,038 tons.
    (vi) [Reserved]
    (20) South Carolina. (i) The NOX ozone season trading 
budget for 2015 and 2016 is 13,909 tons.
    (ii) The NOX ozone season new unit set-aside for 2015 and 
2016 is 264 tons.
    (iii) The NOX ozone season Indian country new unit set-
aside for 2015 and 2016 is 14 tons.
    (iv) The NOX ozone season trading budget for 2017 and 
thereafter is 13,909 tons.
    (v) The NOX ozone season new unit set-aside for 2017 and 
thereafter is 264 tons.
    (vi) The NOX ozone season Indian country new unit set-
aside for 2017 and thereafter is 14 tons.
    (21) Tennessee. (i) The NOX ozone season trading budget 
for 2015 and 2016 is 14,908 tons.
    (ii) The NOX ozone season new unit set-aside for 2015 and 
2016 is 298 tons.
    (iii) [Reserved]
    (iv) The NOX ozone season trading budget for 2017 and 
thereafter is 8,016 tons.

[[Page 408]]

    (v) The NOX ozone season new unit set-aside for 2017 and 
thereafter is 160 tons.
    (vi) [Reserved]
    (22) Texas. (i) The NOX ozone season trading budget for 
2015 and 2016 is 65,560 tons.
    (ii) The NOX ozone season new unit set-aside for 2015 and 
2016 is 2,556 tons.
    (iii) The NOX ozone season Indian country new unit set-
aside for 2015 and 2016 is 66 tons.
    (iv) The NOX ozone season trading budget for 2017 and 
thereafter is 65,560 tons.
    (v) The NOX ozone season new unit set-aside for 2017 and 
thereafter is 2,556 tons.
    (vi) The NOX ozone season Indian country new unit set-
aside for 2017 and thereafter is 66 tons.
    (23) Virginia. (i) The NOX ozone season trading budget 
for 2015 and 2016 is 14,452 tons.
    (ii) The NOX ozone season new unit set-aside for 2015 and 
2016 is 723 tons.
    (iii) [Reserved]
    (iv) The NOX ozone season trading budget for 2017 and 
thereafter is 14,452 tons.
    (v) The NOX ozone season new unit set-aside for 2017 and 
thereafter is 723 tons.
    (vi) [Reserved]
    (24) West Virginia. (i) The NOX ozone season trading 
budget for 2015 and 2016 is 25,283 tons.
    (ii) The NOX ozone season new unit set-aside for 2015 and 
2016 is 1,264 tons.
    (iii) [Reserved]
    (iv) The NOX ozone season trading budget for 2017 and 
thereafter is 23,291 tons.
    (v) The NOX ozone season new unit set-aside for 2017 and 
thereafter is 1,165 tons.
    (vi) [Reserved]
    (25) Wisconsin. (i) The NOX ozone season trading budget 
for 2015 and 2016 is 14,784 tons.
    (ii) The NOX ozone season new unit set-aside for 2015 and 
2016 is 872 tons.
    (iii) The NOX ozone season Indian country new unit set-
aside for 2015 and 2016 is 15 tons.
    (iv) The NOX ozone season trading budget for 2017 and 
thereafter is 14,296 tons.
    (v) The NOX ozone season new unit set-aside for 2017 and 
thereafter is 844 tons.
    (vi) The NOX ozone season Indian country new unit set-
aside for 2017 and thereafter is 14 tons.
    (b) The States' variability limits for the State NOX 
ozone season trading budgets for the control periods in 2017 and 
thereafter are as follows:
    (1) The NOX ozone season variability limit for Alabama is 
6,615 tons.
    (2) The NOX ozone season variability limit for Arkansas 
is 3,173 tons.
    (3) The NOX ozone season variability limit for Florida is 
5,843 tons.
    (4) The NOX ozone season variability limit for Georgia is 
5,049 tons.
    (5) The NOX ozone season variability limit for Illinois 
is 4,454 tons.
    (6) The NOX ozone season variability limit for Indiana is 
9,697 tons.
    (7) The NOX ozone season variability limit for Iowa is 
3,403 tons.
    (8) The NOX ozone season variability limit for Kentucky 
is 6,862 tons.
    (9) The NOX ozone season variability limit for Louisiana 
is 3,804 tons.
    (10) The NOX ozone season variability limit for Maryland 
is 1,508 tons.
    (11) The NOX ozone season variability limit for Michigan 
is 5,673 tons.
    (12) The NOX ozone season variability limit for 
Mississippi is 2,610 tons.
    (13) The NOX ozone season variability limit for Missouri 
is 4,431 tons.
    (14) The NOX ozone season variability limit for New 
Jersey is 784 tons.
    (15) The NOX ozone season variability limit for New York 
is 2,177 tons.
    (16) The NOX ozone season variability limit for North 
Carolina is 3,876 tons.
    (17) The NOX ozone season variability limit for Ohio is 
8,193 tons.
    (18) The NOX ozone season variability limit for Oklahoma 
is 4,766 tons.
    (19) The NOX ozone season variability limit for 
Pennsylvania is 10,902 tons.
    (20) The NOX ozone season variability limit for South 
Carolina is 2,921 tons.
    (21) The NOX ozone season variability limit for Tennessee 
is 1,683 tons.
    (22) The NOX ozone season variability limit for Texas is 
13,768 tons.
    (23) The NOX ozone season variability limit for Virginia 
is 3,035 tons.
    (24) The NOX ozone season variability limit for West 
Virginia is 4,891 tons.

[[Page 409]]

    (25) The NOX ozone season variability limit for Wisconsin 
is 3,002 tons.
    (c) Each NOX ozone season trading budget in this section 
includes any tons in a new unit set aside or Indian country new unit set 
aside, but does not include any tons in a variability limit.

[77 FR 10336, Feb. 21, 2012, as amended at 77 FR 10348, Feb. 21, 2012; 
77 FR 34845, June 12, 2012; 79 FR 71672, Dec. 3, 2014]



Sec. 97.511  Timing requirements for TR NOX Ozone Season allowance
allocations.

    (a) Existing units. (1) TR NOX Ozone Season allowances 
are allocated, for the control periods in 2015 and each year thereafter, 
as provided in a notice of data availability issued by the 
Administrator. Providing an allocation to a unit in such notice does not 
constitute a determination that the unit is a TR NOX Ozone 
Season unit, and not providing an allocation to a unit in such notice 
does not constitute a determination that the unit is not a TR 
NOX Ozone Season unit.
    (2) Notwithstanding paragraph (a)(1) of this section, if a unit 
provided an allocation in the notice of data availability issued under 
paragraph (a)(1) of this section does not operate, starting after 2014, 
during the control period in two consecutive years, such unit will not 
be allocated the TR NOX Ozone Season allowances provided in 
such notice for the unit for the control periods in the fifth year after 
the first such year and in each year after that fifth year. All TR 
NOX Ozone Season allowances that would otherwise have been 
allocated to such unit will be allocated to the new unit set-aside for 
the State where such unit is located and for the respective years 
involved. If such unit resumes operation, the Administrator will 
allocate TR NOX Ozone Season allowances to the unit in 
accordance with paragraph (b) of this section.
    (b) New units. (1) New unit set-asides. (i) By June 1, 2015 and June 
1 of each year thereafter, the Administrator will calculate the TR 
NOX Ozone Season allowance allocation to each TR 
NOX Ozone Season unit in a State, in accordance with Sec. 
97.512(a)(2) through (7) and (12), for the control period in the year of 
the applicable calculation deadline under this paragraph and will 
promulgate a notice of data availability of the results of the 
calculations.
    (ii) For each notice of data availability required in paragraph 
(b)(1)(i) of this section, the Administrator will provide an opportunity 
for submission of objections to the calculations referenced in such 
notice.
    (A) Objections shall be submitted by the deadline specified in each 
notice of data availability required in paragraph (b)(1)(i) of this 
section and shall be limited to addressing whether the calculations 
(including the identification of the TR NOX Ozone Season 
units) are in accordance with Sec. 97.512(a)(2) through (7) and (12) 
and Sec. Sec. 97.506(b)(2) and 97.530 through 97.535.
    (B) The Administrator will adjust the calculations to the extent 
necessary to ensure that they are in accordance with the provisions 
referenced in paragraph (b)(1)(ii)(A) of this section. By August 1 
immediately after the promulgation of each notice of data availability 
required in paragraph (b)(1)(i) of this section, the Administrator will 
promulgate a notice of data availability of any adjustments that the 
Administrator determines to be necessary with regard to allocations 
under Sec. 97.512(a)(2) through (7) and (12) and the reasons for 
accepting or rejecting any objections submitted in accordance with 
paragraph (b)(1)(ii)(A) of this section.
    (iii) If the new unit set-aside for such control period contains any 
TR NOX Ozone Season allowances that have not been allocated 
in the applicable notice of data availability required in paragraph 
(b)(1)(ii) of this section, the Administrator will promulgate, by 
September 15 immediately after such notice, a notice of data 
availability that identifies any TR NOX Ozone Season units 
that commenced commercial operation during the period starting May 1 of 
the year before the year of such control period and ending August 31 of 
year of such control period.
    (iv) For each notice of data availability required in paragraph 
(b)(1)(iii) of this section, the Administrator will provide an 
opportunity for submission of objections to the identification of TR 
NOX Ozone Season units in such notice.

[[Page 410]]

    (A) Objections shall be submitted by the deadline specified in each 
notice of data availability required in paragraph (b)(1)(iii) of this 
section and shall be limited to addressing whether the identification of 
TR NOX Ozone Season units in such notice is in accordance 
with paragraph (b)(1)(iii) of this section.
    (B) The Administrator will adjust the identification of TR 
NOX Ozone Season units in the each notice of data 
availability required in paragraph (b)(1)(iii) of this section to the 
extent necessary to ensure that it is in accordance with paragraph 
(b)(1)(iii) of this section and will calculate the TR NOX 
Ozone Season allowance allocation to each TR NOX Ozone Season 
unit in accordance with Sec. 97.512(a)(9), (10), and (12) and 
Sec. Sec. 97.506(b)(2) and 97.530 through 97.535. By November 15 
immediately after the promulgation of each notice of data availability 
required in paragraph (b)(1)(iii) of this section, the Administrator 
will promulgate a notice of data availability of any adjustments of the 
identification of TR NOX Ozone Season units that the 
Administrator determines to be necessary, the reasons for accepting or 
rejecting any objections submitted in accordance with paragraph 
(b)(1)(iv)(A) of this section, and the results of such calculations.
    (v) To the extent any TR NOX Ozone Season allowances are 
added to the new unit set-aside after promulgation of each notice of 
data availability required in paragraph (b)(1)(iv) of this section, the 
Administrator will promulgate additional notices of data availability, 
as deemed appropriate, of the allocation of such TR NOX Ozone 
Season allowances in accordance with Sec. 97.512(a)(10).
    (2) Indian country new unit set-asides. (i) By June 1, 2015 and June 
1 of each year thereafter, the Administrator will calculate the TR 
NOX Ozone Season allowance allocation to each TR 
NOX Ozone Season unit in Indian country within the borders of 
a State, in accordance with Sec. 97.512(b)(2) through (7) and (12), for 
the control period in the year of the applicable calculation deadline 
under this paragraph and will promulgate a notice of data availability 
of the results of the calculations.
    (ii) For each notice of data availability required in paragraph 
(b)(2)(i) of this section, the Administrator will provide an opportunity 
for submission of objections to the calculations referenced in such 
notice.
    (A) Objections shall be submitted by the deadline specified in each 
notice of data availability required in paragraph (b)(2)(i) of this 
section and shall be limited to addressing whether the calculations 
(including the identification of the TR NOX Ozone Season 
units) are in accordance with Sec. 97.512(b)(2) through (7) and (12) 
and Sec. Sec. 97.506(b)(2) and 97.530 through 97.535.
    (B) The Administrator will adjust the calculations to the extent 
necessary to ensure that they are in accordance with the provisions 
referenced in paragraph (b)(2)(ii)(A) of this section. By August 1 
immediately after the promulgation of each notice of data availability 
required in paragraph (b)(2)(i) of this section, the Administrator will 
promulgate a notice of data availability of any adjustments that the 
Administrator determines to be necessary with regard to allocations 
under Sec. 97.512(b)(2) through (7) and (12) and the reasons for 
accepting or rejecting any objections submitted in accordance with 
paragraph (b)(2)(ii)(A) of this section.
    (iii) If the Indian country new unit set-aside for such control 
period contains any TR NOX Ozone Season allowances that have 
not been allocated in the applicable notice of data availability 
required in paragraph (b)(2)(ii) of this section, the Administrator will 
promulgate, by September 15 immediately after such notice, a notice of 
data availability that identifies any TR NOX Ozone Season 
units that commenced commercial operation during the period starting May 
1 of the year before the year of such control period and ending August 
31 of year of such control period.
    (iv) For each notice of data availability required in paragraph 
(b)(2)(iii) of this section, the Administrator will provide an 
opportunity for submission of objections to the identification of TR 
NOX Ozone Season units in such notice.
    (A) Objections shall be submitted by the deadline specified in each 
notice of

[[Page 411]]

data availability required in paragraph (b)(2)(iii) of this section and 
shall be limited to addressing whether the identification of TR 
NOX Ozone Season units in such notice is in accordance with 
paragraph (b)(2)(iii) of this section.
    (B) The Administrator will adjust the identification of TR 
NOX Ozone Season units in the each notice of data 
availability required in paragraph (b)(2)(iii) of this section to the 
extent necessary to ensure that it is in accordance with paragraph 
(b)(2)(iii) of this section and will calculate the TR NOX 
Ozone Season allowance allocation to each TR NOX Ozone Season 
unit in accordance with Sec. 97.512(b)(9), (10), and (12) and 
Sec. Sec. 97.506(b)(2) and 97.530 through 97.535. By November 15 
immediately after the promulgation of each notice of data availability 
required in paragraph (b)(2)(iii) of this section, the Administrator 
will promulgate a notice of data availability of any adjustments of the 
identification of TR NOX Ozone Season units that the 
Administrator determines to be necessary, the reasons for accepting or 
rejecting any objections submitted in accordance with paragraph 
(b)(2)(iv)(A) of this section, and the results of such calculations. (v) 
To the extent any TR NOX Ozone Season allowances are added to 
the Indian country new unit set-aside after promulgation of each notice 
of data availability required in paragraph (b)(2)(iv) of this section, 
the Administrator will promulgate additional notices of data 
availability, as deemed appropriate, of the allocation of such TR 
NOX Ozone Season allowances in accordance with Sec. 
97.512(b)(10).
    (c) Units incorrectly allocated TR NOX Ozone Season allowances. (1) 
For each control period in 2015 and thereafter, if the Administrator 
determines that TR NOX Ozone Season allowances were allocated 
under paragraph (a) of this section, or under a provision of a SIP 
revision approved under Sec. 52.38(b)(3), (4), or (5) of this chapter, 
where such control period and the recipient are covered by the 
provisions of paragraph (c)(1)(i) of this section or were allocated 
under Sec. 97.512(a)(2) through (7), (9), and (12) and (b)(2) through 
(7), (9), and (12), or under a provision of a SIP revision approved 
under Sec. 52.38(b)(4) or (5) of this chapter, where such control 
period and the recipient are covered by the provisions of paragraph 
(c)(1)(ii) of this section, then the Administrator will notify the 
designated representative of the recipient and will act in accordance 
with the procedures set forth in paragraphs (c)(2) through (5) of this 
section:
    (i)(A) The recipient is not actually a TR NOX Ozone 
Season unit under Sec. 97.504 as of May 1, 2015 and is allocated TR 
NOX Ozone Season allowances for such control period or, in 
the case of an allocation under a provision of a SIP revision approved 
under Sec. 52.38(b)(3), (4), or (5) of this chapter, the recipient is 
not actually a TR NOX Ozone Season unit as of May 1, 2015 and 
is allocated TR NOX Ozone Season allowances for such control 
period that the SIP revision provides should be allocated only to 
recipients that are TR NOX Ozone Season units as of May 1, 
2015; or
    (B) The recipient is not located as of May 1 of the control period 
in the State from whose NOX Ozone Season trading budget the 
TR NOX Ozone Season allowances allocated under paragraph (a) 
of this section, or under a provision of a SIP revision approved under 
Sec. 52.38(b)(3), (4), or (5) of this chapter, were allocated for such 
control period.
    (ii) The recipient is not actually a TR NOX Ozone Season 
unit under Sec. 97.504 as of May 1 of such control period and is 
allocated TR NOX Ozone Season allowances for such control 
period or, in the case of an allocation under a provision of a SIP 
revision approved under Sec. 52.38(b)(3), (4), or (5) of this chapter, 
the recipient is not actually a TR NOX Ozone Season unit as 
of January 1 of such control period and is allocated TR NOX 
Ozone Season allowances for such control period that the SIP revision 
provides should be allocated only to recipients that are TR 
NOX Ozone Season units as of May 1 of such control period.
    (2) Except as provided in paragraph (c)(3) or (4) of this section, 
the Administrator will not record such TR NOX Ozone Season 
allowances under Sec. 97.521.

[[Page 412]]

    (3) If the Administrator already recorded such TR NOX 
Ozone Season allowances under Sec. 97.521 and if the Administrator 
makes the determination under paragraph (c)(1) of this section before 
making deductions for the source that includes such recipient under 
Sec. 97.524(b) for such control period, then the Administrator will 
deduct from the account in which such TR NOX Ozone Season 
allowances were recorded an amount of TR NOX Ozone Season 
allowances allocated for the same or a prior control period equal to the 
amount of such already recorded TR NOX Ozone Season 
allowances. The authorized account representative shall ensure that 
there are sufficient TR NOX Ozone Season allowances in such 
account for completion of the deduction.
    (4) If the Administrator already recorded such TR NOX 
Ozone Season allowances under Sec. 97.521 and if the Administrator 
makes the determination under paragraph (c)(1) of this section after 
making deductions for the source that includes such recipient under 
Sec. 97.524(b) for such control period, then the Administrator will not 
make any deduction to take account of such already recorded TR 
NOX Ozone Season allowances.
    (5)(i) With regard to the TR NOX Ozone Season allowances 
that are not recorded, or that are deducted as an incorrect allocation, 
in accordance with paragraphs (c)(2) and (3) of this section for a 
recipient under paragraph (c)(1)(i) of this section, the Administrator 
will:
    (A) Transfer such TR NOX Ozone Season allowances to the 
new unit set-aside for such control period for the State from whose 
NOX Ozone Season trading budget the TR NOX Ozone 
Season allowances were allocated; or
    (B) If the State has a SIP revision approved under Sec. 52.38(b)(4) 
or (5) covering such control period, include such TR NOX 
Annual allowances in the portion of the State NOX Ozone 
Season trading budget that may be allocated for such control period in 
accordance with such SIP revision.
    (ii) With regard to the TR NOX Ozone Season allowances 
that were not allocated from the Indian country new unit set-aside for 
such control period and that are not recorded, or that are deducted as 
an incorrect allocation, in accordance with paragraphs (c)(2) and (3) of 
this section for a recipient under paragraph (c)(1)(ii) of this 
paragraph, the Administrator will:
    (A) Transfer such TR NOX Ozone Season allowances to the 
new unit set-aside for such control period; or
    (B) If the State has a SIP revision approved under Sec. 52.38(b)(4) 
or (5) covering such control period, include such TR NOX 
Ozone Season allowances in the portion of the State NOX Ozone 
Season trading budget that may be allocated for such control period in 
accordance with such SIP revision.
    (iii) With regard to the TR NOX Ozone Season allowances 
that were allocated from the Indian country new unit set-aside for such 
control period and that are not recorded, or that are deducted as an 
incorrect allocation, in accordance with paragraphs (c)(2) and (3) of 
this section for a recipient under paragraph (c)(1)(ii) of this 
paragraph, the Administrator will transfer such TR NOX Ozone 
Season allowances to the Indian country new unit set-aside for such 
control period.

[76 FR 48379, Aug. 8, 2011, as amended at 79 FR 71672, Dec. 3, 2014]



Sec. 97.512  TR NOX Ozone Season allowance allocations to new units.

    (a) For each control period in 2015 and thereafter and for the TR 
NOX Ozone Season units in each State, the Administrator will 
allocate TR NOX Ozone Season allowances to the TR 
NOX Ozone Season units as follows:
    (1) The TR NOX Ozone Season allowances will be allocated 
to the following TR NOX Ozone Season units, except as 
provided in paragraph (a)(10) of this section:
    (i) TR NOX Ozone Season units that are not allocated an 
amount of TR NOX Ozone Season allowances in the notice of 
data availability issued under Sec. 97.511(a)(1);
    (ii) TR NOX Ozone Season units whose allocation of an 
amount of TR NOX Ozone Season allowances for such control 
period in the notice of data availability issued under Sec. 
97.511(a)(1) is covered by Sec. 97.511(c)(2) or (3);
    (iii) TR NOX Ozone Season units that are allocated an 
amount of TR NOX

[[Page 413]]

Ozone Season allowances for such control period in the notice of data 
availability issued under Sec. 97.511(a)(1), which allocation is 
terminated for such control period pursuant to Sec. 97.511(a)(2), and 
that operate during the control period immediately preceding such 
control period; or
    (iv) For purposes of paragraph (a)(9) of this section, TR 
NOX Ozone Season units under Sec. 97.511(c)(1)(ii) whose 
allocation of an amount of TR NOX Ozone Season allowances for 
such control period in the notice of data availability issued under 
Sec. 97.511(b)(1)(ii)(B) is covered by Sec. 97.511(c)(2) or (3).
    (2) The Administrator will establish a separate new unit set-aside 
for the State for each such control period. Each such new unit set-aside 
will be allocated TR NOX Ozone Season allowances in an amount 
equal to the applicable amount of tons of NOX emissions as 
set forth in Sec. 97.510(a) and will be allocated additional TR 
NOX Ozone Season allowances (if any) in accordance with 
Sec. Sec. 97.511(a)(2) and (c)(5) and paragraph (b)(10) of this 
section.
    (3) The Administrator will determine, for each TR NOX 
Ozone Season unit described in paragraph (a)(1) of this section, an 
allocation of TR NOX Ozone Season allowances for the later of 
the following control periods and for each subsequent control period:
    (i) The control period in 2015;
    (ii) The first control period after the control period in which the 
TR NOX Ozone Season unit commences commercial operation;
    (iii) For a unit described in paragraph (a)(1)(ii) of this section, 
the first control period in which the TR NOX Ozone Season 
unit operates in the State after operating in another jurisdiction and 
for which the unit is not already allocated one or more TR 
NOX Ozone Season allowances; and
    (iv) For a unit described in paragraph (a)(1)(iii) of this section, 
the first control period after the control period in which the unit 
resumes operation.
    (4)(i) The allocation to each TR NOX Ozone Season unit 
described in paragraph (a)(1)(i) through (iii) of this section and for 
each control period described in paragraph (a)(3) of this section will 
be an amount equal to the unit's total tons of NOX emissions 
during the immediately preceding control period.
    (ii) The Administrator will adjust the allocation amount in 
paragraph (a)(4)(i) in accordance with paragraphs (a)(5) through (7) and 
(12) of this section.
    (5) The Administrator will calculate the sum of the TR 
NOX Ozone Season allowances determined for all such TR 
NOX Ozone Season units under paragraph (a)(4)(i) of this 
section in the State for such control period.
    (6) If the amount of TR NOX Ozone Season allowances in 
the new unit set-aside for the State for such control period is greater 
than or equal to the sum under paragraph (a)(5) of this section, then 
the Administrator will allocate the amount of TR NOX Ozone 
Season allowances determined for each such TR NOX Ozone 
Season unit under paragraph (a)(4)(i) of this section.
    (7) If the amount of TR NOX Ozone Season allowances in 
the new unit set-aside for the State for such control period is less 
than the sum under paragraph (a)(5) of this section, then the 
Administrator will allocate to each such TR NOX Ozone Season 
unit the amount of the TR NOX Ozone Season allowances 
determined under paragraph (a)(4)(i) of this section for the unit, 
multiplied by the amount of TR NOX Ozone Season allowances in 
the new unit set-aside for such control period, divided by the sum under 
paragraph (a)(5) of this section, and rounded to the nearest allowance.
    (8) The Administrator will notify the public, through the 
promulgation of the notices of data availability described in Sec. 
97.511(b)(1)(i) and (ii), of the amount of TR NOX Ozone 
Season allowances allocated under paragraphs (a)(2) through (7) and (12) 
of this section for such control period to each TR NOX Ozone 
Season unit eligible for such allocation.
    (9) If, after completion of the procedures under paragraphs (a)(5) 
through (8) of this section for such control period, any unallocated TR 
NOX Ozone Season allowances remain in the new unit set-aside 
for the State for such control period, the Administrator will allocate 
such TR NOX Ozone Season allowances as follows--

[[Page 414]]

    (i) The Administrator will determine, for each unit described in 
paragraph (a)(1) of this section that commenced commercial operation 
during the period starting May 1 of the year before the year of such 
control period and ending August 31 of year of such control period, the 
positive difference (if any) between the unit's emissions during such 
control period and the amount of TR NOX Ozone Season 
allowances referenced in the notice of data availability required under 
Sec. 97.511(b)(1)(ii) for the unit for such control period;
    (ii) The Administrator will determine the sum of the positive 
differences determined under paragraph (a)(9)(i) of this section;
    (iii) If the amount of unallocated TR NOX Ozone Season 
allowances remaining in the new unit set-aside for the State for such 
control period is greater than or equal to the sum determined under 
paragraph (a)(9)(ii) of this section, then the Administrator will 
allocate the amount of TR NOX Ozone Season allowances 
determined for each such TR NOX Ozone Season unit under 
paragraph (a)(9)(i) of this section; and
    (iv) If the amount of unallocated TR NOX Ozone Season 
allowances remaining in the new unit set-aside for the State for such 
control period is less than the sum under paragraph (a)(9)(ii) of this 
section, then the Administrator will allocate to each such TR 
NOX Ozone Season unit the amount of the TR NOX 
Ozone Season allowances determined under paragraph (a)(9)(i) of this 
section for the unit, multiplied by the amount of unallocated TR 
NOX Ozone Season allowances remaining in the new unit set-
aside for such control period, divided by the sum under paragraph 
(a)(9)(ii) of this section, and rounded to the nearest allowance.
    (10) If, after completion of the procedures under paragraphs (a)(9) 
and (12) of this section for such control period, any unallocated TR 
NOX Ozone Season allowances remain in the new unit set-aside 
for the State for such control period, the Administrator will allocate 
to each TR NOX Ozone Season unit that is in the State, is 
allocated an amount of TR NOX Ozone Season allowances in the 
notice of data availability issued under Sec. 97.511(a)(1), and 
continues to be allocated TR NOX Ozone Season allowances for 
such control period in accordance with Sec. 97.511(a)(2), an amount of 
TR NOX Ozone Season allowances equal to the following: the 
total amount of such remaining unallocated TR NOX Ozone 
Season allowances in such new unit set-aside, multiplied by the unit's 
allocation under Sec. 97.511(a) for such control period, divided by the 
remainder of the amount of tons in the applicable State NOX 
Ozone Season trading budget minus the sum of the amounts of tons in such 
new unit set-aside and the Indian country new unit set-aside for the 
State for such control period, and rounded to the nearest allowance.
    (11) The Administrator will notify the public, through the 
promulgation of the notices of data availability described in Sec. 
97.511(b)(1)(iii), (iv), and (v), of the amount of TR NOX 
Ozone Season allowances allocated under paragraphs (a)(9), (10), and 
(12) of this section for such control period to each TR NOX 
Ozone Season unit eligible for such allocation.
    (12)(i) Notwithstanding the requirements of paragraphs (a)(2) 
through (11) of this section, if the calculations of allocations of a 
new unit set-aside for a control period in a given year under paragraph 
(a)(7) of this section, paragraphs (a)(6) and (9)(iv) of this section, 
or paragraphs (a)(6), (9)(iii), and (10) of this section would otherwise 
result in total allocations of such new unit set-aside exceeding the 
total amount of such new unit set-aside, then the Administrator will 
adjust the results of the calculations under paragraph (a)(7), (9)(iv), 
or (10) of this section, as applicable, as follows. The Administrator 
will list the TR NOX Ozone Season units in descending order 
based on the amount of such units' allocations under paragraph (a)(7), 
(9)(iv), or (10) of this section, as applicable, and, in cases of equal 
allocation amounts, in alphabetical order of the relevant source's name 
and numerical order of the relevant unit's identification number, and 
will reduce each unit's allocation under paragraph (a)(7), (9)(iv), or 
(10) of this section, as applicable, by one TR NOX Ozone 
Season allowance (but not below zero) in the order in which the units 
are listed and will repeat this reduction process as necessary, until 
the total allocations of

[[Page 415]]

such new unit set-aside equal the total amount of such new unit set-
aside.
    (ii) Notwithstanding the requirements of paragraphs (a)(10) and (11) 
of this section, if the calculations of allocations of a new unit set-
aside for a control period in a given year under paragraphs (a)(6), 
(9)(iii), and (10) of this section would otherwise result in a total 
allocations of such new unit set-aside less than the total amount of 
such new unit set-aside, then the Administrator will adjust the results 
of the calculations under paragraph (a)(10) of this section, as follows. 
The Administrator will list the TR NOX Ozone Season units in 
descending order based on the amount of such units' allocations under 
paragraph (a)(10) of this section and, in cases of equal allocation 
amounts, in alphabetical order of the relevant source's name and 
numerical order of the relevant unit's identification number, and will 
increase each unit's allocation under paragraph (a)(10) of this section 
by one TR NOX Ozone Season allowance in the order in which 
the units are listed and will repeat this increase process as necessary, 
until the total allocations of such new unit set-aside equal the total 
amount of such new unit set-aside.
    (b) For each control period in 2015 and thereafter and for the TR 
NOX Ozone Season units located in Indian country within the 
borders of each State, the Administrator will allocate TR NOX 
Ozone Season allowances to the TR NOX Ozone Season units as 
follows:
    (1) The TR NOX Ozone Season allowances will be allocated 
to the following TR NOX Ozone Season units, except as 
provided in paragraph (b)(10) of this section:
    (i) TR NOX Ozone Season units that are not allocated an 
amount of TR NOX Ozone Season allowances in the notice of 
data availability issued under Sec. 97.511(a)(1); or
    (ii) For purposes of paragraph (b)(9) of this section, TR 
NOX Ozone Season units under Sec. 97.511(c)(1)(ii) whose 
allocation of an amount of TR NOX Ozone Season allowances for 
such control period in the notice of data availability issued under 
Sec. 97.511(b)(2)(ii)(B) is covered by Sec. 97.511(c)(2) or (3).
    (2) The Administrator will establish a separate Indian country new 
unit set-aside for the State for each such control period. Each such 
Indian country new unit set-aside will be allocated TR NOX 
Ozone Season allowances in an amount equal to the applicable amount of 
tons of NOX emissions as set forth in Sec. 97.510(a) and 
will be allocated additional TR NOX Ozone Season allowances 
(if any) in accordance with Sec. 97.511(c)(5).
    (3) The Administrator will determine, for each TR NOX 
Ozone Season unit described in paragraph (b)(1) of this section, an 
allocation of TR NOX Ozone Season allowances for the later of 
the following control periods and for each subsequent control period:
    (i) The control period in 2015; and
    (ii) The first control period after the control period in which the 
TR NOX Ozone Season unit commences commercial operation.
    (4)(i) The allocation to each TR NOX Ozone Season unit 
described in paragraph (b)(1)(i) of this section and for each control 
period described in paragraph (b)(3) of this section will be an amount 
equal to the unit's total tons of NOX emissions during the 
immediately preceding control period.
    (ii) The Administrator will adjust the allocation amount in 
paragraph (b)(4)(i) in accordance with paragraphs (b)(5) through (7) and 
(12) of this section.
    (5) The Administrator will calculate the sum of the TR 
NOX Ozone Season allowances determined for all such TR 
NOX Ozone Season units under paragraph (b)(4)(i) of this 
section in Indian country within the borders of the State for such 
control period.
    (6) If the amount of TR NOX Ozone Season allowances in 
the Indian country new unit set-aside for the State for such control 
period is greater than or equal to the sum under paragraph (b)(5) of 
this section, then the Administrator will allocate the amount of TR 
NOX Ozone Season allowances determined for each such TR 
NOX Ozone Season unit under paragraph (b)(4)(i) of this 
section.
    (7) If the amount of TR NOX Ozone Season allowances in 
the Indian country new unit set-aside for the State for such control 
period is less than the

[[Page 416]]

sum under paragraph (b)(5) of this section, then the Administrator will 
allocate to each such TR NOX Ozone Season unit the amount of 
the TR NOX Ozone Season allowances determined under paragraph 
(b)(4)(i) of this section for the unit, multiplied by the amount of TR 
NOX Ozone Season allowances in the Indian country new unit 
set-aside for such control period, divided by the sum under paragraph 
(b)(5) of this section, and rounded to the nearest allowance.
    (8) The Administrator will notify the public, through the 
promulgation of the notices of data availability described in Sec. 
97.511(b)(2)(i) and (ii), of the amount of TR NOX Ozone 
Season allowances allocated under paragraphs (b)(2) through (7) and (12) 
of this section for such control period to each TR NOX Ozone 
Season unit eligible for such allocation.
    (9) If, after completion of the procedures under paragraphs (b)(5) 
through (8) of this section for such control period, any unallocated TR 
NOX Ozone Season allowances remain in the Indian country new 
unit set-aside for the State for such control period, the Administrator 
will allocate such TR NOX Ozone Season allowances as 
follows--
    (i) The Administrator will determine, for each unit described in 
paragraph (b)(1) of this section that commenced commercial operation 
during the period starting May 1 of the year before the year of such 
control period and ending August 31 of year of such control period, the 
positive difference (if any) between the unit's emissions during such 
control period and the amount of TR NOX Ozone Season 
allowances referenced in the notice of data availability required under 
Sec. 97.511(b)(2)(ii) for the unit for such control period;
    (ii) The Administrator will determine the sum of the positive 
differences determined under paragraph (b)(9)(i) of this section;
    (iii) If the amount of unallocated TR NOX Ozone Season 
allowances remaining in the Indian country new unit set-aside for the 
State for such control period is greater than or equal to the sum 
determined under paragraph (b)(9)(ii) of this section, then the 
Administrator will allocate the amount of TR NOX Ozone Season 
allowances determined for each such TR NOX Ozone Season unit 
under paragraph (b)(9)(i) of this section; and
    (iv) If the amount of unallocated TR NOX Ozone Season 
allowances remaining in the Indian country new unit set-aside for the 
State for such control period is less than the sum under paragraph 
(b)(9)(ii) of this section, then the Administrator will allocate to each 
such TR NOX Ozone Season unit the amount of the TR 
NOX Ozone Season allowances determined under paragraph 
(b)(9)(i) of this section for the unit, multiplied by the amount of 
unallocated TR NOX Ozone Season allowances remaining in the 
Indian country new unit set-aside for such control period, divided by 
the sum under paragraph (b)(9)(ii) of this section, and rounded to the 
nearest allowance.
    (10) If, after completion of the procedures under paragraphs (b)(9) 
and (12) of this section for such control period, any unallocated TR 
NOX Ozone Season allowances remain in the Indian country new 
unit set-aside for the State for such control period, the Administrator 
will:
    (i) Transfer such unallocated TR NOX Ozone Season 
allowances to the new unit set-aside for the State for such control 
period; or
    (ii) If the State has a SIP revision approved under Sec. 
52.38(b)(4) or (5) covering such control period, include such 
unallocated TR NOX Ozone Season allowances in the portion of 
the State NOX Ozone Season trading budget that may be 
allocated for such control period in accordance with such SIP revision.
    (11) The Administrator will notify the public, through the 
promulgation of the notices of data availability described in Sec. 
97.511(b)(2)(iii), (iv), and (v), of the amount of TR NOX 
Ozone Season allowances allocated under paragraphs (b)(9), (10), and 
(12) of this section for such control period to each TR NOX 
Ozone Season unit eligible for such allocation.
    (12)(i) Notwithstanding the requirements of paragraphs (b)(2) 
through (11) of this section, if the calculations of allocations of an 
Indian country new unit set-aside for a control period in a given year 
under paragraph (b)(7) of this section, paragraphs (b)(6) and

[[Page 417]]

(9)(iv) of this section, or paragraphs (b)(6), (9)(iii), and (10) of 
this section would otherwise result in total allocations of such Indian 
country new unit set-aside exceeding the total amount of such Indian 
country new unit set-aside, then the Administrator will adjust the 
results of the calculations under paragraph (b)(7), (9)(iv), or (10) of 
this section, as applicable, as follows. The Administrator will list the 
TR NOX Ozone Season units in descending order based on the 
amount of such units' allocations under paragraph (b)(7), (9)(iv), or 
(10) of this section, as applicable, and, in cases of equal allocation 
amounts, in alphabetical order of the relevant source's name and 
numerical order of the relevant unit's identification number, and will 
reduce each unit's allocation under paragraph (b)(7), (9)(iv), or (10) 
of this section, as applicable, by one TR NOX Ozone Season 
allowance (but not below zero) in the order in which the units are 
listed and will repeat this reduction process as necessary, until the 
total allocations of such Indian country new unit set-aside equal the 
total amount of such Indian country new unit set-aside.
    (ii) Notwithstanding the requirements of paragraphs (b)(10) and (11) 
of this section, if the calculations of allocations of an Indian country 
new unit set-aside for a control period in a given year under paragraphs 
(b)(6), (9)(iii), and (10) of this section would otherwise result in a 
total allocations of such Indian country new unit set-aside less than 
the total amount of such Indian country new unit set-aside, then the 
Administrator will adjust the results of the calculations under 
paragraph (b)(10) of this section, as follows. The Administrator will 
list the TR NOX Ozone Season units in descending order based 
on the amount of such units' allocations under paragraph (b)(10) of this 
section and, in cases of equal allocation amounts, in alphabetical order 
of the relevant source's name and numerical order of the relevant unit's 
identification number, and will increase each unit's allocation under 
paragraph (b)(10) of this section by one TR NOX Ozone Season 
allowance in the order in which the units are listed and will repeat 
this increase process as necessary, until the total allocations of such 
Indian country new unit set-aside equal the total amount of such Indian 
country new unit set-aside.

[76 FR 48379, Aug. 8, 2011, as amended at 79 FR 71672, Dec. 3, 2014]



Sec. 97.513  Authorization of designated representative and alternate
designated representative.

    (a) Except as provided under Sec. 97.515, each TR NOX 
Ozone Season source, including all TR NOX Ozone Season units 
at the source, shall have one and only one designated representative, 
with regard to all matters under the TR NOX Ozone Season 
Trading Program.
    (1) The designated representative shall be selected by an agreement 
binding on the owners and operators of the source and all TR 
NOX Ozone Season units at the source and shall act in 
accordance with the certification statement in Sec. 97.516(a)(4)(iii).
    (2) Upon and after receipt by the Administrator of a complete 
certificate of representation under Sec. 97.516:
    (i) The designated representative shall be authorized and shall 
represent and, by his or her representations, actions, inactions, or 
submissions, legally bind each owner and operator of the source and each 
TR NOX Ozone Season unit at the source in all matters 
pertaining to the TR NOX Ozone Season Trading Program, 
notwithstanding any agreement between the designated representative and 
such owners and operators; and
    (ii) The owners and operators of the source and each TR 
NOX Ozone Season unit at the source shall be bound by any 
decision or order issued to the designated representative by the 
Administrator regarding the source or any such unit.
    (b) Except as provided under Sec. 97.515, each TR NOX 
Ozone Season source may have one and only one alternate designated 
representative, who may act on behalf of the designated representative. 
The agreement by which the alternate designated representative is 
selected shall include a procedure for authorizing the alternate 
designated representative to act in lieu of the designated 
representative.
    (1) The alternate designated representative shall be selected by an 
agreement binding on the owners and

[[Page 418]]

operators of the source and all TR NOX Ozone Season units at 
the source and shall act in accordance with the certification statement 
in Sec. 97.516(a)(4)(iii).
    (2) Upon and after receipt by the Administrator of a complete 
certificate of representation under Sec. 97.516,
    (i) The alternate designated representative shall be authorized;
    (ii) Any representation, action, inaction, or submission by the 
alternate designated representative shall be deemed to be a 
representation, action, inaction, or submission by the designated 
representative; and
    (iii) The owners and operators of the source and each TR 
NOX Ozone Season unit at the source shall be bound by any 
decision or order issued to the alternate designated representative by 
the Administrator regarding the source or any such unit.
    (c) Except in this section, Sec. 97.502, and Sec. Sec. 97.514 
through 97.518, whenever the term ``designated representative'' (as 
distinguished from the term ``common designated representative'') is 
used in this subpart, the term shall be construed to include the 
designated representative or any alternate designated representative.



Sec. 97.514  Responsibilities of designated representative and 
alternate designated representative.

    (a) Except as provided under Sec. 97.518 concerning delegation of 
authority to make submissions, each submission under the TR 
NOX Ozone Season Trading Program shall be made, signed, and 
certified by the designated representative or alternate designated 
representative for each TR NOX Ozone Season source and TR 
NOX Ozone Season unit for which the submission is made. Each 
such submission shall include the following certification statement by 
the designated representative or alternate designated representative: 
``I am authorized to make this submission on behalf of the owners and 
operators of the source or units for which the submission is made. I 
certify under penalty of law that I have personally examined, and am 
familiar with, the statements and information submitted in this document 
and all its attachments. Based on my inquiry of those individuals with 
primary responsibility for obtaining the information, I certify that the 
statements and information are to the best of my knowledge and belief 
true, accurate, and complete. I am aware that there are significant 
penalties for submitting false statements and information or omitting 
required statements and information, including the possibility of fine 
or imprisonment.''
    (b) The Administrator will accept or act on a submission made for a 
TR NOX Ozone Season source or a TR NOX Ozone 
Season unit only if the submission has been made, signed, and certified 
in accordance with paragraph (a) of this section and Sec. 97.518.



Sec. 97.515  Changing designated representative and alternate
designated representative; changes in owners and operators; changes 
in units at the source.

    (a) Changing designated representative. The designated 
representative may be changed at any time upon receipt by the 
Administrator of a superseding complete certificate of representation 
under Sec. 97.516. Notwithstanding any such change, all 
representations, actions, inactions, and submissions by the previous 
designated representative before the time and date when the 
Administrator receives the superseding certificate of representation 
shall be binding on the new designated representative and the owners and 
operators of the TR NOX Ozone Season source and the TR 
NOX Ozone Season units at the source.
    (b) Changing alternate designated representative. The alternate 
designated representative may be changed at any time upon receipt by the 
Administrator of a superseding complete certificate of representation 
under Sec. 97.516. Notwithstanding any such change, all 
representations, actions, inactions, and submissions by the previous 
alternate designated representative before the time and date when the 
Administrator receives the superseding certificate of representation 
shall be binding on the new alternate designated representative, the 
designated representative, and the owners and operators of the TR 
NOX Ozone Season source and the TR NOX Ozone 
Season units at the source.
    (c) Changes in owners and operators. (1) In the event an owner or 
operator of

[[Page 419]]

a TR NOX Ozone Season source or a TR NOX Ozone 
Season unit at the source is not included in the list of owners and 
operators in the certificate of representation under Sec. 97.516, such 
owner or operator shall be deemed to be subject to and bound by the 
certificate of representation, the representations, actions, inactions, 
and submissions of the designated representative and any alternate 
designated representative of the source or unit, and the decisions and 
orders of the Administrator, as if the owner or operator were included 
in such list.
    (2) Within 30 days after any change in the owners and operators of a 
TR NOX Ozone Season source or a TR NOX Ozone 
Season unit at the source, including the addition or removal of an owner 
or operator, the designated representative or any alternate designated 
representative shall submit a revision to the certificate of 
representation under Sec. 97.516 amending the list of owners and 
operators to reflect the change.
    (d) Changes in units at the source. Within 30 days of any change in 
which units are located at a TR NOX Ozone Season source 
(including the addition or removal of a unit), the designated 
representative or any alternate designated representative shall submit a 
certificate of representation under Sec. 97.516 amending the list of 
units to reflect the change.
    (1) If the change is the addition of a unit that operated (other 
than for purposes of testing by the manufacturer before initial 
installation) before being located at the source, then the certificate 
of representation shall identify, in a format prescribed by the 
Administrator, the entity from whom the unit was purchased or otherwise 
obtained (including name, address, telephone number, and facsimile 
number (if any)), the date on which the unit was purchased or otherwise 
obtained, and the date on which the unit became located at the source.
    (2) If the change is the removal of a unit, then the certificate of 
representation shall identify, in a format prescribed by the 
Administrator, the entity to which the unit was sold or that otherwise 
obtained the unit (including name, address, telephone number, and 
facsimile number (if any)), the date on which the unit was sold or 
otherwise obtained, and the date on which the unit became no longer 
located at the source.



Sec. 97.516  Certificate of representation.

    (a) A complete certificate of representation for a designated 
representative or an alternate designated representative shall include 
the following elements in a format prescribed by the Administrator:
    (1) Identification of the TR NOX Ozone Season source, and 
each TR NOX Ozone Season unit at the source, for which the 
certificate of representation is submitted, including source name, 
source category and NAICS code (or, in the absence of a NAICS code, an 
equivalent code), State, plant code, county, latitude and longitude, 
unit identification number and type, identification number and nameplate 
capacity (in MWe, rounded to the nearest tenth) of each generator served 
by each such unit, actual or projected date of commencement of 
commercial operation, and a statement of whether such source is located 
in Indian Country. If a projected date of commencement of commercial 
operation is provided, the actual date of commencement of commercial 
operation shall be provided when such information becomes available.
    (2) The name, address, e-mail address (if any), telephone number, 
and facsimile transmission number (if any) of the designated 
representative and any alternate designated representative.
    (3) A list of the owners and operators of the TR NOX 
Ozone Season source and of each TR NOX Ozone Season unit at 
the source.
    (4) The following certification statements by the designated 
representative and any alternate designated representative--
    (i) ``I certify that I was selected as the designated representative 
or alternate designated representative, as applicable, by an agreement 
binding on the owners and operators of the source and each TR 
NOX Ozone Season unit at the source.''
    (ii) ``I certify that I have all the necessary authority to carry 
out my duties and responsibilities under the TR NOX Ozone 
Season Trading Program on

[[Page 420]]

behalf of the owners and operators of the source and of each TR 
NOX Ozone Season unit at the source and that each such owner 
and operator shall be fully bound by my representations, actions, 
inactions, or submissions and by any decision or order issued to me by 
the Administrator regarding the source or unit.''
    (iii) ``Where there are multiple holders of a legal or equitable 
title to, or a leasehold interest in, a TR NOX Ozone Season 
unit, or where a utility or industrial customer purchases power from a 
TR NOX Ozone Season unit under a life-of-the-unit, firm power 
contractual arrangement, I certify that: I have given a written notice 
of my selection as the `designated representative' or `alternate 
designated representative', as applicable, and of the agreement by which 
I was selected to each owner and operator of the source and of each TR 
NOX Ozone Season unit at the source; and TR NOX 
Ozone Season allowances and proceeds of transactions involving TR 
NOX Ozone Season allowances will be deemed to be held or 
distributed in proportion to each holder's legal, equitable, leasehold, 
or contractual reservation or entitlement, except that, if such multiple 
holders have expressly provided for a different distribution of TR 
NOX Ozone Season allowances by contract, TR NOX 
Ozone Season allowances and proceeds of transactions involving TR 
NOX Ozone Season allowances will be deemed to be held or 
distributed in accordance with the contract.''
    (5) The signature of the designated representative and any alternate 
designated representative and the dates signed.
    (b) Unless otherwise required by the Administrator, documents of 
agreement referred to in the certificate of representation shall not be 
submitted to the Administrator. The Administrator shall not be under any 
obligation to review or evaluate the sufficiency of such documents, if 
submitted.



Sec. 97.517  Objections concerning designated representative and
alternate designated representative.

    (a) Once a complete certificate of representation under Sec. 97.516 
has been submitted and received, the Administrator will rely on the 
certificate of representation unless and until a superseding complete 
certificate of representation under Sec. 97.516 is received by the 
Administrator.
    (b) Except as provided in paragraph (a) of this section, no 
objection or other communication submitted to the Administrator 
concerning the authorization, or any representation, action, inaction, 
or submission, of a designated representative or alternate designated 
representative shall affect any representation, action, inaction, or 
submission of the designated representative or alternate designated 
representative or the finality of any decision or order by the 
Administrator under the TR NOX Ozone Season Trading Program.
    (c) The Administrator will not adjudicate any private legal dispute 
concerning the authorization or any representation, action, inaction, or 
submission of any designated representative or alternate designated 
representative, including private legal disputes concerning the proceeds 
of TR NOX Ozone Season allowance transfers.



Sec. 97.518  Delegation by designated representative and alternate 
designated representative.

    (a) A designated representative may delegate, to one or more natural 
persons, his or her authority to make an electronic submission to the 
Administrator provided for or required under this subpart.
    (b) An alternate designated representative may delegate, to one or 
more natural persons, his or her authority to make an electronic 
submission to the Administrator provided for or required under this 
subpart.
    (c) In order to delegate authority to a natural person to make an 
electronic submission to the Administrator in accordance with paragraph 
(a) or (b) of this section, the designated representative or alternate 
designated representative, as appropriate, must submit to the 
Administrator a notice of delegation, in a format prescribed by the 
Administrator, that includes the following elements:

[[Page 421]]

    (1) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of such designated representative 
or alternate designated representative;
    (2) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of each such natural person 
(referred to in this section as an ``agent'');
    (3) For each such natural person, a list of the type or types of 
electronic submissions under paragraph (a) or (b) of this section for 
which authority is delegated to him or her; and
    (4) The following certification statements by such designated 
representative or alternate designated representative:
    (i) ``I agree that any electronic submission to the Administrator 
that is made by an agent identified in this notice of delegation and of 
a type listed for such agent in this notice of delegation and that is 
made when I am a designated representative or alternate designated 
representative, as appropriate, and before this notice of delegation is 
superseded by another notice of delegation under 40 CFR 97.518(d) shall 
be deemed to be an electronic submission by me.''
    (ii) ``Until this notice of delegation is superseded by another 
notice of delegation under 40 CFR 97.518(d), I agree to maintain an e-
mail account and to notify the Administrator immediately of any change 
in my e-mail address unless all delegation of authority by me under 40 
CFR 97.518 is terminated.''.
    (d) A notice of delegation submitted under paragraph (c) of this 
section shall be effective, with regard to the designated representative 
or alternate designated representative identified in such notice, upon 
receipt of such notice by the Administrator and until receipt by the 
Administrator of a superseding notice of delegation submitted by such 
designated representative or alternate designated representative, as 
appropriate. The superseding notice of delegation may replace any 
previously identified agent, add a new agent, or eliminate entirely any 
delegation of authority.
    (e) Any electronic submission covered by the certification in 
paragraph (c)(4)(i) of this section and made in accordance with a notice 
of delegation effective under paragraph (d) of this section shall be 
deemed to be an electronic submission by the designated representative 
or alternate designated representative submitting such notice of 
delegation.



Sec. 97.519  [Reserved]



Sec. 97.520  Establishment of compliance accounts, assurance accounts,
and general accounts.

    (a) Compliance accounts. Upon receipt of a complete certificate of 
representation under Sec. 97.516, the Administrator will establish a 
compliance account for the TR NOX Ozone Season source for 
which the certificate of representation was submitted, unless the source 
already has a compliance account. The designated representative and any 
alternate designated representative of the source shall be the 
authorized account representative and the alternate authorized account 
representative respectively of the compliance account.
    (b) Assurance accounts. The Administrator will establish assurance 
accounts for certain owners and operators and States in accordance with 
Sec. 97.525(b)(3).
    (c) General accounts. (1) Application for general account. (i) Any 
person may apply to open a general account, for the purpose of holding 
and transferring TR NOX Ozone Season allowances, by 
submitting to the Administrator a complete application for a general 
account. Such application shall designate one and only one authorized 
account representative and may designate one and only one alternate 
authorized account representative who may act on behalf of the 
authorized account representative.
    (A) The authorized account representative and alternate authorized 
account representative shall be selected by an agreement binding on the 
persons who have an ownership interest with respect to TR NOX 
Ozone Season allowances held in the general account.
    (B) The agreement by which the alternate authorized account 
representative is selected shall include a procedure for authorizing the 
alternate authorized account representative to act

[[Page 422]]

in lieu of the authorized account representative.
    (ii) A complete application for a general account shall include the 
following elements in a format prescribed by the Administrator:
    (A) Name, mailing address, e-mail address (if any), telephone 
number, and facsimile transmission number (if any) of the authorized 
account representative and any alternate authorized account 
representative;
    (B) An identifying name for the general account;
    (C) A list of all persons subject to a binding agreement for the 
authorized account representative and any alternate authorized account 
representative to represent their ownership interest with respect to the 
TR NOX Ozone Season allowances held in the general account;
    (D) The following certification statement by the authorized account 
representative and any alternate authorized account representative: ``I 
certify that I was selected as the authorized account representative or 
the alternate authorized account representative, as applicable, by an 
agreement that is binding on all persons who have an ownership interest 
with respect to TR NOX Ozone Season allowances held in the 
general account. I certify that I have all the necessary authority to 
carry out my duties and responsibilities under the TR NOX 
Ozone Season Trading Program on behalf of such persons and that each 
such person shall be fully bound by my representations, actions, 
inactions, or submissions and by any decision or order issued to me by 
the Administrator regarding the general account.''
    (E) The signature of the authorized account representative and any 
alternate authorized account representative and the dates signed.
    (iii) Unless otherwise required by the Administrator, documents of 
agreement referred to in the application for a general account shall not 
be submitted to the Administrator. The Administrator shall not be under 
any obligation to review or evaluate the sufficiency of such documents, 
if submitted.
    (2) Authorization of authorized account representative and alternate 
authorized account representative. (i) Upon receipt by the Administrator 
of a complete application for a general account under paragraph (b)(1) 
of this section, the Administrator will establish a general account for 
the person or persons for whom the application is submitted, and upon 
and after such receipt by the Administrator:
    (A) The authorized account representative of the general account 
shall be authorized and shall represent and, by his or her 
representations, actions, inactions, or submissions, legally bind each 
person who has an ownership interest with respect to TR NOX 
Ozone Season allowances held in the general account in all matters 
pertaining to the TR NOX Ozone Season Trading Program, 
notwithstanding any agreement between the authorized account 
representative and such person.
    (B) Any alternate authorized account representative shall be 
authorized, and any representation, action, inaction, or submission by 
any alternate authorized account representative shall be deemed to be a 
representation, action, inaction, or submission by the authorized 
account representative.
    (C) Each person who has an ownership interest with respect to TR 
NOX Ozone Season allowances held in the general account shall 
be bound by any decision or order issued to the authorized account 
representative or alternate authorized account representative by the 
Administrator regarding the general account.
    (ii) Except as provided in paragraph (c)(5) of this section 
concerning delegation of authority to make submissions, each submission 
concerning the general account shall be made, signed, and certified by 
the authorized account representative or any alternate authorized 
account representative for the persons having an ownership interest with 
respect to TR NOX Ozone Season allowances held in the general 
account. Each such submission shall include the following certification 
statement by the authorized account representative or any alternate 
authorized account representative: ``I am authorized to make this 
submission on behalf of the persons having an ownership interest with 
respect to the TR NOX Ozone Season allowances held in the 
general account. I certify under penalty of law that I have

[[Page 423]]

personally examined, and am familiar with, the statements and 
information submitted in this document and all its attachments. Based on 
my inquiry of those individuals with primary responsibility for 
obtaining the information, I certify that the statements and information 
are to the best of my knowledge and belief true, accurate, and complete. 
I am aware that there are significant penalties for submitting false 
statements and information or omitting required statements and 
information, including the possibility of fine or imprisonment.''
    (iii) Except in this section, whenever the term ``authorized account 
representative'' is used in this subpart, the term shall be construed to 
include the authorized account representative or any alternate 
authorized account representative.
    (3) Changing authorized account representative and alternate 
authorized account representative; changes in persons with ownership 
interest. (i) The authorized account representative of a general account 
may be changed at any time upon receipt by the Administrator of a 
superseding complete application for a general account under paragraph 
(c)(1) of this section. Notwithstanding any such change, all 
representations, actions, inactions, and submissions by the previous 
authorized account representative before the time and date when the 
Administrator receives the superseding application for a general account 
shall be binding on the new authorized account representative and the 
persons with an ownership interest with respect to the TR NOX 
Ozone Season allowances in the general account.
    (ii) The alternate authorized account representative of a general 
account may be changed at any time upon receipt by the Administrator of 
a superseding complete application for a general account under paragraph 
(c)(1) of this section. Notwithstanding any such change, all 
representations, actions, inactions, and submissions by the previous 
alternate authorized account representative before the time and date 
when the Administrator receives the superseding application for a 
general account shall be binding on the new alternate authorized account 
representative, the authorized account representative, and the persons 
with an ownership interest with respect to the TR NOX Ozone 
Season allowances in the general account.
    (iii)(A) In the event a person having an ownership interest with 
respect to TR NOX Ozone Season allowances in the general 
account is not included in the list of such persons in the application 
for a general account, such person shall be deemed to be subject to and 
bound by the application for a general account, the representation, 
actions, inactions, and submissions of the authorized account 
representative and any alternate authorized account representative of 
the account, and the decisions and orders of the Administrator, as if 
the person were included in such list.
    (B) Within 30 days after any change in the persons having an 
ownership interest with respect to NOX Ozone Season 
allowances in the general account, including the addition or removal of 
a person, the authorized account representative or any alternate 
authorized account representative shall submit a revision to the 
application for a general account amending the list of persons having an 
ownership interest with respect to the TR NOX Ozone Season 
allowances in the general account to include the change.
    (4) Objections concerning authorized account representative and 
alternate authorized account representative. (i) Once a complete 
application for a general account under paragraph (c)(1) of this section 
has been submitted and received, the Administrator will rely on the 
application unless and until a superseding complete application for a 
general account under paragraph (b)(1) of this section is received by 
the Administrator.
    (ii) Except as provided in paragraph (c)(4)(i) of this section, no 
objection or other communication submitted to the Administrator 
concerning the authorization, or any representation, action, inaction, 
or submission of the authorized account representative or any alternate 
authorized account representative of a general account shall affect any 
representation, action, inaction, or submission of the authorized 
account

[[Page 424]]

representative or any alternate authorized account representative or the 
finality of any decision or order by the Administrator under the TR 
NOX Ozone Season Trading Program.
    (iii) The Administrator will not adjudicate any private legal 
dispute concerning the authorization or any representation, action, 
inaction, or submission of the authorized account representative or any 
alternate authorized account representative of a general account, 
including private legal disputes concerning the proceeds of TR 
NOX Ozone Season allowance transfers.
    (5) Delegation by authorized account representative and alternate 
authorized account representative. (i) An authorized account 
representative of a general account may delegate, to one or more natural 
persons, his or her authority to make an electronic submission to the 
Administrator provided for or required under this subpart.
    (ii) An alternate authorized account representative of a general 
account may delegate, to one or more natural persons, his or her 
authority to make an electronic submission to the Administrator provided 
for or required under this subpart.
    (iii) In order to delegate authority to a natural person to make an 
electronic submission to the Administrator in accordance with paragraph 
(c)(5)(i) or (ii) of this section, the authorized account representative 
or alternate authorized account representative, as appropriate, must 
submit to the Administrator a notice of delegation, in a format 
prescribed by the Administrator, that includes the following elements:
    (A) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of such authorized account 
representative or alternate authorized account representative;
    (B) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of each such natural person 
(referred to in this section as an ``agent'');
    (C) For each such natural person, a list of the type or types of 
electronic submissions under paragraph (c)(5)(i) or (ii) of this section 
for which authority is delegated to him or her;
    (D) The following certification statement by such authorized account 
representative or alternate authorized account representative: ``I agree 
that any electronic submission to the Administrator that is made by an 
agent identified in this notice of delegation and of a type listed for 
such agent in this notice of delegation and that is made when I am an 
authorized account representative or alternate authorized 
representative, as appropriate, and before this notice of delegation is 
superseded by another notice of delegation under 40 CFR 97.520(c)(5)(iv) 
shall be deemed to be an electronic submission by me.''; and
    (E) The following certification statement by such authorized account 
representative or alternate authorized account representative: ``Until 
this notice of delegation is superseded by another notice of delegation 
under 40 CFR 97.520(c)(5)(iv), I agree to maintain an e-mail account and 
to notify the Administrator immediately of any change in my e-mail 
address unless all delegation of authority by me under 40 CFR 
97.520(c)(5) is terminated.''.
    (iv) A notice of delegation submitted under paragraph (c)(5)(iii) of 
this section shall be effective, with regard to the authorized account 
representative or alternate authorized account representative identified 
in such notice, upon receipt of such notice by the Administrator and 
until receipt by the Administrator of a superseding notice of delegation 
submitted by such authorized account representative or alternate 
authorized account representative, as appropriate. The superseding 
notice of delegation may replace any previously identified agent, add a 
new agent, or eliminate entirely any delegation of authority.
    (v) Any electronic submission covered by the certification in 
paragraph (c)(5)(iii)(D) of this section and made in accordance with a 
notice of delegation effective under paragraph (c)(5)(iv) of this 
section shall be deemed to be an electronic submission by the designated 
representative or alternate designated representative submitting such 
notice of delegation.
    (6) Closing a general account. (i) The authorized account 
representative or

[[Page 425]]

alternate authorized account representative of a general account may 
submit to the Administrator a request to close the account. Such request 
shall include a correctly submitted TR NOX Ozone Season 
allowance transfer under Sec. 97.522 for any TR NOX Ozone 
Season allowances in the account to one or more other Allowance 
Management System accounts.
    (ii) If a general account has no TR NOX Ozone Season 
allowance transfers to or from the account for a 12-month period or 
longer and does not contain any TR NOX Ozone Season 
allowances, the Administrator may notify the authorized account 
representative for the account that the account will be closed after 30 
days after the notice is sent. The account will be closed after the 30-
day period unless, before the end of the 30-day period, the 
Administrator receives a correctly submitted TR NOX Ozone 
Season allowance transfer under Sec. 97.522 to the account or a 
statement submitted by the authorized account representative or 
alternate authorized account representative demonstrating to the 
satisfaction of the Administrator good cause as to why the account 
should not be closed.
    (d) Account identification. The Administrator will assign a unique 
identifying number to each account established under paragraph (a), (b), 
or (c) of this section.
    (e) Responsibilities of authorized account representative and 
alternate authorized account representative. After the establishment of 
a compliance account or general account, the Administrator will accept 
or act on a submission pertaining to the account, including, but not 
limited to, submissions concerning the deduction or transfer of TR 
NOX Ozone Season allowances in the account, only if the 
submission has been made, signed, and certified in accordance with 
Sec. Sec. 97.514(a) and 97.518 or paragraphs (c)(2)(ii) and (c)(5) of 
this section.



Sec. 97.521  Recordation of TR NOX Ozone Season allowance allocations
and auction results.

    (a) By November 7, 2011 or, with regard to units in Iowa, Michigan, 
Missouri, Oklahoma, and Wisconsin, March 26, 2015, the Administrator 
will record in each TR NOX Ozone Season source's compliance 
account the TR NOX Ozone Season allowances allocated to the 
TR NOX Ozone Season units at the source in accordance with 
Sec. 97.511(a) for the control period in 2015.
    (b) By November 7, 2011 or, with regard to units in Iowa, Michigan, 
Missouri, Oklahoma, and Wisconsin, March 26, 2015, the Administrator 
will record in each TR NOX Ozone Season source's compliance 
account the TR NOX Ozone Season allowances allocated to the 
TR NOX Ozone Season units at the source in accordance with 
Sec. 97.511(a) for the control period in 2016, unless the State in 
which the source is located notifies the Administrator in writing by 
October 17, 2011 or, with regard to TR NOX Ozone Season units 
in Iowa, Michigan, Missouri, Oklahoma, and Wisconsin, March 6, 2015 of 
the State's intent to submit to the Administrator a complete SIP 
revision by April 1, 2015 or, with regard to units in Iowa, Michigan, 
Missouri, Oklahoma, and Wisconsin, October 1, 2015 meeting the 
requirements of Sec. 52.38(b)(3)(i) through (iv) of this chapter.
    (1) If, by April 1, 2015 or, with regard to TR NOX Ozone 
Season units in Iowa, Michigan, Missouri, Oklahoma, and Wisconsin, by 
October 1, 2015, the State does not submit to the Administrator such 
complete SIP revision, the Administrator will record by April 15, 2015 
or, with regard to units in Iowa, Michigan, Missouri, Oklahoma, and 
Wisconsin, October 15, 2015 in each TR NOX Ozone Season 
source's compliance account the TR NOX Ozone Season 
allowances allocated to the TR NOX Ozone Season units at the 
source in accordance with Sec. 97.511(a) for the control period in 
2016.
    (2) If the State submits to the Administrator by April 1, 2015 or, 
with regard to units in Iowa, Michigan, Missouri, Oklahoma, and 
Wisconsin, October 1, 2015, and the Administrator approves by October 1, 
2015 or, with regard to units in Iowa, Michigan, Missouri, Oklahoma, and 
Wisconsin, April 1, 2016, such complete SIP revision, the Administrator 
will record by October 1, 2015 or, with regard to units in Iowa, 
Michigan, Missouri, Oklahoma, and Wisconsin, April 1, 2016 in each TR 
NOX

[[Page 426]]

Ozone Season source's compliance account the TR NOX Ozone 
Season allowances allocated to the TR NOX Ozone Season units 
at the source as provided in such approved, complete SIP revision for 
the control period in 2016.
    (3) If the State submits to the Administrator by April 1, 2015 or, 
with regard to units in Iowa, Michigan, Missouri, Oklahoma, and 
Wisconsin, October 1, 2015, and the Administrator does not approve by 
October 1, 2015 or, with regard to units in Iowa, Michigan, Missouri, 
Oklahoma, and Wisconsin, April 1, 2016, such complete SIP revision, the 
Administrator will record by October 1, 2015 or, with regard to units in 
Iowa, Michigan, Missouri, Oklahoma, and Wisconsin, April 1, 2016 in each 
TR NOX Ozone Season source's compliance account the TR 
NOX Ozone Season allowances allocated to the TR 
NOX Ozone Season units at the source in accordance with Sec. 
97.511(a) for the control period in 2016.
    (c) By July 1, 2016, the Administrator will record in each TR 
NOX Ozone Season source's compliance account the TR 
NOX Ozone Season allowances allocated to the TR 
NOX Ozone Season units at the source, or in each appropriate 
Allowance Management System account the TR NOX Ozone Season 
allowances auctioned to TR NOX Ozone Season units, in 
accordance with Sec. 97.511(a), or with a SIP revision approved under 
Sec. 52.38(b)(4) or (5) of this chapter, for the control period in 2017 
and 2018.
    (d) By July 1, 2017, the Administrator will record in each TR 
NOX Ozone Season source's compliance account the TR 
NOX Ozone Season allowances allocated to the TR 
NOX Ozone Season units at the source, or in each appropriate 
Allowance Management System account the TR NOX Ozone Season 
allowances auctioned to TR NOX Ozone Season units, in 
accordance with Sec. 97.511(a), or with a SIP revision approved under 
Sec. 52.38(b)(4) or (5) of this chapter, for the control period in 2019 
and 2020.
    (e) By July 1, 2018, the Administrator will record in each TR 
NOX Ozone Season source's compliance account the TR 
NOX Ozone Season allowances allocated to the TR 
NOX Ozone Season units at the source, or in each appropriate 
Allowance Management System account the TR NOX Ozone Season 
allowances auctioned to TR NOX Ozone Season units, in 
accordance with Sec. 97.511(a), or with a SIP revision approved under 
Sec. 52.38(b)(4) or (5) of this chapter, for the control period in 2021 
and 2022.
    (f) By July 1, 2019 and July 1 of each year thereafter, the 
Administrator will record in each TR NOX Ozone Season 
source's compliance account the TR NOX Ozone Season 
allowances allocated to the TR NOX Ozone Season units at the 
source, or in each appropriate Allowance Management System account the 
TR NOX Ozone Season allowances auctioned to TR NOX 
Ozone Season units, in accordance with Sec. 97.511(a), or with a SIP 
revision approved under Sec. 52.38(b)(4) or (5) of this chapter, for 
the control period in the fourth year after the year of the applicable 
recordation deadline under this paragraph.
    (g) By August 1, 2015 and August 1 of each year thereafter, the 
Administrator will record in each TR NOX Ozone Season 
source's compliance account the TR NOX Ozone Season 
allowances allocated to the TR NOX Ozone Season units at the 
source, or in each appropriate Allowance Management System account the 
TR NOX Ozone Season allowances auctioned to TR NOX 
Ozone Season units, in accordance with Sec. 97.512(a)(2) through (8) 
and (12), or with a SIP revision approved under Sec. 52.38(b)(4) or (5) 
of this chapter, for the control period in the year of the applicable 
recordation deadline under this paragraph.
    (h) By August 1, 2015 and August 1 of each year thereafter, the 
Administrator will record in each TR NOX Ozone Season 
source's compliance account the TR NOX Ozone Season 
allowances allocated to the TR NOX Ozone Season units at the 
source in accordance with Sec. 97.512(b)(2) through (8) and (12) for 
the control period in the year of the applicable recordation deadline 
under this paragraph.
    (i) By November 15, 2015 and November 15 of each year thereafter, 
the Administrator will record in each TR NOX Ozone Season 
source's compliance account the TR NOX Ozone Season 
allowances allocated to the TR NOX Ozone

[[Page 427]]

Season units at the source in accordance with Sec. 97.512(a)(9) through 
(12), for the control period in the year of the applicable recordation 
deadline under this paragraph.
    (j) By the date on which any allocation or auction results, other 
than an allocation or auction results described in paragraphs (a) 
through (i) of this section, of TR NOX Ozone Season 
allowances to a recipient is made by or are submitted to the 
Administrator in accordance with Sec. 97.511 or Sec. 97.512 or with a 
SIP revision approved under Sec. 52.38(b)(4) or (5) of this chapter, 
the Administrator will record such allocation or auction results in the 
appropriate Allowance Management System account.
    (k) When recording the allocation or auction of TR NOX 
Ozone Season allowances to a TR NOX Ozone Season unit or 
other entity in an Allowance Management System account, the 
Administrator will assign each TR NOX Ozone Season allowance 
a unique identification number that will include digits identifying the 
year of the control period for which the TR NOX Ozone Season 
allowance is allocated or auctioned.

[76 FR 48406, Aug. 8, 2011, as amended at 76 FR 80777, Dec. 27, 2011; 79 
FR 71672, Dec. 3, 2014]



Sec. 97.522  Submission of TR NOX Ozone Season allowance transfers.

    (a) An authorized account representative seeking recordation of a TR 
NOX Ozone Season allowance transfer shall submit the transfer 
to the Administrator.
    (b) A TR NOX Ozone Season allowance transfer shall be 
correctly submitted if:
    (1) The transfer includes the following elements, in a format 
prescribed by the Administrator:
    (i) The account numbers established by the Administrator for both 
the transferor and transferee accounts;
    (ii) The serial number of each TR NOX Ozone Season 
allowance that is in the transferor account and is to be transferred; 
and
    (iii) The name and signature of the authorized account 
representative of the transferor account and the date signed; and
    (2) When the Administrator attempts to record the transfer, the 
transferor account includes each TR NOX Ozone Season 
allowance identified by serial number in the transfer.



Sec. 97.523  Recordation of TR NOX Ozone Season allowance transfers.

    (a) Within 5 business days (except as provided in paragraph (b) of 
this section) of receiving a TR NOX Ozone Season allowance 
transfer that is correctly submitted under Sec. 97.522, the 
Administrator will record a TR NOX Ozone Season allowance 
transfer by moving each TR NOX Ozone Season allowance from 
the transferor account to the transferee account as specified in the 
transfer.
    (b) A TR NOX Ozone Season allowance transfer to or from a 
compliance account that is submitted for recordation after the allowance 
transfer deadline for a control period and that includes any TR 
NOX Ozone Season allowances allocated for any control period 
before such allowance transfer deadline will not be recorded until after 
the Administrator completes the deductions from such compliance account 
under Sec. 97.524 for the control period immediately before such 
allowance transfer deadline.
    (c) Where a TR NOX Ozone Season allowance transfer is not 
correctly submitted under Sec. 97.522, the Administrator will not 
record such transfer.
    (d) Within 5 business days of recordation of a TR NOX 
Ozone Season allowance transfer under paragraphs (a) and (b) of the 
section, the Administrator will notify the authorized account 
representatives of both the transferor and transferee accounts.
    (e) Within 10 business days of receipt of a TR NOX Ozone 
Season allowance transfer that is not correctly submitted under Sec. 
97.522, the Administrator will notify the authorized account 
representatives of both accounts subject to the transfer of:
    (1) A decision not to record the transfer, and
    (2) The reasons for such non-recordation.

[[Page 428]]



Sec. 97.524  Compliance with TR NOX Ozone Season emissions limitation.

    (a) Availability for deduction for compliance. TR NOX 
Ozone Season allowances are available to be deducted for compliance with 
a source's TR NOX Ozone Season emissions limitation for a 
control period in a given year only if the TR NOX Ozone 
Season allowances:
    (1) Were allocated for such control period or a control period in a 
prior year; and
    (2) Are held in the source's compliance account as of the allowance 
transfer deadline for such control period.
    (b) Deductions for compliance. After the recordation, in accordance 
with Sec. 97.523, of TR NOX Ozone Season allowance transfers 
submitted by the allowance transfer deadline for a control period in a 
given year, the Administrator will deduct from each source's compliance 
account TR NOX Ozone Season allowances available under 
paragraph (a) of this section in order to determine whether the source 
meets the TR NOX Ozone Season emissions limitation for such 
control period, as follows:
    (1) Until the amount of TR NOX Ozone Season allowances 
deducted equals the number of tons of total NOX emissions 
from all TR NOX Ozone Season units at the source for such 
control period; or
    (2) If there are insufficient TR NOX Ozone Season 
allowances to complete the deductions in paragraph (b)(1) of this 
section, until no more TR NOX Ozone Season allowances 
available under paragraph (a) of this section remain in the compliance 
account.
    (c)(1) Identification of TR NOX Ozone Season allowances by serial 
number. The authorized account representative for a source's compliance 
account may request that specific TR NOX Ozone Season 
allowances, identified by serial number, in the compliance account be 
deducted for emissions or excess emissions for a control period in a 
given year in accordance with paragraph (b) or (d) of this section. In 
order to be complete, such request shall be submitted to the 
Administrator by the allowance transfer deadline for such control period 
and include, in a format prescribed by the Administrator, the 
identification of the TR NOX Ozone Season source and the 
appropriate serial numbers.
    (2) First-in, first-out. The Administrator will deduct TR 
NOX Ozone Season allowances under paragraph (b) or (d) of 
this section from the source's compliance account in accordance with a 
complete request under paragraph (c)(1) of this section or, in the 
absence of such request or in the case of identification of an 
insufficient amount of TR NOX Ozone Season allowances in such 
request, on a first-in, first-out accounting basis in the following 
order:
    (i) Any TR NOX Ozone Season allowances that were 
allocated to the units at the source and not transferred out of the 
compliance account, in the order of recordation; and then
    (ii) Any TR NOX Ozone Season allowances that were 
allocated to any unit and transferred to and recorded in the compliance 
account pursuant to this subpart, in the order of recordation.
    (d) Deductions for excess emissions. After making the deductions for 
compliance under paragraph (b) of this section for a control period in a 
year in which the TR NOX Ozone Season source has excess 
emissions, the Administrator will deduct from the source's compliance 
account an amount of TR NOX Ozone Season allowances, 
allocated for a control period in a prior year or the control period in 
the year of the excess emissions or in the immediately following year, 
equal to two times the number of tons of the source's excess emissions.
    (e) Recordation of deductions. The Administrator will record in the 
appropriate compliance account all deductions from such an account under 
paragraphs (b) and (d) of this section.



Sec. 97.525  Compliance with TR NOX Ozone Season assurance provisions.

    (a) Availability for deduction. TR NOX Ozone Season 
allowances are available to be deducted for compliance with the TR 
NOX Ozone Season assurance provisions for a control period in 
a given year by the owners and operators of a group of one or more TR 
NOX Ozone Season sources and units in a State (and Indian 
country within the borders of such State) only if the TR NOX 
Ozone Season allowances:

[[Page 429]]

    (1) Were allocated for a control period in a prior year or the 
control period in the given year or in the immediately following year; 
and
    (2) Are held in the assurance account, established by the 
Administrator for such owners and operators of such group of TR 
NOX Ozone Season sources and units in such State (and Indian 
country within the borders of such State) under paragraph (b)(3) of this 
section, as of the deadline established in paragraph (b)(4) of this 
section.
    (b) Deductions for compliance. The Administrator will deduct TR 
NOX Ozone Season allowances available under paragraph (a) of 
this section for compliance with the TR NOX Ozone Season 
assurance provisions for a State for a control period in a given year in 
accordance with the following procedures:
    (1) By June 1, 2018 and June 1 of each year thereafter, the 
Administrator will:
    (i) Calculate, for each State (and Indian country within the borders 
of such State), the total NOX emissions from all TR 
NOX Ozone Season units at TR NOX Ozone Season 
sources in the State (and Indian country within the borders of such 
State) during the control period in the year before the year of this 
calculation deadline and the amount, if any, by which such total 
NOX emissions exceed the State assurance level as described 
in Sec. 97.506(c)(2)(iii); and
    (ii) Promulgate a notice of data availability of the results of the 
calculations required in paragraph (b)(1)(i) of this section, including 
separate calculations of the NOX emissions from each TR 
NOX Ozone Season source.
    (2) For each notice of data availability required in paragraph 
(b)(1)(ii) of this section and for any State (and Indian country within 
the borders of such State) identified in such notice as having TR 
NOX Ozone Season units with total NOX emissions 
exceeding the State assurance level for a control period in a given 
year, as described in Sec. 97.506(c)(2)(iii):
    (i) By July 1 immediately after the promulgation of such notice, the 
designated representative of each TR NOX Ozone Season source 
in each such State (and Indian country within the borders of such State) 
shall submit a statement, in a format prescribed by the Administrator, 
providing for each TR NOX Ozone Season unit (if any) at the 
source that operates during, but is not allocated an amount of TR 
NOX Ozone Season allowances for, such control period, the 
unit's allowable NOX emission rate for such control period 
and, if such rate is expressed in lb per mmBtu, the unit's heat rate.
    (ii) By August 1 immediately after the promulgation of such notice, 
the Administrator will calculate, for each such State (and Indian 
country within the borders of such State) and such control period and 
each common designated representative for such control period for a 
group of one or more TR NOX Ozone Season sources and units in 
the State (and Indian country within the borders of such State), the 
common designated representative's share of the total NOX 
emissions from all TR NOX Ozone Season units at TR 
NOX Ozone Season sources in the State (and Indian country 
within the borders of such State), the common designated 
representative's assurance level, and the amount (if any) of TR 
NOX Ozone Season allowances that the owners and operators of 
such group of sources and units must hold in accordance with the 
calculation formula in Sec. 97.506(c)(2)(i) and will promulgate a 
notice of data availability of the results of these calculations.
    (iii) The Administrator will provide an opportunity for submission 
of objections to the calculations referenced by the notice of data 
availability required in paragraph (b)(2)(ii) of this section and the 
calculations referenced by the relevant notice of data availability 
required in paragraph (b)(1)(i) of this section.
    (A) Objections shall be submitted by the deadline specified in such 
notice and shall be limited to addressing whether the calculations 
referenced in the relevant notice required under paragraph (b)(1)(ii) of 
this section and referenced in the notice required under paragraph 
(b)(2)(ii) of this section are in accordance with Sec. 
97.506(c)(2)(iii), Sec. Sec. 97.506(b) and 97.530 through 97.535, the 
definitions of ``common designated representative'', ``common designated 
representative's assurance level'', and ``common designated 
representative's

[[Page 430]]

share'' in Sec. 97.502, and the calculation formula in Sec. 
97.506(c)(2)(i).
    (B) The Administrator will adjust the calculations to the extent 
necessary to ensure that they are in accordance with the provisions 
referenced in paragraph (b)(2)(iii)(A) of this section. By October 1 
immediately after the promulgation of such notice, the Administrator 
will promulgate a notice of data availability of any adjustments that 
the Administrator determines to be necessary and the reasons for 
accepting or rejecting any objections submitted in accordance with 
paragraph (b)(2)(iii)(A) of this section.
    (3) For any State (and Indian country within the borders of such 
State) referenced in each notice of data availability required in 
paragraph (b)(2)(iii)(B) of this section as having TR NOX 
Ozone Season units with total NOX emissions exceeding the 
State assurance level for a control period in a given year, the 
Administrator will establish one assurance account for each set of 
owners and operators referenced, in the notice of data availability 
required under paragraph (b)(2)(iii)(B) of this section, as all of the 
owners and operators of a group of TR NOX Ozone Season 
sources and units in the State (and Indian country within the borders of 
such State) having a common designated representative for such control 
period and as being required to hold TR NOX Ozone Season 
allowances.
    (4)(i) As of midnight of November 1 immediately after the 
promulgation of each notice of data availability required in paragraph 
(b)(2)(iii)(B) of this section, the owners and operators described in 
paragraph (b)(3) of this section shall hold in the assurance account 
established for the them and for the appropriate TR NOX Ozone 
Season sources, TR NOX Ozone Season units, and State (and 
Indian country within the borders of such State) under paragraph (b)(3) 
of this section a total amount of TR NOX Ozone Season 
allowances, available for deduction under paragraph (a) of this section, 
equal to the amount such owners and operators are required to hold with 
regard to such sources, units and State (and Indian country within the 
borders of such State) as calculated by the Administrator and referenced 
in such notice.
    (ii) Notwithstanding the allowance-holding deadline specified in 
paragraph (b)(4)(i) of this section, if November 1 is not a business 
day, then such allowance-holding deadline shall be midnight of the first 
business day thereafter.
    (5) After November 1 (or the date described in paragraph (b)(4)(ii) 
of this section) immediately after the promulgation of each notice of 
data availability required in paragraph (b)(2)(iii)(B) of this section 
and after the recordation, in accordance with Sec. 97.523, of TR 
NOX Ozone Season allowance transfers submitted by midnight of 
such date, the Administrator will determine whether the owners and 
operators described in paragraph (b)(3) of this section hold, in the 
assurance account for the appropriate TR NOX Ozone Season 
sources, TR NOX Ozone Season units, and State (and Indian 
country within the borders of such State) established under paragraph 
(b)(3) of this section, the amount of TR NOX Ozone Season 
allowances available under paragraph (a) of this section that the owners 
and operators are required to hold with regard to such sources, units, 
and State (and Indian country within the borders of such State) as 
calculated by the Administrator and referenced in the notice required in 
paragraph (b)(2)(iii)(B) of this section.
    (6) Notwithstanding any other provision of this subpart and any 
revision, made by or submitted to the Administrator after the 
promulgation of the notice of data availability required in paragraph 
(b)(2)(iii)(B) of this section for a control period in a given year, of 
any data used in making the calculations referenced in such notice, the 
amounts of TR NOX Ozone Season allowances that the owners and 
operators are required to hold in accordance with Sec. 97.506(c)(2)(i) 
for such control period shall continue to be such amounts as calculated 
by the Administrator and referenced in such notice required in paragraph 
(b)(2)(iii)(B) of this section, except as follows:
    (i) If any such data are revised by the Administrator as a result of 
a decision in or settlement of litigation concerning such data on appeal 
under part 78 of this chapter of such notice, or on appeal under section 
307 of the Clean

[[Page 431]]

Air Act of a decision rendered under part 78 of this chapter on appeal 
of such notice, then the Administrator will use the data as so revised 
to recalculate the amounts of TR NOX Ozone Season allowances 
that owners and operators are required to hold in accordance with the 
calculation formula in Sec. 97.506(c)(2)(i) for such control period 
with regard to the TR NOX Ozone Season sources, TR 
NOX Ozone Season units, and State (and Indian country within 
the borders of such State) involved, provided that such litigation under 
part 78 of this chapter, or the proceeding under part 78 of this chapter 
that resulted in the decision appealed in such litigation under section 
307 of the Clean Air Act, was initiated no later than 30 days after 
promulgation of such notice required in paragraph (b)(2)(iii)(B) of this 
section.
    (ii) If any such data are revised by the owners and operators of a 
TR NOX Ozone Season source and TR NOX Ozone Season 
unit whose designated representative submitted such data under paragraph 
(b)(2)(i) of this section, as a result of a decision in or settlement of 
litigation concerning such submission, then the Administrator will use 
the data as so revised to recalculate the amounts of TR NOX 
Ozone Season allowances that owners and operators are required to hold 
in accordance with the calculation formula in Sec. 97.506(c)(2)(i) for 
such control period with regard to the TR NOX Ozone Season 
sources, TR NOX Ozone Season units, and State (and Indian 
country within the borders of such State) involved, provided that such 
litigation was initiated no later than 30 days after promulgation of 
such notice required in paragraph (b)(2)(iii)(B) of this section.
    (iii) If the revised data are used to recalculate, in accordance 
with paragraphs (b)(6)(i) and (ii) of this section, the amount of TR 
NOX Ozone Season allowances that the owners and operators are 
required to hold for such control period with regard to the TR 
NOX Ozone Season sources, TR NOX Ozone Season 
units, and State (and Indian country within the borders of such State) 
involved--
    (A) Where the amount of TR NOX Ozone Season allowances 
that the owners and operators are required to hold increases as a result 
of the use of all such revised data, the Administrator will establish a 
new, reasonable deadline on which the owners and operators shall hold 
the additional amount of TR NOX Ozone Season allowances in 
the assurance account established by the Administrator for the 
appropriate TR NOX Ozone Season sources, TR NOX 
Ozone Season units, and State (and Indian country within the borders of 
such State) under paragraph (b)(3) of this section. The owners' and 
operators' failure to hold such additional amount, as required, before 
the new deadline shall not be a violation of the Clean Air Act. The 
owners' and operators' failure to hold such additional amount, as 
required, as of the new deadline shall be a violation of the Clean Air 
Act. Each TR NOX Ozone Season allowance that the owners and 
operators fail to hold as required as of the new deadline, and each day 
in such control period, shall be a separate violation of the Clean Air 
Act.
    (B) For the owners and operators for which the amount of TR 
NOX Ozone Season allowances required to be held decreases as 
a result of the use of all such revised data, the Administrator will 
record, in all accounts from which TR NOX Ozone Season 
allowances were transferred by such owners and operators for such 
control period to the assurance account established by the Administrator 
for the appropriate at TR NOX Ozone Season sources, TR 
NOX Ozone Season units, and State (and Indian country within 
the borders of such State) under paragraph (b)(3) of this section, a 
total amount of the TR NOX Ozone Season allowances held in 
such assurance account equal to the amount of the decrease. If TR 
NOX Ozone Season allowances were transferred to such 
assurance account from more than one account, the amount of TR 
NOX Ozone Season allowances recorded in each such transferor 
account will be in proportion to the percentage of the total amount of 
TR NOX Ozone Season allowances transferred to such assurance 
account for such control period from such transferor account.
    (C) Each TR NOX Ozone Season allowance held under 
paragraph (b)(6)(iii)(A)

[[Page 432]]

of this section as a result of recalculation of requirements under the 
TR NOX Ozone Season assurance provisions for such control 
period must be a TR NOX Ozone Season allowance allocated for 
a control period in a year before or the year immediately following, or 
in the same year as, the year of such control period.

[76 FR 48406, Aug. 8, 2011, as amended at 77 FR 10338, Feb. 21, 2012; 79 
FR 71672, Dec. 3, 2014]



Sec. 97.526  Banking.

    (a) A TR NOX Ozone Season allowance may be banked for 
future use or transfer in a compliance account or a general account in 
accordance with paragraph (b) of this section.
    (b) Any TR NOX Ozone Season allowance that is held in a 
compliance account or a general account will remain in such account 
unless and until the TR NOX Ozone Season allowance is 
deducted or transferred under Sec. 97.511(c), Sec. 97.523, Sec. 
97.524, Sec. 97.525, Sec. 97.527, or Sec. 97.528.



Sec. 97.527  Account error.

    The Administrator may, at his or her sole discretion and on his or 
her own motion, correct any error in any Allowance Management System 
account. Within 10 business days of making such correction, the 
Administrator will notify the authorized account representative for the 
account.



Sec. 97.528  Administrator's action on submissions.

    (a) The Administrator may review and conduct independent audits 
concerning any submission under the TR NOX Ozone Season 
Trading Program and make appropriate adjustments of the information in 
the submission.
    (b) The Administrator may deduct TR NOX Ozone Season 
allowances from or transfer TR NOX Ozone Season allowances to 
a compliance account or an assurance account, based on the information 
in a submission, as adjusted under paragraph (a)(1) of this section, and 
record such deductions and transfers.



Sec. 97.529  [Reserved]



Sec. 97.530  General monitoring, recordkeeping, and reporting 
requirements.

    The owners and operators, and to the extent applicable, the 
designated representative, of a TR NOX Ozone Season unit, 
shall comply with the monitoring, recordkeeping, and reporting 
requirements as provided in this subpart and subpart H of part 75 of 
this chapter. For purposes of applying such requirements, the 
definitions in Sec. 97.502 and in Sec. 72.2 of this chapter shall 
apply, the terms ``affected unit,'' ``designated representative,'' and 
``continuous emission monitoring system'' (or ``CEMS'') in part 75 of 
this chapter shall be deemed to refer to the terms ``TR NOX 
Ozone Season unit,'' ``designated representative,'' and ``continuous 
emission monitoring system'' (or ``CEMS'') respectively as defined in 
Sec. 97.502, and the term ``newly affected unit'' shall be deemed to 
mean ``newly affected TR NOX Ozone Season unit''. The owner 
or operator of a unit that is not a TR NOX Ozone Season unit 
but that is monitored under Sec. 75.72(b)(2)(ii) of this chapter shall 
comply with the same monitoring, recordkeeping, and reporting 
requirements as a TR NOX Ozone Season unit.
    (a) Requirements for installation, certification, and data 
accounting. The owner or operator of each TR NOX Ozone Season 
unit shall:
    (1) Install all monitoring systems required under this subpart for 
monitoring NOX mass emissions and individual unit heat input 
(including all systems required to monitor NOX emission rate, 
NOX concentration, stack gas moisture content, stack gas flow 
rate, CO2 or O2 concentration, and fuel flow rate, 
as applicable, in accordance with Sec. Sec. 75.71 and 75.72 of this 
chapter);
    (2) Successfully complete all certification tests required under 
Sec. 97.531 and meet all other requirements of this subpart and part 75 
of this chapter applicable to the monitoring systems under paragraph 
(a)(1) of this section; and
    (3) Record, report, and quality-assure the data from the monitoring 
systems under paragraph (a)(1) of this section.

[[Page 433]]

    (b) Compliance deadlines. Except as provided in paragraph (e) of 
this section, the owner or operator shall meet the monitoring system 
certification and other requirements of paragraphs (a)(1) and (2) of 
this section on or before the following dates and shall record, report, 
and quality-assure the data from the monitoring systems under paragraph 
(a)(1) of this section on and after the following dates.
    (1) For the owner or operator of a TR NOX Ozone Season 
unit that commences commercial operation before July 1, 2014, May 1, 
2015.
    (2) For the owner or operator of a TR NOX Ozone Season 
unit that commences commercial operation on or after July 1, 2014 and 
that reports on an annual basis under Sec. 97.534(d), by the later of 
the following:
    (i) 180 calendar days after the date on which the unit commences 
commercial operation; or
    (ii) May 1, 2015.
    (3) For the owner or operator of a TR NOX Ozone Season 
unit that commences commercial operation on or after July 1, 2014 and 
that reports on a control period basis under Sec. 97.534(d)(2)(ii), by 
the following date:
    (i) 180 calendar days after the date on which the unit commences 
commercial operation; or
    (ii) If the compliance date under paragraph (b)(3)(i) of this 
section is not during a control period, May 1 immediately after the 
compliance date under paragraph (b)(3)(i) of this section.
    (4) The owner or operator of a TR NOX Ozone Season unit 
for which construction of a new stack or flue or installation of add-on 
NOX emission controls is completed after the applicable 
deadline under paragraph (b)(1), (2), or (3) of this section shall meet 
the requirements of Sec. Sec. 75.4(e)(1) through (e)(4) of this 
chapter, except that:
    (i) Such requirements shall apply to the monitoring systems required 
under Sec. 97.530 through Sec. 97.535, rather than the monitoring 
systems required under part 75 of this chapter;
    (ii) NOX emission rate, NOX concentration, 
stack gas moisture content, stack gas volumetric flow rate, and 
O2 or CO2 concentration data shall be determined 
and reported, rather than the data listed in Sec. 75.4(e)(2) of this 
chapter; and
    (iii) Any petition for another procedure under Sec. 75.4(e)(2) of 
this chapter shall be submitted under Sec. 97.535, rather than Sec. 
75.66.
    (c) Reporting data. The owner or operator of a TR NOX 
Ozone Season unit that does not meet the applicable compliance date set 
forth in paragraph (b) of this section for any monitoring system under 
paragraph (a)(1) of this section shall, for each such monitoring system, 
determine, record, and report maximum potential (or, as appropriate, 
minimum potential) values for NOX concentration, 
NOX emission rate, stack gas flow rate, stack gas moisture 
content, fuel flow rate, and any other parameters required to determine 
NOX mass emissions and heat input in accordance with Sec. 
75.31(b)(2) or (c)(3) of this chapter, section 2.4 of appendix D to part 
75 of this chapter, or section 2.5 of appendix E to part 75 of this 
chapter, as applicable.
    (d) Prohibitions. (1) No owner or operator of a TR NOX 
Ozone Season unit shall use any alternative monitoring system, 
alternative reference method, or any other alternative to any 
requirement of this subpart without having obtained prior written 
approval in accordance with Sec. 97.535.
    (2) No owner or operator of a TR NOX Ozone Season unit 
shall operate the unit so as to discharge, or allow to be discharged, 
NOX to the atmosphere without accounting for all such 
NOX in accordance with the applicable provisions of this 
subpart and part 75 of this chapter.
    (3) No owner or operator of a TR NOX Ozone Season unit 
shall disrupt the continuous emission monitoring system, any portion 
thereof, or any other approved emission monitoring method, and thereby 
avoid monitoring and recording NOX mass discharged into the 
atmosphere or heat input, except for periods of recertification or 
periods when calibration, quality assurance testing, or maintenance is 
performed in accordance with the applicable provisions of this subpart 
and part 75 of this chapter.

[[Page 434]]

    (4) No owner or operator of a TR NOX Ozone Season unit 
shall retire or permanently discontinue use of the continuous emission 
monitoring system, any component thereof, or any other approved 
monitoring system under this subpart, except under any one of the 
following circumstances:
    (i) During the period that the unit is covered by an exemption under 
Sec. 97.505 that is in effect;
    (ii) The owner or operator is monitoring emissions from the unit 
with another certified monitoring system approved, in accordance with 
the applicable provisions of this subpart and part 75 of this chapter, 
by the Administrator for use at that unit that provides emission data 
for the same pollutant or parameter as the retired or discontinued 
monitoring system; or
    (iii) The designated representative submits notification of the date 
of certification testing of a replacement monitoring system for the 
retired or discontinued monitoring system in accordance with Sec. 
97.531(d)(3)(i).
    (e) Long-term cold storage. The owner or operator of a TR 
NOX Ozone Season unit is subject to the applicable provisions 
of Sec. 75.4(d) of this chapter concerning units in long-term cold 
storage.

[76 FR 48379, Aug. 8, 2011, as amended at 79 FR 71672, Dec. 3, 2014]



Sec. 97.531  Initial monitoring system certification and 
recertification procedures.

    (a) The owner or operator of a TR NOX Ozone Season unit 
shall be exempt from the initial certification requirements of this 
section for a monitoring system under Sec. 97.530(a)(1) if the 
following conditions are met:
    (1) The monitoring system has been previously certified in 
accordance with part 75 of this chapter; and
    (2) The applicable quality-assurance and quality-control 
requirements of Sec. 75.21 of this chapter and appendices B, D, and E 
to part 75 of this chapter are fully met for the certified monitoring 
system described in paragraph (a)(1) of this section.
    (b) The recertification provisions of this section shall apply to a 
monitoring system under Sec. 97.530(a)(1) that is exempt from initial 
certification requirements under paragraph (a) of this section.
    (c) If the Administrator has previously approved a petition under 
Sec. 75.17(a) or (b) of this chapter for apportioning the 
NOX emission rate measured in a common stack or a petition 
under Sec. 75.66 of this chapter for an alternative to a requirement in 
Sec. 75.12 or Sec. 75.17 of this chapter, the designated 
representative shall resubmit the petition to the Administrator under 
Sec. 97.535 to determine whether the approval applies under the TR 
NOX Ozone Season Trading Program.
    (d) Except as provided in paragraph (a) of this section, the owner 
or operator of a TR NOX Ozone Season unit shall comply with 
the following initial certification and recertification procedures for a 
continuous monitoring system (i.e., a continuous emission monitoring 
system and an excepted monitoring system under appendices D and E to 
part 75 of this chapter) under Sec. 97.530(a)(1). The owner or operator 
of a unit that qualifies to use the low mass emissions excepted 
monitoring methodology under Sec. 75.19 of this chapter or that 
qualifies to use an alternative monitoring system under subpart E of 
part 75 of this chapter shall comply with the procedures in paragraph 
(e) or (f) of this section respectively.
    (1) Requirements for initial certification. The owner or operator 
shall ensure that each continuous monitoring system under Sec. 
97.530(a)(1) (including the automated data acquisition and handling 
system) successfully completes all of the initial certification testing 
required under Sec. 75.20 of this chapter by the applicable deadline in 
Sec. 97.530(b). In addition, whenever the owner or operator installs a 
monitoring system to meet the requirements of this subpart in a location 
where no such monitoring system was previously installed, initial 
certification in accordance with Sec. 75.20 of this chapter is 
required.
    (2) Requirements for recertification. Whenever the owner or operator 
makes a replacement, modification, or change in any certified continuous 
emission monitoring system under Sec. 97.530(a)(1) that may 
significantly affect the ability of the system to accurately measure or 
record NOX mass emissions or

[[Page 435]]

heat input rate or to meet the quality-assurance and quality-control 
requirements of Sec. 75.21 of this chapter or appendix B to part 75 of 
this chapter, the owner or operator shall recertify the monitoring 
system in accordance with Sec. 75.20(b) of this chapter. Furthermore, 
whenever the owner or operator makes a replacement, modification, or 
change to the flue gas handling system or the unit's operation that may 
significantly change the stack flow or concentration profile, the owner 
or operator shall recertify each continuous emission monitoring system 
whose accuracy is potentially affected by the change, in accordance with 
Sec. 75.20(b) of this chapter. Examples of changes to a continuous 
emission monitoring system that require recertification include: 
replacement of the analyzer, complete replacement of an existing 
continuous emission monitoring system, or change in location or 
orientation of the sampling probe or site. Any fuel flowmeter system, 
and any excepted NOX monitoring system under appendix E to 
part 75 of this chapter, under Sec. 97.530(a)(1) are subject to the 
recertification requirements in Sec. 75.20(g)(6) of this chapter.
    (3) Approval process for initial certification and recertification. 
For initial certification of a continuous monitoring system under Sec. 
97.530(a)(1), paragraphs (d)(3)(i) through (v) of this section apply. 
For recertifications of such monitoring systems, paragraphs (d)(3)(i) 
through (iv) of this section and the procedures in Sec. Sec. 
75.20(b)(5) and (g)(7) of this chapter (in lieu of the procedures in 
paragraph (d)(3)(v) of this section) apply, provided that in applying 
paragraphs (d)(3)(i) through (iv) of this section, the words 
``certification'' and ``initial certification'' are replaced by the word 
``recertification'' and the word ``certified'' is replaced by with the 
word ``recertified''.
    (i) Notification of certification. The designated representative 
shall submit to the appropriate EPA Regional Office and the 
Administrator written notice of the dates of certification testing, in 
accordance with Sec. 97.533.
    (ii) Certification application. The designated representative shall 
submit to the Administrator a certification application for each 
monitoring system. A complete certification application shall include 
the information specified in Sec. 75.63 of this chapter.
    (iii) Provisional certification date. The provisional certification 
date for a monitoring system shall be determined in accordance with 
Sec. 75.20(a)(3) of this chapter. A provisionally certified monitoring 
system may be used under the TR NOX Ozone Season Trading 
Program for a period not to exceed 120 days after receipt by the 
Administrator of the complete certification application for the 
monitoring system under paragraph (d)(3)(ii) of this section. Data 
measured and recorded by the provisionally certified monitoring system, 
in accordance with the requirements of part 75 of this chapter, will be 
considered valid quality-assured data (retroactive to the date and time 
of provisional certification), provided that the Administrator does not 
invalidate the provisional certification by issuing a notice of 
disapproval within 120 days of the date of receipt of the complete 
certification application by the Administrator.
    (iv) Certification application approval process. The Administrator 
will issue a written notice of approval or disapproval of the 
certification application to the owner or operator within 120 days of 
receipt of the complete certification application under paragraph 
(d)(3)(ii) of this section. In the event the Administrator does not 
issue such a notice within such 120-day period, each monitoring system 
that meets the applicable performance requirements of part 75 of this 
chapter and is included in the certification application will be deemed 
certified for use under the TR NOX Ozone Season Trading 
Program.
    (A) Approval notice. If the certification application is complete 
and shows that each monitoring system meets the applicable performance 
requirements of part 75 of this chapter, then the Administrator will 
issue a written notice of approval of the certification application 
within 120 days of receipt.
    (B) Incomplete application notice. If the certification application 
is not complete, then the Administrator will issue a written notice of 
incompleteness that sets a reasonable date by

[[Page 436]]

which the designated representative must submit the additional 
information required to complete the certification application. If the 
designated representative does not comply with the notice of 
incompleteness by the specified date, then the Administrator may issue a 
notice of disapproval under paragraph (d)(3)(iv)(C) of this section.
    (C) Disapproval notice. If the certification application shows that 
any monitoring system does not meet the performance requirements of part 
75 of this chapter or if the certification application is incomplete and 
the requirement for disapproval under paragraph (d)(3)(iv)(B) of this 
section is met, then the Administrator will issue a written notice of 
disapproval of the certification application. Upon issuance of such 
notice of disapproval, the provisional certification is invalidated by 
the Administrator and the data measured and recorded by each uncertified 
monitoring system shall not be considered valid quality-assured data 
beginning with the date and hour of provisional certification (as 
defined under Sec. 75.20(a)(3) of this chapter).
    (D) Audit decertification. The Administrator may issue a notice of 
disapproval of the certification status of a monitor in accordance with 
Sec. 97.532(b).
    (v) Procedures for loss of certification. If the Administrator 
issues a notice of disapproval of a certification application under 
paragraph (d)(3)(iv)(C) of this section or a notice of disapproval of 
certification status under paragraph (d)(3)(iv)(D) of this section, 
then:
    (A) The owner or operator shall substitute the following values, for 
each disapproved monitoring system, for each hour of unit operation 
during the period of invalid data specified under Sec. 
75.20(a)(4)(iii), Sec. 75.20(g)(7), or Sec. 75.21(e) of this chapter 
and continuing until the applicable date and hour specified under Sec. 
75.20(a)(5)(i) or (g)(7) of this chapter:
    (1) For a disapproved NOX emission rate (i.e., 
NOX-diluent) system, the maximum potential NOX 
emission rate, as defined in Sec. 72.2 of this chapter.
    (2) For a disapproved NOX pollutant concentration monitor 
and disapproved flow monitor, respectively, the maximum potential 
concentration of NOX and the maximum potential flow rate, as 
defined in sections 2.1.2.1 and 2.1.4.1 of appendix A to part 75 of this 
chapter.
    (3) For a disapproved moisture monitoring system and disapproved 
diluent gas monitoring system, respectively, the minimum potential 
moisture percentage and either the maximum potential CO2 
concentration or the minimum potential O2 concentration (as 
applicable), as defined in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of 
appendix A to part 75 of this chapter.
    (4) For a disapproved fuel flowmeter system, the maximum potential 
fuel flow rate, as defined in section 2.4.2.1 of appendix D to part 75 
of this chapter.
    (5) For a disapproved excepted NOX monitoring system 
under appendix E to part 75 of this chapter, the fuel-specific maximum 
potential NOX emission rate, as defined in Sec. 72.2 of this 
chapter.
    (B) The designated representative shall submit a notification of 
certification retest dates and a new certification application in 
accordance with paragraphs (d)(3)(i) and (ii) of this section.
    (C) The owner or operator shall repeat all certification tests or 
other requirements that were failed by the monitoring system, as 
indicated in the Administrator's notice of disapproval, no later than 30 
unit operating days after the date of issuance of the notice of 
disapproval.
    (e) The owner or operator of a unit qualified to use the low mass 
emissions (LME) excepted methodology under Sec. 75.19 of this chapter 
shall meet the applicable certification and recertification requirements 
in Sec. Sec. 75.19(a)(2) and 75.20(h) of this chapter. If the owner or 
operator of such a unit elects to certify a fuel flowmeter system for 
heat input determination, the owner or operator shall also meet the 
certification and recertification requirements in Sec. 75.20(g) of this 
chapter.
    (f) The designated representative of each unit for which the owner 
or operator intends to use an alternative monitoring system approved by 
the Administrator under subpart E of part 75 of this chapter shall 
comply with the applicable notification and application procedures of 
Sec. 75.20(f) of this chapter.

[[Page 437]]



Sec. 97.532  Monitoring system out-of-control periods.

    (a) General provisions. Whenever any monitoring system fails to meet 
the quality-assurance and quality-control requirements or data 
validation requirements of part 75 of this chapter, data shall be 
substituted using the applicable missing data procedures in subpart D or 
subpart H of, or appendix D or appendix E to, part 75 of this chapter.
    (b) Audit decertification. Whenever both an audit of a monitoring 
system and a review of the initial certification or recertification 
application reveal that any monitoring system should not have been 
certified or recertified because it did not meet a particular 
performance specification or other requirement under Sec. 97.531 or the 
applicable provisions of part 75 of this chapter, both at the time of 
the initial certification or recertification application submission and 
at the time of the audit, the Administrator will issue a notice of 
disapproval of the certification status of such monitoring system. For 
the purposes of this paragraph, an audit shall be either a field audit 
or an audit of any information submitted to the Administrator or any 
State or permitting authority. By issuing the notice of disapproval, the 
Administrator revokes prospectively the certification status of the 
monitoring system. The data measured and recorded by the monitoring 
system shall not be considered valid quality-assured data from the date 
of issuance of the notification of the revoked certification status 
until the date and time that the owner or operator completes 
subsequently approved initial certification or recertification tests for 
the monitoring system. The owner or operator shall follow the applicable 
initial certification or recertification procedures in Sec. 97.531 for 
each disapproved monitoring system.



Sec. 97.533  Notifications concerning monitoring.

    The designated representative of a TR NOX Ozone Season 
unit shall submit written notice to the Administrator in accordance with 
Sec. 75.61 of this chapter.



Sec. 97.534  Recordkeeping and reporting.

    (a) General provisions. The designated representative shall comply 
with all recordkeeping and reporting requirements in paragraphs (b) 
through (e) of this section, the applicable recordkeeping and reporting 
requirements under Sec. 75.73 of this chapter, and the requirements of 
Sec. 97.514(a).
    (b) Monitoring plans. The owner or operator of a TR NOX 
Ozone Season unit shall comply with requirements of Sec. 75.73(c) and 
(e) of this chapter.
    (c) Certification applications. The designated representative shall 
submit an application to the Administrator within 45 days after 
completing all initial certification or recertification tests required 
under Sec. 97.531, including the information required under Sec. 75.63 
of this chapter.
    (d) Quarterly reports. The designated representative shall submit 
quarterly reports, as follows:
    (1) If the TR NOX Ozone Season unit is subject to the 
Acid Rain Program or a TR NOX Annual emissions limitation or 
if the owner or operator of such unit chooses to report on an annual 
basis under this subpart, the designated representative shall meet the 
requirements of subpart H of part 75 of this chapter (concerning 
monitoring of NOX mass emissions) for such unit for the 
entire year and shall report the NOX mass emissions data and 
heat input data for such unit, in an electronic quarterly report in a 
format prescribed by the Administrator, for each calendar quarter 
beginning with:
    (i) For a unit that commences commercial operation before July 1, 
2014, the calendar quarter covering May 1, 2015 through June 30, 2015; 
or
    (ii) For a unit that commences commercial operation on or after July 
1, 2014, the calendar quarter corresponding to the earlier of the date 
of provisional certification or the applicable deadline for initial 
certification under Sec. 97.530(b), unless that quarter is the third or 
fourth quarter of 2014 or the first quarter of 2015, in which case 
reporting shall commence in the quarter covering May 1, 2015 through 
June 30, 2015.
    (2) If the TR NOX Ozone Season unit is not subject to the 
Acid Rain Program or a TR NOX Annual emissions

[[Page 438]]

limitation, then the designated representative shall either:
    (i) Meet the requirements of subpart H of part 75 (concerning 
monitoring of NOX mass emissions) for such unit for the 
entire year and report the NOX mass emissions data and heat 
input data for such unit in accordance with paragraph (d)(1) of this 
section; or
    (ii) Meet the requirements of subpart H of part 75 for the control 
period (including the requirements in Sec. 75.74(c) of this chapter) 
and report NOX mass emissions data and heat input data 
(including the data described in Sec. 75.74(c)(6) of this chapter) for 
such unit only for the control period of each year and report, in an 
electronic quarterly report in a format prescribed by the Administrator, 
for each calendar quarter beginning with:
    (A) For a unit that commences commercial operation before July 1, 
2014, the calendar quarter covering May 1, 2015 through June 30, 2015; 
or
    (B) For a unit that commences commercial operation on or after July 
1, 2014, the calendar quarter corresponding to the earlier of the date 
of provisional certification or the applicable deadline for initial 
certification under Sec. 97.530(b), unless that date is not during a 
control period, in which case reporting shall commence in the quarter 
that includes May 1 through June 30 of the first control period after 
such date.
    (3) The designated representative shall submit each quarterly report 
to the Administrator within 30 days after the end of the calendar 
quarter covered by the report. Quarterly reports shall be submitted in 
the manner specified in Sec. 75.73(f) of this chapter.
    (4) For TR NOX Ozone Season units that are also subject 
to the Acid Rain Program, TR NOX Annual Trading Program, TR 
SO2 Group 1 Trading Program, or TR SO2 Group 2 
Trading Program, quarterly reports shall include the applicable data and 
information required by subparts F through H of part 75 of this chapter 
as applicable, in addition to the NOX mass emission data, 
heat input data, and other information required by this subpart.
    (5) The Administrator may review and conduct independent audits of 
any quarterly report in order to determine whether the quarterly report 
meets the requirements of this subpart and part 75 of this chapter, 
including the requirement to use substitute data.
    (i) The Administrator will notify the designated representative of 
any determination that the quarterly report fails to meet any such 
requirements and specify in such notification any corrections that the 
Administrator believes are necessary to make through resubmission of the 
quarterly report and a reasonable time period within which the 
designated representative must respond. Upon request by the designated 
representative, the Administrator may specify reasonable extensions of 
such time period. Within the time period (including any such extensions) 
specified by the Administrator, the designated representative shall 
resubmit the quarterly report with the corrections specified by the 
Administrator, except to the extent the designated representative 
provides information demonstrating that a specified correction is not 
necessary because the quarterly report already meets the requirements of 
this subpart and part 75 of this chapter that are relevant to the 
specified correction.
    (6) Any resubmission of a quarterly report shall meet the 
requirements applicable to the submission of a quarterly report under 
this subpart and part 75 of this chapter, except for the deadline set 
forth in paragraph (d)(3) of this section.
    (e) Compliance certification. The designated representative shall 
submit to the Administrator a compliance certification (in a format 
prescribed by the Administrator) in support of each quarterly report 
based on reasonable inquiry of those persons with primary responsibility 
for ensuring that all of the unit's emissions are correctly and fully 
monitored. The certification shall state that:
    (1) The monitoring data submitted were recorded in accordance with 
the applicable requirements of this subpart and part 75 of this chapter, 
including the quality assurance procedures and specifications;
    (2) For a unit with add-on NOX emission controls and for 
all hours where NOX data are substituted in accordance with 
Sec. 75.34(a)(1) of this chapter, the

[[Page 439]]

add-on emission controls were operating within the range of parameters 
listed in the quality assurance/quality control program under appendix B 
to part 75 of this chapter and the substitute data values do not 
systematically underestimate NOX emissions; and
    (3) For a unit that is reporting on a control period basis under 
paragraph (d)(2)(ii) of this section, the NOX emission rate 
and NOX concentration values substituted for missing data 
under subpart D of part 75 of this chapter are calculated using only 
values from a control period and do not systematically underestimate 
NOX emissions.

[76 FR 48379, Aug. 8, 2011, as amended at 79 FR 71672, Dec. 3, 2014]



Sec. 97.535  Petitions for alternatives to monitoring, recordkeeping,
or reporting requirements.

    (a) The designated representative of a TR NOX Ozone 
Season unit may submit a petition under Sec. 75.66 of this chapter to 
the Administrator, requesting approval to apply an alternative to any 
requirement of Sec. Sec. 97.530 through 97.534.
    (b) A petition submitted under paragraph (a) of this section shall 
include sufficient information for the evaluation of the petition, 
including, at a minimum, the following information:
    (i) Identification of each unit and source covered by the petition;
    (ii) A detailed explanation of why the proposed alternative is being 
suggested in lieu of the requirement;
    (iii) A description and diagram of any equipment and procedures used 
in the proposed alternative;
    (iv) A demonstration that the proposed alternative is consistent 
with the purposes of the requirement for which the alternative is 
proposed and with the purposes of this subpart and part 75 of this 
chapter and that any adverse effect of approving the alternative will be 
de minimis: and
    (v) Any other relevant information that the Administrator may 
require.
    (c) Use of an alternative to any requirement referenced in paragraph 
(a) of this section is in accordance with this subpart only to the 
extent that the petition is approved in writing by the Administrator and 
that such use is in accordance with such approval.



              Subpart CCCCC_TR SO2 Group 1 Trading Program

    Source: 76 FR 48432, Aug. 8, 2011, unless otherwise noted.



Sec. 97.601  Purpose.

    This subpart sets forth the general, designated representative, 
allowance, and monitoring provisions for the Transport Rule (TR) 
SO2 Group 1 Trading Program, under section 110 of the Clean 
Air Act and Sec. 52.39 of this chapter, as a means of mitigating 
interstate transport of fine particulates and sulfur dioxide.



Sec. 97.602  Definitions.

    The terms used in this subpart shall have the meanings set forth in 
this section as follows:
    Acid Rain Program means a multi-state SO2 and 
NOX air pollution control and emission reduction program 
established by the Administrator under title IV of the Clean Air Act and 
parts 72 through 78 of this chapter.
    Administrator means the Administrator of the United States 
Environmental Protection Agency or the Director of the Clean Air Markets 
Division (or its successor determined by the Administrator) of the 
United States Environmental Protection Agency, the Administrator's duly 
authorized representative under this subpart.
    Allocate or allocation means, with regard to TR SO2 Group 
1 allowances, the determination by the Administrator, State, or 
permitting authority, in accordance with this subpart and any SIP 
revision submitted by the State and approved by the Administrator under 
Sec. 52.39(d), (e), or (f) of this chapter, of the amount of such TR 
SO2 Group 1 allowances to be initially credited, at no cost 
to the recipient, to:
    (1) A TR SO2 Group 1 unit;
    (2) A new unit set-aside;
    (3) An Indian country new unit set-aside; or
    (4) An entity not listed in paragraphs (1) through (3) of this 
definition;
    (5) Provided that, if the Administrator, State, or permitting 
authority initially credits, to a TR SO2 Group 1 unit 
qualifying for an initial credit, a credit in the amount of zero TR 
SO2

[[Page 440]]

Group 1 allowances, the TR SO2 Group 1 unit will be treated 
as being allocated an amount (i.e., zero) of TR SO2 Group 1 
allowances.
    Allowable SO2 emission rate means, for a unit, the most stringent 
State or federal SO2 emission rate limit (in lb/MWhr or, if 
in lb/mmBtu, converted to lb/MWhr by multiplying it by the unit's heat 
rate in mmBtu/MWhr) that is applicable to the unit and covers the 
longest averaging period not exceeding one year.
    Allowance Management System means the system by which the 
Administrator records allocations, deductions, and transfers of TR 
SO2 Group 1 allowances under the TR SO2 Group 1 
Trading Program. Such allowances are allocated, recorded, held, 
deducted, or transferred only as whole allowances.
    Allowance Management System account means an account in the 
Allowance Management System established by the Administrator for 
purposes of recording the allocation, holding, transfer, or deduction of 
TR SO2 Group 1 allowances.
    Allowance transfer deadline means, for a control period in a given 
year, midnight of March 1 (if it is a business day), or midnight of the 
first business day thereafter (if March 1 is not a business day), 
immediately after such control period and is the deadline by which a TR 
SO2 Group 1 allowance transfer must be submitted for 
recordation in a TR SO2 Group 1 source's compliance account 
in order to be available for use in complying with the source's TR 
SO2 Group 1 emissions limitation for such control period in 
accordance with Sec. Sec. 97.606 and 97.624.
    Alternate designated representative means, for a TR SO2 
Group 1 source and each TR SO2 Group 1 unit at the source, 
the natural person who is authorized by the owners and operators of the 
source and all such units at the source, in accordance with this 
subpart, to act on behalf of the designated representative in matters 
pertaining to the TR SO2 Group 1 Trading Program. If the TR 
SO2 Group 1 source is also subject to the Acid Rain Program, 
TR NOX Annual Trading Program, or TR NOX Ozone 
Season Trading Program, then this natural person shall be the same 
natural person as the alternate designated representative, as defined in 
the respective program.
    Assurance account means an Allowance Management System account, 
established by the Administrator under Sec. 97.625(b)(3) for certain 
owners and operators of a group of one or more TR SO2 Group 1 
sources and units in a given State (and Indian country within the 
borders of such State), in which are held TR SO2 Group 1 
allowances available for use for a control period in a given year in 
complying with the TR SO2 Group 1 assurance provisions in 
accordance with Sec. Sec. 97.606 and 97.625.
    Authorized account representative means, for a general account, the 
natural person who is authorized, in accordance with this subpart, to 
transfer and otherwise dispose of TR SO2 Group 1 allowances 
held in the general account and, for a TR SO2 Group 1 
source's compliance account, the designated representative of the 
source.
    Automated data acquisition and handling system or DAHS means the 
component of the continuous emission monitoring system, or other 
emissions monitoring system approved for use under this subpart, 
designed to interpret and convert individual output signals from 
pollutant concentration monitors, flow monitors, diluent gas monitors, 
and other component parts of the monitoring system to produce a 
continuous record of the measured parameters in the measurement units 
required by this subpart.
    Biomass means--
    (1) Any organic material grown for the purpose of being converted to 
energy;
    (2) Any organic byproduct of agriculture that can be converted into 
energy; or
    (3) Any material that can be converted into energy and is 
nonmerchantable for other purposes, that is segregated from other 
material that is nonmerchantable for other purposes, and that is;
    (i) A forest-related organic resource, including mill residues, 
precommercial thinnings, slash, brush, or byproduct from conversion of 
trees to merchantable material; or
    (ii) A wood material, including pallets, crates, dunnage, 
manufacturing and construction materials (other than

[[Page 441]]

pressure-treated, chemically-treated, or painted wood products), and 
landscape or right-of-way tree trimmings.
    Boiler means an enclosed fossil- or other-fuel-fired combustion 
device used to produce heat and to transfer heat to recirculating water, 
steam, or other medium.
    Bottoming-cycle unit means a unit in which the energy input to the 
unit is first used to produce useful thermal energy, where at least some 
of the reject heat from the useful thermal energy application or process 
is then used for electricity production.
    Business day means a day that does not fall on a weekend or a 
federal holiday.
    Certifying official means a natural person who is:
    (1) For a corporation, a president, secretary, treasurer, or vice-
president of the corporation in charge of a principal business function 
or any other person who performs similar policy- or decision-making 
functions for the corporation;
    (2) For a partnership or sole proprietorship, a general partner or 
the proprietor respectively; or
    (3) For a local government entity or State, federal, or other public 
agency, a principal executive officer or ranking elected official.
    Clean Air Act means the Clean Air Act, 42 U.S.C. 7401, et seq.
    Coal means ``coal'' as defined in Sec. 72.2 of this chapter.
    Coal-derived fuel means any fuel (whether in a solid, liquid, or 
gaseous state) produced by the mechanical, thermal, or chemical 
processing of coal.
    Cogeneration system means an integrated group, at a source, of 
equipment (including a boiler, or combustion turbine, and a steam 
turbine generator) designed to produce useful thermal energy for 
industrial, commercial, heating, or cooling purposes and electricity 
through the sequential use of energy.
    Cogeneration unit means a stationary, fossil-fuel-fired boiler or 
stationary, fossil-fuel-fired combustion turbine that is a topping-cycle 
unit or a bottoming-cycle unit:
    (1) Operating as part of a cogeneration system; and
    (2) Producing on an annual average basis--
    (i) For a topping-cycle unit,
    (A) Useful thermal energy not less than 5 percent of total energy 
output; and
    (B) Useful power that, when added to one-half of useful thermal 
energy produced, is not less than 42.5 percent of total energy input, if 
useful thermal energy produced is 15 percent or more of total energy 
output, or not less than 45 percent of total energy input, if useful 
thermal energy produced is less than 15 percent of total energy output.
    (ii) For a bottoming-cycle unit, useful power not less than 45 
percent of total energy input;
    (3) Provided that the requirements in paragraph (2) of this 
definition shall not apply to a calendar year referenced in paragraph 
(2) of this definition during which the unit did not operate at all;
    (4) Provided that the total energy input under paragraphs (2)(i)(B) 
and (2)(ii) of this definition shall equal the unit's total energy input 
from all fuel, except biomass if the unit is a boiler; and
    (5) Provided that, if, throughout its operation during the 12-month 
period or a calendar year referenced in paragraph (2) of this 
definition, a unit is operated as part of a cogeneration system and the 
cogeneration system meets on a system-wide basis the requirement in 
paragraph (2)(i)(B) or (2)(ii) of this definition, the unit shall be 
deemed to meet such requirement during that 12-month period or calendar 
year.
    Combustion turbine means an enclosed device comprising:
    (1) If the device is simple cycle, a compressor, a combustor, and a 
turbine and in which the flue gas resulting from the combustion of fuel 
in the combustor passes through the turbine, rotating the turbine; and
    (2) If the device is combined cycle, the equipment described in 
paragraph (1) of this definition and any associated duct burner, heat 
recovery steam generator, and steam turbine.
    Commence commercial operation means, with regard to a unit:
    (1) To have begun to produce steam, gas, or other heated medium used 
to

[[Page 442]]

generate electricity for sale or use, including test generation, except 
as provided in Sec. 97.605.
    (i) For a unit that is a TR SO2 Group 1 unit under Sec. 
97.604 on the later of January 1, 2005 or the date the unit commences 
commercial operation as defined in the introductory text of paragraph 
(1) of this definition and that subsequently undergoes a physical change 
or is moved to a new location or source, such date shall remain the date 
of commencement of commercial operation of the unit, which shall 
continue to be treated as the same unit.
    (ii) For a unit that is a TR SO2 Group 1 unit under Sec. 
97.604 on the later of January 1, 2005 or the date the unit commences 
commercial operation as defined in the introductory text of paragraph 
(1) of this definition and that is subsequently replaced by a unit at 
the same or a different source, such date shall remain the replaced 
unit's date of commencement of commercial operation, and the replacement 
unit shall be treated as a separate unit with a separate date for 
commencement of commercial operation as defined in paragraph (1) or (2) 
of this definition as appropriate.
    (2) Notwithstanding paragraph (1) of this definition and except as 
provided in Sec. 97.605, for a unit that is not a TR SO2 
Group 1 unit under Sec. 97.604 on the later of January 1, 2005 or the 
date the unit commences commercial operation as defined in introductory 
text of paragraph (1) of this definition, the unit's date for 
commencement of commercial operation shall be the date on which the unit 
becomes a TR SO2 Group 1 unit under Sec. 97.604.
    (i) For a unit with a date for commencement of commercial operation 
as defined in the introductory text of paragraph (2) of this definition 
and that subsequently undergoes a physical change or is moved to a 
different location or source, such date shall remain the date of 
commencement of commercial operation of the unit, which shall continue 
to be treated as the same unit.
    (ii) For a unit with a date for commencement of commercial operation 
as defined in the introductory text of paragraph (2) of this definition 
and that is subsequently replaced by a unit at the same or a different 
source, such date shall remain the replaced unit's date of commencement 
of commercial operation, and the replacement unit shall be treated as a 
separate unit with a separate date for commencement of commercial 
operation as defined in paragraph (1) or (2) of this definition as 
appropriate.
    Common designated representative means, with regard to a control 
period in a given year, a designated representative where, as of April 1 
immediately after the allowance transfer deadline for such control 
period, the same natural person is authorized under Sec. Sec. 97.613(a) 
and 97.615(a) as the designated representative for a group of one or 
more TR SO2 Group 1 sources and units located in a State (and 
Indian country within the borders of such State).
    Common designated representative's assurance level means, with 
regard to a specific common designated representative and a State (and 
Indian country within the borders of such State) and control period in a 
given year for which the State assurance level is exceeded as described 
in Sec. 97.606(c)(2)(iii), the common designated representative's share 
of the State SO2 Group 1 trading budget with the variability 
limit for the State for such control period.
    Common designated representative's share means, with regard to a 
specific common designated representative for a control period in a 
given year:
    (1) With regard to a total amount of SO2 emissions from 
all TR SO2 Group 1 units in a State (and Indian country 
within the borders of such State) during such control period, the total 
tonnage of SO2 emissions during such control period from a 
group of one or more TR SO2 Group 1 units located in such 
State (and such Indian country) and having the common designated 
representative for such control period;
    (2) With regard to a State SO2 Group 1 trading budget 
with the variability limit for such control period, the amount (rounded 
to the nearest allowance) equal to the sum of the total amount of TR 
SO2 Group 1 allowances allocated for such control period to a 
group of one or more TR SO2 Group 1 units located in the 
State (and Indian country within the borders of such

[[Page 443]]

State) and having the common designated representative for such control 
period and of the total amount of TR SO2 Group 1 allowances 
purchased by an owner or operator of such TR SO2 Group 1 
units in an auction for such control period and submitted by the State 
or the permitting authority to the Administrator for recordation in the 
compliance accounts for such TR SO2 Group 1 units in 
accordance with the TR SO2 Group 1 allowance auction 
provisions in a SIP revision approved by the Administrator under Sec. 
52.39(e) or (f) of this chapter, multiplied by the sum of the State 
SO2 Group 1 trading budget under Sec. 97.610(a) and the 
State's variability limit under Sec. 97.610(b) for such control period 
and divided by such State SO2 Group 1 trading budget;
    (3) Provided that, in the case of a unit that operates during, but 
has no amount of TR SO2 Group 1 allowances allocated under 
Sec. Sec. 97.611 and 97.612 for, such control period, the unit shall be 
treated, solely for purposes of this definition, as being allocated an 
amount (rounded to the nearest allowance) of TR SO2 Group 1 
allowances for such control period equal to the unit's allowable 
SO2 emission rate applicable to such control period, 
multiplied by a capacity factor of 0.85 (if the unit is a boiler 
combusting any amount of coal or coal-derived fuel during such control 
period), 0.24 (if the unit is a simple combustion turbine during such 
control period), 0.67 (if the unit is a combined cycle turbine during 
such control period), 0.74 (if the unit is an integrated coal 
gasification combined cycle unit during such control period), or 0.36 
(for any other unit), multiplied by the unit's maximum hourly load as 
reported in accordance with this subpart and by 8,760 hours/control 
period, and divided by 2,000 lb/ton.
    Common stack means a single flue through which emissions from 2 or 
more units are exhausted.
    Compliance account means an Allowance Management System account, 
established by the Administrator for a TR SO2 Group 1 source 
under this subpart, in which any TR SO2 Group 1 allowance 
allocations to the TR SO2 Group 1 units at the source are 
recorded and in which are held any TR SO2 Group 1 allowances 
available for use for a control period in a given year in complying with 
the source's TR SO2 Group 1 emissions limitation in 
accordance with Sec. Sec. 97.606 and 97.624.
    Continuous emission monitoring system or CEMS means the equipment 
required under this subpart to sample, analyze, measure, and provide, by 
means of readings recorded at least once every 15 minutes and using an 
automated data acquisition and handling system (DAHS), a permanent 
record of SO2 emissions, stack gas volumetric flow rate, 
stack gas moisture content, and O2 or CO2 
concentration (as applicable), in a manner consistent with part 75 of 
this chapter and Sec. Sec. 97.630 through 97.635. The following systems 
are the principal types of continuous emission monitoring systems:
    (1) A flow monitoring system, consisting of a stack flow rate 
monitor and an automated data acquisition and handling system and 
providing a permanent, continuous record of stack gas volumetric flow 
rate, in standard cubic feet per hour (scfh);
    (2) A SO2 monitoring system, consisting of a 
SO2 pollutant concentration monitor and an automated data 
acquisition and handling system and providing a permanent, continuous 
record of SO2 emissions, in parts per million (ppm);
    (3) A moisture monitoring system, as defined in Sec. 75.11(b)(2) of 
this chapter and providing a permanent, continuous record of the stack 
gas moisture content, in percent H2O;
    (4) A CO2 monitoring system, consisting of a 
CO2 pollutant concentration monitor (or an O2 
monitor plus suitable mathematical equations from which the 
CO2 concentration is derived) and an automated data 
acquisition and handling system and providing a permanent, continuous 
record of CO2 emissions, in percent CO2; and
    (5) An O2 monitoring system, consisting of an 
O2 concentration monitor and an automated data acquisition 
and handling system and providing a permanent, continuous record of 
O2, in percent O2.
    Control period means the period starting January 1 of a calendar 
year, except as provided in Sec. 97.606(c)(3), and ending on December 
31 of the same year, inclusive.

[[Page 444]]

    Designated representative means, for a TR SO2 Group 1 
source and each TR SO2 Group 1 unit at the source, the 
natural person who is authorized by the owners and operators of the 
source and all such units at the source, in accordance with this 
subpart, to represent and legally bind each owner and operator in 
matters pertaining to the TR SO2 Group 1 Trading Program. If 
the TR SO2 Group 1 source is also subject to the Acid Rain 
Program, TR NOX Annual Trading Program, or TR NOX 
Ozone Season Trading Program, then this natural person shall be the same 
natural person as the designated representative, as defined in the 
respective program.
    Emissions means air pollutants exhausted from a unit or source into 
the atmosphere, as measured, recorded, and reported to the Administrator 
by the designated representative, and as modified by the Administrator:
    (1) In accordance with this subpart; and
    (2) With regard to a period before the unit or source is required to 
measure, record, and report such air pollutants in accordance with this 
subpart, in accordance with part 75 of this chapter.
    Excess emissions means any ton of emissions from the TR 
SO2 Group 1 units at a TR SO2 Group 1 source 
during a control period in a given year that exceeds the TR 
SO2 Group 1 emissions limitation for the source for such 
control period.
    Fossil fuel means--
    (1) Natural gas, petroleum, coal, or any form of solid, liquid, or 
gaseous fuel derived from such material; or
    (2) For purposes of applying the limitation on ``average annual fuel 
consumption of fossil fuel'' in Sec. Sec. 97.604(b)(2)(i)(B) and (ii), 
natural gas, petroleum, coal, or any form of solid, liquid, or gaseous 
fuel derived from such material for the purpose of creating useful heat.
    Fossil-fuel-fired means, with regard to a unit, combusting any 
amount of fossil fuel in 2005 or any calendar year thereafter.
    General account means an Allowance Management System account, 
established under this subpart, that is not a compliance account or an 
assurance account.
    Generator means a device that produces electricity.
    Gross electrical output means, for a unit, electricity made 
available for use, including any such electricity used in the power 
production process (which process includes, but is not limited to, any 
on-site processing or treatment of fuel combusted at the unit and any 
on-site emission controls).
    Heat input means, for a unit for a specified period of time, the 
product (in mmBtu/time) of the gross calorific value of the fuel (in 
mmBtu/lb) fed into the unit multiplied by the fuel feed rate (in lb of 
fuel/time), as measured, recorded, and reported to the Administrator by 
the designated representative and as modified by the Administrator in 
accordance with this subpart and excluding the heat derived from 
preheated combustion air, recirculated flue gases, or exhaust.
    Heat input rate means, for a unit, the amount of heat input (in 
mmBtu) divided by unit operating time (in hr) or, for a unit and a 
specific fuel, the amount of heat input attributed to the fuel (in 
mmBtu) divided by the unit operating time (in hr) during which the unit 
combusts the fuel.
    Heat rate means, for a unit, the unit's maximum design heat input 
(in Btu/hr), divided by the product of 1,000,000 Btu/mmBtu and the 
unit's maximum hourly load.
    Indian country means ``Indian country'' as defined in 18 U.S.C. 
1151.
    Life-of-the-unit, firm power contractual arrangement means a unit 
participation power sales agreement under which a utility or industrial 
customer reserves, or is entitled to receive, a specified amount or 
percentage of nameplate capacity and associated energy generated by any 
specified unit and pays its proportional amount of such unit's total 
costs, pursuant to a contract:
    (1) For the life of the unit;
    (2) For a cumulative term of no less than 30 years, including 
contracts that permit an election for early termination; or
    (3) For a period no less than 25 years or 70 percent of the economic 
useful life of the unit determined as of the time the unit is built, 
with option

[[Page 445]]

rights to purchase or release some portion of the nameplate capacity and 
associated energy generated by the unit at the end of the period.
    Maximum design heat input means, for a unit, the maximum amount of 
fuel per hour (in Btu/hr) that the unit is capable of combusting on a 
steady state basis as of the initial installation of the unit as 
specified by the manufacturer of the unit.
    Monitoring system means any monitoring system that meets the 
requirements of this subpart, including a continuous emission monitoring 
system, an alternative monitoring system, or an excepted monitoring 
system under part 75 of this chapter.
    Nameplate capacity means, starting from the initial installation of 
a generator, the maximum electrical generating output (in MWe, rounded 
to the nearest tenth) that the generator is capable of producing on a 
steady state basis and during continuous operation (when not restricted 
by seasonal or other deratings) as of such installation as specified by 
the manufacturer of the generator or, starting from the completion of 
any subsequent physical change in the generator resulting in an increase 
in the maximum electrical generating output that the generator is 
capable of producing on a steady state basis and during continuous 
operation (when not restricted by seasonal or other deratings), such 
increased maximum amount (in MWe, rounded to the nearest tenth) as of 
such completion as specified by the person conducting the physical 
change.
    Natural gas means ``natural gas'' as defined in Sec. 72.2 of this 
chapter.
    Newly affected TR SO2 Group 1 unit means a unit that was not a TR 
SO2 Group 1 unit when it began operating but that thereafter 
becomes a TR SO2 Group 1 unit.
    Operate or operation means, with regard to a unit, to combust fuel.
    Operator means, for a TR SO2 Group 1 source or a TR 
SO2 Group 1 unit at a source respectively, any person who 
operates, controls, or supervises a TR SO2 Group 1 unit at 
the source or the TR SO2 Group 1 unit and shall include, but 
not be limited to, any holding company, utility system, or plant manager 
of such source or unit.
    Owner means, for a TR SO2 Group 1 source or a TR 
SO2 Group 1 unit at a source respectively, any of the 
following persons:
    (1) Any holder of any portion of the legal or equitable title in a 
TR SO2 Group 1 unit at the source or the TR SO2 
Group 1 unit;
    (2) Any holder of a leasehold interest in a TR SO2 Group 
1 unit at the source or the TR SO2 Group 1 unit, provided 
that, unless expressly provided for in a leasehold agreement, ``owner'' 
shall not include a passive lessor, or a person who has an equitable 
interest through such lessor, whose rental payments are not based 
(either directly or indirectly) on the revenues or income from such TR 
SO2 Group 1 unit; and
    (3) Any purchaser of power from a TR SO2 Group 1 unit at 
the source or the TR SO2 Group 1 unit under a life-of-the-
unit, firm power contractual arrangement.
    Permanently retired means, with regard to a unit, a unit that is 
unavailable for service and that the unit's owners and operators do not 
expect to return to service in the future.
    Permitting authority means ``permitting authority'' as defined in 
Sec. Sec. 70.2 and 71.2 of this chapter.
    Potential electrical output capacity means, for a unit, 33 percent 
of the unit's maximum design heat input, divided by 3,413 Btu/kWh, 
divided by 1,000 kWh/MWh, and multiplied by 8,760 hr/yr.
    Receive or receipt of means, when referring to the Administrator, to 
come into possession of a document, information, or correspondence 
(whether sent in hard copy or by authorized electronic transmission), as 
indicated in an official log, or by a notation made on the document, 
information, or correspondence, by the Administrator in the regular 
course of business.
    Recordation, record, or recorded means, with regard to TR 
SO2 Group 1 allowances, the moving of TR SO2 Group 
1 allowances by the Administrator into, out of, or between Allowance 
Management System accounts, for purposes of allocation, auction, 
transfer, or deduction.
    Reference method means any direct test method of sampling and 
analyzing

[[Page 446]]

for an air pollutant as specified in Sec. 75.22 of this chapter.
    Replacement, replace, or replaced means, with regard to a unit, the 
demolishing of a unit, or the permanent retirement and permanent 
disabling of a unit, and the construction of another unit (the 
replacement unit) to be used instead of the demolished or retired unit 
(the replaced unit).
    Sequential use of energy means:
    (1) The use of reject heat from electricity production in a useful 
thermal energy application or process; or
    (2) The use of reject heat from useful thermal energy application or 
process in electricity production.
    Serial number means, for a TR SO2 Group 1 allowance, the 
unique identification number assigned to each TR SO2 Group 1 
allowance by the Administrator.
    Solid waste incineration unit means a stationary, fossil-fuel-fired 
boiler or stationary, fossil-fuel-fired combustion turbine that is a 
``solid waste incineration unit'' as defined in section 129(g)(1) of the 
Clean Air Act.
    Source means all buildings, structures, or installations located in 
one or more contiguous or adjacent properties under common control of 
the same person or persons. This definition does not change or otherwise 
affect the definition of ``major source'', ``stationary source'', or 
``source'' as set forth and implemented in a title V operating permit 
program or any other program under the Clean Air Act.
    State means one of the States that is subject to the TR 
SO2 Group 1 Trading Program pursuant to Sec. 52.39(a), (b), 
(d), (e), and (f) of this chapter.
    Submit or serve means to send or transmit a document, information, 
or correspondence to the person specified in accordance with the 
applicable regulation:
    (1) In person;
    (2) By United States Postal Service; or
    (3) By other means of dispatch or transmission and delivery;
    (4) Provided that compliance with any ``submission'' or ``service'' 
deadline shall be determined by the date of dispatch, transmission, or 
mailing and not the date of receipt.
    Topping-cycle unit means a unit in which the energy input to the 
unit is first used to produce useful power, including electricity, where 
at least some of the reject heat from the electricity production is then 
used to provide useful thermal energy.
    Total energy input means, for a unit, total energy of all forms 
supplied to the unit, excluding energy produced by the unit. Each form 
of energy supplied shall be measured by the lower heating value of that 
form of energy calculated as follows:

LHV = HHV - 10.55(W + 9H)

where:

LHV = lower heating value of the form of energy in Btu/lb,
HHV = higher heating value of the form of energy in Btu/lb,
W = weight % of moisture in the form of energy, and
H = weight % of hydrogen in the form of energy.

    Total energy output means, for a unit, the sum of useful power and 
useful thermal energy produced by the unit.
    TR NOX Annual Trading Program means a multi-state NOX air 
pollution control and emission reduction program established in 
accordance with subpart AAAAA of this part and Sec. 52.38(a) of this 
chapter (including such a program that is revised in a SIP revision 
approved by the Administrator under Sec. 52.38(a)(3) or (4) of this 
chapter or that is established in a SIP revision approved by the 
Administrator under Sec. 52.38(a)(5) of this chapter), as a means of 
mitigating interstate transport of fine particulates and NOX.
    TR NOX Ozone Season Trading Program means a multi-state 
NOX air pollution control and emission reduction program 
established in accordance with subpart BBBBB of this part and Sec. 
52.38(b) of this chapter (including such a program that is revised in a 
SIP revision approved by the Administrator under Sec. 52.38(b)(3) or 
(4) of this chapter or that is established in a SIP revision approved by 
the Administrator under Sec. 52.38(b)(5) of this chapter), as a means 
of mitigating interstate transport of ozone and NOX.
    TR SO2 Group 1 allowance means a limited authorization issued and 
allocated or auctioned by the Administrator under this subpart, or by a 
State

[[Page 447]]

or permitting authority under a SIP revision approved by the 
Administrator under Sec. 52.39(d), (e), or (f) of this chapter, to emit 
one ton of SO2 during a control period of the specified 
calendar year for which the authorization is allocated or auctioned or 
of any calendar year thereafter under the TR SO2 Group 1 
Trading Program.
    TR SO2 Group 1 allowance deduction or deduct TR SO2 Group 
1 allowances means the permanent withdrawal of TR SO2 Group 1 
allowances by the Administrator from a compliance account (e.g., in 
order to account for compliance with the TR SO2 Group 1 
emissions limitation) or from an assurance account (e.g., in order to 
account for compliance with the assurance provisions under Sec. Sec. 
97.606 and 97.625).
    TR SO2 Group 1 allowances held or hold TR SO2 Group 1 allowances 
means the TR SO2 Group 1 allowances treated as included in an 
Allowance Management System account as of a specified point in time 
because at that time they:
    (1) Have been recorded by the Administrator in the account or 
transferred into the account by a correctly submitted, but not yet 
recorded, TR SO2 Group 1 allowance transfer in accordance 
with this subpart; and
    (2) Have not been transferred out of the account by a correctly 
submitted, but not yet recorded, TR SO2 Group 1 allowance 
transfer in accordance with this subpart.
    TR SO2 Group 1 emissions limitation means, for a TR SO2 
Group 1 source, the tonnage of SO2 emissions authorized in a 
control period by the TR SO2 Group 1 allowances available for 
deduction for the source under Sec. 97.624(a) for such control period.
    TR SO2 Group 1 source means a source that includes one or more TR 
SO2 Group 1 units.
    TR SO2 Group 1 Trading Program means a multi-state SO2 
air pollution control and emission reduction program established in 
accordance with this subpart and Sec. 52.39(a), (b), (d) through (f), 
(j), and (k) of this chapter (including such a program that is revised 
in a SIP revision approved by the Administrator under Sec. 52.39(d) or 
(e) of this chapter or that is established in a SIP revision approved by 
the Administrator under Sec. 52.39(f) of this chapter), as a means of 
mitigating interstate transport of fine particulates and SO2.
    TR SO2 Group 1 unit means a unit that is subject to the TR 
SO2 Group 1 Trading Program under Sec. 97.604.
    Unit means a stationary, fossil-fuel-fired boiler, stationary, 
fossil-fuel-fired combustion turbine, or other stationary, fossil-fuel-
fired combustion device. A unit that undergoes a physical change or is 
moved to a different location or source shall continue to be treated as 
the same unit. A unit (the replaced unit) that is replaced by another 
unit (the replacement unit) at the same or a different source shall 
continue to be treated as the same unit, and the replacement unit shall 
be treated as a separate unit.
    Unit operating day means, with regard to a unit, a calendar day in 
which the unit combusts any fuel.
    Unit operating hour or hour of unit operation means, with regard to 
a unit, an hour in which the unit combusts any fuel.
    Useful power means, with regard to a unit, electricity or mechanical 
energy that the unit makes available for use, excluding any such energy 
used in the power production process (which process includes, but is not 
limited to, any on-site processing or treatment of fuel combusted at the 
unit and any on-site emission controls).
    Useful thermal energy means thermal energy that is:
    (1) Made available to an industrial or commercial process (not a 
power production process), excluding any heat contained in condensate 
return or makeup water;
    (2) Used in a heating application (e.g., space heating or domestic 
hot water heating); or
    (3) Used in a space cooling application (i.e., in an absorption 
chiller).
    Utility power distribution system means the portion of an 
electricity grid owned or operated by a utility and dedicated to 
delivering electricity to customers.



Sec. 97.603  Measurements, abbreviations, and acronyms.

    Measurements, abbreviations, and acronyms used in this subpart are 
defined as follows:

Btu--British thermal unit

[[Page 448]]

CO2--carbon dioxide
H2O--water
hr--hour
kW--kilowatt electrical
kWh--kilowatt hour
lb--pound
mmBtu--million Btu
MWe--megawatt electrical
MWh--megawatt hour
NOX--nitrogen oxides
O2--oxygen
ppm--parts per million
scfh--standard cubic feet per hour
SO2--sulfur dioxide
yr--year



Sec. 97.604  Applicability.

    (a) Except as provided in paragraph (b) of this section:
    (1) The following units in a State (and Indian country within the 
borders of such State) shall be TR SO2 Group 1 units, and any 
source that includes one or more such units shall be a TR SO2 
Group 1 source, subject to the requirements of this subpart: any 
stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired 
combustion turbine serving at any time, on or after January 1, 2005, a 
generator with nameplate capacity of more than 25 MWe producing 
electricity for sale.
    (2) If a stationary boiler or stationary combustion turbine that, 
under paragraph (a)(1) of this section, is not a TR SO2 Group 
1 unit begins to combust fossil fuel or to serve a generator with 
nameplate capacity of more than 25 MWe producing electricity for sale, 
the unit shall become a TR SO2 Group 1 unit as provided in 
paragraph (a)(1) of this section on the first date on which it both 
combusts fossil fuel and serves such generator.
    (b) Any unit in a State (and Indian country within the borders of 
such State) that otherwise is a TR SO2 Group 1 unit under 
paragraph (a) of this section and that meets the requirements set forth 
in paragraph (b)(1)(i) or (2)(i) of this section shall not be a TR 
SO2 Group 1 unit:
    (1)(i) Any unit:
    (A) Qualifying as a cogeneration unit throughout the later of 2005 
or the 12-month period starting on the date the unit first produces 
electricity and continuing to qualify as a cogeneration unit throughout 
each calendar year ending after the later of 2005 or such 12-month 
period; and
    (B) Not supplying in 2005 or any calendar year thereafter more than 
one-third of the unit's potential electric output capacity or 219,000 
MWh, whichever is greater, to any utility power distribution system for 
sale.
    (ii) If, after qualifying under paragraph (b)(1)(i) of this section 
as not being a TR SO2 Group 1 unit, a unit subsequently no 
longer meets all the requirements of paragraph (b)(1)(i) of this 
section, the unit shall become a TR SO2 Group 1 unit starting 
on the earlier of January 1 after the first calendar year during which 
the unit first no longer qualifies as a cogeneration unit or January 1 
after the first calendar year during which the unit no longer meets the 
requirements of paragraph (b)(1)(i)(B) of this section. The unit shall 
thereafter continue to be a TR SO2 Group 1 unit.
    (2)(i) Any unit:
    (A) Qualifying as a solid waste incineration unit throughout the 
later of 2005 or the 12-month period starting on the date the unit first 
produces electricity and continuing to qualify as a solid waste 
incineration unit throughout each calendar year ending after the later 
of 2005 or such 12-month period; and
    (B) With an average annual fuel consumption of fossil fuel for the 
first 3 consecutive calendar years of operation starting no earlier than 
2005 of less than 20 percent (on a Btu basis) and an average annual fuel 
consumption of fossil fuel for any 3 consecutive calendar years 
thereafter of less than 20 percent (on a Btu basis).
    (ii) If, after qualifying under paragraph (b)(2)(i) of this section 
as not being a TR SO2 Group 1 unit, a unit subsequently no 
longer meets all the requirements of paragraph (b)(1)(i) of this 
section, the unit shall become a TR SO2 Group 1 unit starting 
on the earlier of January 1 after the first calendar year during which 
the unit first no longer qualifies as a solid waste incineration unit or 
January 1 after the first 3 consecutive calendar years after 2005 for 
which the unit has an average annual fuel consumption of fossil fuel of 
20 percent or more. The unit shall thereafter continue to be a TR 
SO2 Group 1 unit.

[[Page 449]]

    (c) A certifying official of an owner or operator of any unit or 
other equipment may submit a petition (including any supporting 
documents) to the Administrator at any time for a determination 
concerning the applicability, under paragraphs (a) and (b) of this 
section or a SIP revision approved under Sec. 52.39(e) or (f) of this 
chapter, of the TR SO2 Group 1 Trading Program to the unit or 
other equipment.
    (1) Petition content. The petition shall be in writing and include 
the identification of the unit or other equipment and the relevant facts 
about the unit or other equipment. The petition and any other documents 
provided to the Administrator in connection with the petition shall 
include the following certification statement, signed by the certifying 
official: ``I am authorized to make this submission on behalf of the 
owners and operators of the unit or other equipment for which the 
submission is made. I certify under penalty of law that I have 
personally examined, and am familiar with, the statements and 
information submitted in this document and all its attachments. Based on 
my inquiry of those individuals with primary responsibility for 
obtaining the information, I certify that the statements and information 
are to the best of my knowledge and belief true, accurate, and complete. 
I am aware that there are significant penalties for submitting false 
statements and information or omitting required statements and 
information, including the possibility of fine or imprisonment.''
    (2) Response. The Administrator will issue a written response to the 
petition and may request supplemental information determined by the 
Administrator to be relevant to such petition. The Administrator's 
determination concerning the applicability, under paragraphs (a) and (b) 
of this section, of the TR SO2 Group 1 Trading Program to the 
unit or other equipment shall be binding on any State or permitting 
authority unless the Administrator determines that the petition or other 
documents or information provided in connection with the petition 
contained significant, relevant errors or omissions.



Sec. 97.605  Retired unit exemption.

    (a)(1) Any TR SO2 Group 1 unit that is permanently 
retired shall be exempt from Sec. 97.606(b) and (c)(1), Sec. 97.624, 
and Sec. Sec. 97.630 through 97.635.
    (2) The exemption under paragraph (a)(1) of this section shall 
become effective the day on which the TR SO2 Group 1 unit is 
permanently retired. Within 30 days of the unit's permanent retirement, 
the designated representative shall submit a statement to the 
Administrator. The statement shall state, in a format prescribed by the 
Administrator, that the unit was permanently retired on a specified date 
and will comply with the requirements of paragraph (b) of this section.
    (b) Special provisions. (1) A unit exempt under paragraph (a) of 
this section shall not emit any SO2, starting on the date 
that the exemption takes effect.
    (2) For a period of 5 years from the date the records are created, 
the owners and operators of a unit exempt under paragraph (a) of this 
section shall retain, at the source that includes the unit, records 
demonstrating that the unit is permanently retired. The 5-year period 
for keeping records may be extended for cause, at any time before the 
end of the period, in writing by the Administrator. The owners and 
operators bear the burden of proof that the unit is permanently retired.
    (3) The owners and operators and, to the extent applicable, the 
designated representative of a unit exempt under paragraph (a) of this 
section shall comply with the requirements of the TR SO2 
Group 1 Trading Program concerning all periods for which the exemption 
is not in effect, even if such requirements arise, or must be complied 
with, after the exemption takes effect.
    (4) A unit exempt under paragraph (a) of this section shall lose its 
exemption on the first date on which the unit resumes operation. Such 
unit shall be treated, for purposes of applying allocation, monitoring, 
reporting, and recordkeeping requirements under this subpart, as a unit 
that commences commercial operation on the first date on which the unit 
resumes operation.

[[Page 450]]



Sec. 97.606  Standard requirements.

    (a) Designated representative requirements. The owners and operators 
shall comply with the requirement to have a designated representative, 
and may have an alternate designated representative, in accordance with 
Sec. Sec. 97.613 through 97.618.
    (b) Emissions monitoring, reporting, and recordkeeping requirements. 
(1) The owners and operators, and the designated representative, of each 
TR SO2 Group 1 source and each TR SO2 Group 1 unit 
at the source shall comply with the monitoring, reporting, and 
recordkeeping requirements of Sec. Sec. 97.630 through 97.635.
    (2) The emissions data determined in accordance with Sec. Sec. 
97.630 through 97.635 shall be used to calculate allocations of TR 
SO2 Group 1 allowances under Sec. Sec. 97.611(a)(2) and (b) 
and 97.612 and to determine compliance with the TR SO2 Group 
1 emissions limitation and assurance provisions under paragraph (c) of 
this section, provided that, for each monitoring location from which 
mass emissions are reported, the mass emissions amount used in 
calculating such allocations and determining such compliance shall be 
the mass emissions amount for the monitoring location determined in 
accordance with Sec. Sec. 97.630 through 97.635 and rounded to the 
nearest ton, with any fraction of a ton less than 0.50 being deemed to 
be zero.
    (c) SO2 emissions requirements. (1) TR SO2 Group 1 
emissions limitation. (i) As of the allowance transfer deadline for a 
control period in a given year, the owners and operators of each TR 
SO2 Group 1 source and each TR SO2 Group 1 unit at 
the source shall hold, in the source's compliance account, TR 
SO2 Group 1 allowances available for deduction for such 
control period under Sec. 97.624(a) in an amount not less than the tons 
of total SO2 emissions for such control period from all TR 
SO2 Group 1 units at the source.
    (ii) If total SO2 emissions during a control period in a 
given year from the TR SO2 Group 1 units at a TR 
SO2 Group 1 source are in excess of the TR SO2 
Group 1 emissions limitation set forth in paragraph (c)(1)(i) of this 
section, then:
    (A) The owners and operators of the source and each TR 
SO2 Group 1 unit at the source shall hold the TR 
SO2 Group 1 allowances required for deduction under Sec. 
97.624(d); and
    (B) The owners and operators of the source and each TR 
SO2 Group 1 unit at the source shall pay any fine, penalty, 
or assessment or comply with any other remedy imposed, for the same 
violations, under the Clean Air Act, and each ton of such excess 
emissions and each day of such control period shall constitute a 
separate violation of this subpart and the Clean Air Act.
    (2) TR SO2 Group 1 assurance provisions. (i) If total 
SO2 emissions during a control period in a given year from 
all TR SO2 Group 1 units at TR SO2 Group 1 sources 
in a State (and Indian country within the borders of such State) exceed 
the State assurance level, then the owners and operators of such sources 
and units in each group of one or more sources and units having a common 
designated representative for such control period, where the common 
designated representative's share of such SO2 emissions 
during such control period exceeds the common designated 
representative's assurance level for the State and such control period, 
shall hold (in the assurance account established for the owners and 
operators of such group) TR SO2 Group 1 allowances available 
for deduction for such control period under Sec. 97.625(a) in an amount 
equal to two times the product (rounded to the nearest whole number), as 
determined by the Administrator in accordance with Sec. 97.625(b), of 
multiplying--
    (A) The quotient of the amount by which the common designated 
representative's share of such SO2 emissions exceeds the 
common designated representative's assurance level divided by the sum of 
the amounts, determined for all common designated representatives for 
such sources and units in the State (and Indian country within the 
borders of such State) for such control period, by which each common 
designated representative's share of such SO2 emissions 
exceeds the respective common designated representative's assurance 
level; and
    (B) The amount by which total SO2 emissions from all TR 
SO2 Group 1 units at TR SO2 Group 1 sources in the 
State (and Indian country within the borders of such State) for such 
control

[[Page 451]]

period exceed the State assurance level.
    (ii) The owners and operators shall hold the TR SO2 Group 
1 allowances required under paragraph (c)(2)(i) of this section, as of 
midnight of November 1 (if it is a business day), or midnight of the 
first business day thereafter (if November 1 is not a business day), 
immediately after such control period.
    (iii) Total SO2 emissions from all TR SO2 
Group 1 units at TR SO2 Group 1 sources in a State (and 
Indian country within the borders of such State) during a control period 
in a given year exceed the State assurance level if such total 
SO2 emissions exceed the sum, for such control period, of the 
State SO2 Group 1 trading budget under Sec. 97.610(a) and 
the State's variability limit under Sec. 97.610(b).
    (iv) It shall not be a violation of this subpart or of the Clean Air 
Act if total SO2 emissions from all TR SO2 Group 1 
units at TR SO2 Group 1 sources in a State (and Indian 
country within the borders of such State) during a control period exceed 
the State assurance level or if a common designated representative's 
share of total SO2 emissions from the TR SO2 Group 
1 units at TR SO2 Group 1 sources in a State (and Indian 
country within the borders of such State) during a control period 
exceeds the common designated representative's assurance level.
    (v) To the extent the owners and operators fail to hold TR 
SO2 Group 1 allowances for a control period in a given year 
in accordance with paragraphs (c)(2)(i) through (iii) of this section,
    (A) The owners and operators shall pay any fine, penalty, or 
assessment or comply with any other remedy imposed under the Clean Air 
Act; and
    (B) Each TR SO2 Group 1 allowance that the owners and 
operators fail to hold for such control period in accordance with 
paragraphs (c)(2)(i) through (iii) of this section and each day of such 
control period shall constitute a separate violation of this subpart and 
the Clean Air Act.
    (3) Compliance periods. (i) A TR SO2 Group 1 unit shall 
be subject to the requirements under paragraph (c)(1) of this section 
for the control period starting on the later of January 1, 2015 or the 
deadline for meeting the unit's monitor certification requirements under 
Sec. 97.630(b) and for each control period thereafter.
    (ii) A TR SO2 Group 1 unit shall be subject to the 
requirements under paragraph (c)(2) of this section for the control 
period starting on the later of January 1, 2017 or the deadline for 
meeting the unit's monitor certification requirements under Sec. 
97.630(b) and for each control period thereafter.
    (4) Vintage of allowances held for compliance. (i) A TR 
SO2 Group 1 allowance held for compliance with the 
requirements under paragraph (c)(1)(i) of this section for a control 
period in a given year must be a TR SO2 Group 1 allowance 
that was allocated for such control period or a control period in a 
prior year.
    (ii) A TR SO2 Group 1 allowance held for compliance with 
the requirements under paragraphs (c)(1)(ii)(A) and (2)(i) through (iii) 
of this section for a control period in a given year must be a TR 
SO2 Group 1 allowance that was allocated for a control period 
in a prior year or the control period in the given year or in the 
immediately following year.
    (5) Allowance Management System requirements. Each TR SO2 
Group 1 allowance shall be held in, deducted from, or transferred into, 
out of, or between Allowance Management System accounts in accordance 
with this subpart.
    (6) Limited authorization. A TR SO2 Group 1 allowance is 
a limited authorization to emit one ton of SO2 during the 
control period in one year. Such authorization is limited in its use and 
duration as follows:
    (i) Such authorization shall only be used in accordance with the TR 
SO2 Group 1 Trading Program; and
    (ii) Notwithstanding any other provision of this subpart, the 
Administrator has the authority to terminate or limit the use and 
duration of such authorization to the extent the Administrator 
determines is necessary or appropriate to implement any provision of the 
Clean Air Act.
    (7) Property right. A TR SO2 Group 1 allowance does not 
constitute a property right.

[[Page 452]]

    (d) Title V permit requirements. (1) No title V permit revision 
shall be required for any allocation, holding, deduction, or transfer of 
TR SO2 Group 1 allowances in accordance with this subpart.
    (2) A description of whether a unit is required to monitor and 
report SO2 emissions using a continuous emission monitoring 
system (under subpart H of part 75 of this chapter), an excepted 
monitoring system (under appendices D and E to part 75 of this chapter), 
a low mass emissions excepted monitoring methodology (under Sec. 75.19 
of this chapter), or an alternative monitoring system (under subpart E 
of part 75 of this chapter) in accordance with Sec. Sec. 97.630 through 
97.635 may be added to, or changed in, a title V permit using minor 
permit modification procedures in accordance with Sec. Sec. 70.7(e)(2) 
and 71.7(e)(1) of this chapter, provided that the requirements 
applicable to the described monitoring and reporting (as added or 
changed, respectively) are already incorporated in such permit. This 
paragraph explicitly provides that the addition of, or change to, a 
unit's description as described in the prior sentence is eligible for 
minor permit modification procedures in accordance with Sec. Sec. 
70.7(e)(2)(i)(B) and 71.7(e)(1)(i)(B) of this chapter.
    (e) Additional recordkeeping and reporting requirements. (1) Unless 
otherwise provided, the owners and operators of each TR SO2 
Group 1 source and each TR SO2 Group 1 unit at the source 
shall keep on site at the source each of the following documents (in 
hardcopy or electronic format) for a period of 5 years from the date the 
document is created. This period may be extended for cause, at any time 
before the end of 5 years, in writing by the Administrator.
    (i) The certificate of representation under Sec. 97.616 for the 
designated representative for the source and each TR SO2 
Group 1 unit at the source and all documents that demonstrate the truth 
of the statements in the certificate of representation; provided that 
the certificate and documents shall be retained on site at the source 
beyond such 5-year period until such certificate of representation and 
documents are superseded because of the submission of a new certificate 
of representation under Sec. 97.616 changing the designated 
representative.
    (ii) All emissions monitoring information, in accordance with this 
subpart.
    (iii) Copies of all reports, compliance certifications, and other 
submissions and all records made or required under, or to demonstrate 
compliance with the requirements of, the TR SO2 Group 1 
Trading Program.
    (2) The designated representative of a TR SO2 Group 1 
source and each TR SO2 Group 1 unit at the source shall make 
all submissions required under the TR SO2 Group 1 Trading 
Program, except as provided in Sec. 97.618. This requirement does not 
change, create an exemption from, or otherwise affect the responsible 
official submission requirements under a title V operating permit 
program in parts 70 and 71 of this chapter.
    (f) Liability. (1) Any provision of the TR SO2 Group 1 
Trading Program that applies to a TR SO2 Group 1 source or 
the designated representative of a TR SO2 Group 1 source 
shall also apply to the owners and operators of such source and of the 
TR SO2 Group 1 units at the source.
    (2) Any provision of the TR SO2 Group 1 Trading Program 
that applies to a TR SO2 Group 1 unit or the designated 
representative of a TR SO2 Group 1 unit shall also apply to 
the owners and operators of such unit.
    (g) Effect on other authorities. No provision of the TR 
SO2 Group 1 Trading Program or exemption under Sec. 97.605 
shall be construed as exempting or excluding the owners and operators, 
and the designated representative, of a TR SO2 Group 1 source 
or TR SO2 Group 1 unit from compliance with any other 
provision of the applicable, approved State implementation plan, a 
federally enforceable permit, or the Clean Air Act.

[76 FR 48432, Aug. 8, 2011, as amended at 77 FR 10338, Feb. 21, 2012; 79 
FR 71672, Dec. 3, 2014]



Sec. 97.607  Computation of time.

    (a) Unless otherwise stated, any time period scheduled, under the TR 
SO2 Group 1 Trading Program, to begin on the occurrence of an 
act or event shall

[[Page 453]]

begin on the day the act or event occurs.
    (b) Unless otherwise stated, any time period scheduled, under the TR 
SO2 Group 1 Trading Program, to begin before the occurrence 
of an act or event shall be computed so that the period ends the day 
before the act or event occurs.
    (c) Unless otherwise stated, if the final day of any time period, 
under the TR SO2 Group 1 Trading Program, is not a business 
day, the time period shall be extended to the next business day.



Sec. 97.608  Administrative appeal procedures.

    The administrative appeal procedures for decisions of the 
Administrator under the TR SO2 Group 1 Trading Program are 
set forth in part 78 of this chapter.



Sec. 97.609  [Reserved]



Sec. 97.610  State SO[bdi2] Group 1 trading budgets, new unit set-
asides, Indian country new unit set-aside, and variability limits.

    (a) The State SO2 trading budgets, new unit set-asides, 
and Indian country new unit-set asides for allocations of TR 
SO2 Group 1 allowances for the control periods in 2015 and 
thereafter are as follows:
    (1) Illinois. (i) The SO2 trading budget for 2015 and 
2016 is 234,889 tons.
    (ii) The SO2 new unit set-aside for 2015 and 2016 is 
11,744 tons.
    (iii) [Reserved]
    (iv) The SO2 trading budget for 2017 and thereafter is 
124,123 tons.
    (v) The SO2 new unit set-aside for 2017 and thereafter is 
6,206 tons.
    (vi) [Reserved]
    (2) Indiana. (i) The SO2 trading budget for 2015 and 2016 
is 290,762 tons.
    (ii) The SO2 new unit set-aside for 2015 and 2016 is 
8,723 tons.
    (iii) [Reserved]
    (iv) The SO2 trading budget for 2017 and thereafter is 
166,449 tons.
    (v) The SO2 new unit set-aside for 2017 and thereafter is 
4,993 tons.
    (3) Iowa. (i) The SO2 trading budget for 2015 and 2016 is 
107,085 tons.
    (ii) The SO2 new unit set-aside for 2015 and 2016 is 
2,035 tons.
    (iii) The SO2 Indian country new unit set-aside for 2015 
and 2016 is 107 tons.
    (iv) The SO2 trading budget for 2017 and thereafter is 
75,184 tons.
    (v) The SO2 new unit set-aside for 2017 and thereafter is 
1,429 tons.
    (vi) The SO2 Indian country new unit set-aside for 2017 
and thereafter is 75 tons.
    (4) Kentucky. (i) The SO2 trading budget for 2015 and 
2016 is 232,662 tons.
    (ii) The SO2 new unit set-aside for 2015 and 2016 is 
13,960 tons.
    (iii) [Reserved]
    (iv) The SO2 trading budget for 2017 and thereafter is 
106,284 tons.
    (v) The SO2 new unit set-aside for 2017 and thereafter is 
6,377 tons.
    (vi) [Reserved]
    (5) Maryland. (i) The SO2 trading budget for 2015 and 
2016 is 30,120 tons.
    (ii) The SO2 new unit set-aside for 2015 and 2016 is 602 
tons.
    (iii) [Reserved]
    (iv) The SO2 trading budget for 2017 and thereafter is 
28,203 tons.
    (v) The SO2 new unit set-aside for 2017 and thereafter is 
564 tons.
    (vi) [Reserved]
    (6) Michigan. (i) The SO2 trading budget for 2015 and 
2016 is 229,303 tons.
    (ii) The SO2 new unit set-aside for 2015 and 2016 is 
4,357 tons.
    (iii) The SO2 Indian country new unit set-aside for 2015 
and 2016 is 229 tons.
    (iv) The SO2 trading budget for 2017 and thereafter is 
143,995 tons.
    (v) The SO2 new unit set-aside for 2017 and thereafter is 
2,736 tons.
    (vi) The SO2 Indian country new unit set-aside for 2017 
and thereafter is 144 tons.
    (7) Missouri. (i) The SO2 trading budget for 2015 and 
2016 is 207,466 tons.
    (ii) The SO2 new unit set-aside for 2015 is 4,149 tons 
and for 2016 is 6,224 tons.
    (iii) [Reserved]
    (iv) The SO2 trading budget for 2017 and thereafter is 
165,941 tons.
    (v) The SO2 new unit set-aside for 2017 and thereafter is 
4,978 tons.
    (vi) [Reserved]
    (8) New Jersey. (i) The SO2 trading budget for 2015 and 
2016 is 7,670 tons.
    (ii) The SO2 new unit set-aside for 2015 and 2016 is 153 
tons.
    (iii) [Reserved]
    (iv) The SO2 trading budget for 2017 and thereafter is 
5,574 tons.

[[Page 454]]

    (v) The SO2 new unit set-aside for 2017 and thereafter is 
111 tons.
    (vi) [Reserved]
    (9) New York. (i) The SO2 trading budget for 2015 and 
2016 is 36,296 tons.
    (ii) The SO2 new unit set-aside for 2015 and 2016 is 690 
tons.
    (iii) The SO2 Indian country new unit set-aside for 2015 
and 2016 is 36 tons.
    (iv) The SO2 trading budget for 2017 and thereafter is 
27,556 tons.
    (v) The SO2 new unit set-aside for 2017 and thereafter is 
523 tons.
    (vi) The SO2 Indian country new unit set-aside for 2017 
and thereafter is 28 tons.
    (10) North Carolina. (i) The SO2 trading budget for 2015 
and 2016 is 136,881 tons.
    (ii) The SO2 new unit set-aside for 2015 and 2016 is 
10,813 tons.
    (iii) The SO2 Indian country new unit set-aside for 2015 
and 2016 is 137 tons.
    (iv) The SO2 trading budget for 2017 and thereafter is 
57,620 tons.
    (v) The SO2 new unit set-aside for 2017 and thereafter is 
4,552 tons.
    (vi) The SO2 Indian country new unit set-aside for 2017 
and thereafter is 58 tons.
    (11) Ohio. (i) The SO2 trading budget for 2015 and 2016 
is 315,393 tons.
    (ii) The SO2 new unit set-aside for 2015 and 2016 is 
6,308 tons.
    (iii) [Reserved]
    (iv) The SO2 trading budget for 2017 and thereafter is 
142,240 tons.
    (v) The SO2 new unit set-aside for 2017 and thereafter is 
2,845 tons.
    (12) Pennsylvania. (i) The SO2 trading budget for 2015 
and 2016 is 278,651 tons.
    (ii) The SO2 new unit set-aside for 2015 and 2016 is 
5,573 tons.
    (iii) [Reserved]
    (iv) The SO2 trading budget for 2017 and thereafter is 
112,021 tons.
    (v) The SO2 new unit set-aside for 2017 and thereafter is 
2,240 tons.
    (vi) [Reserved]
    (13) Tennessee. (i) The SO2 trading budget for 2015 and 
2016 is 148,150 tons.
    (ii) The SO2 new unit set-aside for 2015 and 2016 is 
2,963 tons.
    (iii) [Reserved]
    (iv) The SO2 trading budget for 2017 and thereafter is 
58,833 tons.
    (v) The SO2 new unit set-aside for 2017 and thereafter is 
1,177 tons.
    (vi) [Reserved]
    (14) Virginia. (i) The SO2 trading budget for 2015 and 
2016 is 70,820 tons.
    (ii) The SO2 new unit set-aside for 2015 and 2016 is 
2,833 tons.
    (iii) [Reserved]
    (iv) The SO2 trading budget for 2017 and thereafter is 
35,057 tons.
    (v) The SO2 new unit set-aside for 2017 and thereafter is 
1,402 tons.
    (vi) [Reserved]
    (15) West Virginia. (i) The SO2 trading budget for 2015 
and 2016 is 146,174 tons.
    (ii) The SO2 new unit set-aside for 2015 and 2016 is 
10,232 tons.
    (iii) [Reserved]
    (iv) The SO2 trading budget for 2017 and thereafter is 
75,668 tons.
    (v) The SO2 new unit set-aside for 2017 and thereafter is 
5,297 tons.
    (vi) [Reserved]
    (16) Wisconsin. (i) The SO2 trading budget for 2015 and 
2016 is 79,480 tons.
    (ii) The SO2 new unit set-aside for 2015 and 2016 is 
3,099 tons.
    (iii) The SO2 Indian country new unit set-aside for 2015 
and 2016 is 80 tons.
    (iv) The SO2 trading budget for 2017 and thereafter is 
47,883 tons.
    (v) The SO2 new unit set-aside for 2017 and thereafter is 
1,867 tons.
    (vi) The SO2 Indian country new unit set-aside for 2017 
and thereafter is 48 tons.
    (b) The States' variability limits for the State SO2 
Group 1 trading budgets for the control periods in 2017 and thereafter 
are as follows:
    (1) The SO2 variability limit for Illinois is 22,342 
tons.
    (2) The SO2 variability limit for Indiana is 29,961 tons.
    (3) The SO2 variability limit for Iowa is 13,533 tons.
    (4) The SO2 variability limit for Kentucky is 19,131 
tons.
    (5) The SO2 variability limit for Maryland is 5,077 tons.
    (6) The SO2 variability limit for Michigan is 25,919 
tons.
    (7) The SO2 variability limit for Missouri is 29,869 
tons.
    (8) The SO2 variability limit for New Jersey is 1,003 
tons.
    (9) The SO2 variability limit for New York is 4,960 tons.
    (10) The SO2 variability limit for North Carolina is 
10,372 tons.
    (11) The SO2 variability limit for Ohio is 25,603 tons.

[[Page 455]]

    (12) The SO2 variability limit for Pennsylvania is 20,164 
tons.
    (13) The SO2 variability limit for Tennessee is 10,590 
tons.
    (14) The SO2 variability limit for Virginia is 6,310 
tons.
    (15) The SO2 variability limit for West Virginia is 
13,620 tons.
    (16) The SO2 variability limit for Wisconsin is 8,619 
tons.
    (c) Each SO2 trading budget in this section includes any 
tons in a new unit set aside or Indian country new unit set aside, but 
does not include any tons in a variability limit.

[77 FR 10339, Feb. 21, 2012, as amended at 77 FR 10348, Feb. 21, 2012; 
77 FR 34846, June 12, 2012; 79 FR 71672, Dec. 3, 2014]



Sec. 97.611  Timing requirements for TR SO[bdi2] Group 1 allowance
allocations.

    (a) Existing units. (1) TR SO2 Group 1 allowances are 
allocated, for the control periods in 2015 and each year thereafter, as 
provided in a notice of data availability issued by the Administrator. 
Providing an allocation to a unit in such notice does not constitute a 
determination that the unit is a TR SO2 Group 1 unit, and not 
providing an allocation to a unit in such notice does not constitute a 
determination that the unit is not a TR SO2 Group 1 unit.
    (2) Notwithstanding paragraph (a)(1) of this section, if a unit 
provided an allocation in the notice of data availability issued under 
paragraph (a)(1) of this section does not operate, starting after 2014, 
during the control period in two consecutive years, such unit will not 
be allocated the TR SO2 Group 1 allowances provided in such 
notice for the unit for the control periods in the fifth year after the 
first such year and in each year after that fifth year. All TR 
SO2 Group 1 allowances that would otherwise have been 
allocated to such unit will be allocated to the new unit set-aside for 
the State where such unit is located and for the respective years 
involved. If such unit resumes operation, the Administrator will 
allocate TR SO2 Group 1 allowances to the unit in accordance 
with paragraph (b) of this section.
    (b) New units. (1) New unit set-asides. (i) By June 1, 2015 and June 
1 of each year thereafter, the Administrator will calculate the TR 
SO2 Group 1 allowance allocation to each TR SO2 
Group 1 unit in a State, in accordance with Sec. 97.612(a)(2) through 
(7) and (12), for the control period in the year of the applicable 
calculation deadline under this paragraph and will promulgate a notice 
of data availability of the results of the calculations.
    (ii) For each notice of data availability required in paragraph 
(b)(1)(i) of this section, the Administrator will provide an opportunity 
for submission of objections to the calculations referenced in such 
notice.
    (A) Objections shall be submitted by the deadline specified in each 
notice of data availability required in paragraph (b)(1)(i) of this 
section and shall be limited to addressing whether the calculations 
(including the identification of the TR SO2 Group 1 units) 
are in accordance with Sec. 97.612(a)(2) through (7) and (12) and 
Sec. Sec. 97.606(b)(2) and 97.630 through 97.635.
    (B) The Administrator will adjust the calculations to the extent 
necessary to ensure that they are in accordance with the provisions 
referenced in paragraph (b)(1)(ii)(A) of this section. By August 1 
immediately after the promulgation of each notice of data availability 
required in paragraph (b)(1)(i) of this section, the Administrator will 
promulgate a notice of data availability of any adjustments that the 
Administrator determines to be necessary with regard to allocations 
under Sec. 97.612(a)(2) through (7) and (12) and the reasons for 
accepting or rejecting any objections submitted in accordance with 
paragraph (b)(1)(ii)(A) of this section.
    (iii) If the new unit set-aside for such control period contains any 
TR SO2 Group 1 allowances that have not been allocated in the 
applicable notice of data availability required in paragraph (b)(1)(ii) 
of this section, the Administrator will promulgate, by December 15 
immediately after such notice, a notice of data availability that 
identifies any TR SO2 Group 1 units that commenced commercial 
operation during the period starting January 1 of the year before the 
year of such control period and ending November 30 of year of such 
control period.
    (iv) For each notice of data availability required in paragraph 
(b)(1)(iii)

[[Page 456]]

of this section, the Administrator will provide an opportunity for 
submission of objections to the identification of TR SO2 
annual units in such notice.
    (A) Objections shall be submitted by the deadline specified in each 
notice of data availability required in paragraph (b)(1)(iii) of this 
section and shall be limited to addressing whether the identification of 
TR SO2 annual units in such notice is in accordance with 
paragraph (b)(1)(iii) of this section.
    (B) The Administrator will adjust the identification of TR 
SO2 Group 1 units in each notice of data availability 
required in paragraph (b)(1)(iii) of this section to the extent 
necessary to ensure that it is in accordance with paragraph (b)(1)(iii) 
of this section and will calculate the TR SO2 Group 1 
allowance allocation to each TR SO2 Group 1 unit in 
accordance with Sec. 97.612(a)(9), (10), and (12) and Sec. Sec. 
97.606(b)(2) and 97.630 through 97.635. By February 15 immediately after 
the promulgation of each notice of data availability required in 
paragraph (b)(1)(iii) of this section, the Administrator will promulgate 
a notice of data availability of any adjustments of the identification 
of TR SO2 Group 1 units that the Administrator determines to 
be necessary, the reasons for accepting or rejecting any objections 
submitted in accordance with paragraph (b)(1)(iv)(A) of this section, 
and the results of such calculations.
    (v) To the extent any TR SO2 Group 1 allowances are added 
to the new unit set-aside after promulgation of each notice of data 
availability required in paragraph (b)(1)(iv) of this section, the 
Administrator will promulgate additional notices of data availability, 
as deemed appropriate, of the allocation of such TR SO2 Group 
1 allowances in accordance with Sec. 97.612(a)(10).
    (2) Indian country new unit set-asides. (i) By June 1, 2015 and June 
1 of each year thereafter, the Administrator will calculate the TR 
SO2 Group 1 allowance allocation to each TR SO2 
Group 1 unit in Indian country within the borders of a State, in 
accordance with Sec. 97.612(b)(2) through (7) and (12), for the control 
period in the year of the applicable calculation deadline under this 
paragraph and will promulgate a notice of data availability of the 
results of the calculations.
    (ii) For each notice of data availability required in paragraph 
(b)(2)(i) of this section, the Administrator will provide an opportunity 
for submission of objections to the calculations referenced in such 
notice.
    (A) Objections shall be submitted by the deadline specified in each 
notice of data availability required in paragraph (b)(2)(i) of this 
section and shall be limited to addressing whether the calculations 
(including the identification of the TR SO2 Group 1 units) 
are in accordance with Sec. 97.612(b)(2) through (7) and (12) and 
Sec. Sec. 97.606(b)(2) and 97.630 through 97.635.
    (B) The Administrator will adjust the calculations to the extent 
necessary to ensure that they are in accordance with the provisions 
referenced in paragraph (b)(2)(ii)(A) of this section. By August 1 
immediately after the promulgation of each notice of data availability 
required in paragraph (b)(2)(i) of this section, the Administrator will 
promulgate a notice of data availability of any adjustments that the 
Administrator determines to be necessary with regard to allocations 
under Sec. 97.612(b)(2) through (7) and (12) and the reasons for 
accepting or rejecting any objections submitted in accordance with 
paragraph (b)(2)(ii)(A) of this section.
    (iii) If the Indian country new unit set-aside for such control 
period contains any TR SO2 Group 1 allowances that have not 
been allocated in the applicable notice of data availability required in 
paragraph (b)(2)(ii) of this section, the Administrator will promulgate, 
by December 15 immediately after such notice, a notice of data 
availability that identifies any TR SO2 Group 1 units that 
commenced commercial operation during the period starting January 1 of 
the year before the year of such control period and ending November 30 
of year of such control period.
    (iv) For each notice of data availability required in paragraph 
(b)(2)(iii) of this section, the Administrator will provide an 
opportunity for submission of objections to the identification of TR 
SO2 annual units in such notice.
    (A) Objections shall be submitted by the deadline specified in each 
notice of data availability required in paragraph

[[Page 457]]

(b)(2)(iii) of this section and shall be limited to addressing whether 
the identification of TR SO2 annual units in such notice is 
in accordance with paragraph (b)(2)(iii) of this section.
    (B) The Administrator will adjust the identification of TR 
SO2 Group 1 units in each notice of data availability 
required in paragraph (b)(2)(iii) of this section to the extent 
necessary to ensure that it is in accordance with paragraph (b)(2)(iii) 
of this section and will calculate the TR SO2 Group 1 
allowance allocation to each TR SO2 Group 1 unit in 
accordance with Sec. 97.612(b)(9), (10), and (12) and Sec. Sec. 
97.606(b)(2) and 97.630 through 97.635. By February 15 immediately after 
the promulgation of each notice of data availability required in 
paragraph (b)(2)(iii) of this section, the Administrator will promulgate 
a notice of data availability of any adjustments of the identification 
of TR SO2 Group 1 units that the Administrator determines to 
be necessary, the reasons for accepting or rejecting any objections 
submitted in accordance with paragraph (b)(2)(iv)(A) of this section, 
and the results of such calculations.
    (v) To the extent any TR SO2 Group 1 allowances are added 
to the Indian country new unit set-aside after promulgation of each 
notice of data availability required in paragraph (b)(2)(iv) of this 
section, the Administrator will promulgate additional notices of data 
availability, as deemed appropriate, of the allocation of such TR 
NOX Annual allowances in accordance with Sec. 97.612(b)(10).
    (c) Units incorrectly allocated TR SO2 Group 1 
allowances. (1) For each control period in 2015 and thereafter, if the 
Administrator determines that TR SO2 Group 1 allowances were 
allocated under paragraph (a) of this section, or under a provision of a 
SIP revision approved under Sec. 52.39(d), (e), or (f) of this chapter, 
where such control period and the recipient are covered by the 
provisions of paragraph (c)(1)(i) of this section or were allocated 
under Sec. 97.612(a)(2) through (7), (9), and (12) and (b)(2) through 
(7), (9), and (12), or under a provision of a SIP revision approved 
under Sec. 52.39(e) or (f) of this chapter, where such control period 
and the recipient are covered by the provisions of paragraph (c)(1)(ii) 
of this section, then the Administrator will notify the designated 
representative of the recipient and will act in accordance with the 
procedures set forth in paragraphs (c)(2) through (5) of this section:
    (i)(A) The recipient is not actually a TR SO2 Group 1 
unit under Sec. 97.604 as of January 1, 2015 and is allocated TR 
SO2 Group 1 allowances for such control period or, in the 
case of an allocation under a provision of a SIP revision approved under 
Sec. 52.39(d), (e), or (f) of this chapter, the recipient is not 
actually a TR SO2 Group 1 unit as of January 1, 2015 and is 
allocated TR SO2 Group 1 allowances for such control period 
that the SIP revision provides should be allocated only to recipients 
that are TR SO2 Group 1 units as of January 1, 2015; or
    (B) The recipient is not located as of January 1 of the control 
period in the State from whose SO2 Group 1 trading budget the 
TR SO2 Group 1 allowances allocated under paragraph (a) of 
this section, or under a provision of a SIP revision approved under 
Sec. 52.39(d), (e), or (f) of this chapter, were allocated for such 
control period.
    (ii) The recipient is not actually a TR SO2 Group 1 unit 
under Sec. 97.604 as of January 1 of such control period and is 
allocated TR SO2 Group 1 allowances for such control period 
or, in the case of an allocation under a provision of a SIP revision 
approved under Sec. 52.39(d), (e), or (f) of this chapter, the 
recipient is not actually a TR SO2 Group 1 unit as of January 
1 of such control period and is allocated TR SO2 Group 1 
allowances for such control period that the SIP revision provides should 
be allocated only to recipients that are TR SO2 Group 1 units 
as of January 1 of such control period.
    (2) Except as provided in paragraph (c)(3) or (4) of this section, 
the Administrator will not record such TR SO2 Group 1 
allowances under Sec. 97.621.
    (3) If the Administrator already recorded such TR SO2 
Group 1 allowances under Sec. 97.621 and if the Administrator makes the 
determination under paragraph (c)(1) of this section before making 
deductions for the source that includes such recipient under Sec. 
97.624(b)

[[Page 458]]

for such control period, then the Administrator will deduct from the 
account in which such TR SO2 Group 1 allowances were recorded 
an amount of TR SO2 Group 1 allowances allocated for the same 
or a prior control period equal to the amount of such already recorded 
TR SO2 Group 1 allowances. The authorized account 
representative shall ensure that there are sufficient TR SO2 
Group 1 allowances in such account for completion of the deduction.
    (4) If the Administrator already recorded such TR SO2 
Group 1 allowances under Sec. 97.621 and if the Administrator makes the 
determination under paragraph (c)(1) of this section after making 
deductions for the source that includes such recipient under Sec. 
97.624(b) for such control period, then the Administrator will not make 
any deduction to take account of such already recorded TR SO2 
Group 1 allowances.
    (5)(i) With regard to the TR SO2 Group 1 allowances that 
are not recorded, or that are deducted as an incorrect allocation, in 
accordance with paragraphs (c)(2) and (3) of this section for a 
recipient under paragraph (c)(1)(i) of this section, the Administrator 
will:
    (A) Transfer such TR SO2 Group 1 allowances to the new 
unit set-aside for such control period for the State from whose 
SO2 Group 1 trading budget the TR SO2 Group 1 
allowances were allocated; or
    (B) If the State has a SIP revision approved under Sec. 52.39(e) or 
(f) covering such control period, include such TR SO2 Group 1 
allowances in the portion of the State SO2 Group 1 trading 
budget that may be allocated for such control period in accordance with 
such SIP revision.
    (ii) With regard to the TR SO2 Group 1 allowances that 
were not allocated from the Indian country new unit set-aside for such 
control period and that are not recorded, or that are deducted as an 
incorrect allocation, in accordance with paragraphs (c)(2) and (3) of 
this section for a recipient under paragraph (c)(1)(ii) of this 
paragraph, the Administrator will:
    (A) Transfer such TR SO2 Group 1 allowances to the new 
unit set-aside for such control period; or
    (B) If the State has a SIP revision approved under Sec. 52.39(e) or 
(f) covering such control period, include such TR SO2 Group 1 
allowances in the portion of the State SO2 Group 1 trading 
budget that may be allocated for such control period in accordance with 
such SIP revision.
    (iii) With regard to the TR SO2 Group 1 allowances that 
were allocated from the Indian country new unit set-aside for such 
control period and that are not recorded, or that are deducted as an 
incorrect allocation, in accordance with paragraphs (c)(2) and (3) of 
this section for a recipient under paragraph (c)(1)(ii) of this 
paragraph, the Administrator will transfer such TR SO2 Group 
1 allowances to the Indian country new unit set-aside for such control 
period.

[76 FR 48379, Aug. 8, 2011, as amended at 79 FR 71672, Dec. 3, 2014]



Sec. 97.612  TR SO[bdi2] Group 1 allowance allocations to new units.

    (a) For each control period in 2015 and thereafter and for the TR 
SO2 Group 1 units in each State, the Administrator will 
allocate TR SO2 Group 1 allowances to the TR SO2 
Group 1 units as follows:
    (1) The TR SO2 Group 1 allowances will be allocated to 
the following TR SO2 Group 1 units, except as provided in 
paragraph (a)(10) of this section:
    (i) TR SO2 Group 1 units that are not allocated an amount 
of TR SO2 Group 1 allowances in the notice of data 
availability issued under Sec. 97.611(a)(1);
    (ii) TR SO2 Group 1 units whose allocation of an amount 
of TR SO2 Group 1 allowances for such control period in the 
notice of data availability issued under Sec. 97.611(a)(1) is covered 
by Sec. 97.611(c)(2) or (3);
    (iii) TR SO2 Group 1 units that are allocated an amount 
of TR SO2 Group 1 allowances for such control period in the 
notice of data availability issued under Sec. 97.611(a)(1), which 
allocation is terminated for such control period pursuant to Sec. 
97.611(a)(2), and that operate during the control period immediately 
preceding such control period; or
    (iv) For purposes of paragraph (a)(9) of this section, TR 
SO2 Group 1 units under Sec. 97.611(c)(1)(ii) whose 
allocation of an amount of TR SO2 Group 1 allowances for such 
control period in the notice of data availability issued under

[[Page 459]]

Sec. 97.611(b)(1)(ii)(B) is covered by Sec. 97.611(c)(2) or (3).
    (2) The Administrator will establish a separate new unit set-aside 
for the State for each such control period. Each such new unit set-aside 
will be allocated TR SO2 Group 1 allowances in an amount 
equal to the applicable amount of tons of SO2 emissions as 
set forth in Sec. 97.610(a) and will be allocated additional TR 
SO2 Group 1 allowances (if any) in accordance with Sec. Sec. 
97.611(a)(2) and (c)(5) and paragraph (b)(10) of this section.
    (3) The Administrator will determine, for each TR SO2 
Group 1 unit described in paragraph (a)(1) of this section, an 
allocation of TR SO2 Group 1 allowances for the later of the 
following control periods and for each subsequent control period:
    (i) The control period in 2015;
    (ii) The first control period after the control period in which the 
TR SO2 Group 1 unit commences commercial operation;
    (iii) For a unit described in paragraph (a)(1)(ii) of this section, 
the first control period in which the TR SO2 Group 1 unit 
operates in the State after operating in another jurisdiction and for 
which the unit is not already allocated one or more TR SO2 
Group 1 allowances; and
    (iv) For a unit described in paragraph (a)(1)(iii) of this section, 
the first control period after the control period in which the unit 
resumes operation.
    (4)(i) The allocation to each TR SO2 annual unit 
described in paragraph (a)(1)(i) through (iii) of this section and for 
each control period described in paragraph (a)(3) of this section will 
be an amount equal to the unit's total tons of SO2 emissions 
during the immediately preceding control period.
    (ii) The Administrator will adjust the allocation amount in 
paragraph (a)(4)(i) in accordance with paragraphs (a)(5) through (7) and 
(12) of this section.
    (5) The Administrator will calculate the sum of the TR 
SO2 Group 1 allowances determined for all such TR 
SO2 Group 1 units under paragraph (a)(4)(i) of this section 
in the State for such control period.
    (6) If the amount of TR SO2 Group 1 allowances in the new 
unit set-aside for the State for such control period is greater than or 
equal to the sum under paragraph (a)(5) of this section, then the 
Administrator will allocate the amount of TR SO2 Group 1 
allowances determined for each such TR SO2 Group 1 unit under 
paragraph (a)(4)(i) of this section.
    (7) If the amount of TR SO2 Group 1 allowances in the new 
unit set-aside for the State for such control period is less than the 
sum under paragraph (a)(5) of this section, then the Administrator will 
allocate to each such TR SO2 Group 1 unit the amount of the 
TR SO2 Group 1 allowances determined under paragraph 
(a)(4)(i) of this section for the unit, multiplied by the amount of TR 
SO2 Group 1 allowances in the new unit set-aside for such 
control period, divided by the sum under paragraph (a)(5) of this 
section, and rounded to the nearest allowance.
    (8) The Administrator will notify the public, through the 
promulgation of the notices of data availability described in Sec. 
97.611(b)(1)(i) and (ii), of the amount of TR SO2 Group 1 
allowances allocated under paragraphs (a)(2) through (7) and (12) of 
this section for such control period to each TR SO2 Group 1 
unit eligible for such allocation.
    (9) If, after completion of the procedures under paragraphs (a)(5) 
through (8) of this section for such control period, any unallocated TR 
SO2 Group 1 allowances remain in the new unit set-aside for 
the State for such control period, the Administrator will allocate such 
TR SO2 Group 1 allowances as follows--
    (i) The Administrator will determine, for each unit described in 
paragraph (a)(1) of this section that commenced commercial operation 
during the period starting January 1 of the year before the year of such 
control period and ending November 30 of year of such control period, 
the positive difference (if any) between the unit's emissions during 
such control period and the amount of TR SO2 Group 1 
allowances referenced in the notice of data availability required under 
Sec. 97.611(b)(1)(ii) for the unit for such control period;

[[Page 460]]

    (ii) The Administrator will determine the sum of the positive 
differences determined under paragraph (a)(9)(i) of this section;
    (iii) If the amount of unallocated TR SO2 Group 1 
allowances remaining in the new unit set-aside for the State for such 
control period is greater than or equal to the sum determined under 
paragraph (a)(9)(ii) of this section, then the Administrator will 
allocate the amount of TR SO2 Group 1 allowances determined 
for each such TR SO2 Group 1 unit under paragraph (a)(9)(i) 
of this section; and
    (iv) If the amount of unallocated TR SO2 Group 1 
allowances remaining in the new unit set-aside for the State for such 
control period is less than the sum under paragraph (a)(9)(ii) of this 
section, then the Administrator will allocate to each such TR 
SO2 Group 1 unit the amount of the TR SO2 Group 1 
allowances determined under paragraph (a)(9)(i) of this section for the 
unit, multiplied by the amount of unallocated TR SO2 Group 1 
allowances remaining in the new unit set-aside for such control period, 
divided by the sum under paragraph (a)(9)(ii) of this section, and 
rounded to the nearest allowance.
    (10) If, after completion of the procedures under paragraphs (a)(9) 
and (12) of this section for such control period, any unallocated TR 
SO2 Group 1 allowances remain in the new unit set-aside for 
the State for such control period, the Administrator will allocate to 
each TR SO2 Group 1 unit that is in the State, is allocated 
an amount of TR SO2 Group 1 allowances in the notice of data 
availability issued under Sec. 97.611(a)(1), and continues to be 
allocated TR SO2 Group 1 allowances for such control period 
in accordance with Sec. 97.611(a)(2), an amount of TR SO2 
Group 1 allowances equal to the following: The total amount of such 
remaining unallocated TR SO2 Group 1 allowances in such new 
unit set-aside, multiplied by the unit's allocation under Sec. 
97.611(a) for such control period, divided by the remainder of the 
amount of tons in the applicable State SO2 Group 1 trading 
budget minus the sum of the amounts of tons in such new unit set-aside 
and the Indian country new unit set-aside for the State for such control 
period, and rounded to the nearest allowance.
    (11) The Administrator will notify the public, through the 
promulgation of the notices of data availability described in Sec. 
97.611(b)(1)(iii), (iv), and (v), of the amount of TR SO2 
Group 1 allowances allocated under paragraphs (a)(9), (10), and (12) of 
this section for such control period to each TR SO2 Group 1 
unit eligible for such allocation.
    (12)(i) Notwithstanding the requirements of paragraphs (a)(2) 
through (11) of this section, if the calculations of allocations of a 
new unit set-aside for a control period in a given year under paragraph 
(a)(7) of this section, paragraphs (a)(6) and (9)(iv) of this section, 
or paragraphs (a)(6), (9)(iii), and (10) of this section would otherwise 
result in total allocations of such new unit set-aside exceeding the 
total amount of such new unit set-aside, then the Administrator will 
adjust the results of the calculations under paragraph (a)(7), (9)(iv), 
or (10) of this section, as applicable, as follows. The Administrator 
will list the TR SO2 Group 1 units in descending order based 
on the amount of such units' allocations under paragraph (a)(7), 
(9)(iv), or (10) of this section, as applicable, and, in cases of equal 
allocation amounts, in alphabetical order of the relevant source's name 
and numerical order of the relevant unit's identification number, and 
will reduce each unit's allocation under paragraph (a)(7), (9)(iv), or 
(10) of this section, as applicable, by one TR SO2 Group 1 
allowance (but not below zero) in the order in which the units are 
listed and will repeat this reduction process as necessary, until the 
total allocations of such new unit set-aside equal the total amount of 
such new unit set-aside.
    (ii) Notwithstanding the requirements of paragraphs (a)(10) and (11) 
of this section, if the calculations of allocations of a new unit set-
aside for a control period in a given year under paragraphs (a)(6), 
(9)(iii), and (10) of this section would otherwise result in a total 
allocations of such new unit set-aside less than the total amount of 
such new unit set-aside, then the Administrator will adjust the results 
of the calculations under paragraph (a)(10) of this section, as follows. 
The

[[Page 461]]

Administrator will list the TR SO2 Group 1 units in 
descending order based on the amount of such units' allocations under 
paragraph (a)(10) of this section and, in cases of equal allocation 
amounts, in alphabetical order of the relevant source's name and 
numerical order of the relevant unit's identification number, and will 
increase each unit's allocation under paragraph (a)(10) of this section 
by one TR SO2 Group 1 allowance in the order in which the 
units are listed and will repeat this increase process as necessary, 
until the total allocations of such new unit set-aside equal the total 
amount of such new unit set-aside.
    (b) For each control period in 2015 and thereafter and for the TR 
SO2 Group 1 units located in Indian country within the 
borders of each State, the Administrator will allocate TR SO2 
Group 1 allowances to the TR SO2 Group 1 units as follows:
    (1) The TR SO2 Group 1 allowances will be allocated to 
the following TR SO2 Group 1 units, except as provided in 
paragraph (b)(10) of this section:
    (i) TR SO2 Group 1 units that are not allocated an amount 
of TR SO2 Group 1 allowances in the notice of data 
availability issued under Sec. 97.611(a)(1); or
    (ii) For purposes of paragraph (b)(9) of this section, TR 
SO2 Group 1 units under Sec. 97.611(c)(1)(ii) whose 
allocation of an amount of TR SO2 Group 1 allowances for such 
control period in the notice of data availability issued under Sec. 
97.611(b)(2)(ii)(B) is covered by Sec. 97.611(c)(2) or (3).
    (2) The Administrator will establish a separate Indian country new 
unit set-aside for the State for each such control period. Each such 
Indian country new unit set-aside will be allocated TR SO2 
Group 1 allowances in an amount equal to the applicable amount of tons 
of SO2 emissions as set forth in Sec. 97.610(a) and will be 
allocated additional TR SO2 Group 1 allowances (if any) in 
accordance with Sec. 97.611(c)(5).
    (3) The Administrator will determine, for each TR SO2 
Group 1 unit described in paragraph (b)(1) of this section, an 
allocation of TR SO2 Group 1 allowances for the later of the 
following control periods and for each subsequent control period:
    (i) The control period in 2015; and
    (ii) The first control period after the control period in which the 
TR SO2 Group 1 unit commences commercial operation.
    (4)(i) The allocation to each TR SO2 annual unit 
described in paragraph (b)(1)(i) of this section and for each control 
period described in paragraph (b)(3) of this section will be an amount 
equal to the unit's total tons of SO2 emissions during the 
immediately preceding control period.
    (ii) The Administrator will adjust the allocation amount in 
paragraph (b)(4)(i) in accordance with paragraphs (b)(5) through (7) and 
(12) of this section.
    (5) The Administrator will calculate the sum of the TR 
SO2 Group 1 allowances determined for all such TR 
SO2 Group 1 units under paragraph (b)(4)(i) of this section 
in Indian country within the borders of the State for such control 
period.
    (6) If the amount of TR SO2 Group 1 allowances in the 
Indian country new unit set-aside for the State for such control period 
is greater than or equal to the sum under paragraph (b)(5) of this 
section, then the Administrator will allocate the amount of TR 
SO2 Group 1 allowances determined for each such TR 
SO2 Group 1 unit under paragraph (b)(4)(i) of this section.
    (7) If the amount of TR SO2 Group 1 allowances in the 
Indian country new unit set-aside for the State for such control period 
is less than the sum under paragraph (b)(5) of this section, then the 
Administrator will allocate to each such TR SO2 Group 1 unit 
the amount of the TR SO2 Group 1 allowances determined under 
paragraph (b)(4)(i) of this section for the unit, multiplied by the 
amount of TR SO2 Group 1 allowances in the Indian country new 
unit set-aside for such control period, divided by the sum under 
paragraph (b)(5) of this section, and rounded to the nearest allowance.
    (8) The Administrator will notify the public, through the 
promulgation of the notices of data availability described in Sec. 
97.611(b)(2)(i) and (ii), of the amount of TR SO2 Group 1 
allowances allocated under paragraphs (b)(2) through (7) and (12) of 
this section for such control period to each TR SO2

[[Page 462]]

Group 1 unit eligible for such allocation.
    (9) If, after completion of the procedures under paragraphs (b)(5) 
through (8) of this section for such control period, any unallocated TR 
SO2 Group 1 allowances remain in the Indian country new unit 
set-aside for the State for such control period, the Administrator will 
allocate such TR SO2 Group 1 allowances as follows--
    (i) The Administrator will determine, for each unit described in 
paragraph (b)(1) of this section that commenced commercial operation 
during the period starting January 1 of the year before the year of such 
control period and ending November 30 of year of such control period, 
the positive difference (if any) between the unit's emissions during 
such control period and the amount of TR SO2 Group 1 
allowances referenced in the notice of data availability required under 
Sec. 97.611(b)(2)(ii) for the unit for such control period;
    (ii) The Administrator will determine the sum of the positive 
differences determined under paragraph (b)(9)(i) of this section;
    (iii) If the amount of unallocated TR SO2 Group 1 
allowances remaining in the Indian country new unit set-aside for the 
State for such control period is greater than or equal to the sum 
determined under paragraph (b)(9)(ii) of this section, then the 
Administrator will allocate the amount of TR SO2 Group 1 
allowances determined for each such TR SO2 Group 1 unit under 
paragraph (b)(9)(i) of this section; and
    (iv) If the amount of unallocated TR SO2 Group 1 
allowances remaining in the Indian country new unit set-aside for the 
State for such control period is less than the sum under paragraph 
(b)(9)(ii) of this section, then the Administrator will allocate to each 
such TR SO2 Group 1 unit the amount of the TR SO2 
Group 1 allowances determined under paragraph (b)(9)(i) of this section 
for the unit, multiplied by the amount of unallocated TR SO2 
Group 1 allowances remaining in the Indian country new unit set-aside 
for such control period, divided by the sum under paragraph (b)(9)(ii) 
of this section, and rounded to the nearest allowance.
    (10) If, after completion of the procedures under paragraphs (b)(9) 
and (12) of this section for such control period, any unallocated TR 
SO2 Group 1 allowances remain in the Indian country new unit 
set-aside for the State for such control period, the Administrator will:
    (i) Transfer such unallocated TR SO2 Group 1 allowances 
to the new unit set-aside for the State for such control period; or
    (ii) If the State has a SIP revision approved under Sec. 52.39(d), 
(e), or (f) of this chapter covering such control period, include such 
unallocated TR SO2 Group 1 allowances in the portion of the 
State SO2 Group 1 trading budget that may be allocated for 
such control period in accordance with such SIP revision.
    (11) The Administrator will notify the public, through the 
promulgation of the notices of data availability described in Sec. 
97.611(b)(2)(iii), (iv), and (v), of the amount of TR SO2 
Group 1 allowances allocated under paragraphs (b)(9), (10), and (12) for 
such control period to each TR SO2 Group 1 unit eligible for 
such allocation.
    (12)(i) Notwithstanding the requirements of paragraphs (b)(2) 
through (11) of this section, if the calculations of allocations of an 
Indian country new unit set-aside for a control period in a given year 
under paragraph (b)(7) of this section, paragraphs (b)(6) and (9)(iv) of 
this section, or paragraphs (b)(6), (9)(iii), and (10) of this section 
would otherwise result in total allocations of such Indian country new 
unit set-aside exceeding the total amount of such Indian country new 
unit set-aside, then the Administrator will adjust the results of the 
calculations under paragraph (b)(7), (9)(iv), or (10) of this section, 
as applicable, as follows. The Administrator will list the TR 
SO2 Group 1 units in descending order based on the amount of 
such units' allocations under paragraph (b)(7), (9)(iv), or (10) of this 
section, as applicable, and, in cases of equal allocation amounts, in 
alphabetical order of the relevant source's name and numerical order of 
the relevant unit's identification number, and will reduce each unit's 
allocation under paragraph (b)(7), (9)(iv), or (10) of this section, as 
applicable, by one TR SO2 Group 1 allowance (but not below 
zero) in the order in which the

[[Page 463]]

units are listed and will repeat this reduction process as necessary, 
until the total allocations of such Indian country new unit set-aside 
equal the total amount of such Indian country new unit set-aside.
    (ii) Notwithstanding the requirements of paragraphs (b)(10) and (11) 
of this section, if the calculations of allocations of an Indian country 
new unit set-aside for a control period in a given year under paragraphs 
(b)(6), (9)(iii), and (10) of this section would otherwise result in a 
total allocations of such Indian country new unit set-aside less than 
the total amount of such Indian country new unit set-aside, then the 
Administrator will adjust the results of the calculations under 
paragraph (b)(10) of this section, as follows. The Administrator will 
list the TR SO2 Group 1 units in descending order based on 
the amount of such units' allocations under paragraph (b)(10) of this 
section and, in cases of equal allocation amounts, in alphabetical order 
of the relevant source's name and numerical order of the relevant unit's 
identification number, and will increase each unit's allocation under 
paragraph (b)(10) of this section by one TR SO2 Group 1 
allowance in the order in which the units are listed and will repeat 
this increase process as necessary, until the total allocations of such 
Indian country new unit set-aside equal the total amount of such Indian 
country new unit set-aside.

[76 FR 48379, Aug. 8, 2011, as amended at 79 FR 71672, Dec. 3, 2014]



Sec. 97.613  Authorization of designated representative and alternate
designated representative.

    (a) Except as provided under Sec. 97.615, each TR SO2 
Group 1 source, including all TR SO2 Group 1 units at the 
source, shall have one and only one designated representative, with 
regard to all matters under the TR SO2 Group 1 Trading 
Program.
    (1) The designated representative shall be selected by an agreement 
binding on the owners and operators of the source and all TR 
SO2 Group 1 units at the source and shall act in accordance 
with the certification statement in Sec. 97.616(a)(4)(iii).
    (2) Upon and after receipt by the Administrator of a complete 
certificate of representation under Sec. 97.616:
    (i) The designated representative shall be authorized and shall 
represent and, by his or her representations, actions, inactions, or 
submissions, legally bind each owner and operator of the source and each 
TR SO2 Group 1 unit at the source in all matters pertaining 
to the TR SO2 Group 1 Trading Program, notwithstanding any 
agreement between the designated representative and such owners and 
operators; and
    (ii) The owners and operators of the source and each TR 
SO2 Group 1 unit at the source shall be bound by any decision 
or order issued to the designated representative by the Administrator 
regarding the source or any such unit.
    (b) Except as provided under Sec. 97.615, each TR SO2 
Group 1 source may have one and only one alternate designated 
representative, who may act on behalf of the designated representative. 
The agreement by which the alternate designated representative is 
selected shall include a procedure for authorizing the alternate 
designated representative to act in lieu of the designated 
representative.
    (1) The alternate designated representative shall be selected by an 
agreement binding on the owners and operators of the source and all TR 
SO2 Group 1 units at the source and shall act in accordance 
with the certification statement in Sec. 97.616(a)(4)(iii).
    (2) Upon and after receipt by the Administrator of a complete 
certificate of representation under Sec. 97.616,
    (i) The alternate designated representative shall be authorized;
    (ii) Any representation, action, inaction, or submission by the 
alternate designated representative shall be deemed to be a 
representation, action, inaction, or submission by the designated 
representative; and
    (iii) The owners and operators of the source and each TR 
SO2 Group 1 unit at the source shall be bound by any decision 
or order issued to the alternate designated representative by the 
Administrator regarding the source or any such unit.
    (c) Except in this section, Sec. 97.602, and Sec. Sec. 97.614 
through 97.618, whenever the

[[Page 464]]

term ``designated representative'' (as distinguished from the term 
``common designated representative'') is used in this subpart, the term 
shall be construed to include the designated representative or any 
alternate designated representative.



Sec. 97.614  Responsibilities of designated representative and 
alternate designated representative.

    (a) Except as provided under Sec. 97.618 concerning delegation of 
authority to make submissions, each submission under the TR 
SO2 Group 1 Trading Program shall be made, signed, and 
certified by the designated representative or alternate designated 
representative for each TR SO2 Group 1 source and TR 
SO2 Group 1 unit for which the submission is made. Each such 
submission shall include the following certification statement by the 
designated representative or alternate designated representative: ``I am 
authorized to make this submission on behalf of the owners and operators 
of the source or units for which the submission is made. I certify under 
penalty of law that I have personally examined, and am familiar with, 
the statements and information submitted in this document and all its 
attachments. Based on my inquiry of those individuals with primary 
responsibility for obtaining the information, I certify that the 
statements and information are to the best of my knowledge and belief 
true, accurate, and complete. I am aware that there are significant 
penalties for submitting false statements and information or omitting 
required statements and information, including the possibility of fine 
or imprisonment.''
    (b) The Administrator will accept or act on a submission made for a 
TR SO2 Group 1 source or a TR SO2 Group 1 unit 
only if the submission has been made, signed, and certified in 
accordance with paragraph (a) of this section and Sec. 97.618.



Sec. 97.615  Changing designated representative and alternate
designated representative; changes in owners and operators;
changes in units at the source.

    (a) Changing designated representative. The designated 
representative may be changed at any time upon receipt by the 
Administrator of a superseding complete certificate of representation 
under Sec. 97.616. Notwithstanding any such change, all 
representations, actions, inactions, and submissions by the previous 
designated representative before the time and date when the 
Administrator receives the superseding certificate of representation 
shall be binding on the new designated representative and the owners and 
operators of the TR SO2 Group 1 source and the TR 
SO2 Group 1 units at the source.
    (b) Changing alternate designated representative. The alternate 
designated representative may be changed at any time upon receipt by the 
Administrator of a superseding complete certificate of representation 
under Sec. 97.616. Notwithstanding any such change, all 
representations, actions, inactions, and submissions by the previous 
alternate designated representative before the time and date when the 
Administrator receives the superseding certificate of representation 
shall be binding on the new alternate designated representative, the 
designated representative, and the owners and operators of the TR 
SO2 Group 1 source and the TR SO2 Group 1 units at 
the source.
    (c) Changes in owners and operators. (1) In the event an owner or 
operator of a TR SO2 Group 1 source or a TR SO2 
Group 1 unit at the source is not included in the list of owners and 
operators in the certificate of representation under Sec. 97.616, such 
owner or operator shall be deemed to be subject to and bound by the 
certificate of representation, the representations, actions, inactions, 
and submissions of the designated representative and any alternate 
designated representative of the source or unit, and the decisions and 
orders of the Administrator, as if the owner or operator were included 
in such list.
    (2) Within 30 days after any change in the owners and operators of a 
TR SO2 Group 1 source or a TR SO2 Group 1 unit at 
the source, including the addition or removal of an owner or operator, 
the designated representative or any alternate designated representative 
shall submit a revision to the certificate of representation under Sec. 
97.616 amending the list of owners and operators to reflect the change.

[[Page 465]]

    (d) Changes in units at the source. Within 30 days of any change in 
which units are located at a TR SO2 Group 1 source (including 
the addition or removal of a unit), the designated representative or any 
alternate designated representative shall submit a certificate of 
representation under Sec. 97.616 amending the list of units to reflect 
the change.
    (1) If the change is the addition of a unit that operated (other 
than for purposes of testing by the manufacturer before initial 
installation) before being located at the source, then the certificate 
of representation shall identify, in a format prescribed by the 
Administrator, the entity from whom the unit was purchased or otherwise 
obtained (including name, address, telephone number, and facsimile 
number (if any)), the date on which the unit was purchased or otherwise 
obtained, and the date on which the unit became located at the source.
    (2) If the change is the removal of a unit, then the certificate of 
representation shall identify, in a format prescribed by the 
Administrator, the entity to which the unit was sold or that otherwise 
obtained the unit (including name, address, telephone number, and 
facsimile number (if any)), the date on which the unit was sold or 
otherwise obtained, and the date on which the unit became no longer 
located at the source.



Sec. 97.616  Certificate of representation.

    (a) A complete certificate of representation for a designated 
representative or an alternate designated representative shall include 
the following elements in a format prescribed by the Administrator:
    (1) Identification of the TR SO2 Group 1 source, and each 
TR SO2 Group 1 unit at the source, for which the certificate 
of representation is submitted, including source name, source category 
and NAICS code (or, in the absence of a NAICS code, an equivalent code), 
State, plant code, county, latitude and longitude, unit identification 
number and type, identification number and nameplate capacity (in MWe, 
rounded to the nearest tenth) of each generator served by each such 
unit, actual or projected date of commencement of commercial operation, 
and a statement of whether such source is located in Indian Country. If 
a projected date of commencement of commercial operation is provided, 
the actual date of commencement of commercial operation shall be 
provided when such information becomes available.
    (2) The name, address, e-mail address (if any), telephone number, 
and facsimile transmission number (if any) of the designated 
representative and any alternate designated representative.
    (3) A list of the owners and operators of the TR SO2 
Group 1 source and of each TR SO2 Group 1 unit at the source.
    (4) The following certification statements by the designated 
representative and any alternate designated representative--
    (i) ``I certify that I was selected as the designated representative 
or alternate designated representative, as applicable, by an agreement 
binding on the owners and operators of the source and each TR 
SO2 Group 1 unit at the source.''
    (ii) ``I certify that I have all the necessary authority to carry 
out my duties and responsibilities under the TR SO2 Group 1 
Trading Program on behalf of the owners and operators of the source and 
of each TR SO2 Group 1 unit at the source and that each such 
owner and operator shall be fully bound by my representations, actions, 
inactions, or submissions and by any decision or order issued to me by 
the Administrator regarding the source or unit.''
    (iii) ``Where there are multiple holders of a legal or equitable 
title to, or a leasehold interest in, a TR SO2 Group 1 unit, 
or where a utility or industrial customer purchases power from a TR 
SO2 Group 1 unit under a life-of-the-unit, firm power 
contractual arrangement, I certify that: I have given a written notice 
of my selection as the `designated representative' or `alternate 
designated representative', as applicable, and of the agreement by which 
I was selected to each owner and operator of the source and of each TR 
SO2 Group 1 unit at the source; and TR SO2 Group 1 
allowances and proceeds of transactions involving TR SO2 
Group 1 allowances will be deemed to be held or

[[Page 466]]

distributed in proportion to each holder's legal, equitable, leasehold, 
or contractual reservation or entitlement, except that, if such multiple 
holders have expressly provided for a different distribution of TR 
SO2 Group 1 allowances by contract, TR SO2 Group 1 
allowances and proceeds of transactions involving TR SO2 
Group 1 allowances will be deemed to be held or distributed in 
accordance with the contract.''
    (5) The signature of the designated representative and any alternate 
designated representative and the dates signed.
    (b) Unless otherwise required by the Administrator, documents of 
agreement referred to in the certificate of representation shall not be 
submitted to the Administrator. The Administrator shall not be under any 
obligation to review or evaluate the sufficiency of such documents, if 
submitted.



Sec. 97.617  Objections concerning designated representative and
alternate designated representative.

    (a) Once a complete certificate of representation under Sec. 97.616 
has been submitted and received, the Administrator will rely on the 
certificate of representation unless and until a superseding complete 
certificate of representation under Sec. 97.616 is received by the 
Administrator.
    (b) Except as provided in paragraph (a) of this section, no 
objection or other communication submitted to the Administrator 
concerning the authorization, or any representation, action, inaction, 
or submission, of a designated representative or alternate designated 
representative shall affect any representation, action, inaction, or 
submission of the designated representative or alternate designated 
representative or the finality of any decision or order by the 
Administrator under the TR SO2 Group 1 Trading Program.
    (c) The Administrator will not adjudicate any private legal dispute 
concerning the authorization or any representation, action, inaction, or 
submission of any designated representative or alternate designated 
representative, including private legal disputes concerning the proceeds 
of TR SO2 Group 1 allowance transfers.



Sec. 97.618  Delegation by designated representative and alternate
designated representative.

    (a) A designated representative may delegate, to one or more natural 
persons, his or her authority to make an electronic submission to the 
Administrator provided for or required under this subpart.
    (b) An alternate designated representative may delegate, to one or 
more natural persons, his or her authority to make an electronic 
submission to the Administrator provided for or required under this 
subpart.
    (c) In order to delegate authority to a natural person to make an 
electronic submission to the Administrator in accordance with paragraph 
(a) or (b) of this section, the designated representative or alternate 
designated representative, as appropriate, must submit to the 
Administrator a notice of delegation, in a format prescribed by the 
Administrator, that includes the following elements:
    (1) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of such designated representative 
or alternate designated representative;
    (2) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of each such natural person 
(referred to in this section as an ``agent'');
    (3) For each such natural person, a list of the type or types of 
electronic submissions under paragraph (a) or (b) of this section for 
which authority is delegated to him or her; and
    (4) The following certification statements by such designated 
representative or alternate designated representative:
    (i) ``I agree that any electronic submission to the Administrator 
that is made by an agent identified in this notice of delegation and of 
a type listed for such agent in this notice of delegation and that is 
made when I am a designated representative or alternate designated 
representative, as appropriate, and before this notice of delegation is 
superseded by another notice of delegation under 40 CFR 97.618(d) shall 
be deemed to be an electronic submission by me.''

[[Page 467]]

    (ii) ``Until this notice of delegation is superseded by another 
notice of delegation under 40 CFR 97.618(d), I agree to maintain an e-
mail account and to notify the Administrator immediately of any change 
in my e-mail address unless all delegation of authority by me under 40 
CFR 97.618 is terminated.''.
    (d) A notice of delegation submitted under paragraph (c) of this 
section shall be effective, with regard to the designated representative 
or alternate designated representative identified in such notice, upon 
receipt of such notice by the Administrator and until receipt by the 
Administrator of a superseding notice of delegation submitted by such 
designated representative or alternate designated representative, as 
appropriate. The superseding notice of delegation may replace any 
previously identified agent, add a new agent, or eliminate entirely any 
delegation of authority.
    (e) Any electronic submission covered by the certification in 
paragraph (c)(4)(i) of this section and made in accordance with a notice 
of delegation effective under paragraph (d) of this section shall be 
deemed to be an electronic submission by the designated representative 
or alternate designated representative submitting such notice of 
delegation.



Sec. 97.619  [Reserved]



Sec. 97.620  Establishment of compliance accounts, assurance accounts,
and general accounts.

    (a) Compliance accounts. Upon receipt of a complete certificate of 
representation under Sec. 97.616, the Administrator will establish a 
compliance account for the TR SO2 Group 1 source for which 
the certificate of representation was submitted, unless the source 
already has a compliance account. The designated representative and any 
alternate designated representative of the source shall be the 
authorized account representative and the alternate authorized account 
representative respectively of the compliance account.
    (b) Assurance accounts. The Administrator will establish assurance 
accounts for certain owners and operators and States in accordance with 
Sec. 97.625(b)(3).
    (c) General accounts. (1) Application for general account. (i) Any 
person may apply to open a general account, for the purpose of holding 
and transferring TR SO2 Group 1 allowances, by submitting to 
the Administrator a complete application for a general account. Such 
application shall designate one and only one authorized account 
representative and may designate one and only one alternate authorized 
account representative who may act on behalf of the authorized account 
representative.
    (A) The authorized account representative and alternate authorized 
account representative shall be selected by an agreement binding on the 
persons who have an ownership interest with respect to TR SO2 
Group 1 allowances held in the general account.
    (B) The agreement by which the alternate authorized account 
representative is selected shall include a procedure for authorizing the 
alternate authorized account representative to act in lieu of the 
authorized account representative.
    (ii) A complete application for a general account shall include the 
following elements in a format prescribed by the Administrator:
    (A) Name, mailing address, e-mail address (if any), telephone 
number, and facsimile transmission number (if any) of the authorized 
account representative and any alternate authorized account 
representative;
    (B) An identifying name for the general account;
    (C) A list of all persons subject to a binding agreement for the 
authorized account representative and any alternate authorized account 
representative to represent their ownership interest with respect to the 
TR SO2 Group 1 allowances held in the general account;
    (D) The following certification statement by the authorized account 
representative and any alternate authorized account representative: ``I 
certify that I was selected as the authorized account representative or 
the alternate authorized account representative, as applicable, by an 
agreement that is binding on all persons who have an ownership interest 
with respect to TR SO2 Group 1 allowances held in the general 
account. I certify that I have all

[[Page 468]]

the necessary authority to carry out my duties and responsibilities 
under the TR SO2 Group 1 Trading Program on behalf of such 
persons and that each such person shall be fully bound by my 
representations, actions, inactions, or submissions and by any decision 
or order issued to me by the Administrator regarding the general 
account.''
    (E) The signature of the authorized account representative and any 
alternate authorized account representative and the dates signed.
    (iii) Unless otherwise required by the Administrator, documents of 
agreement referred to in the application for a general account shall not 
be submitted to the Administrator. The Administrator shall not be under 
any obligation to review or evaluate the sufficiency of such documents, 
if submitted.
    (2) Authorization of authorized account representative and alternate 
authorized account representative. (i) Upon receipt by the Administrator 
of a complete application for a general account under paragraph (b)(1) 
of this section, the Administrator will establish a general account for 
the person or persons for whom the application is submitted, and upon 
and after such receipt by the Administrator:
    (A) The authorized account representative of the general account 
shall be authorized and shall represent and, by his or her 
representations, actions, inactions, or submissions, legally bind each 
person who has an ownership interest with respect to TR SO2 
Group 1 allowances held in the general account in all matters pertaining 
to the TR SO2 Group 1 Trading Program, notwithstanding any 
agreement between the authorized account representative and such person.
    (B) Any alternate authorized account representative shall be 
authorized, and any representation, action, inaction, or submission by 
any alternate authorized account representative shall be deemed to be a 
representation, action, inaction, or submission by the authorized 
account representative.
    (C) Each person who has an ownership interest with respect to TR 
SO2 Group 1 allowances held in the general account shall be 
bound by any decision or order issued to the authorized account 
representative or alternate authorized account representative by the 
Administrator regarding the general account.
    (ii) Except as provided in paragraph (c)(5) of this section 
concerning delegation of authority to make submissions, each submission 
concerning the general account shall be made, signed, and certified by 
the authorized account representative or any alternate authorized 
account representative for the persons having an ownership interest with 
respect to TR SO2 Group 1 allowances held in the general 
account. Each such submission shall include the following certification 
statement by the authorized account representative or any alternate 
authorized account representative: ``I am authorized to make this 
submission on behalf of the persons having an ownership interest with 
respect to the TR SO2 Group 1 allowances held in the general 
account. I certify under penalty of law that I have personally examined, 
and am familiar with, the statements and information submitted in this 
document and all its attachments. Based on my inquiry of those 
individuals with primary responsibility for obtaining the information, I 
certify that the statements and information are to the best of my 
knowledge and belief true, accurate, and complete. I am aware that there 
are significant penalties for submitting false statements and 
information or omitting required statements and information, including 
the possibility of fine or imprisonment.''
    (iii) Except in this section, whenever the term ``authorized account 
representative'' is used in this subpart, the term shall be construed to 
include the authorized account representative or any alternate 
authorized account representative.
    (3) Changing authorized account representative and alternate 
authorized account representative; changes in persons with ownership 
interest. (i) The authorized account representative of a general account 
may be changed at any time upon receipt by the Administrator of a 
superseding complete application for a general account under paragraph 
(c)(1) of this section. Notwithstanding any such change, all 
representations, actions, inactions, and submissions by the previous 
authorized

[[Page 469]]

account representative before the time and date when the Administrator 
receives the superseding application for a general account shall be 
binding on the new authorized account representative and the persons 
with an ownership interest with respect to the TR SO2 Group 1 
allowances in the general account.
    (ii) The alternate authorized account representative of a general 
account may be changed at any time upon receipt by the Administrator of 
a superseding complete application for a general account under paragraph 
(c)(1) of this section. Notwithstanding any such change, all 
representations, actions, inactions, and submissions by the previous 
alternate authorized account representative before the time and date 
when the Administrator receives the superseding application for a 
general account shall be binding on the new alternate authorized account 
representative, the authorized account representative, and the persons 
with an ownership interest with respect to the TR SO2 Group 1 
allowances in the general account.
    (iii)(A) In the event a person having an ownership interest with 
respect to TR SO2 Group 1 allowances in the general account 
is not included in the list of such persons in the application for a 
general account, such person shall be deemed to be subject to and bound 
by the application for a general account, the representation, actions, 
inactions, and submissions of the authorized account representative and 
any alternate authorized account representative of the account, and the 
decisions and orders of the Administrator, as if the person were 
included in such list.
    (B) Within 30 days after any change in the persons having an 
ownership interest with respect to SO2 Group 1 allowances in 
the general account, including the addition or removal of a person, the 
authorized account representative or any alternate authorized account 
representative shall submit a revision to the application for a general 
account amending the list of persons having an ownership interest with 
respect to the TR SO2 Group 1 allowances in the general 
account to include the change.
    (4) Objections concerning authorized account representative and 
alternate authorized account representative. (i) Once a complete 
application for a general account under paragraph (c)(1) of this section 
has been submitted and received, the Administrator will rely on the 
application unless and until a superseding complete application for a 
general account under paragraph (b)(1) of this section is received by 
the Administrator.
    (ii) Except as provided in paragraph (c)(4)(i) of this section, no 
objection or other communication submitted to the Administrator 
concerning the authorization, or any representation, action, inaction, 
or submission of the authorized account representative or any alternate 
authorized account representative of a general account shall affect any 
representation, action, inaction, or submission of the authorized 
account representative or any alternate authorized account 
representative or the finality of any decision or order by the 
Administrator under the TR SO2 Group 1 Trading Program.
    (iii) The Administrator will not adjudicate any private legal 
dispute concerning the authorization or any representation, action, 
inaction, or submission of the authorized account representative or any 
alternate authorized account representative of a general account, 
including private legal disputes concerning the proceeds of TR 
SO2 Group 1 allowance transfers.
    (5) Delegation by authorized account representative and alternate 
authorized account representative. (i) An authorized account 
representative of a general account may delegate, to one or more natural 
persons, his or her authority to make an electronic submission to the 
Administrator provided for or required under this subpart.
    (ii) An alternate authorized account representative of a general 
account may delegate, to one or more natural persons, his or her 
authority to make an electronic submission to the Administrator provided 
for or required under this subpart.
    (iii) In order to delegate authority to a natural person to make an 
electronic submission to the Administrator in accordance with paragraph 
(c)(5)(i) or (ii) of this section, the authorized account

[[Page 470]]

representative or alternate authorized account representative, as 
appropriate, must submit to the Administrator a notice of delegation, in 
a format prescribed by the Administrator, that includes the following 
elements:
    (A) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of such authorized account 
representative or alternate authorized account representative;
    (B) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of each such natural person 
(referred to in this section as an ``agent'');
    (C) For each such natural person, a list of the type or types of 
electronic submissions under paragraph (c)(5)(i) or (ii) of this section 
for which authority is delegated to him or her;
    (D) The following certification statement by such authorized account 
representative or alternate authorized account representative: ``I agree 
that any electronic submission to the Administrator that is made by an 
agent identified in this notice of delegation and of a type listed for 
such agent in this notice of delegation and that is made when I am an 
authorized account representative or alternate authorized 
representative, as appropriate, and before this notice of delegation is 
superseded by another notice of delegation under 40 CFR 97.620(c)(5)(iv) 
shall be deemed to be an electronic submission by me.''; and
    (E) The following certification statement by such authorized account 
representative or alternate authorized account representative: ``Until 
this notice of delegation is superseded by another notice of delegation 
under 40 CFR 97.620(c)(5)(iv), I agree to maintain an e-mail account and 
to notify the Administrator immediately of any change in my e-mail 
address unless all delegation of authority by me under 40 CFR 
97.620(c)(5) is terminated.''.
    (iv) A notice of delegation submitted under paragraph (c)(5)(iii) of 
this section shall be effective, with regard to the authorized account 
representative or alternate authorized account representative identified 
in such notice, upon receipt of such notice by the Administrator and 
until receipt by the Administrator of a superseding notice of delegation 
submitted by such authorized account representative or alternate 
authorized account representative, as appropriate. The superseding 
notice of delegation may replace any previously identified agent, add a 
new agent, or eliminate entirely any delegation of authority.
    (v) Any electronic submission covered by the certification in 
paragraph (c)(5)(iii)(D) of this section and made in accordance with a 
notice of delegation effective under paragraph (c)(5)(iv) of this 
section shall be deemed to be an electronic submission by the designated 
representative or alternate designated representative submitting such 
notice of delegation.
    (6) Closing a general account. (i) The authorized account 
representative or alternate authorized account representative of a 
general account may submit to the Administrator a request to close the 
account. Such request shall include a correctly submitted TR 
SO2 Group 1 allowance transfer under Sec. 97.622 for any TR 
SO2 Group 1 allowances in the account to one or more other 
Allowance Management System accounts.
    (ii) If a general account has no TR SO2 Group 1 allowance 
transfers to or from the account for a 12-month period or longer and 
does not contain any TR SO2 Group 1 allowances, the 
Administrator may notify the authorized account representative for the 
account that the account will be closed after 30 days after the notice 
is sent. The account will be closed after the 30-day period unless, 
before the end of the 30-day period, the Administrator receives a 
correctly submitted TR SO2 Group 1 allowance transfer under 
Sec. 97.622 to the account or a statement submitted by the authorized 
account representative or alternate authorized account representative 
demonstrating to the satisfaction of the Administrator good cause as to 
why the account should not be closed.
    (d) Account identification. The Administrator will assign a unique 
identifying number to each account established under paragraph (a), (b), 
or (c) of this section.

[[Page 471]]

    (e) Responsibilities of authorized account representative and 
alternate authorized account representative. After the establishment of 
a compliance account or general account, the Administrator will accept 
or act on a submission pertaining to the account, including, but not 
limited to, submissions concerning the deduction or transfer of TR 
SO2 Group 1 allowances in the account, only if the submission 
has been made, signed, and certified in accordance with Sec. Sec. 
97.614(a) and 97.618 or paragraphs (c)(2)(ii) and (c)(5) of this 
section.



Sec. 97.621  Recordation of TR SO[bdi2] Group 1 allowance allocations
and auction results.

    (a) By November 7, 2011, the Administrator will record in each TR 
SO2 Group 1 source's compliance account the TR SO2 
Group 1 allowances allocated to the TR SO2 Group 1 units at 
the source in accordance with Sec. 97.611(a) for the control period in 
2015.
    (b) By November 7, 2011, the Administrator will record in each TR 
SO2 Group 1 source's compliance account the TR SO2 
Group 1 allowances allocated to the TR SO2 Group 1 units at 
the source in accordance with Sec. 97.611(a) for the control period in 
2016, unless the State in which the source is located notifies the 
Administrator in writing by October 17, 2011 of the State's intent to 
submit to the Administrator a complete SIP revision by April 1, 2015 
meeting the requirements of Sec. 52.39(d)(1) through (4) of this 
chapter.
    (1) If, by April 1, 2015, the State does not submit to the 
Administrator such complete SIP revision, the Administrator will record 
by April 15, 2015 in each TR SO2 Group 1 source's compliance 
account the TR SO2 Group 1 allowances allocated to the TR 
SO2 Group 1 units at the source in accordance with Sec. 
97.611(a) for the control period in 2016.
    (2) If the State submits to the Administrator by April 1, 2015, and 
the Administrator approves by October 1, 2015, such complete SIP 
revision, the Administrator will record by October 1, 2015 in each TR 
SO2 Group 1 source's compliance account the TR SO2 
Group 1 allowances allocated to the TR SO2 Group 1 units at 
the source as provided in such approved, complete SIP revision for the 
control period in 2016.
    (3) If the State submits to the Administrator by April 1, 2015, and 
the Administrator does not approve by October 1, 2015, such complete SIP 
revision, the Administrator will record by October 1, 2015 in each TR 
SO2 Group 1 source's compliance account the TR SO2 
Group 1 allowances allocated to the TR SO2 Group 1 units at 
the source in accordance with Sec. 97.611(a) for the control period in 
2016.
    (c) By July 1, 2016, the Administrator will record in each TR 
SO2 Group 1 source's compliance account the TR SO2 
Group 1 allowances allocated to the TR SO2 Group 1 units at 
the source, or in each appropriate Allowance Management System account 
the TR SO2 Group 1 allowances auctioned to TR SO2 
Group 1 units, in accordance with Sec. 97.611(a), or with a SIP 
revision approved under Sec. 52.39(e) or (f) of this chapter, for the 
control period in 2017 and 2018.
    (d) By July 1, 2017, the Administrator will record in each TR 
SO2 Group 1 source's compliance account the TR SO2 
Group 1 allowances allocated to the TR SO2 Group 1 units at 
the source, or in each appropriate Allowance Management System account 
the TR SO2 Group 1 allowances auctioned to TR SO2 
Group 1 units, in accordance with Sec. 97.611(a), or with a SIP 
revision approved under Sec. 52.39(e) or (f) of this chapter, for the 
control period in 2019 and 2020.
    (e) By July 1, 2018, the Administrator will record in each TR 
SO2 Group 1 source's compliance account the TR SO2 
Group 1 allowances allocated to the TR SO2 Group 1 units at 
the source, or in each appropriate Allowance Management System account 
the TR SO2 Group 1 allowances auctioned to TR SO2 
Group 1 units, in accordance with Sec. 97.611(a), or with a SIP 
revision approved under Sec. 52.39(e) or (f) of this chapter, for the 
control period in 2021 and 2022.
    (f) By July 1, 2019 and July 1 of each year thereafter, the 
Administrator will record in each TR SO2 Group 1 source's 
compliance account the TR SO2 Group 1 allowances allocated to 
the TR SO2 Group 1 units at the source, or in each

[[Page 472]]

appropriate Allowance Management System account the TR SO2 
Group 1 allowances auctioned to TR SO2 Group 1 units, in 
accordance with Sec. 97.611(a), or with a SIP revision approved under 
Sec. 52.39(e) and (f) of this chapter, for the control period in the 
fourth year after the year of the applicable recordation deadline under 
this paragraph.
    (g) By August 1, 2015 and August 1 of each year thereafter, the 
Administrator will record in each TR SO2 Group 1 source's 
compliance account the TR SO2 Group 1 allowances allocated to 
the TR SO2 Group 1 units at the source, or in each 
appropriate Allowance Management System account the TR SO2 
Group 1 allowances auctioned to TR SO2 Group 1 units, in 
accordance with Sec. 97.612(a)(2) through (8) and (12), or with a SIP 
revision approved under Sec. 52.39(e) and (f) of this chapter, for the 
control period in the year of the applicable recordation deadline under 
this paragraph.
    (h) By August 1, 2015 and August 1 of each year thereafter, the 
Administrator will record in each TR SO2 Group 1 source's 
compliance account the TR SO2 Group 1 allowances allocated to 
the TR SO2 Group 1 units at the source in accordance with 
Sec. 97.612(b)(2) through (8) and (12) for the control period in the 
year of the applicable recordation deadline under this paragraph.
    (i) By February 15, 2016 and February 15 of each year thereafter, 
the Administrator will record in each TR SO2 Group 1 source's 
compliance account the TR SO2 Group 1 allowances allocated to 
the TR SO2 Group 1 units at the source in accordance with 
Sec. 97.612(a)(9) through (12), for the control period in the year 
before the year of the applicable recordation deadline under this 
paragraph.
    (j) By the date on which any allocation or auction results, other 
than an allocation or auction results described in paragraphs (a) 
through (i) of this section, of TR SO2 Group 1 allowances to 
a recipient is made by or are submitted to the Administrator in 
accordance with Sec. 97.611 or Sec. 97.612 or with a SIP revision 
approved under Sec. 52.39(e) or (f) of this chapter, the Administrator 
will record such allocation or auction results in the appropriate 
Allowance Management System account.
    (k) When recording the allocation or auction of TR SO2 
Group 1 allowances to a TR SO2 Group 1 unit or other entity 
in an Allowance Management System account, the Administrator will assign 
each TR SO2 Group 1 allowance a unique identification number 
that will include digits identifying the year of the control period for 
which the TR SO2 Group 1 allowance is allocated or auctioned.

[76 FR 48379, Aug. 8, 2011, as amended at 79 FR 71672, Dec. 3, 2014]



Sec. 97.622  Submission of TR SO[bdi2] Group 1 allowance transfers.

    (a) An authorized account representative seeking recordation of a TR 
SO2 Group 1 allowance transfer shall submit the transfer to 
the Administrator.
    (b) A TR SO2 Group 1 allowance transfer shall be 
correctly submitted if:
    (1) The transfer includes the following elements, in a format 
prescribed by the Administrator:
    (i) The account numbers established by the Administrator for both 
the transferor and transferee accounts;
    (ii) The serial number of each TR SO2 Group 1 allowance 
that is in the transferor account and is to be transferred; and
    (iii) The name and signature of the authorized account 
representative of the transferor account and the date signed; and
    (2) When the Administrator attempts to record the transfer, the 
transferor account includes each TR SO2 Group 1 allowance 
identified by serial number in the transfer.



Sec. 97.623  Recordation of TR SO[bdi2] Group 1 allowance transfers.

    (a) Within 5 business days (except as provided in paragraph (b) of 
this section) of receiving a TR SO2 Group 1 allowance 
transfer that is correctly submitted under Sec. 97.622, the 
Administrator will record a TR SO2 Group 1 allowance transfer 
by moving each TR SO2 Group 1 allowance from the transferor 
account to the transferee account as specified in the transfer.
    (b) A TR SO2 Group 1 allowance transfer to or from a 
compliance account that is submitted for recordation

[[Page 473]]

after the allowance transfer deadline for a control period and that 
includes any TR SO2 Group 1 allowances allocated for any 
control period before such allowance transfer deadline will not be 
recorded until after the Administrator completes the deductions from 
such compliance account under Sec. 97.624 for the control period 
immediately before such allowance transfer deadline.
    (c) Where a TR SO2 Group 1 allowance transfer is not 
correctly submitted under Sec. 97.622, the Administrator will not 
record such transfer.
    (d) Within 5 business days of recordation of a TR SO2 
Group 1 allowance transfer under paragraphs (a) and (b) of the section, 
the Administrator will notify the authorized account representatives of 
both the transferor and transferee accounts.
    (e) Within 10 business days of receipt of a TR SO2 Group 
1 allowance transfer that is not correctly submitted under Sec. 97.622, 
the Administrator will notify the authorized account representatives of 
both accounts subject to the transfer of:
    (1) A decision not to record the transfer, and
    (2) The reasons for such non-recordation.



Sec. 97.624  Compliance with TR SO[bdi2] Group 1 emissions limitation.

    (a) Availability for deduction for compliance. TR SO2 
Group 1 allowances are available to be deducted for compliance with a 
source's TR SO2 Group 1 emissions limitation for a control 
period in a given year only if the TR SO2 Group 1 allowances:
    (1) Were allocated for such control period or a control period in a 
prior year; and
    (2) Are held in the source's compliance account as of the allowance 
transfer deadline for such control period.
    (b) Deductions for compliance. After the recordation, in accordance 
with Sec. 97.623, of TR SO2 Group 1 allowance transfers 
submitted by the allowance transfer deadline for a control period in a 
given year, the Administrator will deduct from each source's compliance 
account TR SO2 Group 1 allowances available under paragraph 
(a) of this section in order to determine whether the source meets the 
TR SO2 Group 1 emissions limitation for such control period, 
as follows:
    (1) Until the amount of TR SO2 Group 1 allowances 
deducted equals the number of tons of total SO2 emissions 
from all TR SO2 Group 1 units at the source for such control 
period; or
    (2) If there are insufficient TR SO2 Group 1 allowances 
to complete the deductions in paragraph (b)(1) of this section, until no 
more TR SO2 Group 1 allowances available under paragraph (a) 
of this section remain in the compliance account.
    (c)(1) Identification of TR SO2 Group 1 allowances by serial number. 
The authorized account representative for a source's compliance account 
may request that specific TR SO2 Group 1 allowances, 
identified by serial number, in the compliance account be deducted for 
emissions or excess emissions for a control period in a given year in 
accordance with paragraph (b) or (d) of this section. In order to be 
complete, such request shall be submitted to the Administrator by the 
allowance transfer deadline for such control period and include, in a 
format prescribed by the Administrator, the identification of the TR 
SO2 Group 1 source and the appropriate serial numbers.
    (2) First-in, first-out. The Administrator will deduct TR 
SO2 Group 1 allowances under paragraph (b) or (d) of this 
section from the source's compliance account in accordance with a 
complete request under paragraph (c)(1) of this section or, in the 
absence of such request or in the case of identification of an 
insufficient amount of TR SO2 Group 1 allowances in such 
request, on a first-in, first-out accounting basis in the following 
order:
    (i) Any TR SO2 Group 1 allowances that were allocated to 
the units at the source and not transferred out of the compliance 
account, in the order of recordation; and then
    (ii) Any TR SO2 Group 1 allowances that were allocated to 
any unit and transferred to and recorded in the compliance account 
pursuant to this subpart, in the order of recordation.
    (d) Deductions for excess emissions. After making the deductions for 
compliance under paragraph (b) of this section for a control period in a 
year in which the TR SO2 Group 1 source has

[[Page 474]]

excess emissions, the Administrator will deduct from the source's 
compliance account an amount of TR SO2 Group 1 allowances, 
allocated for a control period in a prior year or the control period in 
the year of the excess emissions or in the immediately following year, 
equal to two times the number of tons of the source's excess emissions.
    (e) Recordation of deductions. The Administrator will record in the 
appropriate compliance account all deductions from such an account under 
paragraphs (b) and (d) of this section.



Sec. 97.625  Compliance with TR SO[bdi2] Group 1 assurance provisions.

    (a) Availability for deduction. TR SO2 Group 1 allowances 
are available to be deducted for compliance with the TR SO2 
Group 1 assurance provisions for a control period in a given year by the 
owners and operators of a group of one or more TR SO2 Group 1 
sources and units in a State (and Indian country within the borders of 
such State) only if the TR SO2 Group 1 allowances:
    (1) Were allocated for a control period in a prior year or the 
control period in the given year or in the immediately following year; 
and
    (2) Are held in the assurance account, established by the 
Administrator for such owners and operators of such group of TR 
SO2 Group 1 sources and units in such State (and Indian 
country within the borders of such State) under paragraph (b)(3) of this 
section, as of the deadline established in paragraph (b)(4) of this 
section.
    (b) Deductions for compliance. The Administrator will deduct TR 
SO2 Group 1 allowances available under paragraph (a) of this 
section for compliance with the TR SO2 Group 1 assurance 
provisions for a State for a control period in a given year in 
accordance with the following procedures:
    (1) By June 1, 2018 and June 1 of each year thereafter, the 
Administrator will:
    (i) Calculate, for each State (and Indian country within the borders 
of such State), the total SO2 emissions from all TR 
SO2 Group 1 units at TR SO2 Group 1 sources in the 
State (and Indian country within the borders of such State) during the 
control period in the year before the year of this calculation deadline 
and the amount, if any, by which such total SO2 emissions 
exceed the State assurance level as described in Sec. 
97.606(c)(2)(iii); and
    (ii) Promulgate a notice of data availability of the results of the 
calculations required in paragraph (b)(1)(i) of this section, including 
separate calculations of the SO2 emissions from each TR 
SO2 Group 1 source.
    (2) For each notice of data availability required in paragraph 
(b)(1)(ii) of this section and for any State (and Indian country within 
the borders of such State) identified in such notice as having TR 
SO2 Group 1 units with total SO2 emissions 
exceeding the State assurance level for a control period in a given 
year, as described in Sec. 97.606(c)(2)(iii):
    (i) By July 1 immediately after the promulgation of such notice, the 
designated representative of each TR SO2 Group 1 source in 
each such State (and Indian country within the borders of such State) 
shall submit a statement, in a format prescribed by the Administrator, 
providing for each TR SO2 Group 1 unit (if any) at the source 
that operates during, but is not allocated an amount of TR 
SO2 Group 1 allowances for, such control period, the unit's 
allowable SO2 emission rate for such control period and, if 
such rate is expressed in lb per mmBtu, the unit's heat rate.
    (ii) By August 1 immediately after the promulgation of such notice, 
the Administrator will calculate, for each such State (and Indian 
country within the borders of such State) and such control period and 
each common designated representative for such control period for a 
group of one or more TR SO2 Group 1 sources and units in the 
State (and Indian country within the borders of such State), the common 
designated representative's share of the total SO2 emissions 
from all TR SO2 Group 1 units at TR SO2 Group 1 
sources in the State (and Indian country within the borders of such 
State), the common designated representative's assurance level, and the 
amount (if any) of TR SO2 Group 1 allowances that the owners 
and operators of such group of sources and units must hold in

[[Page 475]]

accordance with the calculation formula in Sec. 97.606(c)(2)(i) and 
will promulgate a notice of data availability of the results of these 
calculations.
    (iii) The Administrator will provide an opportunity for submission 
of objections to the calculations referenced by the notice of data 
availability required in paragraph (b)(2)(ii) of this section and the 
calculations referenced by the relevant notice of data availability 
required in paragraph (b)(1)(i) of this section.
    (A) Objections shall be submitted by the deadline specified in such 
notice and shall be limited to addressing whether the calculations 
referenced in the relevant notice required under paragraph (b)(1)(ii) of 
this section and referenced in the notice required under paragraph 
(b)(2)(ii) of this section are in accordance with Sec. 
97.606(c)(2)(iii), Sec. Sec. 97.606(b) and 97.630 through 97.635, the 
definitions of ``common designated representative'', ``common designated 
representative's assurance level'', and ``common designated 
representative's share'' in Sec. 97.602, and the calculation formula in 
Sec. 97.606(c)(2)(i).
    (B) The Administrator will adjust the calculations to the extent 
necessary to ensure that they are in accordance with the provisions 
referenced in paragraph (b)(2)(iii)(A) of this section. By October 1 
immediately after the promulgation of such notice, the Administrator 
will promulgate a notice of data availability of any adjustments that 
the Administrator determines to be necessary and the reasons for 
accepting or rejecting any objections submitted in accordance with 
paragraph (b)(2)(iii)(A) of this section.
    (3) For any State (and Indian country within the borders of such 
State) referenced in each notice of data availability required in 
paragraph (b)(2)(iii)(B) of this section as having TR SO2 
Group 1 units with total SO2 emissions exceeding the State 
assurance level for a control period in a given year, the Administrator 
will establish one assurance account for each set of owners and 
operators referenced, in the notice of data availability required under 
paragraph (b)(2)(iii)(B) of this section, as all of the owners and 
operators of a group of TR SO2 Group 1 sources and units in 
the State (and Indian country within the borders of such State) having a 
common designated representative for such control period and as being 
required to hold TR SO2 Group 1 allowances.
    (4)(i) As of midnight of November 1 immediately after the 
promulgation of each notice of data availability required in paragraph 
(b)(2)(iii)(B) of this section, the owners and operators described in 
paragraph (b)(3) of this section shall hold in the assurance account 
established for them and for the appropriate TR SO2 Group 1 
sources, TR SO2 Group 1 units, and State (and Indian country 
within the borders of such State) under paragraph (b)(3) of this section 
a total amount of TR SO2 Group 1 allowances, available for 
deduction under paragraph (a) of this section, equal to the amount such 
owners and operators are required to hold with regard to such sources, 
units and State (and Indian country within the borders of such State) as 
calculated by the Administrator and referenced in such notice.
    (ii) Notwithstanding the allowance-holding deadline specified in 
paragraph (b)(4)(i) of this section, if November 1 is not a business 
day, then such allowance-holding deadline shall be midnight of the first 
business day thereafter.
    (5) After November 1 (or the date described in paragraph (b)(4)(ii) 
of this section) immediately after the promulgation of each notice of 
data availability required in paragraph (b)(2)(iii)(B) of this section 
and after the recordation, in accordance with Sec. 97.623, of TR 
SO2 Group 1 allowance transfers submitted by midnight of such 
date, the Administrator will determine whether the owners and operators 
described in paragraph (b)(3) of this section hold, in the assurance 
account for the appropriate TR SO2 Group 1 sources, TR 
SO2 Group 1 units, and State (and Indian country within the 
borders of such State) established under paragraph (b)(3) of this 
section, the amount of TR SO2 Group 1 allowances available 
under paragraph (a) of this section that the owners and operators are 
required to hold with regard to such sources, units, and State (and 
Indian country within the borders of such

[[Page 476]]

State) as calculated by the Administrator and referenced in the notice 
required in paragraph (b)(2)(iii)(B) of this section.
    (6) Notwithstanding any other provision of this subpart and any 
revision, made by or submitted to the Administrator after the 
promulgation of the notice of data availability required in paragraph 
(b)(2)(iii)(B) of this section for a control period in a given year, of 
any data used in making the calculations referenced in such notice, the 
amounts of TR SO2 Group 1 allowances that the owners and 
operators are required to hold in accordance with Sec. 97.606(c)(2)(i) 
for such control period shall continue to be such amounts as calculated 
by the Administrator and referenced in such notice required in paragraph 
(b)(2)(iii)(B) of this section, except as follows:
    (i) If any such data are revised by the Administrator as a result of 
a decision in or settlement of litigation concerning such data on appeal 
under part 78 of this chapter of such notice, or on appeal under section 
307 of the Clean Air Act of a decision rendered under part 78 of this 
chapter on appeal of such notice, then the Administrator will use the 
data as so revised to recalculate the amounts of TR SO2 Group 
1 allowances that owners and operators are required to hold in 
accordance with the calculation formula in Sec. 97.606(c)(2)(i) for 
such control period with regard to the TR SO2 Group 1 
sources, TR SO2 Group 1 units, and State (and Indian country 
within the borders of such State) involved, provided that such 
litigation under part 78 of this chapter, or the proceeding under part 
78 of this chapter that resulted in the decision appealed in such 
litigation under section 307 of the Clean Air Act, was initiated no 
later than 30 days after promulgation of such notice required in 
paragraph (b)(2)(iii)(B) of this section.
    (ii) If any such data are revised by the owners and operators of a 
TR SO2 Group 1 source and TR SO2 Group 1 unit 
whose designated representative submitted such data under paragraph 
(b)(2)(i) of this section, as a result of a decision in or settlement of 
litigation concerning such submission, then the Administrator will use 
the data as so revised to recalculate the amounts of TR SO2 
Group 1 allowances that owners and operators are required to hold in 
accordance with the calculation formula in Sec. 97.606(c)(2)(i) for 
such control period with regard to the TR SO2 Group 1 
sources, TR SO2 Group 1 units, and State (and Indian country 
within the borders of such State) involved, provided that such 
litigation was initiated no later than 30 days after promulgation of 
such notice required in paragraph (b)(2)(iii)(B) of this section.
    (iii) If the revised data are used to recalculate, in accordance 
with paragraphs (b)(6)(i) and (ii) of this section, the amount of TR 
SO2 Group 1 allowances that the owners and operators are 
required to hold for such control period with regard to the TR 
SO2 Group 1 sources, TR SO2 Group 1 units, and 
State (and Indian country within the borders of such State) involved--
    (A) Where the amount of TR SO2 Group 1 allowances that 
the owners and operators are required to hold increases as a result of 
the use of all such revised data, the Administrator will establish a 
new, reasonable deadline on which the owners and operators shall hold 
the additional amount of TR SO2 Group 1 allowances in the 
assurance account established by the Administrator for the appropriate 
TR SO2 Group 1 sources, TR SO2 Group 1 units, and 
State (and Indian country within the borders of such State) under 
paragraph (b)(3) of this section. The owners' and operators' failure to 
hold such additional amount, as required, before the new deadline shall 
not be a violation of the Clean Air Act. The owners' and operators' 
failure to hold such additional amount, as required, as of the new 
deadline shall be a violation of the Clean Air Act. Each TR 
SO2 Group 1 allowance that the owners and operators fail to 
hold as required as of the new deadline, and each day in such control 
period, shall be a separate violation of the Clean Air Act.
    (B) For the owners and operators for which the amount of TR 
SO2 Group 1 allowances required to be held decreases as a 
result of the use of all such revised data, the Administrator will 
record, in all accounts from which TR SO2 Group 1 allowances 
were transferred by such owners and operators for

[[Page 477]]

such control period to the assurance account established by the 
Administrator for the appropriate TR SO2 Group 1 sources, TR 
SO2 Group 1 units, and State (and Indian country within the 
borders of such State) under paragraph (b)(3) of this section, a total 
amount of the TR SO2 Group 1 allowances held in such 
assurance account equal to the amount of the decrease. If TR 
SO2 Group 1 allowances were transferred to such assurance 
account from more than one account, the amount of TR SO2 
Group 1 allowances recorded in each such transferor account will be in 
proportion to the percentage of the total amount of TR SO2 
Group 1 allowances transferred to such assurance account for such 
control period from such transferor account.
    (C) Each TR SO2 Group 1 allowance held under paragraph 
(b)(6)(iii)(A) of this section as a result of recalculation of 
requirements under the TR SO2 Group 1 assurance provisions 
for such control period must be a TR SO2 Group 1 allowance 
allocated for a control period in a year before or the year immediately 
following, or in the same year as, the year of such control period.

[76 FR 48432, Aug. 8, 2011, as amended at 77 FR 10340, Feb. 21, 2012; 79 
FR 71672, Dec. 3, 2014]



Sec. 97.626  Banking.

    (a) A TR SO2 Group 1 allowance may be banked for future 
use or transfer in a compliance account or a general account in 
accordance with paragraph (b) of this section.
    (b) Any TR SO2 Group 1 allowance that is held in a 
compliance account or a general account will remain in such account 
unless and until the TR SO2 Group 1 allowance is deducted or 
transferred under Sec. 97.611(c), Sec. 97.623, Sec. 97.624, Sec. 
97.625, Sec. 97.627, or Sec. 97.628.



Sec. 97.627  Account error.

    The Administrator may, at his or her sole discretion and on his or 
her own motion, correct any error in any Allowance Management System 
account. Within 10 business days of making such correction, the 
Administrator will notify the authorized account representative for the 
account.



Sec. 97.628  Administrator's action on submissions.

    (a) The Administrator may review and conduct independent audits 
concerning any submission under the TR SO2 Group 1 Trading 
Program and make appropriate adjustments of the information in the 
submission.
    (b) The Administrator may deduct TR SO2 Group 1 
allowances from or transfer TR SO2 Group 1 allowances to a 
compliance account or an assurance account, based on the information in 
a submission, as adjusted under paragraph (a)(1) of this section, and 
record such deductions and transfers.



Sec. 97.629  [Reserved]



Sec. 97.630  General monitoring, recordkeeping, and reporting 
requirements.

    The owners and operators, and to the extent applicable, the 
designated representative, of a TR SO2 Group 1 unit, shall 
comply with the monitoring, recordkeeping, and reporting requirements as 
provided in this subpart and subparts F and G of part 75 of this 
chapter. For purposes of applying such requirements, the definitions in 
Sec. 97.602 and in Sec. 72.2 of this chapter shall apply, the terms 
``affected unit,'' ``designated representative,'' and ``continuous 
emission monitoring system'' (or ``CEMS'') in part 75 of this chapter 
shall be deemed to refer to the terms ``TR SO2 Group 1 
unit,'' ``designated representative,'' and ``continuous emission 
monitoring system'' (or ``CEMS'') respectively as defined in Sec. 
97.602, and the term ``newly affected unit'' shall be deemed to mean 
``newly affected TR SO2 Group 1 unit''. The owner or operator 
of a unit that is not a TR SO2 Group 1 unit but that is 
monitored under Sec. 75.16(b)(2) of this chapter shall comply with the 
same monitoring, recordkeeping, and reporting requirements as a TR 
SO2 Group 1 unit.
    (a) Requirements for installation, certification, and data 
accounting. The owner or operator of each TR SO2 Group 1 unit 
shall:
    (1) Install all monitoring systems required under this subpart for 
monitoring SO2 mass emissions and individual unit heat input 
(including all

[[Page 478]]

systems required to monitor SO2 concentration, stack gas 
moisture content, stack gas flow rate, CO2 or O2 
concentration, and fuel flow rate, as applicable, in accordance with 
Sec. Sec. 75.11 and 75.16 of this chapter);
    (2) Successfully complete all certification tests required under 
Sec. 97.631 and meet all other requirements of this subpart and part 75 
of this chapter applicable to the monitoring systems under paragraph 
(a)(1) of this section; and
    (3) Record, report, and quality-assure the data from the monitoring 
systems under paragraph (a)(1) of this section.
    (b) Compliance deadlines. Except as provided in paragraph (e) of 
this section, the owner or operator shall meet the monitoring system 
certification and other requirements of paragraphs (a)(1) and (2) of 
this section on or before the following dates and shall record, report, 
and quality-assure the data from the monitoring systems under paragraph 
(a)(1) of this section on and after the following dates.
    (1) For the owner or operator of a TR SO2 Group 1 unit 
that commences commercial operation before July 1, 2014, January 1, 
2015.
    (2) For the owner or operator of a TR SO2 Group 1 unit 
that commences commercial operation on or after July 1, 2014, by the 
later of the following:
    (i) January 1, 2015; or
    (ii) 180 calendar days after the date on which the unit commences 
commercial operation.
    (3) The owner or operator of a TR SO2 Group 1 unit for 
which construction of a new stack or flue or installation of add-on 
SO2 emission controls is completed after the applicable 
deadline under paragraph (b)(1) or (2) of this section shall meet the 
requirements of Sec. Sec. 75.4(e)(1) through (e)(4) of this chapter, 
except that:
    (i) Such requirements shall apply to the monitoring systems required 
under Sec. 97.630 through Sec. 97.635, rather than the monitoring 
systems required under part 75 of this chapter;
    (ii) SO2 concentration, stack gas moisture content, stack 
gas volumetric flow rate, and O2 or CO2 
concentration data shall be determined and reported, rather than the 
data listed in Sec. 75.4(e)(2) of this chapter; and
    (iii) Any petition for another procedure under Sec. 75.4(e)(2) of 
this chapter shall be submitted under Sec. 97.635, rather than Sec. 
75.66.
    (c) Reporting data. The owner or operator of a TR SO2 
Group 1 unit that does not meet the applicable compliance date set forth 
in paragraph (b) of this section for any monitoring system under 
paragraph (a)(1) of this section shall, for each such monitoring system, 
determine, record, and report maximum potential (or, as appropriate, 
minimum potential) values for SO2 concentration, stack gas 
flow rate, stack gas moisture content, fuel flow rate, and any other 
parameters required to determine SO2 mass emissions and heat 
input in accordance with Sec. 75.31(b)(2) or (c)(3) of this chapter or 
section 2.4 of appendix D to part 75 of this chapter, as applicable.
    (d) Prohibitions. (1) No owner or operator of a TR SO2 
Group 1 unit shall use any alternative monitoring system, alternative 
reference method, or any other alternative to any requirement of this 
subpart without having obtained prior written approval in accordance 
with Sec. 97.635.
    (2) No owner or operator of a TR SO2 Group 1 unit shall 
operate the unit so as to discharge, or allow to be discharged, 
SO2 to the atmosphere without accounting for all such 
SO2 in accordance with the applicable provisions of this 
subpart and part 75 of this chapter.
    (3) No owner or operator of a TR SO2 Group 1 unit shall 
disrupt the continuous emission monitoring system, any portion thereof, 
or any other approved emission monitoring method, and thereby avoid 
monitoring and recording SO2 mass discharged into the 
atmosphere or heat input, except for periods of recertification or 
periods when calibration, quality assurance testing, or maintenance is 
performed in accordance with the applicable provisions of this subpart 
and part 75 of this chapter.
    (4) No owner or operator of a TR SO2 Group 1 unit shall 
retire or permanently discontinue use of the continuous emission 
monitoring system, any component thereof, or any other approved 
monitoring system under this subpart, except under any one of the 
following circumstances:

[[Page 479]]

    (i) During the period that the unit is covered by an exemption under 
Sec. 97.605 that is in effect;
    (ii) The owner or operator is monitoring emissions from the unit 
with another certified monitoring system approved, in accordance with 
the applicable provisions of this subpart and part 75 of this chapter, 
by the Administrator for use at that unit that provides emission data 
for the same pollutant or parameter as the retired or discontinued 
monitoring system; or
    (iii) The designated representative submits notification of the date 
of certification testing of a replacement monitoring system for the 
retired or discontinued monitoring system in accordance with Sec. 
97.631(d)(3)(i).
    (e) Long-term cold storage. The owner or operator of a TR 
SO2 Group 1 unit is subject to the applicable provisions of 
Sec. 75.4(d) of this chapter concerning units in long-term cold 
storage.

[76 FR 48379, Aug. 8, 2011, as amended at 79 FR 71672, Dec. 3, 2014]



Sec. 97.631  Initial monitoring system certification and 
recertification procedures.

    (a) The owner or operator of a TR SO2 Group 1 unit shall 
be exempt from the initial certification requirements of this section 
for a monitoring system under Sec. 97.630(a)(1) if the following 
conditions are met:
    (1) The monitoring system has been previously certified in 
accordance with part 75 of this chapter; and
    (2) The applicable quality-assurance and quality-control 
requirements of Sec. 75.21 of this chapter and appendices B and D to 
part 75 of this chapter are fully met for the certified monitoring 
system described in paragraph (a)(1) of this section.
    (b) The recertification provisions of this section shall apply to a 
monitoring system under Sec. 97.630(a)(1) that is exempt from initial 
certification requirements under paragraph (a) of this section.
    (c) [Reserved]
    (d) Except as provided in paragraph (a) of this section, the owner 
or operator of a TR SO2 Group 1 unit shall comply with the 
following initial certification and recertification procedures, for a 
continuous monitoring system (i.e., a continuous emission monitoring 
system and an excepted monitoring system under appendix D to part 75 of 
this chapter) under Sec. 97.630(a)(1). The owner or operator of a unit 
that qualifies to use the low mass emissions excepted monitoring 
methodology under Sec. 75.19 of this chapter or that qualifies to use 
an alternative monitoring system under subpart E of part 75 of this 
chapter shall comply with the procedures in paragraph (e) or (f) of this 
section respectively.
    (1) Requirements for initial certification. The owner or operator 
shall ensure that each continuous monitoring system under Sec. 
97.630(a)(1) (including the automated data acquisition and handling 
system) successfully completes all of the initial certification testing 
required under Sec. 75.20 of this chapter by the applicable deadline in 
Sec. 97.630(b). In addition, whenever the owner or operator installs a 
monitoring system to meet the requirements of this subpart in a location 
where no such monitoring system was previously installed, initial 
certification in accordance with Sec. 75.20 of this chapter is 
required.
    (2) Requirements for recertification. Whenever the owner or operator 
makes a replacement, modification, or change in any certified continuous 
emission monitoring system under Sec. 97.630(a)(1) that may 
significantly affect the ability of the system to accurately measure or 
record SO2 mass emissions or heat input rate or to meet the 
quality-assurance and quality-control requirements of Sec. 75.21 of 
this chapter or appendix B to part 75 of this chapter, the owner or 
operator shall recertify the monitoring system in accordance with Sec. 
75.20(b) of this chapter. Furthermore, whenever the owner or operator 
makes a replacement, modification, or change to the flue gas handling 
system or the unit's operation that may significantly change the stack 
flow or concentration profile, the owner or operator shall recertify 
each continuous emission monitoring system whose accuracy is potentially 
affected by the change, in accordance with Sec. 75.20(b) of this 
chapter. Examples of changes to a continuous

[[Page 480]]

emission monitoring system that require recertification include: 
Replacement of the analyzer, complete replacement of an existing 
continuous emission monitoring system, or change in location or 
orientation of the sampling probe or site. Any fuel flowmeter system 
under Sec. 97.630(a)(1) is subject to the recertification requirements 
in Sec. 75.20(g)(6) of this chapter.
    (3) Approval process for initial certification and recertification. 
For initial certification of a continuous monitoring system under Sec. 
97.630(a)(1), paragraphs (d)(3)(i) through (v) of this section apply. 
For recertifications of such monitoring systems, paragraphs (d)(3)(i) 
through (iv) of this section and the procedures in Sec. Sec. 
75.20(b)(5) and (g)(7) of this chapter (in lieu of the procedures in 
paragraph (d)(3)(v) of this section) apply, provided that in applying 
paragraphs (d)(3)(i) through (iv) of this section, the words 
``certification'' and ``initial certification'' are replaced by the word 
``recertification'' and the word ``certified'' is replaced by the word 
``recertified''.
    (i) Notification of certification. The designated representative 
shall submit to the appropriate EPA Regional Office and the 
Administrator written notice of the dates of certification testing, in 
accordance with Sec. 97.633.
    (ii) Certification application. The designated representative shall 
submit to the Administrator a certification application for each 
monitoring system. A complete certification application shall include 
the information specified in Sec. 75.63 of this chapter.
    (iii) Provisional certification date. The provisional certification 
date for a monitoring system shall be determined in accordance with 
Sec. 75.20(a)(3) of this chapter. A provisionally certified monitoring 
system may be used under the TR SO2 Group 1 Trading Program 
for a period not to exceed 120 days after receipt by the Administrator 
of the complete certification application for the monitoring system 
under paragraph (d)(3)(ii) of this section. Data measured and recorded 
by the provisionally certified monitoring system, in accordance with the 
requirements of part 75 of this chapter, will be considered valid 
quality-assured data (retroactive to the date and time of provisional 
certification), provided that the Administrator does not invalidate the 
provisional certification by issuing a notice of disapproval within 120 
days of the date of receipt of the complete certification application by 
the Administrator.
    (iv) Certification application approval process. The Administrator 
will issue a written notice of approval or disapproval of the 
certification application to the owner or operator within 120 days of 
receipt of the complete certification application under paragraph 
(d)(3)(ii) of this section. In the event the Administrator does not 
issue such a notice within such 120-day period, each monitoring system 
that meets the applicable performance requirements of part 75 of this 
chapter and is included in the certification application will be deemed 
certified for use under the TR SO2 Group 1 Trading Program.
    (A) Approval notice. If the certification application is complete 
and shows that each monitoring system meets the applicable performance 
requirements of part 75 of this chapter, then the Administrator will 
issue a written notice of approval of the certification application 
within 120 days of receipt.
    (B) Incomplete application notice. If the certification application 
is not complete, then the Administrator will issue a written notice of 
incompleteness that sets a reasonable date by which the designated 
representative must submit the additional information required to 
complete the certification application. If the designated representative 
does not comply with the notice of incompleteness by the specified date, 
then the Administrator may issue a notice of disapproval under paragraph 
(d)(3)(iv)(C) of this section.
    (C) Disapproval notice. If the certification application shows that 
any monitoring system does not meet the performance requirements of part 
75 of this chapter or if the certification application is incomplete and 
the requirement for disapproval under paragraph (d)(3)(iv)(B) of this 
section is met, then the Administrator will issue a written notice of 
disapproval of the certification application. Upon issuance of such 
notice of disapproval,

[[Page 481]]

the provisional certification is invalidated by the Administrator and 
the data measured and recorded by each uncertified monitoring system 
shall not be considered valid quality-assured data beginning with the 
date and hour of provisional certification (as defined under Sec. 
75.20(a)(3) of this chapter).
    (D) Audit decertification. The Administrator may issue a notice of 
disapproval of the certification status of a monitor in accordance with 
Sec. 97.632(b).
    (v) Procedures for loss of certification. If the Administrator 
issues a notice of disapproval of a certification application under 
paragraph (d)(3)(iv)(C) of this section or a notice of disapproval of 
certification status under paragraph (d)(3)(iv)(D) of this section, 
then:
    (A) The owner or operator shall substitute the following values, for 
each disapproved monitoring system, for each hour of unit operation 
during the period of invalid data specified under Sec. 
75.20(a)(4)(iii), Sec. 75.20(g)(7), or Sec. 75.21(e) of this chapter 
and continuing until the applicable date and hour specified under Sec. 
75.20(a)(5)(i) or (g)(7) of this chapter:
    (1) For a disapproved SO2 pollutant concentration monitor 
and disapproved flow monitor, respectively, the maximum potential 
concentration of SO2 and the maximum potential flow rate, as 
defined in sections 2.1.1.1 and 2.1.4.1 of appendix A to part 75 of this 
chapter.
    (2) For a disapproved moisture monitoring system and disapproved 
diluent gas monitoring system, respectively, the minimum potential 
moisture percentage and either the maximum potential CO2 
concentration or the minimum potential O2 concentration (as 
applicable), as defined in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of 
appendix A to part 75 of this chapter.
    (3) For a disapproved fuel flowmeter system, the maximum potential 
fuel flow rate, as defined in section 2.4.2.1 of appendix D to part 75 
of this chapter.
    (B) The designated representative shall submit a notification of 
certification retest dates and a new certification application in 
accordance with paragraphs (d)(3)(i) and (ii) of this section.
    (C) The owner or operator shall repeat all certification tests or 
other requirements that were failed by the monitoring system, as 
indicated in the Administrator's notice of disapproval, no later than 30 
unit operating days after the date of issuance of the notice of 
disapproval.
    (e) The owner or operator of a unit qualified to use the low mass 
emissions (LME) excepted methodology under Sec. 75.19 of this chapter 
shall meet the applicable certification and recertification requirements 
in Sec. Sec. 75.19(a)(2) and 75.20(h) of this chapter. If the owner or 
operator of such a unit elects to certify a fuel flowmeter system for 
heat input determination, the owner or operator shall also meet the 
certification and recertification requirements in Sec. 75.20(g) of this 
chapter.
    (f) The designated representative of each unit for which the owner 
or operator intends to use an alternative monitoring system approved by 
the Administrator under subpart E of part 75 of this chapter shall 
comply with the applicable notification and application procedures of 
Sec. 75.20(f) of this chapter.



Sec. 97.632  Monitoring system out-of-control periods.

    (a) General provisions. Whenever any monitoring system fails to meet 
the quality-assurance and quality-control requirements or data 
validation requirements of part 75 of this chapter, data shall be 
substituted using the applicable missing data procedures in subpart D or 
appendix D to part 75 of this chapter.
    (b) Audit decertification. Whenever both an audit of a monitoring 
system and a review of the initial certification or recertification 
application reveal that any monitoring system should not have been 
certified or recertified because it did not meet a particular 
performance specification or other requirement under Sec. 97.631 or the 
applicable provisions of part 75 of this chapter, both at the time of 
the initial certification or recertification application submission and 
at the time of the audit, the Administrator will issue a notice of 
disapproval of the certification status of such monitoring system. For 
the purposes of this paragraph, an audit shall be either a field audit 
or an audit of any information submitted to the Administrator or any

[[Page 482]]

State or permitting authority. By issuing the notice of disapproval, the 
Administrator revokes prospectively the certification status of the 
monitoring system. The data measured and recorded by the monitoring 
system shall not be considered valid quality-assured data from the date 
of issuance of the notification of the revoked certification status 
until the date and time that the owner or operator completes 
subsequently approved initial certification or recertification tests for 
the monitoring system. The owner or operator shall follow the applicable 
initial certification or recertification procedures in Sec. 97.631 for 
each disapproved monitoring system.



Sec. 97.633  Notifications concerning monitoring.

    The designated representative of a TR SO2 Group 1 unit 
shall submit written notice to the Administrator in accordance with 
Sec. 75.61 of this chapter.



Sec. 97.634  Recordkeeping and reporting.

    (a) General provisions. The designated representative shall comply 
with all recordkeeping and reporting requirements in paragraphs (b) 
through (e) of this section, the applicable recordkeeping and reporting 
requirements in subparts F and G of part 75 of this chapter, and the 
requirements of Sec. 97.614(a).
    (b) Monitoring plans. The owner or operator of a TR SO2 
Group 1 unit shall comply with requirements of Sec. 75.62 of this 
chapter.
    (c) Certification applications. The designated representative shall 
submit an application to the Administrator within 45 days after 
completing all initial certification or recertification tests required 
under Sec. 97.631, including the information required under Sec. 75.63 
of this chapter.
    (d) Quarterly reports. The designated representative shall submit 
quarterly reports, as follows:
    (1) The designated representative shall report the SO2 
mass emissions data and heat input data for the TR SO2 Group 
1 unit, in an electronic quarterly report in a format prescribed by the 
Administrator, for each calendar quarter beginning with:
    (i) For a unit that commences commercial operation before July 1, 
2014, the calendar quarter covering January 1, 2015 through March 31, 
2015; or
    (ii) For a unit that commences commercial operation on or after July 
1, 2014, the calendar quarter corresponding to the earlier of the date 
of provisional certification or the applicable deadline for initial 
certification under Sec. 97.630(b), unless that quarter is the third or 
fourth quarter of 2014, in which case reporting shall commence in the 
quarter covering January 1, 2015 through March 31, 2015.
    (2) The designated representative shall submit each quarterly report 
to the Administrator within 30 days after the end of the calendar 
quarter covered by the report. Quarterly reports shall be submitted in 
the manner specified in Sec. 75.64 of this chapter.
    (3) For TR SO2 Group 1 units that are also subject to the 
Acid Rain Program, TR NOX Annual Trading Program, or TR 
NOX Ozone Season Trading Program, quarterly reports shall 
include the applicable data and information required by subparts F 
through H of part 75 of this chapter as applicable, in addition to the 
SO2 mass emission data, heat input data, and other 
information required by this subpart.
    (4) The Administrator may review and conduct independent audits of 
any quarterly report in order to determine whether the quarterly report 
meets the requirements of this subpart and part 75 of this chapter, 
including the requirement to use substitute data.
    (i) The Administrator will notify the designated representative of 
any determination that the quarterly report fails to meet any such 
requirements and specify in such notification any corrections that the 
Administrator believes are necessary to make through resubmission of the 
quarterly report and a reasonable time period within which the 
designated representative must respond. Upon request by the designated 
representative, the Administrator may specify reasonable extensions of 
such time period. Within the time period (including any such extensions) 
specified by the Administrator, the designated representative shall 
resubmit the quarterly report with the

[[Page 483]]

corrections specified by the Administrator, except to the extent the 
designated representative provides information demonstrating that a 
specified correction is not necessary because the quarterly report 
already meets the requirements of this subpart and part 75 of this 
chapter that are relevant to the specified correction.
    (ii) Any resubmission of a quarterly report shall meet the 
requirements applicable to the submission of a quarterly report under 
this subpart and part 75 of this chapter, except for the deadline set 
forth in paragraph (d)(2) of this section.
    (e) Compliance certification. The designated representative shall 
submit to the Administrator a compliance certification (in a format 
prescribed by the Administrator) in support of each quarterly report 
based on reasonable inquiry of those persons with primary responsibility 
for ensuring that all of the unit's emissions are correctly and fully 
monitored. The certification shall state that:
    (1) The monitoring data submitted were recorded in accordance with 
the applicable requirements of this subpart and part 75 of this chapter, 
including the quality assurance procedures and specifications; and
    (2) For a unit with add-on SO2 emission controls and for 
all hours where SO2 data are substituted in accordance with 
Sec. 75.34(a)(1) of this chapter, the add-on emission controls were 
operating within the range of parameters listed in the quality 
assurance/quality control program under appendix B to part 75 of this 
chapter and the substitute data values do not systematically 
underestimate SO2 emissions.

[76 FR 48379, Aug. 8, 2011, as amended at 79 FR 71672, Dec. 3, 2014]



Sec. 97.635  Petitions for alternatives to monitoring, recordkeeping,
or reporting requirements.

    (a) The designated representative of a TR SO2 Group 1 
unit may submit a petition under Sec. 75.66 of this chapter to the 
Administrator, requesting approval to apply an alternative to any 
requirement of Sec. Sec. 97.630 through 97.634.
    (b) A petition submitted under paragraph (a) of this section shall 
include sufficient information for the evaluation of the petition, 
including, at a minimum, the following information:
    (i) Identification of each unit and source covered by the petition;
    (ii) A detailed explanation of why the proposed alternative is being 
suggested in lieu of the requirement;
    (iii) A description and diagram of any equipment and procedures used 
in the proposed alternative;
    (iv) A demonstration that the proposed alternative is consistent 
with the purposes of the requirement for which the alternative is 
proposed and with the purposes of this subpart and part 75 of this 
chapter and that any adverse effect of approving the alternative will be 
de minimis; and
    (v) Any other relevant information that the Administrator may 
require.
    (c) Use of an alternative to any requirement referenced in paragraph 
(a) of this section is in accordance with this subpart only to the 
extent that the petition is approved in writing by the Administrator and 
that such use is in accordance with such approval.



              Subpart DDDDD_TR SO2 Group 2 Trading Program

    Source: 76 FR 48458, Aug. 8, 2011, unless otherwise noted.



Sec. 97.701  Purpose.

    This subpart sets forth the general, designated representative, 
allowance, and monitoring provisions for the Transport Rule (TR) 
SO2 Group 2 Trading Program, under section 110 of the Clean 
Air Act and Sec. 52.39 of this chapter, as a means of mitigating 
interstate transport of fine particulates and sulfur dioxide.



Sec. 97.702  Definitions.

    The terms used in this subpart shall have the meanings set forth in 
this section as follows:
    Acid Rain Program means a multi-state SO2 and 
NOX air pollution control and emission reduction program 
established by the Administrator under title IV of the Clean Air Act and 
parts 72 through 78 of this chapter.

[[Page 484]]

    Administrator means the Administrator of the United States 
Environmental Protection Agency or the Director of the Clean Air Markets 
Division (or its successor determined by the Administrator) of the 
United States Environmental Protection Agency, the Administrator's duly 
authorized representative under this subpart.
    Allocate or allocation means, with regard to TR SO2 Group 
2 allowances, the determination by the Administrator, State, or 
permitting authority, in accordance with this subpart and any SIP 
revision submitted by the State and approved by the Administrator under 
Sec. 52.39(g), (h), or (i) of this chapter, of the amount of such TR 
SO2 Group 2 allowances to be initially credited, at no cost 
to the recipient, to:
    (1) A TR SO2 Group 2 unit;
    (2) A new unit set-aside;
    (3) An Indian country new unit set-aside; or
    (4) An entity not listed in paragraphs (1) through (3) of this 
definition;
    (5) Provided that, if the Administrator, State, or permitting 
authority initially credits, to a TR SO2 Group 2 unit 
qualifying for an initial credit, a credit in the amount of zero TR 
SO2 Group 2 allowances, the TR SO2 Group 2 unit 
will be treated as being allocated an amount (i.e., zero) of TR 
SO2 Group 2 allowances.
    Allowable SO2 emission rate means, for a unit, the most stringent 
State or federal SO2 emission rate limit (in lb/MWhr or, if 
in lb/mmBtu, converted to lb/MWhr by multiplying it by the unit's heat 
rate in mmBtu/MWhr) that is applicable to the unit and covers the 
longest averaging period not exceeding one year.
    Allowance Management System means the system by which the 
Administrator records allocations, deductions, and transfers of TR 
SO2 Group 2 allowances under the TR SO2 Group 2 
Trading Program. Such allowances are allocated, recorded, held, 
deducted, or transferred only as whole allowances.
    Allowance Management System account means an account in the 
Allowance Management System established by the Administrator for 
purposes of recording the allocation, holding, transfer, or deduction of 
TR SO2 Group 2 allowances.
    Allowance transfer deadline means, for a control period in a given 
year, midnight of March 1 (if it is a business day), or midnight of the 
first business day thereafter (if March 1 is not a business day), 
immediately after such control period and is the deadline by which a TR 
SO2 Group 2 allowance transfer must be submitted for 
recordation in a TR SO2 Group 2 source's compliance account 
in order to be available for use in complying with the source's TR 
SO2 Group 2 emissions limitation for such control period in 
accordance with Sec. Sec. 97.706 and 97.724.
    Alternate designated representative means, for a TR SO2 
Group 2 source and each TR SO2 Group 2 unit at the source, 
the natural person who is authorized by the owners and operators of the 
source and all such units at the source, in accordance with this 
subpart, to act on behalf of the designated representative in matters 
pertaining to the TR SO2 Group 2 Trading Program. If the TR 
SO2 Group 2 source is also subject to the Acid Rain Program, 
TR NOX Annual Trading Program, or TR NOX Ozone 
Season Trading Program, then this natural person shall be the same 
natural person as the alternate designated representative, as defined in 
the respective program.
    Assurance account means an Allowance Management System account, 
established by the Administrator under Sec. 97.725(b)(3) for certain 
owners and operators of a group of one or more TR SO2 Group 2 
sources and units in a given State (and Indian country within the 
borders of such State), in which are held TR SO2 Group 2 
allowances available for use for a control period in a given year in 
complying with the TR SO2 Group 2 assurance provisions in 
accordance with Sec. Sec. 97.706 and 97.725.
    Authorized account representative means, for a general account, the 
natural person who is authorized, in accordance with this subpart, to 
transfer and otherwise dispose of TR SO2 Group 2 allowances 
held in the general account and, for a TR SO2 Group 2 
source's compliance account, the designated representative of the 
source.

[[Page 485]]

    Automated data acquisition and handling system or DAHS means the 
component of the continuous emission monitoring system, or other 
emissions monitoring system approved for use under this subpart, 
designed to interpret and convert individual output signals from 
pollutant concentration monitors, flow monitors, diluent gas monitors, 
and other component parts of the monitoring system to produce a 
continuous record of the measured parameters in the measurement units 
required by this subpart.
    Biomass means--
    (1) Any organic material grown for the purpose of being converted to 
energy;
    (2) Any organic byproduct of agriculture that can be converted into 
energy; or
    (3) Any material that can be converted into energy and is 
nonmerchantable for other purposes, that is segregated from other 
material that is nonmerchantable for other purposes, and that is;
    (i) A forest-related organic resource, including mill residues, 
precommercial thinnings, slash, brush, or byproduct from conversion of 
trees to merchantable material; or
    (ii) A wood material, including pallets, crates, dunnage, 
manufacturing and construction materials (other than pressure-treated, 
chemically-treated, or painted wood products), and landscape or right-
of-way tree trimmings.
    Boiler means an enclosed fossil- or other-fuel-fired combustion 
device used to produce heat and to transfer heat to recirculating water, 
steam, or other medium.
    Bottoming-cycle unit means a unit in which the energy input to the 
unit is first used to produce useful thermal energy, where at least some 
of the reject heat from the useful thermal energy application or process 
is then used for electricity production.
    Business day means a day that does not fall on a weekend or a 
federal holiday.
    Certifying official means a natural person who is:
    (1) For a corporation, a president, secretary, treasurer, or vice-
president of the corporation in charge of a principal business function 
or any other person who performs similar policy- or decision-making 
functions for the corporation;
    (2) For a partnership or sole proprietorship, a general partner or 
the proprietor respectively; or
    (3) For a local government entity or State, federal, or other public 
agency, a principal executive officer or ranking elected official.
    Clean Air Act means the Clean Air Act, 42 U.S.C. 7401, et seq.
    Coal means ``coal'' as defined in Sec. 72.2 of this chapter.
    Coal-derived fuel means any fuel (whether in a solid, liquid, or 
gaseous state) produced by the mechanical, thermal, or chemical 
processing of coal.
    Cogeneration system means an integrated group, at a source, of 
equipment (including a boiler, or combustion turbine, and a steam 
turbine generator) designed to produce useful thermal energy for 
industrial, commercial, heating, or cooling purposes and electricity 
through the sequential use of energy.
    Cogeneration unit means a stationary, fossil-fuel-fired boiler or 
stationary, fossil-fuel-fired combustion turbine that is a topping-cycle 
unit or a bottoming-cycle unit:
    (1) Operating as part of a cogeneration system; and
    (2) Producing on an annual average basis--
    (i) For a topping-cycle unit,
    (A) Useful thermal energy not less than 5 percent of total energy 
output; and
    (B) Useful power that, when added to one-half of useful thermal 
energy produced, is not less than 42.5 percent of total energy input, if 
useful thermal energy produced is 15 percent or more of total energy 
output, or not less than 45 percent of total energy input, if useful 
thermal energy produced is less than 15 percent of total energy output.
    (ii) For a bottoming-cycle unit, useful power not less than 45 
percent of total energy input;
    (3) Provided that the requirements in paragraph (2) of this 
definition shall not apply to a calendar year referenced in paragraph 
(2) of this definition during which the unit did not operate at all;

[[Page 486]]

    (4) Provided that the total energy input under paragraphs (2)(i)(B) 
and (2)(ii) of this definition shall equal the unit's total energy input 
from all fuel, except biomass if the unit is a boiler; and
    (5) Provided that, if, throughout its operation during the 12-month 
period or a calendar year referenced in paragraph (2) of this 
definition, a unit is operated as part of a cogeneration system and the 
cogeneration system meets on a system-wide basis the requirement in 
paragraph (2)(i)(B) or (2)(ii) of this definition, the unit shall be 
deemed to meet such requirement during that 12-month period or calendar 
year.
    Combustion turbine means an enclosed device comprising:
    (1) If the device is simple cycle, a compressor, a combustor, and a 
turbine and in which the flue gas resulting from the combustion of fuel 
in the combustor passes through the turbine, rotating the turbine; and
    (2) If the device is combined cycle, the equipment described in 
paragraph (1) of this definition and any associated duct burner, heat 
recovery steam generator, and steam turbine.
    Commence commercial operation means, with regard to a unit:
    (1) To have begun to produce steam, gas, or other heated medium used 
to generate electricity for sale or use, including test generation, 
except as provided in Sec. 97.705.
    (i) For a unit that is a TR SO2 Group 2 unit under Sec. 
97.704 on the later of January 1, 2005 or the date the unit commences 
commercial operation as defined in the introductory text of paragraph 
(1) of this definition and that subsequently undergoes a physical change 
or is moved to a new location or source, such date shall remain the date 
of commencement of commercial operation of the unit, which shall 
continue to be treated as the same unit.
    (ii) For a unit that is a TR SO2 Group 2 unit under Sec. 
97.704 on the later of January 1, 2005 or the date the unit commences 
commercial operation as defined in the introductory text of paragraph 
(1) of this definition and that is subsequently replaced by a unit at 
the same or a different source, such date shall remain the replaced 
unit's date of commencement of commercial operation, and the replacement 
unit shall be treated as a separate unit with a separate date for 
commencement of commercial operation as defined in paragraph (1) or (2) 
of this definition as appropriate.
    (2) Notwithstanding paragraph (1) of this definition and except as 
provided in Sec. 97.705, for a unit that is not a TR SO2 
Group 2 unit under Sec. 97.704 on the later of January 1, 2005 or the 
date the unit commences commercial operation as defined in introductory 
text of paragraph (1) of this definition, the unit's date for 
commencement of commercial operation shall be the date on which the unit 
becomes a TR SO2 Group 2 unit under Sec. 97.704.
    (i) For a unit with a date for commencement of commercial operation 
as defined in the introductory text of paragraph (2) of this definition 
and that subsequently undergoes a physical change or is moved to a 
different location or source, such date shall remain the date of 
commencement of commercial operation of the unit, which shall continue 
to be treated as the same unit.
    (ii) For a unit with a date for commencement of commercial operation 
as defined in the introductory text of paragraph (2) of this definition 
and that is subsequently replaced by a unit at the same or a different 
source, such date shall remain the replaced unit's date of commencement 
of commercial operation, and the replacement unit shall be treated as a 
separate unit with a separate date for commencement of commercial 
operation as defined in paragraph (1) or (2) of this definition as 
appropriate.
    Common designated representative means, with regard to a control 
period in a given year, a designated representative where, as of April 1 
immediately after the allowance transfer deadline for such control 
period, the same natural person is authorized under Sec. Sec. 97.713(a) 
and 97.715(a) as the designated representative for a group of one or 
more TR SO2 Group 2 sources and units located in a State (and 
Indian country within the borders of such State).
    Common designated representative's assurance level means, with 
regard to a

[[Page 487]]

specific common designated representative and a State (and Indian 
country within the borders of such State) and control period in a given 
year for which the State assurance level is exceeded as described in 
Sec. 97.706(c)(2)(iii), the common designated representative's share of 
the State SO2 Group 2 trading budget with the variability 
limit for the State for such control period.
    Common designated representative's share means, with regard to a 
specific common designated representative for a control period in a 
given year:
    (1) With regard to a total amount of SO2 emissions from 
all TR SO2 Group 2 units in a State (and Indian country 
within the borders of such State) during such control period, the total 
tonnage of SO2 emissions during such control period from a 
group of one or more TR SO2 Group 2 units located in such 
State (and such Indian country) and having the common designated 
representative for such control period;
    (2) With regard to a State SO2 Group 2 trading budget 
with the variability limit for such control period, the amount (rounded 
to the nearest allowance) equal to the sum of the total amount of TR 
SO2 Group 2 allowances allocated for such control period to a 
group of one or more TR SO2 Group 2 units located in the 
State (and Indian country within the borders of such State) and having 
the common designated representative for such control period and of the 
total amount of TR SO2 Group 2 allowances purchased by an 
owner or operator of such TR SO2 Group 2 units in an auction 
for such control period and submitted by the State or the permitting 
authority to the Administrator for recordation in the compliance 
accounts for such TR SO2 Group 2 units in accordance with the 
TR SO2 Group 2 allowance auction provisions in a SIP revision 
approved by the Administrator under Sec. 52.39(h) or (i) of this 
chapter, multiplied by the sum of the State SO2 Group 2 
trading budget under Sec. 97.710(a) and the State's variability limit 
under Sec. 97.710(b) for such control period and divided by such State 
SO2 Group 2 trading budget;
    (3) Provided that, in the case of a unit that operates during, but 
has no amount of TR SO2 Group 2 allowances allocated under 
Sec. Sec. 97.711 and 97.712 for, such control period, the unit shall be 
treated, solely for purposes of this definition, as being allocated an 
amount (rounded to the nearest allowance) of TR SO2 Group 2 
allowances for such control period equal to the unit's allowable 
SO2 emission rate applicable to such control period, 
multiplied by a capacity factor of 0.85 (if the unit is a boiler 
combusting any amount of coal or coal-derived fuel during such control 
period), 0.24 (if the unit is a simple combustion turbine during such 
control period), 0.67 (if the unit is a combined cycle turbine during 
such control period), 0.74 (if the unit is an integrated coal 
gasification combined cycle unit during such control period), or 0.36 
(for any other unit), multiplied by the unit's maximum hourly load as 
reported in accordance with this subpart and by 8,760 hours/control 
period, and divided by 2,000 lb/ton.
    Common stack means a single flue through which emissions from 2 or 
more units are exhausted.
    Compliance account means an Allowance Management System account, 
established by the Administrator for a TR SO2 Group 2 source 
under this subpart, in which any TR SO2 Group 2 allowance 
allocations to the TR SO2 Group 2 units at the source are 
recorded and in which are held any TR SO2 Group 2 allowances 
available for use for a control period in a given year in complying with 
the source's TR SO2 Group 2 emissions limitation in 
accordance with Sec. Sec. 97.706 and 97.724.
    Continuous emission monitoring system or CEMS means the equipment 
required under this subpart to sample, analyze, measure, and provide, by 
means of readings recorded at least once every 15 minutes and using an 
automated data acquisition and handling system (DAHS), a permanent 
record of SO2 emissions, stack gas volumetric flow rate, 
stack gas moisture content, and O2 or CO2 
concentration (as applicable), in a manner consistent with part 75 of 
this chapter and Sec. Sec. 97.730 through 97.735. The following systems 
are the principal types of continuous emission monitoring systems:
    (1) A flow monitoring system, consisting of a stack flow rate 
monitor and an automated data acquisition and

[[Page 488]]

handling system and providing a permanent, continuous record of stack 
gas volumetric flow rate, in standard cubic feet per hour (scfh);
    (2) A SO2 monitoring system, consisting of a 
SO2 pollutant concentration monitor and an automated data 
acquisition and handling system and providing a permanent, continuous 
record of SO2 emissions, in parts per million (ppm);
    (3) A moisture monitoring system, as defined in Sec. 75.11(b)(2) of 
this chapter and providing a permanent, continuous record of the stack 
gas moisture content, in percent H2O;
    (4) A CO2 monitoring system, consisting of a 
CO2 pollutant concentration monitor (or an O2 
monitor plus suitable mathematical equations from which the 
CO2 concentration is derived) and an automated data 
acquisition and handling system and providing a permanent, continuous 
record of CO2 emissions, in percent CO2; and
    (5) An O2 monitoring system, consisting of an 
O2 concentration monitor and an automated data acquisition 
and handling system and providing a permanent, continuous record of 
O2, in percent O2.
    Control period means the period starting January 1 of a calendar 
year, except as provided in Sec. 97.706(c)(3), and ending on December 
31 of the same year, inclusive.
    Designated representative means, for a TR SO2 Group 2 
source and each TR SO2 Group 2 unit at the source, the 
natural person who is authorized by the owners and operators of the 
source and all such units at the source, in accordance with this 
subpart, to represent and legally bind each owner and operator in 
matters pertaining to the TR SO2 Group 2 Trading Program. If 
the TR SO2 Group 2 source is also subject to the Acid Rain 
Program, TR NOX Annual Trading Program, or TR NOX 
Ozone Season Trading Program, then this natural person shall be the same 
natural person as the designated representative, as defined in the 
respective program.
    Emissions means air pollutants exhausted from a unit or source into 
the atmosphere, as measured, recorded, and reported to the Administrator 
by the designated representative, and as modified by the Administrator:
    (1) In accordance with this subpart; and
    (2) With regard to a period before the unit or source is required to 
measure, record, and report such air pollutants in accordance with this 
subpart, in accordance with part 75 of this chapter.
    Excess emissions means any ton of emissions from the TR 
SO2 Group 2 units at a TR SO2 Group 2 source 
during a control period in a given year that exceeds the TR 
SO2 Group 2 emissions limitation for the source for such 
control period.
    Fossil fuel means--
    (1) Natural gas, petroleum, coal, or any form of solid, liquid, or 
gaseous fuel derived from such material; or
    (2) For purposes of applying the limitation on ``average annual fuel 
consumption of fossil fuel'' in Sec. Sec. 97.704(b)(2)(i)(B) and (ii), 
natural gas, petroleum, coal, or any form of solid, liquid, or gaseous 
fuel derived from such material for the purpose of creating useful heat.
    Fossil-fuel-fired means, with regard to a unit, combusting any 
amount of fossil fuel in 2005 or any calendar year thereafter.
    General account means an Allowance Management System account, 
established under this subpart, that is not a compliance account or an 
assurance account.
    Generator means a device that produces electricity.
    Gross electrical output means, for a unit, electricity made 
available for use, including any such electricity used in the power 
production process (which process includes, but is not limited to, any 
on-site processing or treatment of fuel combusted at the unit and any 
on-site emission controls).
    Heat input means, for a unit for a specified period of time, the 
product (in mmBtu/time) of the gross calorific value of the fuel (in 
mmBtu/lb) fed into the unit multiplied by the fuel feed rate (in lb of 
fuel/time), as measured, recorded, and reported to the Administrator by 
the designated representative and as modified by the Administrator in 
accordance with this subpart and excluding the heat derived from

[[Page 489]]

preheated combustion air, recirculated flue gases, or exhaust.
    Heat input rate means, for a unit, the amount of heat input (in 
mmBtu) divided by unit operating time (in hr) or, for a unit and a 
specific fuel, the amount of heat input attributed to the fuel (in 
mmBtu) divided by the unit operating time (in hr) during which the unit 
combusts the fuel.
    Heat rate means, for a unit, the unit's maximum design heat input 
(in Btu/hr), divided by the product of 1,000,000 Btu/mmBtu and the 
unit's maximum hourly load.
    Indian country means ``Indian country'' as defined in 18 U.S.C. 
1151.
    Life-of-the-unit, firm power contractual arrangement means a unit 
participation power sales agreement under which a utility or industrial 
customer reserves, or is entitled to receive, a specified amount or 
percentage of nameplate capacity and associated energy generated by any 
specified unit and pays its proportional amount of such unit's total 
costs, pursuant to a contract:
    (1) For the life of the unit;
    (2) For a cumulative term of no less than 30 years, including 
contracts that permit an election for early termination; or
    (3) For a period no less than 25 years or 70 percent of the economic 
useful life of the unit determined as of the time the unit is built, 
with option rights to purchase or release some portion of the nameplate 
capacity and associated energy generated by the unit at the end of the 
period.
    Maximum design heat input means, for a unit, the maximum amount of 
fuel per hour (in Btu/hr) that the unit is capable of combusting on a 
steady state basis as of the initial installation of the unit as 
specified by the manufacturer of the unit.
    Monitoring system means any monitoring system that meets the 
requirements of this subpart, including a continuous emission monitoring 
system, an alternative monitoring system, or an excepted monitoring 
system under part 75 of this chapter.
    Nameplate capacity means, starting from the initial installation of 
a generator, the maximum electrical generating output (in MWe, rounded 
to the nearest tenth) that the generator is capable of producing on a 
steady state basis and during continuous operation (when not restricted 
by seasonal or other deratings) as of such installation as specified by 
the manufacturer of the generator or, starting from the completion of 
any subsequent physical change in the generator resulting in an increase 
in the maximum electrical generating output that the generator is 
capable of producing on a steady state basis and during continuous 
operation (when not restricted by seasonal or other deratings), such 
increased maximum amount (in MWe, rounded to the nearest tenth) as of 
such completion as specified by the person conducting the physical 
change.
    Natural gas means ``natural gas'' as defined in Sec. 72.2 of this 
chapter.
    Newly affected TR SO2 Group 2 unit means a unit that was 
not a TR SO2 Group 2 unit when it began operating but that 
thereafter becomes a TR SO2 Group 2 unit.
    Operate or operation means, with regard to a unit, to combust fuel.
    Operator means, for a TR SO2 Group 2 source or a TR 
SO2 Group 2 unit at a source respectively, any person who 
operates, controls, or supervises a TR SO2 Group 2 unit at 
the source or the TR SO2 Group 2 unit and shall include, but 
not be limited to, any holding company, utility system, or plant manager 
of such source or unit.
    Owner means, for a TR SO2 Group 2 source or a TR 
SO2 Group 2 unit at a source respectively, any of the 
following persons:
    (1) Any holder of any portion of the legal or equitable title in a 
TR SO2 Group 2 unit at the source or the TR SO2 
Group 2 unit;
    (2) Any holder of a leasehold interest in a TR SO2 Group 
2 unit at the source or the TR SO2 Group 2 unit, provided 
that, unless expressly provided for in a leasehold agreement, ``owner'' 
shall not include a passive lessor, or a person who has an equitable 
interest through such lessor, whose rental payments are not based 
(either directly or indirectly) on the revenues or income from such TR 
SO2 Group 2 unit; and
    (3) Any purchaser of power from a TR SO2 Group 2 unit at 
the source or the TR SO2 Group 2 unit under a life-of-

[[Page 490]]

the-unit, firm power contractual arrangement.
    Permanently retired means, with regard to a unit, a unit that is 
unavailable for service and that the unit's owners and operators do not 
expect to return to service in the future.
    Permitting authority means ``permitting authority'' as defined in 
Sec. Sec. 70.2 and 71.2 of this chapter.
    Potential electrical output capacity means, for a unit, 33 percent 
of the unit's maximum design heat input, divided by 3,413 Btu/kWh, 
divided by 1,000 kWh/MWh, and multiplied by 8,760 hr/yr.
    Receive or receipt of means, when referring to the Administrator, to 
come into possession of a document, information, or correspondence 
(whether sent in hard copy or by authorized electronic transmission), as 
indicated in an official log, or by a notation made on the document, 
information, or correspondence, by the Administrator in the regular 
course of business.
    Recordation, record, or recorded means, with regard to TR 
SO2 Group 2 allowances, the moving of TR SO2 Group 
2 allowances by the Administrator into, out of, or between Allowance 
Management System accounts, for purposes of allocation, auction, 
transfer, or deduction.
    Reference method means any direct test method of sampling and 
analyzing for an air pollutant as specified in Sec. 75.22 of this 
chapter.
    Replacement, replace, or replaced means, with regard to a unit, the 
demolishing of a unit, or the permanent retirement and permanent 
disabling of a unit, and the construction of another unit (the 
replacement unit) to be used instead of the demolished or retired unit 
(the replaced unit).
    Sequential use of energy means:
    (1) The use of reject heat from electricity production in a useful 
thermal energy application or process; or
    (2) The use of reject heat from useful thermal energy application or 
process in electricity production.
    Serial number means, for a TR SO2 Group 2 allowance, the 
unique identification number assigned to each TR SO2 Group 2 
allowance by the Administrator.
    Solid waste incineration unit means a stationary, fossil-fuel-fired 
boiler or stationary, fossil-fuel-fired combustion turbine that is a 
``solid waste incineration unit'' as defined in section 129(g)(1) of the 
Clean Air Act.
    Source means all buildings, structures, or installations located in 
one or more contiguous or adjacent properties under common control of 
the same person or persons. This definition does not change or otherwise 
affect the definition of ``major source'', ``stationary source'', or 
``source'' as set forth and implemented in a title V operating permit 
program or any other program under the Clean Air Act.
    State means one of the States that is subject to the TR 
SO2 Group 2 Trading Program pursuant to Sec. 52.39(a), (c), 
(g), (h), and (i) of this chapter.
    Submit or serve means to send or transmit a document, information, 
or correspondence to the person specified in accordance with the 
applicable regulation:
    (1) In person;
    (2) By United States Postal Service; or
    (3) By other means of dispatch or transmission and delivery;
    (4) Provided that compliance with any ``submission'' or ``service'' 
deadline shall be determined by the date of dispatch, transmission, or 
mailing and not the date of receipt.
    Topping-cycle unit means a unit in which the energy input to the 
unit is first used to produce useful power, including electricity, where 
at least some of the reject heat from the electricity production is then 
used to provide useful thermal energy.
    Total energy input means, for a unit, total energy of all forms 
supplied to the unit, excluding energy produced by the unit. Each form 
of energy supplied shall be measured by the lower heating value of that 
form of energy calculated as follows:

LHV = HHV - 10.55(W + 9H)

where:

LHV = lower heating value of the form of energy in Btu/lb,
HHV = higher heating value of the form of energy in Btu/lb,
W = weight % of moisture in the form of energy, and

[[Page 491]]

H = weight % of hydrogen in the form of energy.

    Total energy output means, for a unit, the sum of useful power and 
useful thermal energy produced by the unit.
    TR NOX Annual Trading Program means a multi-state NOX air 
pollution control and emission reduction program established in 
accordance with subpart AAAAA of this part and Sec. 52.38(a) of this 
chapter (including such a program that is revised in a SIP revision 
approved by the Administrator under Sec. 52.38(a)(3) or (4) of this 
chapter or that is established in a SIP revision approved by the 
Administrator under Sec. 52.38(a)(5) of this chapter), as a means of 
mitigating interstate transport of fine particulates and NOX.
    TR NOX Ozone Season Trading Program means a multi-state 
NOX air pollution control and emission reduction program 
established in accordance with subpart BBBBB of this part and Sec. 
52.38(b) of this chapter (including such a program that is revised in a 
SIP revision approved by the Administrator under Sec. 52.38(b)(3) or 
(4) of this chapter or that is established in a SIP revision approved by 
the Administrator under Sec. 52.38(b)(5) of this chapter), as a means 
of mitigating interstate transport of ozone and NOX.
    TR SO2 Group 2 allowance means a limited authorization issued and 
allocated or auctioned by the Administrator under this subpart, or by a 
State or permitting authority under a SIP revision approved by the 
Administrator under Sec. 52.39(g), (h), or (i) of this chapter, to emit 
one ton of SO2 during a control period of the specified 
calendar year for which the authorization is allocated or auctioned or 
of any calendar year thereafter under the TR SO2 Group 2 
Trading Program.
    TR SO2 Group 2 allowance deduction or deduct TR SO2 Group 2 
allowances means the permanent withdrawal of TR SO2 Group 2 
allowances by the Administrator from a compliance account (e.g., in 
order to account for compliance with the TR SO2 Group 2 
emissions limitation) or from an assurance account (e.g., in order to 
account for compliance with the assurance provisions under Sec. Sec. 
97.706 and 97.725).
    TR SO2 Group 2 allowances held or hold TR SO2 Group 2 allowances 
means the TR SO2 Group 2 allowances treated as included in an 
Allowance Management System account as of a specified point in time 
because at that time they:
    (1) Have been recorded by the Administrator in the account or 
transferred into the account by a correctly submitted, but not yet 
recorded, TR SO2 Group 2 allowance transfer in accordance 
with this subpart; and
    (2) Have not been transferred out of the account by a correctly 
submitted, but not yet recorded, TR SO2 Group 2 allowance 
transfer in accordance with this subpart.
    TR SO2 Group 2 emissions limitation means, for a TR SO2 
Group 2 source, the tonnage of SO2 emissions authorized in a 
control period by the TR SO2 Group 2 allowances available for deduction 
for the source under Sec. 97.724(a) for such control period.
    TR SO2 Group 2 source means a source that includes one or more TR 
SO2 Group 2 units.
    TR SO2 Group 2 Trading Program means a multi-state SO2 
air pollution control and emission reduction program established in 
accordance with this subpart and Sec. 52.39(a), (c), and (g) through 
(k) of this chapter (including such a program that is revised in a SIP 
revision approved by the Administrator under Sec. 52.39(g) or (h) of 
this chapter or that is established in a SIP revision approved by the 
Administrator under Sec. 52.39(i) of this chapter), as a means of 
mitigating interstate transport of fine particulates and SO2.
    TR SO2 Group 2 unit means a unit that is subject to the TR 
SO2 Group 2 Trading Program under Sec. 97.704.
    Unit means a stationary, fossil-fuel-fired boiler, stationary, 
fossil-fuel-fired combustion turbine, or other stationary, fossil-fuel-
fired combustion device. A unit that undergoes a physical change or is 
moved to a different location or source shall continue to be treated as 
the same unit. A unit (the replaced unit) that is replaced by another 
unit (the replacement unit) at the same or a different source shall 
continue to be treated as the same unit, and the replacement unit shall 
be treated as a separate unit.

[[Page 492]]

    Unit operating day means, with regard to a unit, a calendar day in 
which the unit combusts any fuel.
    Unit operating hour or hour of unit operation means, with regard to 
a unit, an hour in which the unit combusts any fuel.
    Useful power means, with regard to a unit, electricity or mechanical 
energy that the unit makes available for use, excluding any such energy 
used in the power production process (which process includes, but is not 
limited to, any on-site processing or treatment of fuel combusted at the 
unit and any on-site emission controls).
    Useful thermal energy means thermal energy that is:
    (1) Made available to an industrial or commercial process (not a 
power production process), excluding any heat contained in condensate 
return or makeup water;
    (2) Used in a heating application (e.g., space heating or domestic 
hot water heating); or
    (3) Used in a space cooling application (i.e., in an absorption 
chiller).
    Utility power distribution system means the portion of an 
electricity grid owned or operated by a utility and dedicated to 
delivering electricity to customers.



Sec. 97.703  Measurements, abbreviations, and acronyms.

    Measurements, abbreviations, and acronyms used in this subpart are 
defined as follows:

Btu--British thermal unit
CO2--carbon dioxide
H2O--water
hr--hour
kW--kilowatt electrical
kWh--kilowatt hour
lb--pound
mmBtu--million Btu
MWe--megawatt electrical
MWh--megawatt hour
NOX--nitrogen oxides
O2--oxygen
ppm--parts per million
scfh--standard cubic feet per hour
SO2--sulfur dioxide
yr--year



Sec. 97.704  Applicability.

    (a) Except as provided in paragraph (b) of this section:
    (1) The following units in a State (and Indian country within the 
borders of such State) shall be TR SO2 Group 2 units, and any 
source that includes one or more such units shall be a TR SO2 
Group 2 source, subject to the requirements of this subpart: Any 
stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired 
combustion turbine serving at any time, on or after January 1, 2005, a 
generator with nameplate capacity of more than 25 MWe producing 
electricity for sale.
    (2) If a stationary boiler or stationary combustion turbine that, 
under paragraph (a)(1) of this section, is not a TR SO2 Group 
2 unit begins to combust fossil fuel or to serve a generator with 
nameplate capacity of more than 25 MWe producing electricity for sale, 
the unit shall become a TR SO2 Group 2 unit as provided in 
paragraph (a)(1) of this section on the first date on which it both 
combusts fossil fuel and serves such generator.
    (b) Any unit in a State (and Indian country within the borders of 
such State) that otherwise is a TR SO2 Group 2 unit under 
paragraph (a) of this section and that meets the requirements set forth 
in paragraph (b)(1)(i) or (2)(i) of this section shall not be a TR 
SO2 Group 2 unit:
    (1)(i) Any unit:
    (A) Qualifying as a cogeneration unit throughout the later of 2005 
or the 12-month period starting on the date the unit first produces 
electricity and continuing to qualify as a cogeneration unit throughout 
each calendar year ending after the later of 2005 or such 12-month 
period; and
    (B) Not supplying in 2005 or any calendar year thereafter more than 
one-third of the unit's potential electric output capacity or 219,000 
MWh, whichever is greater, to any utility power distribution system for 
sale.
    (ii) If, after qualifying under paragraph (b)(1)(i) of this section 
as not being a TR SO2 Group 2 unit, a unit subsequently no 
longer meets all the requirements of paragraph (b)(1)(i) of this 
section, the unit shall become a TR SO2 Group 2 unit starting 
on the earlier of January 1 after the first calendar year during which 
the unit first no longer qualifies as a cogeneration unit or January 1 
after the first calendar year during which the unit no longer meets the 
requirements of paragraph (b)(1)(i)(B) of this section. The

[[Page 493]]

unit shall thereafter continue to be a TR SO2 Group 2 unit.
    (2)(i) Any unit:
    (A) Qualifying as a solid waste incineration unit throughout the 
later of 2005 or the 12-month period starting on the date the unit first 
produces electricity and continuing to qualify as a solid waste 
incineration unit throughout each calendar year ending after the later 
of 2005 or such 12-month period; and
    (B) With an average annual fuel consumption of fossil fuel for the 
first 3 consecutive calendar years of operation starting no earlier than 
2005 of less than 20 percent (on a Btu basis) and an average annual fuel 
consumption of fossil fuel for any 3 consecutive calendar years 
thereafter of less than 20 percent (on a Btu basis).
    (ii) If, after qualifying under paragraph (b)(2)(i) of this section 
as not being a TR SO2 Group 2 unit, a unit subsequently no 
longer meets all the requirements of paragraph (b)(1)(i) of this 
section, the unit shall become a TR SO2 Group 2 unit starting 
on the earlier of January 1 after the first calendar year during which 
the unit first no longer qualifies as a solid waste incineration unit or 
January 1 after the first 3 consecutive calendar years after 2005 for 
which the unit has an average annual fuel consumption of fossil fuel of 
20 percent or more. The unit shall thereafter continue to be a TR 
SO2 Group 2 unit.
    (c) A certifying official of an owner or operator of any unit or 
other equipment may submit a petition (including any supporting 
documents) to the Administrator at any time for a determination 
concerning the applicability, under paragraphs (a) and (b) of this 
section or a SIP revision approved under Sec. 52.39(h) or (i) of this 
chapter, of the TR SO2 Group 2 Trading Program to the unit or 
other equipment.
    (1) Petition content. The petition shall be in writing and include 
the identification of the unit or other equipment and the relevant facts 
about the unit or other equipment. The petition and any other documents 
provided to the Administrator in connection with the petition shall 
include the following certification statement, signed by the certifying 
official: ``I am authorized to make this submission on behalf of the 
owners and operators of the unit or other equipment for which the 
submission is made. I certify under penalty of law that I have 
personally examined, and am familiar with, the statements and 
information submitted in this document and all its attachments. Based on 
my inquiry of those individuals with primary responsibility for 
obtaining the information, I certify that the statements and information 
are to the best of my knowledge and belief true, accurate, and complete. 
I am aware that there are significant penalties for submitting false 
statements and information or omitting required statements and 
information, including the possibility of fine or imprisonment.''
    (2) Response. The Administrator will issue a written response to the 
petition and may request supplemental information determined by the 
Administrator to be relevant to such petition. The Administrator's 
determination concerning the applicability, under paragraphs (a) and (b) 
of this section, of the TR SO2 Group 2 Trading Program to the 
unit or other equipment shall be binding on any State or permitting 
authority unless the Administrator determines that the petition or other 
documents or information provided in connection with the petition 
contained significant, relevant errors or omissions.



Sec. 97.705  Retired unit exemption.

    (a)(1) Any TR SO2 Group 2 unit that is permanently 
retired shall be exempt from Sec. 97.706(b) and (c)(1), Sec. 97.724, 
and Sec. Sec. 97.730 through 97.735.
    (2) The exemption under paragraph (a)(1) of this section shall 
become effective the day on which the TR SO2 Group 2 unit is 
permanently retired. Within 30 days of the unit's permanent retirement, 
the designated representative shall submit a statement to the 
Administrator. The statement shall state, in a format prescribed by the 
Administrator, that the unit was permanently retired on a specified date 
and will comply with the requirements of paragraph (b) of this section.
    (b) Special provisions. (1) A unit exempt under paragraph (a) of 
this section shall not emit any SO2, starting

[[Page 494]]

on the date that the exemption takes effect.
    (2) For a period of 5 years from the date the records are created, 
the owners and operators of a unit exempt under paragraph (a) of this 
section shall retain, at the source that includes the unit, records 
demonstrating that the unit is permanently retired. The 5-year period 
for keeping records may be extended for cause, at any time before the 
end of the period, in writing by the Administrator. The owners and 
operators bear the burden of proof that the unit is permanently retired.
    (3) The owners and operators and, to the extent applicable, the 
designated representative of a unit exempt under paragraph (a) of this 
section shall comply with the requirements of the TR SO2 
Group 2 Trading Program concerning all periods for which the exemption 
is not in effect, even if such requirements arise, or must be complied 
with, after the exemption takes effect.
    (4) A unit exempt under paragraph (a) of this section shall lose its 
exemption on the first date on which the unit resumes operation. Such 
unit shall be treated, for purposes of applying allocation, monitoring, 
reporting, and recordkeeping requirements under this subpart, as a unit 
that commences commercial operation on the first date on which the unit 
resumes operation.



Sec. 97.706  Standard requirements.

    (a) Designated representative requirements. The owners and operators 
shall comply with the requirement to have a designated representative, 
and may have an alternate designated representative, in accordance with 
Sec. Sec. 97.713 through 97.718.
    (b) Emissions monitoring, reporting, and recordkeeping requirements. 
(1) The owners and operators, and the designated representative, of each 
TR SO2 Group 2 source and each TR SO2 Group 2 unit 
at the source shall comply with the monitoring, reporting, and 
recordkeeping requirements of Sec. Sec. 97.730 through 97.735.
    (2) The emissions data determined in accordance with Sec. Sec. 
97.730 through 97.735 shall be used to calculate allocations of TR 
SO2 Group 2 allowances under Sec. Sec. 97.711(a)(2) and (b) 
and 97.712 and to determine compliance with the TR SO2 Group 
2 emissions limitation and assurance provisions under paragraph (c) of 
this section, provided that, for each monitoring location from which 
mass emissions are reported, the mass emissions amount used in 
calculating such allocations and determining such compliance shall be 
the mass emissions amount for the monitoring location determined in 
accordance with Sec. Sec. 97.730 through 97.735 and rounded to the 
nearest ton, with any fraction of a ton less than 0.50 being deemed to 
be zero.
    (c) SO2 emissions requirements. (1) TR SO2 Group 2 
emissions limitation. (i) As of the allowance transfer deadline for a 
control period in a given year, the owners and operators of each TR 
SO2 Group 2 source and each TR SO2 Group 2 unit at 
the source shall hold, in the source's compliance account, TR 
SO2 Group 2 allowances available for deduction for such 
control period under Sec. 97.724(a) in an amount not less than the tons 
of total SO2 emissions for such control period from all TR 
SO2 Group 2 units at the source.
    (ii) If total SO2 emissions during a control period in a 
given year from the TR SO2 Group 2 units at a TR 
SO2 Group 2 source are in excess of the TR SO2 
Group 2 emissions limitation set forth in paragraph (c)(1)(i) of this 
section, then:
    (A) The owners and operators of the source and each TR 
SO2 Group 2 unit at the source shall hold the TR 
SO2 Group 2 allowances required for deduction under Sec. 
97.724(d); and
    (B) The owners and operators of the source and each TR 
SO2 Group 2 unit at the source shall pay any fine, penalty, 
or assessment or comply with any other remedy imposed, for the same 
violations, under the Clean Air Act, and each ton of such excess 
emissions and each day of such control period shall constitute a 
separate violation of this subpart and the Clean Air Act.
    (2) TR SO2 Group 2 assurance provisions. (i) If total 
SO2 emissions during a control period in a given year from 
all TR SO2 Group 2 units at TR SO2 Group 2 sources 
in a State (and Indian country within the borders of such State) exceed 
the State assurance level, then the owners and operators of such sources 
and units in each group of one or more sources and units having a

[[Page 495]]

common designated representative for such control period, where the 
common designated representative's share of such SO2 
emissions during such control period exceeds the common designated 
representative's assurance level for the State and such control period, 
shall hold (in the assurance account established for the owners and 
operators of such group) TR SO2 Group 2 allowances available 
for deduction for such control period under Sec. 97.725(a) in an amount 
equal to two times the product (rounded to the nearest whole number), as 
determined by the Administrator in accordance with Sec. 97.725(b), of 
multiplying--
    (A) The quotient of the amount by which the common designated 
representative's share of such SO2 emissions exceeds the 
common designated representative's assurance level divided by the sum of 
the amounts, determined for all common designated representatives for 
such sources and units in the State (and Indian country within the 
borders of such State) for such control period, by which each common 
designated representative's share of such SO2 emissions 
exceeds the respective common designated representative's assurance 
level; and
    (B) The amount by which total SO2 emissions from all TR 
SO2 Group 2 units at TR SO2 Group 2 sources in the 
State (and Indian country within the borders of such State) for such 
control period exceed the State assurance level.
    (ii) The owners and operators shall hold the TR SO2 Group 
2 allowances required under paragraph (c)(2)(i) of this section, as of 
midnight of November 1 (if it is a business day), or midnight of the 
first business day thereafter (if November 1 is not a business day), 
immediately after such control period.
    (iii) Total SO2 emissions from all TR SO2 
Group 2 units at TR SO2 Group 2 sources in a State (and 
Indian country within the borders of such State) during a control period 
in a given year exceed the State assurance level if such total 
SO2 emissions exceed the sum, for such control period, of the 
State SO2 Group 2 trading budget under Sec. 97.710(a) and 
the State's variability limit under Sec. 97.710(b).
    (iv) It shall not be a violation of this subpart or of the Clean Air 
Act if total SO2 emissions from all TR SO2 Group 2 
units at TR SO2 Group 2 sources in a State (and Indian 
country within the borders of such State) during a control period exceed 
the State assurance level or if a common designated representative's 
share of total SO2 emissions from the TR SO2 Group 
2 units at TR SO2 Group 2 sources in a State (and Indian 
country within the borders of such State) during a control period 
exceeds the common designated representative's assurance level.
    (v) To the extent the owners and operators fail to hold TR 
SO2 Group 2 allowances for a control period in a given year 
in accordance with paragraphs (c)(2)(i) through (iii) of this section,
    (A) The owners and operators shall pay any fine, penalty, or 
assessment or comply with any other remedy imposed under the Clean Air 
Act; and
    (B) Each TR SO2 Group 2 allowance that the owners and 
operators fail to hold for such control period in accordance with 
paragraphs (c)(2)(i) through (iii) of this section and each day of such 
control period shall constitute a separate violation of this subpart and 
the Clean Air Act.
    (3) Compliance periods. (i) A TR SO2 Group 2 unit shall 
be subject to the requirements under paragraph (c)(1) of this section 
for the control period starting on the later of January 1, 2015 or the 
deadline for meeting the unit's monitor certification requirements under 
Sec. 97.730(b) and for each control period thereafter.
    (ii) A TR SO2 Group 2 unit shall be subject to the 
requirements under paragraph (c)(2) of this section for the control 
period starting on the later of January 1, 2017 or the deadline for 
meeting the unit's monitor certification requirements under Sec. 
97.730(b) and for each control period thereafter.
    (4) Vintage of allowances held for compliance. (i) A TR 
SO2 Group 2 allowance held for compliance with the 
requirements under paragraph (c)(1)(i) of this section for a control 
period in a given year must be a TR SO2 Group 2 allowance 
that was allocated for such control period or a control period in a 
prior year.

[[Page 496]]

    (ii) A TR SO2 Group 2 allowance held for compliance with 
the requirements under paragraphs (c)(1)(ii)(A) and (2)(i) through (iii) 
of this section for a control period in a given year must be a TR 
SO2 Group 2 allowance that was allocated for a control period 
in a prior year or the control period in the given year or in the 
immediately following year.
    (5) Allowance Management System requirements. Each TR SO2 
Group 2 allowance shall be held in, deducted from, or transferred into, 
out of, or between Allowance Management System accounts in accordance 
with this subpart.
    (6) Limited authorization. A TR SO2 Group 2 allowance is 
a limited authorization to emit one ton of SO2 during the 
control period in one year. Such authorization is limited in its use and 
duration as follows:
    (i) Such authorization shall only be used in accordance with the TR 
SO2 Group 2 Trading Program; and
    (ii) Notwithstanding any other provision of this subpart, the 
Administrator has the authority to terminate or limit the use and 
duration of such authorization to the extent the Administrator 
determines is necessary or appropriate to implement any provision of the 
Clean Air Act.
    (7) Property right. A TR SO2 Group 2 allowance does not 
constitute a property right.
    (d) Title V permit requirements. (1) No title V permit revision 
shall be required for any allocation, holding, deduction, or transfer of 
TR SO2 Group 2 allowances in accordance with this subpart.
    (2) A description of whether a unit is required to monitor and 
report SO2 emissions using a continuous emission monitoring 
system (under subpart H of part 75 of this chapter), an excepted 
monitoring system (under appendices D and E to part 75 of this chapter), 
a low mass emissions excepted monitoring methodology (under Sec. 75.19 
of this chapter), or an alternative monitoring system (under subpart E 
of part 75 of this chapter) in accordance with Sec. Sec. 97.730 through 
97.735 may be added to, or changed in, a title V permit using minor 
permit modification procedures in accordance with Sec. Sec. 70.7(e)(2) 
and 71.7(e)(1) of this chapter, provided that the requirements 
applicable to the described monitoring and reporting (as added or 
changed, respectively) are already incorporated in such permit. This 
paragraph explicitly provides that the addition of, or change to, a 
unit's description as described in the prior sentence is eligible for 
minor permit modification procedures in accordance with Sec. Sec. 
70.7(e)(2)(i)(B) and 71.7(e)(1)(i)(B) of this chapter.
    (e) Additional recordkeeping and reporting requirements. (1) Unless 
otherwise provided, the owners and operators of each TR SO2 
Group 2 source and each TR SO2 Group 2 unit at the source 
shall keep on site at the source each of the following documents (in 
hardcopy or electronic format) for a period of 5 years from the date the 
document is created. This period may be extended for cause, at any time 
before the end of 5 years, in writing by the Administrator.
    (i) The certificate of representation under Sec. 97.716 for the 
designated representative for the source and each TR SO2 
Group 2 unit at the source and all documents that demonstrate the truth 
of the statements in the certificate of representation; provided that 
the certificate and documents shall be retained on site at the source 
beyond such 5-year period until such certificate of representation and 
documents are superseded because of the submission of a new certificate 
of representation under Sec. 97.716 changing the designated 
representative.
    (ii) All emissions monitoring information, in accordance with this 
subpart.
    (iii) Copies of all reports, compliance certifications, and other 
submissions and all records made or required under, or to demonstrate 
compliance with the requirements of, the TR SO2 Group 2 
Trading Program.
    (2) The designated representative of a TR SO2 Group 2 
source and each TR SO2 Group 2 unit at the source shall make 
all submissions required under the TR SO2 Group 2 Trading 
Program, except as provided in Sec. 97.718. This requirement does not 
change, create an exemption from, or otherwise affect the responsible 
official submission requirements under a title V operating

[[Page 497]]

permit program in parts 70 and 71 of this chapter.
    (f) Liability. (1) Any provision of the TR SO2 Group 2 
Trading Program that applies to a TR SO2 Group 2 source or 
the designated representative of a TR SO2 Group 2 source 
shall also apply to the owners and operators of such source and of the 
TR SO2 Group 2 units at the source.
    (2) Any provision of the TR SO2 Group 2 Trading Program 
that applies to a TR SO2 Group 2 unit or the designated 
representative of a TR SO2 Group 2 unit shall also apply to 
the owners and operators of such unit.
    (g) Effect on other authorities. No provision of the TR 
SO2 Group 2 Trading Program or exemption under Sec. 97.705 
shall be construed as exempting or excluding the owners and operators, 
and the designated representative, of a TR SO2 Group 2 source 
or TR SO2 Group 2 unit from compliance with any other 
provision of the applicable, approved State implementation plan, a 
federally enforceable permit, or the Clean Air Act.

[76 FR 48458, Aug. 8, 2011, as amended at 77 FR 10340, Feb. 21, 2012; 79 
FR 71672, Dec. 3, 2014]



Sec. 97.707  Computation of time.

    (a) Unless otherwise stated, any time period scheduled, under the TR 
SO2 Group 2 Trading Program, to begin on the occurrence of an 
act or event shall begin on the day the act or event occurs.
    (b) Unless otherwise stated, any time period scheduled, under the TR 
SO2 Group 2 Trading Program, to begin before the occurrence 
of an act or event shall be computed so that the period ends the day 
before the act or event occurs.
    (c) Unless otherwise stated, if the final day of any time period, 
under the TR SO2 Group 2 Trading Program, is not a business 
day, the time period shall be extended to the next business day.



Sec. 97.708  Administrative appeal procedures.

    The administrative appeal procedures for decisions of the 
Administrator under the TR SO2 Group 2 Trading Program are 
set forth in part 78 of this chapter.



Sec. 97.709  [Reserved]



Sec. 97.710  State SO[bdi2] Group 2 trading budgets, new unit set-
asides, Indian country new unit set-aside, and variability limits.

    (a) The State SO2 trading budgets, new unit set-asides, 
and Indian country new unit-set asides for allocations of TR 
SO2 Group 2 allowances for the control periods in 2015 and 
thereafter are as follows:
    (1) Alabama. (i) The SO2 trading budget for 2015 and 2016 
is 216,033 tons.
    (ii) The SO2 new unit set-aside for 2015 and 2016 is 
4,321 tons.
    (iii) [Reserved]
    (iv) The SO2 trading budget for 2017 and thereafter is 
213,258 tons.
    (v) The SO2 new unit set-aside for 2017 and thereafter is 
4,265 tons.
    (vi) [Reserved]
    (2) Georgia. (i) The SO2 trading budget for 2015 and 2016 
is 158,527 tons.
    (ii) The SO2 new unit set-aside for 2015 and 2016 is 
3,171 tons.
    (iii) [Reserved]
    (iv) The SO2 trading budget for 2017 and thereafter is 
135,565 tons.
    (v) The SO2 new unit set-aside for 2017 and thereafter is 
2,711 tons.
    (vi) [Reserved]
    (3) Kansas. (i) The SO2 trading budget for 2015 and 2016 
is 41,980 tons.
    (ii) The SO2 new unit set-aside for 2015 and 2016 is 798 
tons.
    (iii) The SO2 Indian country new unit set-aside for 2015 
and 2016 is 42 tons.
    (iv) The SO2 trading budget for 2017 and thereafter is 
41,980 tons.
    (v) The SO2 new unit set-aside for 2017 and thereafter is 
798 tons.
    (vi) The SO2 Indian country new unit set-aside for 2017 
and thereafter is 42 tons.
    (4) Minnesota. (i) The SO2 trading budget for 2015 and 
2016 is 41,981 tons.
    (ii) The SO2 new unit set-aside for 2015 and 2016 is 798 
tons.
    (iii) The SO2 Indian country new unit set-aside for 2015 
and 2016 is 42 tons.
    (iv) The SO2 trading budget for 2017 and thereafter is 
41,981 tons.
    (v) The SO2 new unit set-aside for 2017 and thereafter is 
798 tons.

[[Page 498]]

    (vi) The SO2 Indian country new unit set-aside for 2017 
and thereafter is 42 tons.
    (5) Nebraska. (i) The SO2 trading budget for 2015 and 
2016 is 68,162 tons.
    (ii) The SO2 new unit set-aside for 2015 and 2016 is 
2,658 tons.
    (iii) The SO2 Indian country new unit set-aside for 2015 
and 2016 is 68 tons.
    (iv) The SO2 trading budget for 2017 and thereafter is 
68,162 tons.
    (v) The SO2 new unit set-aside for 2017 and thereafter is 
2,658 tons.
    (vi) The SO2 Indian country new unit set-aside for 2017 
and thereafter is 68 tons.
    (6) South Carolina. (i) The SO2 trading budget for 2015 
and 2016 is 96,633 tons.
    (ii) The SO2 new unit set-aside for 2015 and 2016 is 
1,836 tons.
    (iii) The SO2 Indian country new unit set-aside for 2015 
and 2016 is 97 tons.
    (iv) The SO2 trading budget for 2017 and thereafter is 
96,633 tons.
    (v) The SO2 new unit set-aside for 2017 and thereafter is 
1,836 tons.
    (vi) The SO2 Indian country new unit set-aside for 2017 
and thereafter is 97 tons.
    (7) Texas. (i) The SO2 trading budget for 2015 and 2016 
is 294,471 tons.
    (ii) The SO2 new unit set-aside for 2015 and 2016 is 
14,430 tons.
    (iii) The SO2 Indian country new unit set-aside for 2015 
and 2016 is 294 tons.
    (iv) The SO2 trading budget for 2017 and thereafter is 
294,471 tons.
    (v) The SO2 new unit set-aside for 2017 and thereafter is 
14,430 tons.
    (vi) The SO2 Indian country new unit set-aside for 2017 
and thereafter is 294 tons.
    (b) The States' variability limits for the State SO2 
Group 2 trading budgets for the control periods in 2017 and thereafter 
are as follows:
    (1) The SO2 variability limit for Alabama is 38,386 tons.
    (2) The SO2 variability limit for Georgia is 24,402 tons.
    (3) The SO2 variability limit for Kansas is 7,556 tons.
    (4) The SO2 variability limit for Minnesota is 7,557 
tons.
    (5) The SO2 variability limit for Nebraska is 12,269 
tons.
    (6) The SO2 variability limit for South Carolina is 
17,394 tons.
    (7) The SO2 variability limit for Texas is 53,005 tons.
    (c) Each SO2 Group 2 trading budget in this section 
includes any tons identified under a new unit set aside or Indian 
country new unit set aside, but excludes any tons in a variability 
limit.

[77 FR 10340, Feb. 21, 2012, as amended at 77 FR 10349, Feb. 21, 2012; 
77 FR 34846, June 12, 2012; 79 FR 71672, Dec. 3, 2014]



Sec. 97.711  Timing requirements for TR SO[bdi2] Group 2 allowance
allocations.

    (a) Existing units. (1) TR SO2 Group 2 allowances are 
allocated, for the control periods in 2015 and each year thereafter, as 
provided in a notice of data availability issued by the Administrator. 
Providing an allocation to a unit in such notice does not constitute a 
determination that the unit is a TR SO2 Group 2 unit, and not 
providing an allocation to a unit in such notice does not constitute a 
determination that the unit is not a TR SO2 Group 2 unit.
    (2) Notwithstanding paragraph (a)(1) of this section, if a unit 
provided an allocation in the notice of data availability issued under 
paragraph (a)(1) of this section does not operate, starting after 2014, 
during the control period in two consecutive years, such unit will not 
be allocated the TR SO2 Group 2 allowances provided in such 
notice for the unit for the control periods in the fifth year after the 
first such year and in each year after that fifth year. All TR 
SO2 Group 2 allowances that would otherwise have been 
allocated to such unit will be allocated to the new unit set-aside for 
the State where such unit is located and for the respective years 
involved. If such unit resumes operation, the Administrator will 
allocate TR SO2 Group 2 allowances to the unit in accordance 
with paragraph (b) of this section.
    (b) New units. (1) New unit set-asides. (i) By June 1, 2015 and June 
1 of each year thereafter, the Administrator will calculate the TR 
SO2 Group 2 allowance allocation to each TR SO2 
Group 2 unit in a State, in accordance with Sec. 97.712(a)(2) through 
(7) and (12), for the control period in the year of the applicable 
calculation deadline under this paragraph and will promulgate a notice

[[Page 499]]

of data availability of the results of the calculations.
    (ii) For each notice of data availability required in paragraph 
(b)(1)(i) of this section, the Administrator will provide an opportunity 
for submission of objections to the calculations referenced in such 
notice.
    (A) Objections shall be submitted by the deadline specified in each 
notice of data availability required in paragraph (b)(1)(i) of this 
section and shall be limited to addressing whether the calculations 
(including the identification of the TR SO2 Group 2 units) 
are in accordance with Sec. 97.712(a)(2) through (7) and (12) and 
Sec. Sec. 97.706(b)(2) and 97.730 through 97.735.
    (B) The Administrator will adjust the calculations to the extent 
necessary to ensure that they are in accordance with the provisions 
referenced in paragraph (b)(1)(ii)(A) of this section. By August 1 
immediately after the promulgation of each notice of data availability 
required in paragraph (b)(1)(i) of this section, the Administrator will 
promulgate a notice of data availability of any adjustments that the 
Administrator determines to be necessary with regard to allocations 
under Sec. 97.712(a)(2) through (7) and (12) and the reasons for 
accepting or rejecting any objections submitted in accordance with 
paragraph (b)(1)(ii)(A) of this section.
    (iii) If the new unit set-aside for such control period contains any 
TR SO2 Group 2 allowances that have not been allocated in the 
applicable notice of data availability required in paragraph (b)(1)(ii) 
of this section, the Administrator will promulgate, by December 15 
immediately after such notice, a notice of data availability that 
identifies any TR SO2 Group 2 units that commenced commercial 
operation during the period starting January 1 of the year before the 
year of such control period and ending November 30 of year of such 
control period.
    (iv) For each notice of data availability required in paragraph 
(b)(1)(iii) of this section, the Administrator will provide an 
opportunity for submission of objections to the identification of TR 
SO2 annual units in such notice.
    (A) Objections shall be submitted by the deadline specified in each 
notice of data availability required in paragraph (b)(1)(iii) of this 
section and shall be limited to addressing whether the identification of 
TR SO2 annual units in such notice is in accordance with 
paragraph (b)(1)(iii) of this section.
    (B) The Administrator will adjust the identification of TR 
SO2 Group 2 units in the each notice of data availability 
required in paragraph (b)(1)(iii) of this section to the extent 
necessary to ensure that it is in accordance with paragraph (b)(1)(iii) 
of this section and will calculate the TR SO2 Group 2 
allowance allocation to each TR SO2 Group 2 unit in 
accordance with Sec. 97.712(a)(9), (10), and (12) and Sec. Sec. 
97.706(b)(2) and 97.730 through 97.735. By February 15 immediately after 
the promulgation of each notice of data availability required in 
paragraph (b)(1)(iii) of this section, the Administrator will promulgate 
a notice of data availability of any adjustments of the identification 
of TR SO2 Group 2 units that the Administrator determines to 
be necessary, the reasons for accepting or rejecting any objections 
submitted in accordance with paragraph (b)(1)(iv)(A) of this section, 
and the results of such calculations.
    (v) To the extent any TR SO2 Group 2 allowances are added 
to the new unit set-aside after promulgation of each notice of data 
availability required in paragraph (b)(1)(iv) of this section, the 
Administrator will promulgate additional notices of data availability, 
as deemed appropriate, of the allocation of such TR SO2 Group 
2 allowances in accordance with Sec. 97.712(a)(10).
    (2) Indian country new unit set-asides. (i) By June 1, 2015 and June 
1 of each year thereafter, the Administrator will calculate the TR 
SO2 Group 2 allowance allocation to each TR SO2 
Group 2 unit in Indian country within the borders of a State, in 
accordance with Sec. 97.712(b)(2) through (7) and (12), for the control 
period in the year of the applicable calculation deadline under this 
paragraph and will promulgate a notice of data availability of the 
results of the calculations.
    (ii) For each notice of data availability required in paragraph 
(b)(2)(i) of this section, the Administrator will provide an opportunity 
for submission

[[Page 500]]

of objections to the calculations referenced in such notice.
    (A) Objections shall be submitted by the deadline specified in each 
notice of data availability required in paragraph (b)(2)(i) of this 
section and shall be limited to addressing whether the calculations 
(including the identification of the TR SO2 Group 2 units) 
are in accordance with Sec. 97.712(b)(2) through (7) and (12) and 
Sec. Sec. 97.706(b)(2) and 97.730 through 97.735.
    (B) The Administrator will adjust the calculations to the extent 
necessary to ensure that they are in accordance with the provisions 
referenced in paragraph (b)(2)(ii)(A) of this section. By August 1 
immediately after the promulgation of each notice of data availability 
required in paragraph (b)(2)(i) of this section, the Administrator will 
promulgate a notice of data availability of any adjustments that the 
Administrator determines to be necessary with regard to allocations 
under Sec. 97.712(b)(2) through (7) and (12) and the reasons for 
accepting or rejecting any objections submitted in accordance with 
paragraph (b)(2)(ii)(A) of this section.
    (iii) If the Indian country new unit set-aside for such control 
period contains any TR SO2 Group 2 allowances that have not 
been allocated in the applicable notice of data availability required in 
paragraph (b)(2)(ii) of this section, the Administrator will promulgate, 
by December 15 immediately after such notice, a notice of data 
availability that identifies any TR SO2 Group 2 units that 
commenced commercial operation during the period starting January 1 of 
the year before the year of such control period and ending November 30 
of year of such control period.
    (iv) For each notice of data availability required in paragraph 
(b)(2)(iii) of this section, the Administrator will provide an 
opportunity for submission of objections to the identification of TR 
SO2 annual units in such notice.
    (A) Objections shall be submitted by the deadline specified in each 
notice of data availability required in paragraph (b)(2)(iii) of this 
section and shall be limited to addressing whether the identification of 
TR SO2 annual units in such notice is in accordance with 
paragraph (b)(2)(iii) of this section.
    (B) The Administrator will adjust the identification of TR 
SO2 Group 2 units in the each notice of data availability 
required in paragraph (b)(2)(iii) of this section to the extent 
necessary to ensure that it is in accordance with paragraph (b)(2)(iii) 
of this section and will calculate the TR SO2 Group 2 
allowance allocation to each TR SO2 Group 2 unit in 
accordance with Sec. 97.712(b)(9), (10), and (12) and Sec. Sec. 
97.706(b)(2) and 97.730 through 97.735. By February 15 immediately after 
the promulgation of each notice of data availability required in 
paragraph (b)(2)(iii) of this section, the Administrator will promulgate 
a notice of data availability of any adjustments of the identification 
of TR SO2 Group 2 units that the Administrator determines to 
be necessary, the reasons for accepting or rejecting any objections 
submitted in accordance with paragraph (b)(2)(iv)(A) of this section, 
and the results of such calculations.
    (v) To the extent any TR SO2 Group 2 allowances are added 
to the Indian country new unit set-aside after promulgation of each 
notice of data availability required in paragraph (b)(2)(iv) of this 
section, the Administrator will promulgate additional notices of data 
availability, as deemed appropriate, of the allocation of such TR 
SO2 Group 2 allowances in accordance with Sec. 
97.712(b)(10).
    (c) Units incorrectly allocated TR SO2 Group 2 allowances. (1) For 
each control period in 2015 and thereafter, if the Administrator 
determines that TR SO2 Group 2 allowances were allocated 
under paragraph (a) of this section, or under a provision of a SIP 
revision approved Sec. 52.39(g), (h), or (i) of this chapter, where 
such control period and the recipient are covered by the provisions of 
paragraph (c)(1)(i) of this section or were allocated under Sec. 
97.712(a)(2) through (7), (9), and (12) and (b)(2) through (7), (9), and 
(12), or under a provision of a SIP revision approved Sec. 52.39(h) or 
(i) of this chapter, where such control period and the recipient are 
covered by the provisions of paragraph (c)(1)(ii) of this section, then 
the Administrator will notify the designated representative of the 
recipient

[[Page 501]]

and will act in accordance with the procedures set forth in paragraphs 
(c)(2) through (5) of this section:
    (i)(A) The recipient is not actually a TR SO2 Group 2 
unit under Sec. 97.704 as of January 1, 2015 and is allocated TR 
SO2 Group 2 allowances for such control period or, in the 
case of an allocation under a provision of a SIP revision approved under 
Sec. 52.39(g), (h), or (i) of this chapter, the recipient is not 
actually a TR SO2 Group 2 unit as of January 1, 2015 and is 
allocated TR SO2 Group 2 allowances for such control period 
that the SIP revision provides should be allocated only to recipients 
that are TR SO2 Group 2 units as of January 1, 2015; or
    (B) The recipient is not located as of January 1 of the control 
period in the State from whose SO2 Group 2 trading budget the 
TR SO2 Group 2 allowances allocated under paragraph (a) of 
this section, or under a provision of a SIP revision approved under 
Sec. 52.39(g), (h), or (i) of this chapter, were allocated for such 
control period.
    (ii) The recipient is not actually a TR SO2 Group 2 unit 
under Sec. 97.704 as of January 1 of such control period and is 
allocated TR SO2 Group 2 allowances for such control period 
or, in the case of an allocation under a provision of a SIP revision 
approved under Sec. 52.39(g), (h), or (i) of this chapter, the 
recipient is not actually a TR SO2 Group 2 unit as of January 
1 of such control period and is allocated TR SO2 Group 2 
allowances for such control period that the SIP revision provides should 
be allocated only to recipients that are TR SO2 Group 2 units 
as of January 1 of such control period.
    (2) Except as provided in paragraph (c)(3) or (4) of this section, 
the Administrator will not record such TR SO2 Group 2 
allowances under Sec. 97.721.
    (3) If the Administrator already recorded such TR SO2 
Group 2 allowances under Sec. 97.721 and if the Administrator makes the 
determination under paragraph (c)(1) of this section before making 
deductions for the source that includes such recipient under Sec. 
97.724(b) for such control period, then the Administrator will deduct 
from the account in which such TR SO2 Group 2 allowances were 
recorded an amount of TR SO2 Group 2 allowances allocated for 
the same or a prior control period equal to the amount of such already 
recorded TR SO2 Group 2 allowances. The authorized account 
representative shall ensure that there are sufficient TR SO2 
Group 2 allowances in such account for completion of the deduction.
    (4) If the Administrator already recorded such TR SO2 
Group 2 allowances under Sec. 97.721 and if the Administrator makes the 
determination under paragraph (c)(1) of this section after making 
deductions for the source that includes such recipient under Sec. 
97.724(b) for such control period, then the Administrator will not make 
any deduction to take account of such already recorded TR SO2 
Group 2 allowances.
    (5)(i) With regard to the TR SO2 Group 2 allowances that 
are not recorded, or that are deducted as an incorrect allocation, in 
accordance with paragraphs (c)(2) and (3) of this section for a 
recipient under paragraph (c)(1)(i) of this section, the Administrator 
will:
    (A) Transfer such TR SO2 Group 2 allowances to the new 
unit set-aside for such control period for the State from whose 
SO2 Group 2 trading budget the TR SO2 Group 2 
allowances were allocated; or
    (B) If the State has a SIP revision approved under Sec. 52.39(h) or 
(i) covering such control period, include such TR SO2 Group 2 
allowances in the portion of the State SO2 Group 2 trading 
budget that may be allocated for such control period in accordance with 
such SIP revision.
    (ii) With regard to the TR SO2 Group 2 allowances that 
were not allocated from the Indian country new unit set-aside for such 
control period and that are not recorded, or that are deducted as an 
incorrect allocation, in accordance with paragraphs (c)(2) and (3) of 
this section for a recipient under paragraph (c)(1)(ii) of this 
paragraph, the Administrator will:
    (A) Transfer such TR SO2 Group 2 allowances to the new 
unit set-aside for such control period; or
    (B) If the State has a SIP revision approved under Sec. 52.39(h) or 
(i) covering such control period, include such TR SO2 Group 2 
allowances in the portion

[[Page 502]]

of the State SO2 Group 2 trading budget that may be allocated 
for such control period in accordance with such SIP revision.
    (iii) With regard to the TR SO2 Group 2 allowances that 
were allocated from the Indian country new unit set-aside for such 
control period and that are not recorded, or that are deducted as an 
incorrect allocation, in accordance with paragraphs (c)(2) and (3) of 
this section for a recipient under paragraph (c)(1)(ii) of this 
paragraph, the Administrator will transfer such TR SO2 Group 
2 allowances to the Indian country new unit set-aside for such control 
period.

[76 FR 48379, Aug. 8, 2011, as amended at 79 FR 71672, Dec. 3, 2014]



Sec. 97.712  TR SO[bdi2] Group 2 allowance allocations to new units.

    (a) For each control period in 2015 and thereafter and for the TR 
SO2 Group 2 units in each State, the Administrator will 
allocate TR SO2 Group 2 allowances to the TR SO2 
Group 2 units as follows:
    (1) The TR SO2 Group 2 allowances will be allocated to 
the following TR SO2 Group 2 units, except as provided in 
paragraph (a)(10) of this section:
    (i) TR SO2 Group 2 units that are not allocated an amount 
of TR SO2 Group 2 allowances in the notice of data 
availability issued under Sec. 97.711(a)(1);
    (ii) TR SO2 Group 2 units whose allocation of an amount 
of TR SO2 Group 2 allowances for such control period in the 
notice of data availability issued under Sec. 97.711(a)(1) is covered 
by Sec. 97.711(c)(2) or (3);
    (iii) TR SO2 Group 2 units that are allocated an amount 
of TR SO2 Group 2 allowances for such control period in the 
notice of data availability issued under Sec. 97.711(a)(1), which 
allocation is terminated for such control period pursuant to Sec. 
97.711(a)(2), and that operate during the control period immediately 
preceding such control period; or
    (iv) For purposes of paragraph (a)(9) of this section, TR 
SO2 Group 2 units under Sec. 97.711(c)(1)(ii) whose 
allocation of an amount of TR SO2 Group 2 allowances for such 
control period in the notice of data availability issued under Sec. 
97.711(b)(1)(ii)(B) is covered by Sec. 97.711(c)(2) or (3).
    (2) The Administrator will establish a separate new unit set-aside 
for the State for each such control period. Each such new unit set-aside 
will be allocated TR SO2 Group 2 allowances in an amount 
equal to the applicable amount of tons of SO2 emissions as 
set forth in Sec. 97.710(a) and will be allocated additional TR 
SO2 Group 2 allowances (if any) in accordance with Sec. Sec. 
97.711(a)(2) and (c)(5) and paragraph (b)(10) of this section.
    (3) The Administrator will determine, for each TR SO2 
Group 2 unit described in paragraph (a)(1) of this section, an 
allocation of TR SO2 Group 2 allowances for the later of the 
following control periods and for each subsequent control period:
    (i) The control period in 2015;
    (ii) The first control period after the control period in which the 
TR SO2 Group 2 unit commences commercial operation;
    (iii) For a unit described in paragraph (a)(1)(ii) of this section, 
the first control period in which the TR SO2 Group 2 unit 
operates in the State after operating in another jurisdiction and for 
which the unit is not already allocated one or more TR SO2 
Group 2 allowances; and
    (iv) For a unit described in paragraph (a)(1)(iii) of this section, 
the first control period after the control period in which the unit 
resumes operation.
    (4)(i) The allocation to each TR SO2 annual unit 
described in paragraph (a)(1)(i) through (iii) of this section and for 
each control period described in paragraph (a)(3) of this section will 
be an amount equal to the unit's total tons of SO2 emissions 
during the immediately preceding control period.
    (ii) The Administrator will adjust the allocation amount in 
paragraph (a)(4)(i) in accordance with paragraphs (a)(5) through (7) and 
(12) of this section.
    (5) The Administrator will calculate the sum of the TR 
SO2 Group 2 allowances determined for all such TR 
SO2 Group 2 units under paragraph (a)(4)(i) of this section 
in the State for such control period.
    (6) If the amount of TR SO2 Group 2 allowances in the new 
unit set-aside for the State for such control period is greater than or 
equal to the sum under

[[Page 503]]

paragraph (a)(5) of this section, then the Administrator will allocate 
the amount of TR SO2 Group 2 allowances determined for each 
such TR SO2 Group 2 unit under paragraph (a)(4)(i) of this 
section.
    (7) If the amount of TR SO2 Group 2 allowances in the new 
unit set-aside for the State for such control period is less than the 
sum under paragraph (a)(5) of this section, then the Administrator will 
allocate to each such TR SO2 Group 2 unit the amount of the 
TR SO2 Group 2 allowances determined under paragraph 
(a)(4)(i) of this section for the unit, multiplied by the amount of TR 
SO2 Group 2 allowances in the new unit set-aside for such 
control period, divided by the sum under paragraph (a)(5) of this 
section, and rounded to the nearest allowance.
    (8) The Administrator will notify the public, through the 
promulgation of the notices of data availability described in Sec. 
97.711(b)(1)(i) and (ii), of the amount of TR SO2 Group 2 
allowances allocated under paragraphs (a)(2) through (7) and (12) of 
this section for such control period to each TR SO2 Group 2 
unit eligible for such allocation.
    (9) If, after completion of the procedures under paragraphs (a)(5) 
through (8) of this section for such control period, any unallocated TR 
SO2 Group 2 allowances remain in the new unit set-aside for 
the State for such control period, the Administrator will allocate such 
TR SO2 Group 2 allowances as follows--
    (i) The Administrator will determine, for each unit described in 
paragraph (a)(1) of this section that commenced commercial operation 
during the period starting January 1 of the year before the year of such 
control period and ending November 30 of year of such control period, 
the positive difference (if any) between the unit's emissions during 
such control period and the amount of TR SO2 Group 2 
allowances referenced in the notice of data availability required under 
Sec. 97.711(b)(1)(ii) for the unit for such control period;
    (ii) The Administrator will determine the sum of the positive 
differences determined under paragraph (a)(9)(i) of this section;
    (iii) If the amount of unallocated TR SO2 Group 2 
allowances remaining in the new unit set-aside for the State for such 
control period is greater than or equal to the sum determined under 
paragraph (a)(9)(ii) of this section, then the Administrator will 
allocate the amount of TR SO2 Group 2 allowances determined 
for each such TR SO2 Group 2 unit under paragraph (a)(9)(i) 
of this section; and
    (iv) If the amount of unallocated TR SO2 Group 2 
allowances remaining in the new unit set-aside for the State for such 
control period is less than the sum under paragraph (a)(9)(ii) of this 
section, then the Administrator will allocate to each such TR 
SO2 Group 2 unit the amount of the TR SO2 Group 2 
allowances determined under paragraph (a)(9)(i) of this section for the 
unit, multiplied by the amount of unallocated TR SO2 Group 2 
allowances remaining in the new unit set-aside for such control period, 
divided by the sum under paragraph (a)(9)(ii) of this section, and 
rounded to the nearest allowance.
    (10) If, after completion of the procedures under paragraphs (a)(9) 
and (12) of this section for such control period, any unallocated TR 
SO2 Group 2 allowances remain in the new unit set-aside for 
the State for such control period, the Administrator will allocate to 
each TR SO2 Group 2 unit that is in the State, is allocated 
an amount of TR SO2 Group 2 allowances in the notice of data 
availability issued under Sec. 97.711(a)(1), and continues to be 
allocated TR SO2 Group 2 allowances for such control period 
in accordance with Sec. 97.711(a)(2), an amount of TR SO2 
Group 2 allowances equal to the following: The total amount of such 
remaining unallocated TR SO2 Group 2 allowances in such new 
unit set-aside, multiplied by the unit's allocation under Sec. 
97.711(a) for such control period, divided by the remainder of the 
amount of tons in the applicable State SO2 Group 2 trading 
budget minus the sum of the amounts of tons in such new unit set-aside 
and the Indian country new unit set-aside for the State for such control 
period, and rounded to the nearest allowance.
    (11) The Administrator will notify the public, through the 
promulgation

[[Page 504]]

of the notices of data availability described in Sec. 
97.711(b)(1)(iii), (iv), and (v), of the amount of TR SO2 
Group 2 allowances allocated under paragraphs (a)(9), (10), and (12) of 
this section for such control period to each TR SO2 Group 2 
unit eligible for such allocation.
    (12)(i) Notwithstanding the requirements of paragraphs (a)(2) 
through (11) of this section, if the calculations of allocations of a 
new unit set-aside for a control period in a given year under paragraph 
(a)(7) of this section, paragraphs (a)(6) and (9)(iv) of this section, 
or paragraphs (a)(6), (9)(iii), and (10) of this section would otherwise 
result in total allocations of such new unit set-aside exceeding the 
total amount of such new unit set-aside, then the Administrator will 
adjust the results of the calculations under paragraph (a)(7), (9)(iv), 
or (10) of this section, as applicable, as follows. The Administrator 
will list the TR SO2 Group 2 units in descending order based 
on the amount of such units' allocations under paragraph (a)(7), 
(9)(iv), or (10) of this section, as applicable, and, in cases of equal 
allocation amounts, in alphabetical order of the relevant source's name 
and numerical order of the relevant unit's identification number, and 
will reduce each unit's allocation under paragraph (a)(7), (9)(iv), or 
(10) of this section, as applicable, by one TR SO2 Group 2 
allowance (but not below zero) in the order in which the units are 
listed and will repeat this reduction process as necessary, until the 
total allocations of such new unit set-aside equal the total amount of 
such new unit set-aside.
    (ii) Notwithstanding the requirements of paragraphs (a)(10) and (11) 
of this section, if the calculations of allocations of a new unit set-
aside for a control period in a given year under paragraphs (a)(6), 
(9)(iii), and (10) of this section would otherwise result in a total 
allocations of such new unit set-aside less than the total amount of 
such new unit set-aside, then the Administrator will adjust the results 
of the calculations under paragraph (a)(10) of this section, as follows. 
The Administrator will list the TR SO2 Group 2 units in 
descending order based on the amount of such units' allocations under 
paragraph (a)(10) of this section and, in cases of equal allocation 
amounts, in alphabetical order of the relevant source's name and 
numerical order of the relevant unit's identification number, and will 
increase each unit's allocation under paragraph (a)(10) of this section 
by one TR SO2 Group 2 allowance in the order in which the 
units are listed and will repeat this increase process as necessary, 
until the total allocations of such new unit set-aside equal the total 
amount of such new unit set-aside.
    (b) For each control period in 2015 and thereafter and for the TR 
SO2 Group 2 units located in Indian country within the 
borders of each State, the Administrator will allocate TR SO2 
Group 2 allowances to the TR SO2 Group 2 units as follows:
    (1) The TR SO2 Group 2 allowances will be allocated to 
the following TR SO2 Group 2 units, except as provided in 
paragraph (b)(10) of this section:
    (i) TR SO2 Group 2 units that are not allocated an amount 
of TR SO2 Group 2 allowances in the notice of data 
availability issued under Sec. 97.711(a)(1); or
    (ii) For purposes of paragraph (b)(9) of this section, TR 
SO2 Group 2 units under Sec. 97.711(c)(1)(ii) whose 
allocation of an amount of TR SO2 Group 2 allowances for such 
control period in the notice of data availability issued under Sec. 
97.711(b)(2)(ii)(B) is covered by Sec. 97.711(c)(2) or (3).
    (2) The Administrator will establish a separate Indian country new 
unit set-aside for the State for each such control period. Each such 
Indian country new unit set-aside will be allocated TR SO2 
Group 2 allowances in an amount equal to the applicable amount of tons 
of SO2 emissions as set forth in Sec. 97.710(a) and will be 
allocated additional TR SO2 Group 2 allowances (if any) in 
accordance with Sec. 97.711(c)(5).
    (3) The Administrator will determine, for each TR SO2 
Group 2 unit described in paragraph (b)(1) of this section, an 
allocation of TR SO2 Group 2 allowances for the later of the 
following control periods and for each subsequent control period:
    (i) The control period in 2015; and
    (ii) The first control period after the control period in which the 
TR SO2 Group 2 unit commences commercial operation.

[[Page 505]]

    (4)(i) The allocation to each TR SO2 annual unit 
described in paragraph (b)(1)(i) of this section and for each control 
period described in paragraph (b)(3) of this section will be an amount 
equal to the unit's total tons of SO2 emissions during the 
immediately preceding control period.
    (ii) The Administrator will adjust the allocation amount in 
paragraph (b)(4)(i) in accordance with paragraphs (b)(5) through (7) and 
(12) of this section.
    (5) The Administrator will calculate the sum of the TR 
SO2 Group 2 allowances determined for all such TR 
SO2 Group 2 units under paragraph (b)(4)(i) of this section 
in Indian country within the borders of the State for such control 
period.
    (6) If the amount of TR SO2 Group 2 allowances in the 
Indian country new unit set-aside for the State for such control period 
is greater than or equal to the sum under paragraph (b)(5) of this 
section, then the Administrator will allocate the amount of TR 
SO2 Group 2 allowances determined for each such TR 
SO2 Group 2 unit under paragraph (b)(4)(i) of this section.
    (7) If the amount of TR SO2 Group 2 allowances in the 
Indian country new unit set-aside for the State for such control period 
is less than the sum under paragraph (b)(5) of this section, then the 
Administrator will allocate to each such TR SO2 Group 2 unit 
the amount of the TR SO2 Group 2 allowances determined under 
paragraph (b)(4)(i) of this section for the unit, multiplied by the 
amount of TR SO2 Group 2 allowances in the Indian country new 
unit set-aside for such control period, divided by the sum under 
paragraph (b)(5) of this section, and rounded to the nearest allowance.
    (8) The Administrator will notify the public, through the 
promulgation of the notices of data availability described in Sec. 
97.711(b)(2)(i) and (ii), of the amount of TR SO2 Group 2 
allowances allocated under paragraphs (b)(2) through (7) and (12) of 
this section for such control period to each TR SO2 Group 2 
unit eligible for such allocation.
    (9) If, after completion of the procedures under paragraphs (b)(5) 
through (8) of this section for such control period, any unallocated TR 
SO2 Group 2 allowances remain in the Indian country new unit 
set-aside for the State for such control period, the Administrator will 
allocate such TR SO2 Group 2 allowances as follows--
    (i) The Administrator will determine, for each unit described in 
paragraph (b)(1) of this section that commenced commercial operation 
during the period starting January 1 of the year before the year of such 
control period and ending November 30 of year of such control period, 
the positive difference (if any) between the unit's emissions during 
such control period and the amount of TR SO2 Group 2 
allowances referenced in the notice of data availability required under 
Sec. 97.711(b)(2)(ii) for the unit for such control period;
    (ii) The Administrator will determine the sum of the positive 
differences determined under paragraph (b)(9)(i) of this section;
    (iii) If the amount of unallocated TR SO2 Group 2 
allowances remaining in the Indian country new unit set-aside for the 
State for such control period is greater than or equal to the sum 
determined under paragraph (b)(9)(ii) of this section, then the 
Administrator will allocate the amount of TR SO2 Group 2 
allowances determined for each such TR SO2 Group 2 unit under 
paragraph (b)(9)(i) of this section; and
    (iv) If the amount of unallocated TR SO2 Group 2 
allowances remaining in the Indian country new unit set-aside for the 
State for such control period is less than the sum under paragraph 
(b)(9)(ii) of this section, then the Administrator will allocate to each 
such TR SO2 Group 2 unit the amount of the TR SO2 
Group 2 allowances determined under paragraph (b)(9)(i) of this section 
for the unit, multiplied by the amount of unallocated TR SO2 
Group 2 allowances remaining in the Indian country new unit set-aside 
for such control period, divided by the sum under paragraph (b)(9)(ii) 
of this section, and rounded to the nearest allowance.
    (10) If, after completion of the procedures under paragraphs (b)(9) 
and (12) of this section for such control period, any unallocated TR 
SO2 Group 2 allowances remain in the Indian country new unit 
set-aside for the State for

[[Page 506]]

such control period, the Administrator will:
    (i) Transfer such unallocated TR SO2 Group 2 allowances 
to the new unit set-aside for the State for such control period; or
    (ii) If the State has a SIP revision approved under Sec. 52.39(g), 
(h), or (i) of this chapter covering such control period, include such 
unallocated TR SO2 Group 2 allowances in the portion of the 
State SO2 Group 2 trading budget that may be allocated for 
such control period in accordance with such SIP revision.
    (11) The Administrator will notify the public, through the 
promulgation of the notices of data availability described in Sec. 
97.711(b)(2)(iii), (iv), and (v), of the amount of TR SO2 
Group 2 allowances allocated under paragraphs (b)(9), (10), and (12) of 
this section for such control period to each TR SO2 Group 2 
unit eligible for such allocation.
    (12)(i) Notwithstanding the requirements of paragraphs (b)(2) 
through (11) of this section, if the calculations of allocations of an 
Indian country new unit set-aside for a control period in a given year 
under paragraph (b)(7) of this section, paragraphs (b)(6) and (9)(iv) of 
this section, or paragraphs (b)(6), (9)(iii), and (10) of this section 
would otherwise result in total allocations of such Indian country new 
unit set-aside exceeding the total amount of such Indian country new 
unit set-aside, then the Administrator will adjust the results of the 
calculations under paragraph (b)(7), (9)(iv), or (10) of this section, 
as applicable, as follows. The Administrator will list the TR 
SO2 Group 2 units in descending order based on the amount of 
such units' allocations under paragraph (b)(7), (9)(iv), or (10) of this 
section, as applicable, and, in cases of equal allocation amounts, in 
alphabetical order of the relevant source's name and numerical order of 
the relevant unit's identification number, and will reduce each unit's 
allocation under paragraph (b)(7), (9)(iv), or (10) of this section, as 
applicable, by one TR SO2 Group 2 allowance (but not below 
zero) in the order in which the units are listed and will repeat this 
reduction process as necessary, until the total allocations of such 
Indian country new unit set-aside equal the total amount of such Indian 
country new unit set-aside.
    (ii) Notwithstanding the requirements of paragraphs (b)(10) and (11) 
of this section, if the calculations of allocations of an Indian country 
new unit set-aside for a control period in a given year under paragraphs 
(b)(6), (9)(iii), and (10) of this section would otherwise result in a 
total allocations of such Indian country new unit set-aside less than 
the total amount of such Indian country new unit set-aside, then the 
Administrator will adjust the results of the calculations under 
paragraph (b)(10) of this section, as follows. The Administrator will 
list the TR SO2 Group 2 units in descending order based on 
the amount of such units' allocations under paragraph (b)(10) of this 
section and, in cases of equal allocation amounts, in alphabetical order 
of the relevant source's name and numerical order of the relevant unit's 
identification number, and will increase each unit's allocation under 
paragraph (b)(10) of this section by one TR SO2 Group 2 
allowance in the order in which the units are listed and will repeat 
this increase process as necessary, until the total allocations of such 
Indian country new unit set-aside equal the total amount of such Indian 
country new unit set-aside.

[76 FR 48379, Aug. 8, 2011, as amended at 79 FR 71672, Dec. 3, 2014]



Sec. 97.713  Authorization of designated representative and alternate
designated representative.

    (a) Except as provided under Sec. 97.715, each TR SO2 
Group 2 source, including all TR SO2 Group 2 units at the 
source, shall have one and only one designated representative, with 
regard to all matters under the TR SO2 Group 2 Trading 
Program.
    (1) The designated representative shall be selected by an agreement 
binding on the owners and operators of the source and all TR 
SO2 Group 2 units at the source and shall act in accordance 
with the certification statement in Sec. 97.716(a)(4)(iii).
    (2) Upon and after receipt by the Administrator of a complete 
certificate of representation under Sec. 97.716:
    (i) The designated representative shall be authorized and shall 
represent

[[Page 507]]

and, by his or her representations, actions, inactions, or submissions, 
legally bind each owner and operator of the source and each TR 
SO2 Group 2 unit at the source in all matters pertaining to 
the TR SO2 Group 2 Trading Program, notwithstanding any 
agreement between the designated representative and such owners and 
operators; and
    (ii) The owners and operators of the source and each TR 
SO2 Group 2 unit at the source shall be bound by any decision 
or order issued to the designated representative by the Administrator 
regarding the source or any such unit.
    (b) Except as provided under Sec. 97.715, each TR SO2 
Group 2 source may have one and only one alternate designated 
representative, who may act on behalf of the designated representative. 
The agreement by which the alternate designated representative is 
selected shall include a procedure for authorizing the alternate 
designated representative to act in lieu of the designated 
representative.
    (1) The alternate designated representative shall be selected by an 
agreement binding on the owners and operators of the source and all TR 
SO2 Group 2 units at the source and shall act in accordance 
with the certification statement in Sec. 97.716(a)(4)(iii).
    (2) Upon and after receipt by the Administrator of a complete 
certificate of representation under Sec. 97.716,
    (i) The alternate designated representative shall be authorized;
    (ii) Any representation, action, inaction, or submission by the 
alternate designated representative shall be deemed to be a 
representation, action, inaction, or submission by the designated 
representative; and
    (iii) The owners and operators of the source and each TR 
SO2 Group 2 unit at the source shall be bound by any decision 
or order issued to the alternate designated representative by the 
Administrator regarding the source or any such unit.
    (c) Except in this section, Sec. 97.702, and Sec. Sec. 97.714 
through 97.718, whenever the term ``designated representative'' (as 
distinguished from the term ``common designated representative'') is 
used in this subpart, the term shall be construed to include the 
designated representative or any alternate designated representative.



Sec. 97.714  Responsibilities of designated representative and 
alternate designated representative.

    (a) Except as provided under Sec. 97.718 concerning delegation of 
authority to make submissions, each submission under the TR 
SO2 Group 2 Trading Program shall be made, signed, and 
certified by the designated representative or alternate designated 
representative for each TR SO2 Group 2 source and TR 
SO2 Group 2 unit for which the submission is made. Each such 
submission shall include the following certification statement by the 
designated representative or alternate designated representative: ``I am 
authorized to make this submission on behalf of the owners and operators 
of the source or units for which the submission is made. I certify under 
penalty of law that I have personally examined, and am familiar with, 
the statements and information submitted in this document and all its 
attachments. Based on my inquiry of those individuals with primary 
responsibility for obtaining the information, I certify that the 
statements and information are to the best of my knowledge and belief 
true, accurate, and complete. I am aware that there are significant 
penalties for submitting false statements and information or omitting 
required statements and information, including the possibility of fine 
or imprisonment.''
    (b) The Administrator will accept or act on a submission made for a 
TR SO2 Group 2 source or a TR SO2 Group 2 unit 
only if the submission has been made, signed, and certified in 
accordance with paragraph (a) of this section and Sec. 97.718.



Sec. 97.715  Changing designated representative and alternate 
designated representative; changes in owners and operators;
changes in units at the source.

    (a) Changing designated representative. The designated 
representative may be changed at any time upon receipt by the 
Administrator of a superseding complete certificate of representation 
under Sec. 97.716. Notwithstanding any such change, all 
representations, actions, inactions, and submissions by

[[Page 508]]

the previous designated representative before the time and date when the 
Administrator receives the superseding certificate of representation 
shall be binding on the new designated representative and the owners and 
operators of the TR SO2 Group 2 source and the TR 
SO2 Group 2 units at the source.
    (b) Changing alternate designated representative. The alternate 
designated representative may be changed at any time upon receipt by the 
Administrator of a superseding complete certificate of representation 
under Sec. 97.716. Notwithstanding any such change, all 
representations, actions, inactions, and submissions by the previous 
alternate designated representative before the time and date when the 
Administrator receives the superseding certificate of representation 
shall be binding on the new alternate designated representative, the 
designated representative, and the owners and operators of the TR 
SO2 Group 2 source and the TR SO2 Group 2 units at 
the source.
    (c) Changes in owners and operators. (1) In the event an owner or 
operator of a TR SO2 Group 2 source or a TR SO2 
Group 2 unit at the source is not included in the list of owners and 
operators in the certificate of representation under Sec. 97.716, such 
owner or operator shall be deemed to be subject to and bound by the 
certificate of representation, the representations, actions, inactions, 
and submissions of the designated representative and any alternate 
designated representative of the source or unit, and the decisions and 
orders of the Administrator, as if the owner or operator were included 
in such list.
    (2) Within 30 days after any change in the owners and operators of a 
TR SO2 Group 2 source or a TR SO2 Group 2 unit at 
the source, including the addition or removal of an owner or operator, 
the designated representative or any alternate designated representative 
shall submit a revision to the certificate of representation under Sec. 
97.716 amending the list of owners and operators to reflect the change.
    (d) Changes in units at the source. Within 30 days of any change in 
which units are located at a TR SO2 Group 2 source (including 
the addition or removal of a unit), the designated representative or any 
alternate designated representative shall submit a certificate of 
representation under Sec. 97.716 amending the list of units to reflect 
the change.
    (1) If the change is the addition of a unit that operated (other 
than for purposes of testing by the manufacturer before initial 
installation) before being located at the source, then the certificate 
of representation shall identify, in a format prescribed by the 
Administrator, the entity from whom the unit was purchased or otherwise 
obtained (including name, address, telephone number, and facsimile 
number (if any)), the date on which the unit was purchased or otherwise 
obtained, and the date on which the unit became located at the source.
    (2) If the change is the removal of a unit, then the certificate of 
representation shall identify, in a format prescribed by the 
Administrator, the entity to which the unit was sold or that otherwise 
obtained the unit (including name, address, telephone number, and 
facsimile number (if any)), the date on which the unit was sold or 
otherwise obtained, and the date on which the unit became no longer 
located at the source.



Sec. 97.716  Certificate of representation.

    (a) A complete certificate of representation for a designated 
representative or an alternate designated representative shall include 
the following elements in a format prescribed by the Administrator:
    (1) Identification of the TR SO2 Group 2 source, and each 
TR SO2 Group 2 unit at the source, for which the certificate 
of representation is submitted, including source name, source category 
and NAICS code (or, in the absence of a NAICS code, an equivalent code), 
State, plant code, county, latitude and longitude, unit identification 
number and type, identification number and nameplate capacity (in MWe, 
rounded to the nearest tenth) of each generator served by each such 
unit, actual or projected date of commencement of commercial operation, 
and a statement of whether such source is located in Indian Country. If 
a projected date of commencement of commercial operation is provided, 
the actual date of

[[Page 509]]

commencement of commercial operation shall be provided when such 
information becomes available.
    (2) The name, address, e-mail address (if any), telephone number, 
and facsimile transmission number (if any) of the designated 
representative and any alternate designated representative.
    (3) A list of the owners and operators of the TR SO2 
Group 2 source and of each TR SO2 Group 2 unit at the source.
    (4) The following certification statements by the designated 
representative and any alternate designated representative--
    (i) ``I certify that I was selected as the designated representative 
or alternate designated representative, as applicable, by an agreement 
binding on the owners and operators of the source and each TR 
SO2 Group 2 unit at the source.''
    (ii) ``I certify that I have all the necessary authority to carry 
out my duties and responsibilities under the TR SO2 Group 2 
Trading Program on behalf of the owners and operators of the source and 
of each TR SO2 Group 2 unit at the source and that each such 
owner and operator shall be fully bound by my representations, actions, 
inactions, or submissions and by any decision or order issued to me by 
the Administrator regarding the source or unit.''
    (iii) ``Where there are multiple holders of a legal or equitable 
title to, or a leasehold interest in, a TR SO2 Group 2 unit, 
or where a utility or industrial customer purchases power from a TR 
SO2 Group 2 unit under a life-of-the-unit, firm power 
contractual arrangement, I certify that: I have given a written notice 
of my selection as the `designated representative' or `alternate 
designated representative', as applicable, and of the agreement by which 
I was selected to each owner and operator of the source and of each TR 
SO2 Group 2 unit at the source; and TR SO2 Group 2 
allowances and proceeds of transactions involving TR SO2 
Group 2 allowances will be deemed to be held or distributed in 
proportion to each holder's legal, equitable, leasehold, or contractual 
reservation or entitlement, except that, if such multiple holders have 
expressly provided for a different distribution of TR SO2 
Group 2 allowances by contract, TR SO2 Group 2 allowances and 
proceeds of transactions involving TR SO2 Group 2 allowances 
will be deemed to be held or distributed in accordance with the 
contract.''
    (5) The signature of the designated representative and any alternate 
designated representative and the dates signed.
    (b) Unless otherwise required by the Administrator, documents of 
agreement referred to in the certificate of representation shall not be 
submitted to the Administrator. The Administrator shall not be under any 
obligation to review or evaluate the sufficiency of such documents, if 
submitted.



Sec. 97.717  Objections concerning designated representative and
alternate designated representative.

    (a) Once a complete certificate of representation under Sec. 97.716 
has been submitted and received, the Administrator will rely on the 
certificate of representation unless and until a superseding complete 
certificate of representation under Sec. 97.716 is received by the 
Administrator.
    (b) Except as provided in paragraph (a) of this section, no 
objection or other communication submitted to the Administrator 
concerning the authorization, or any representation, action, inaction, 
or submission, of a designated representative or alternate designated 
representative shall affect any representation, action, inaction, or 
submission of the designated representative or alternate designated 
representative or the finality of any decision or order by the 
Administrator under the TR SO2 Group 2 Trading Program.
    (c) The Administrator will not adjudicate any private legal dispute 
concerning the authorization or any representation, action, inaction, or 
submission of any designated representative or alternate designated 
representative, including private legal disputes concerning the proceeds 
of TR SO2 Group 2 allowance transfers.



Sec. 97.718  Delegation by designated representative and alternate
designated representative.

    (a) A designated representative may delegate, to one or more natural 
persons, his or her authority to make an

[[Page 510]]

electronic submission to the Administrator provided for or required 
under this subpart.
    (b) An alternate designated representative may delegate, to one or 
more natural persons, his or her authority to make an electronic 
submission to the Administrator provided for or required under this 
subpart.
    (c) In order to delegate authority to a natural person to make an 
electronic submission to the Administrator in accordance with paragraph 
(a) or (b) of this section, the designated representative or alternate 
designated representative, as appropriate, must submit to the 
Administrator a notice of delegation, in a format prescribed by the 
Administrator, that includes the following elements:
    (1) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of such designated representative 
or alternate designated representative;
    (2) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of each such natural person 
(referred to in this section as an ``agent'');
    (3) For each such natural person, a list of the type or types of 
electronic submissions under paragraph (a) or (b) of this section for 
which authority is delegated to him or her; and
    (4) The following certification statements by such designated 
representative or alternate designated representative:
    (i) ``I agree that any electronic submission to the Administrator 
that is made by an agent identified in this notice of delegation and of 
a type listed for such agent in this notice of delegation and that is 
made when I am a designated representative or alternate designated 
representative, as appropriate, and before this notice of delegation is 
superseded by another notice of delegation under 40 CFR 97.718(d) shall 
be deemed to be an electronic submission by me.''
    (ii) ``Until this notice of delegation is superseded by another 
notice of delegation under 40 CFR 97.718(d), I agree to maintain an e-
mail account and to notify the Administrator immediately of any change 
in my e-mail address unless all delegation of authority by me under 40 
CFR 97.718 is terminated.''.
    (d) A notice of delegation submitted under paragraph (c) of this 
section shall be effective, with regard to the designated representative 
or alternate designated representative identified in such notice, upon 
receipt of such notice by the Administrator and until receipt by the 
Administrator of a superseding notice of delegation submitted by such 
designated representative or alternate designated representative, as 
appropriate. The superseding notice of delegation may replace any 
previously identified agent, add a new agent, or eliminate entirely any 
delegation of authority.
    (e) Any electronic submission covered by the certification in 
paragraph (c)(4)(i) of this section and made in accordance with a notice 
of delegation effective under paragraph (d) of this section shall be 
deemed to be an electronic submission by the designated representative 
or alternate designated representative submitting such notice of 
delegation.



Sec. 97.719  [Reserved]



Sec. 97.720  Establishment of compliance accounts, assurance accounts,
and general accounts.

    (a) Compliance accounts. Upon receipt of a complete certificate of 
representation under Sec. 97.716, the Administrator will establish a 
compliance account for the TR SO2 Group 2 source for which 
the certificate of representation was submitted, unless the source 
already has a compliance account. The designated representative and any 
alternate designated representative of the source shall be the 
authorized account representative and the alternate authorized account 
representative respectively of the compliance account.
    (b) Assurance accounts. The Administrator will establish assurance 
accounts for certain owners and operators and States in accordance with 
Sec. 97.725(b)(3).
    (c) General accounts. (1) Application for general account. (i) Any 
person may apply to open a general account, for the purpose of holding 
and transferring TR SO2 Group 2 allowances, by submitting to 
the Administrator a

[[Page 511]]

complete application for a general account. Such application shall 
designate one and only one authorized account representative and may 
designate one and only one alternate authorized account representative 
who may act on behalf of the authorized account representative.
    (A) The authorized account representative and alternate authorized 
account representative shall be selected by an agreement binding on the 
persons who have an ownership interest with respect to TR SO2 
Group 2 allowances held in the general account.
    (B) The agreement by which the alternate authorized account 
representative is selected shall include a procedure for authorizing the 
alternate authorized account representative to act in lieu of the 
authorized account representative.
    (ii) A complete application for a general account shall include the 
following elements in a format prescribed by the Administrator:
    (A) Name, mailing address, e-mail address (if any), telephone 
number, and facsimile transmission number (if any) of the authorized 
account representative and any alternate authorized account 
representative;
    (B) An identifying name for the general account;
    (C) A list of all persons subject to a binding agreement for the 
authorized account representative and any alternate authorized account 
representative to represent their ownership interest with respect to the 
TR SO2 Group 2 allowances held in the general account;
    (D) The following certification statement by the authorized account 
representative and any alternate authorized account representative: ``I 
certify that I was selected as the authorized account representative or 
the alternate authorized account representative, as applicable, by an 
agreement that is binding on all persons who have an ownership interest 
with respect to TR SO2 Group 2 allowances held in the general 
account. I certify that I have all the necessary authority to carry out 
my duties and responsibilities under the TR SO2 Group 2 
Trading Program on behalf of such persons and that each such person 
shall be fully bound by my representations, actions, inactions, or 
submissions and by any decision or order issued to me by the 
Administrator regarding the general account.''
    (E) The signature of the authorized account representative and any 
alternate authorized account representative and the dates signed.
    (iii) Unless otherwise required by the Administrator, documents of 
agreement referred to in the application for a general account shall not 
be submitted to the Administrator. The Administrator shall not be under 
any obligation to review or evaluate the sufficiency of such documents, 
if submitted.
    (2) Authorization of authorized account representative and alternate 
authorized account representative. (i) Upon receipt by the Administrator 
of a complete application for a general account under paragraph (b)(1) 
of this section, the Administrator will establish a general account for 
the person or persons for whom the application is submitted, and upon 
and after such receipt by the Administrator:
    (A) The authorized account representative of the general account 
shall be authorized and shall represent and, by his or her 
representations, actions, inactions, or submissions, legally bind each 
person who has an ownership interest with respect to TR SO2 
Group 2 allowances held in the general account in all matters pertaining 
to the TR SO2 Group 2 Trading Program, notwithstanding any 
agreement between the authorized account representative and such person.
    (B) Any alternate authorized account representative shall be 
authorized, and any representation, action, inaction, or submission by 
any alternate authorized account representative shall be deemed to be a 
representation, action, inaction, or submission by the authorized 
account representative.
    (C) Each person who has an ownership interest with respect to TR 
SO2 Group 2 allowances held in the general account shall be 
bound by any decision or order issued to the authorized account 
representative or alternate authorized account representative by the 
Administrator regarding the general account.
    (ii) Except as provided in paragraph (c)(5) of this section 
concerning delegation of authority to make submissions,

[[Page 512]]

each submission concerning the general account shall be made, signed, 
and certified by the authorized account representative or any alternate 
authorized account representative for the persons having an ownership 
interest with respect to TR SO2 Group 2 allowances held in 
the general account. Each such submission shall include the following 
certification statement by the authorized account representative or any 
alternate authorized account representative: ``I am authorized to make 
this submission on behalf of the persons having an ownership interest 
with respect to the TR SO2 Group 2 allowances held in the 
general account. I certify under penalty of law that I have personally 
examined, and am familiar with, the statements and information submitted 
in this document and all its attachments. Based on my inquiry of those 
individuals with primary responsibility for obtaining the information, I 
certify that the statements and information are to the best of my 
knowledge and belief true, accurate, and complete. I am aware that there 
are significant penalties for submitting false statements and 
information or omitting required statements and information, including 
the possibility of fine or imprisonment.''
    (iii) Except in this section, whenever the term ``authorized account 
representative'' is used in this subpart, the term shall be construed to 
include the authorized account representative or any alternate 
authorized account representative.
    (3) Changing authorized account representative and alternate 
authorized account representative; changes in persons with ownership 
interest. (i) The authorized account representative of a general account 
may be changed at any time upon receipt by the Administrator of a 
superseding complete application for a general account under paragraph 
(c)(1) of this section. Notwithstanding any such change, all 
representations, actions, inactions, and submissions by the previous 
authorized account representative before the time and date when the 
Administrator receives the superseding application for a general account 
shall be binding on the new authorized account representative and the 
persons with an ownership interest with respect to the TR SO2 
Group 2 allowances in the general account.
    (ii) The alternate authorized account representative of a general 
account may be changed at any time upon receipt by the Administrator of 
a superseding complete application for a general account under paragraph 
(c)(1) of this section. Notwithstanding any such change, all 
representations, actions, inactions, and submissions by the previous 
alternate authorized account representative before the time and date 
when the Administrator receives the superseding application for a 
general account shall be binding on the new alternate authorized account 
representative, the authorized account representative, and the persons 
with an ownership interest with respect to the TR SO2 Group 2 
allowances in the general account.
    (iii)(A) In the event a person having an ownership interest with 
respect to TR SO2 Group 2 allowances in the general account 
is not included in the list of such persons in the application for a 
general account, such person shall be deemed to be subject to and bound 
by the application for a general account, the representation, actions, 
inactions, and submissions of the authorized account representative and 
any alternate authorized account representative of the account, and the 
decisions and orders of the Administrator, as if the person were 
included in such list.
    (B) Within 30 days after any change in the persons having an 
ownership interest with respect to SO2 Group 2 allowances in 
the general account, including the addition or removal of a person, the 
authorized account representative or any alternate authorized account 
representative shall submit a revision to the application for a general 
account amending the list of persons having an ownership interest with 
respect to the TR SO2 Group 2 allowances in the general 
account to include the change.
    (4) Objections concerning authorized account representative and 
alternate authorized account representative. (i) Once a complete 
application for a general account under paragraph (c)(1) of this section 
has been submitted and received, the Administrator will rely on

[[Page 513]]

the application unless and until a superseding complete application for 
a general account under paragraph (b)(1) of this section is received by 
the Administrator.
    (ii) Except as provided in paragraph (c)(4)(i) of this section, no 
objection or other communication submitted to the Administrator 
concerning the authorization, or any representation, action, inaction, 
or submission of the authorized account representative or any alternate 
authorized account representative of a general account shall affect any 
representation, action, inaction, or submission of the authorized 
account representative or any alternate authorized account 
representative or the finality of any decision or order by the 
Administrator under the TR SO2 Group 2 Trading Program.
    (iii) The Administrator will not adjudicate any private legal 
dispute concerning the authorization or any representation, action, 
inaction, or submission of the authorized account representative or any 
alternate authorized account representative of a general account, 
including private legal disputes concerning the proceeds of TR 
SO2 Group 2 allowance transfers.
    (5) Delegation by authorized account representative and alternate 
authorized account representative. (i) An authorized account 
representative of a general account may delegate, to one or more natural 
persons, his or her authority to make an electronic submission to the 
Administrator provided for or required under this subpart.
    (ii) An alternate authorized account representative of a general 
account may delegate, to one or more natural persons, his or her 
authority to make an electronic submission to the Administrator provided 
for or required under this subpart.
    (iii) In order to delegate authority to a natural person to make an 
electronic submission to the Administrator in accordance with paragraph 
(c)(5)(i) or (ii) of this section, the authorized account representative 
or alternate authorized account representative, as appropriate, must 
submit to the Administrator a notice of delegation, in a format 
prescribed by the Administrator, that includes the following elements:
    (A) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of such authorized account 
representative or alternate authorized account representative;
    (B) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of each such natural person 
(referred to in this section as an ``agent'');
    (C) For each such natural person, a list of the type or types of 
electronic submissions under paragraph (c)(5)(i) or (ii) of this section 
for which authority is delegated to him or her;
    (D) The following certification statement by such authorized account 
representative or alternate authorized account representative: ``I agree 
that any electronic submission to the Administrator that is made by an 
agent identified in this notice of delegation and of a type listed for 
such agent in this notice of delegation and that is made when I am an 
authorized account representative or alternate authorized 
representative, as appropriate, and before this notice of delegation is 
superseded by another notice of delegation under 40 CFR 97.720(c)(5)(iv) 
shall be deemed to be an electronic submission by me.''; and
    (E) The following certification statement by such authorized account 
representative or alternate authorized account representative: ``Until 
this notice of delegation is superseded by another notice of delegation 
under 40 CFR 97.720(c)(5)(iv), I agree to maintain an e-mail account and 
to notify the Administrator immediately of any change in my e-mail 
address unless all delegation of authority by me under 40 CFR 
97.720(c)(5) is terminated.''.
    (iv) A notice of delegation submitted under paragraph (c)(5)(iii) of 
this section shall be effective, with regard to the authorized account 
representative or alternate authorized account representative identified 
in such notice, upon receipt of such notice by the Administrator and 
until receipt by the Administrator of a superseding notice of delegation 
submitted by such authorized account representative or alternate 
authorized account representative, as appropriate. The superseding 
notice of delegation may replace any

[[Page 514]]

previously identified agent, add a new agent, or eliminate entirely any 
delegation of authority.
    (v) Any electronic submission covered by the certification in 
paragraph (c)(5)(iii)(D) of this section and made in accordance with a 
notice of delegation effective under paragraph (c)(5)(iv) of this 
section shall be deemed to be an electronic submission by the designated 
representative or alternate designated representative submitting such 
notice of delegation.
    (6) Closing a general account. (i) The authorized account 
representative or alternate authorized account representative of a 
general account may submit to the Administrator a request to close the 
account. Such request shall include a correctly submitted TR 
SO2 Group 2 allowance transfer under Sec. 97.722 for any TR 
SO2 Group 2 allowances in the account to one or more other 
Allowance Management System accounts.
    (ii) If a general account has no TR SO2 Group 2 allowance 
transfers to or from the account for a 12-month period or longer and 
does not contain any TR SO2 Group 2 allowances, the 
Administrator may notify the authorized account representative for the 
account that the account will be closed after 30 days after the notice 
is sent. The account will be closed after the 30-day period unless, 
before the end of the 30-day period, the Administrator receives a 
correctly submitted TR SO2 Group 2 allowance transfer under 
Sec. 97.722 to the account or a statement submitted by the authorized 
account representative or alternate authorized account representative 
demonstrating to the satisfaction of the Administrator good cause as to 
why the account should not be closed.
    (d) Account identification. The Administrator will assign a unique 
identifying number to each account established under paragraph (a), (b), 
or (c) of this section.
    (e) Responsibilities of authorized account representative and 
alternate authorized account representative. After the establishment of 
a compliance account or general account, the Administrator will accept 
or act on a submission pertaining to the account, including, but not 
limited to, submissions concerning the deduction or transfer of TR 
SO2 Group 2 allowances in the account, only if the submission 
has been made, signed, and certified in accordance with Sec. Sec. 
97.714(a) and 97.718 or paragraphs (c)(2)(ii) and (c)(5) of this 
section.



Sec. 97.721  Recordation of TR SO[bdi2] Group 2 allowance allocations
and auction results.

    (a) By November 7, 2011, the Administrator will record in each TR 
SO2 Group 2 source's compliance account the TR SO2 
Group 2 allowances allocated to the TR SO2 Group 2 units at 
the source in accordance with Sec. 97.711(a) for the control period in 
2015.
    (b) By November 7, 2011, the Administrator will record in each TR 
SO2 Group 2 source's compliance account the TR SO2 
Group 2 allowances allocated to the TR SO2 Group 2 units at 
the source in accordance with Sec. 97.711(a) for the control period in 
2016, unless the State in which the source is located notifies the 
Administrator in writing by October 17, 2011 of the State's intent to 
submit to the Administrator a complete SIP revision by April 1, 2015 
meeting the requirements of Sec. 52.39(g)(1) through (4) of this 
chapter.
    (1) If, by April 1, 2015, the State does not submit to the 
Administrator such complete SIP revision, the Administrator will record 
by April 15, 2015 in each TR SO2 Group 2 source's compliance 
account the TR SO2 Group 2 allowances allocated to the TR 
SO2 Group 2 units at the source in accordance with Sec. 
97.711(a) for the control period in 2016.
    (2) If the State submits to the Administrator by April 1, 2015, and 
the Administrator approves by October 1, 2015, such complete SIP 
revision, the Administrator will record by October 1, 2015 in each TR 
SO2 Group 2 source's compliance account the TR SO2 
Group 2 allowances allocated to the TR SO2 Group 2 units at 
the source as provided in such approved, complete SIP revision for the 
control period in 2016.
    (3) If the State submits to the Administrator by April 1, 2015, and 
the Administrator does not approve by October 1, 2015, such complete SIP 
revision, the Administrator will record by

[[Page 515]]

October 1, 2015 in each TR SO2 Group 2 source's compliance 
account the TR SO2 Group 2 allowances allocated to the TR 
SO2 Group 2 units at the source in accordance with Sec. 
97.711(a) for the control period in 2016.
    (c) By July 1, 2016, the Administrator will record in each TR 
SO2 Group 2 source's compliance account the TR SO2 
Group 2 allowances allocated to the TR SO2 Group 2 units at 
the source, or in each appropriate Allowance Management System account 
the TR SO2 Group 2 allowances auctioned to TR SO2 
Group 2 units, in accordance with Sec. 97.711(a), or with a SIP 
revision approved under Sec. 52.39(h) or (i) of this chapter, for the 
control period in 2017 and 2018.
    (d) By July 1, 2017, the Administrator will record in each TR 
SO2 Group 2 source's compliance account the TR SO2 
Group 2 allowances allocated to the TR SO2 Group 2 units at 
the source, or in each appropriate Allowance Management System account 
the TR SO2 Group 2 allowances auctioned to TR SO2 
Group 2 units, in accordance with Sec. 97.711(a), or with a SIP 
revision approved under Sec. 52.39(h) or (i) of this chapter, for the 
control period in 2019 and 2020.
    (e) By July 1, 2018, the Administrator will record in each TR 
SO2 Group 2 source's compliance account the TR SO2 
Group 2 allowances allocated to the TR SO2 Group 2 units at 
the source, or in each appropriate Allowance Management System account 
the TR SO2 Group 2 allowances auctioned to TR SO2 
Group 2 units, in accordance with Sec. 97.711(a), or with a SIP 
revision approved under Sec. 52.39(h) or (i) of this chapter, for the 
control period in 2021 and 2022.
    (f) By July 1, 2019 and July 1 of each year thereafter, the 
Administrator will record in each TR SO2 Group 2 source's 
compliance account the TR SO2 Group 2 allowances allocated to 
the TR SO2 Group 2 units at the source, or in each 
appropriate Allowance Management System account the TR SO2 
Group 2 allowances auctioned to TR SO2 Group 2 units, in 
accordance with Sec. 97.711(a), or with a SIP revision approved under 
Sec. 52.39(h) and (i) of this chapter, for the control period in the 
fourth year after the year of the applicable recordation deadline under 
this paragraph.
    (g) By August 1, 2015 and August 1 of each year thereafter, the 
Administrator will record in each TR SO2 Group 2 source's 
compliance account the TR SO2 Group 2 allowances allocated to 
the TR SO2 Group 2 units at the source, or in each 
appropriate Allowance Management System account the TR SO2 
Group 2 allowances auctioned to TR SO2 Group 2 units, in 
accordance with Sec. 97.712(a)(2) through (8) and (12), or with a SIP 
revision approved under Sec. 52.39(h) and (i) of this chapter, for the 
control period in the year of the applicable recordation deadline under 
this paragraph.
    (h) By August 1, 2015 and August 1 of each year thereafter, the 
Administrator will record in each TR SO2 Group 2 source's 
compliance account the TR SO2 Group 2 allowances allocated to 
the TR SO2 Group 2 units at the source in accordance with 
Sec. 97.712(b)(2) through (8) and (12) for the control period in the 
year of the applicable recordation deadline under this paragraph.
    (i) By February 15, 2016 and February 15 of each year thereafter, 
the Administrator will record in each TR SO2 Group 2 source's 
compliance account the TR SO2 Group 2 allowances allocated to 
the TR SO2 Group 2 units at the source in accordance with 
Sec. 97.712(a)(9) through (12), for the control period in the year 
before the year of the applicable recordation deadline under this 
paragraph.
    (j) By the date on which any allocation or auction results, other 
than an allocation or auction results, described in paragraphs (a) 
through (i) of this section, of TR SO2 Group 2 allowances to 
a recipient is made by or are submitted to the Administrator in 
accordance with Sec. 97.711 or Sec. 97.712 or with a SIP revision 
approved under Sec. 52.39(h) or (i) of this chapter, the Administrator 
will record such allocation or auction results in the appropriate 
Allowance Management System account.
    (k) When recording the allocation or auction of TR SO2 
Group 2 allowances to a TR SO2 Group 2 unit or other entity 
in an Allowance Management System account, the Administrator will assign 
each TR SO2 Group 2 allowance

[[Page 516]]

a unique identification number that will include digits identifying the 
year of the control period for which the TR SO2 Group 2 
allowance is allocated or auctioned.

[76 FR 48379, Aug. 8, 2011, as amended at 79 FR 71672, Dec. 3, 2014]



Sec. 97.722  Submission of TR SO[bdi2] Group 2 allowance transfers.

    (a) An authorized account representative seeking recordation of a TR 
SO2 Group 2 allowance transfer shall submit the transfer to 
the Administrator.
    (b) A TR SO2 Group 2 allowance transfer shall be 
correctly submitted if:
    (1) The transfer includes the following elements, in a format 
prescribed by the Administrator:
    (i) The account numbers established by the Administrator for both 
the transferor and transferee accounts;
    (ii) The serial number of each TR SO2 Group 2 allowance 
that is in the transferor account and is to be transferred; and
    (iii) The name and signature of the authorized account 
representative of the transferor account and the date signed; and
    (2) When the Administrator attempts to record the transfer, the 
transferor account includes each TR SO2 Group 2 allowance 
identified by serial number in the transfer.



Sec. 97.723  Recordation of TR SO[bdi2] Group 2 allowance transfers.

    (a) Within 5 business days (except as provided in paragraph (b) of 
this section) of receiving a TR SO2 Group 2 allowance 
transfer that is correctly submitted under Sec. 97.722, the 
Administrator will record a TR SO2 Group 2 allowance transfer 
by moving each TR SO2 Group 2 allowance from the transferor 
account to the transferee account as specified in the transfer.
    (b) A TR SO2 Group 2 allowance transfer to or from a 
compliance account that is submitted for recordation after the allowance 
transfer deadline for a control period and that includes any TR 
SO2 Group 2 allowances allocated for any control period 
before such allowance transfer deadline will not be recorded until after 
the Administrator completes the deductions from such compliance account 
under Sec. 97.724 for the control period immediately before such 
allowance transfer deadline.
    (c) Where a TR SO2 Group 2 allowance transfer is not 
correctly submitted under Sec. 97.722, the Administrator will not 
record such transfer.
    (d) Within 5 business days of recordation of a TR SO2 
Group 2 allowance transfer under paragraphs (a) and (b) of the section, 
the Administrator will notify the authorized account representatives of 
both the transferor and transferee accounts.
    (e) Within 10 business days of receipt of a TR SO2 Group 
2 allowance transfer that is not correctly submitted under Sec. 97.722, 
the Administrator will notify the authorized account representatives of 
both accounts subject to the transfer of:
    (1) A decision not to record the transfer, and
    (2) The reasons for such non-recordation.



Sec. 97.724  Compliance with TR SO[bdi2] Group 2 emissions limitation.

    (a) Availability for deduction for compliance. TR SO2 
Group 2 allowances are available to be deducted for compliance with a 
source's TR SO2 Group 2 emissions limitation for a control 
period in a given year only if the TR SO2 Group 2 allowances:
    (1) Were allocated for such control period or a control period in a 
prior year; and
    (2) Are held in the source's compliance account as of the allowance 
transfer deadline for such control period.
    (b) Deductions for compliance. After the recordation, in accordance 
with Sec. 97.723, of TR SO2 Group 2 allowance transfers 
submitted by the allowance transfer deadline for a control period in a 
given year, the Administrator will deduct from each source's compliance 
account TR SO2 Group 2 allowances available under paragraph 
(a) of this section in order to determine whether the source meets the 
TR SO2 Group 2 emissions limitation for such control period, 
as follows:
    (1) Until the amount of TR SO2 Group 2 allowances 
deducted equals the number of tons of total SO2 emissions 
from all TR SO2 Group 2 units at the source for such control 
period; or

[[Page 517]]

    (2) If there are insufficient TR SO2 Group 2 allowances 
to complete the deductions in paragraph (b)(1) of this section, until no 
more TR SO2 Group 2 allowances available under paragraph (a) 
of this section remain in the compliance account.
    (c)(1) Identification of TR SO2 Group 2 allowances by serial number. 
The authorized account representative for a source's compliance account 
may request that specific TR SO2 Group 2 allowances, 
identified by serial number, in the compliance account be deducted for 
emissions or excess emissions for a control period in a given year in 
accordance with paragraph (b) or (d) of this section. In order to be 
complete, such request shall be submitted to the Administrator by the 
allowance transfer deadline for such control period and include, in a 
format prescribed by the Administrator, the identification of the TR 
SO2 Group 2 source and the appropriate serial numbers.
    (2) First-in, first-out. The Administrator will deduct TR 
SO2 Group 2 allowances under paragraph (b) or (d) of this 
section from the source's compliance account in accordance with a 
complete request under paragraph (c)(1) of this section or, in the 
absence of such request or in the case of identification of an 
insufficient amount of TR SO2 Group 2 allowances in such 
request, on a first-in, first-out accounting basis in the following 
order:
    (i) Any TR SO2 Group 2 allowances that were allocated to 
the units at the source and not transferred out of the compliance 
account, in the order of recordation; and then
    (ii) Any TR SO2 Group 2 allowances that were allocated to 
any unit and transferred to and recorded in the compliance account 
pursuant to this subpart, in the order of recordation.
    (d) Deductions for excess emissions. After making the deductions for 
compliance under paragraph (b) of this section for a control period in a 
year in which the TR SO2 Group 2 source has excess emissions, 
the Administrator will deduct from the source's compliance account an 
amount of TR SO2 Group 2 allowances, allocated for a control 
period in a prior year or the control period in the year of the excess 
emissions or in the immediately following year, equal to two times the 
number of tons of the source's excess emissions.
    (e) Recordation of deductions. The Administrator will record in the 
appropriate compliance account all deductions from such an account under 
paragraphs (b) and (d) of this section.



Sec. 97.725  Compliance with TR SO[bdi2] Group 2 assurance provisions.

    (a) Availability for deduction. TR SO2 Group 2 allowances 
are available to be deducted for compliance with the TR SO2 
Group 2 assurance provisions for a control period in a given year by the 
owners and operators of a group of one or more TR SO2 Group 2 
sources and units in a State (and Indian country within the borders of 
such State) only if the TR SO2 Group 2 allowances:
    (1) Were allocated for a control period in a prior year or the 
control period in the given year or in the immediately following year; 
and
    (2) Are held in the assurance account, established by the 
Administrator for such owners and operators of such group of TR 
SO2 Group 2 sources and units in such State (and Indian 
country within the borders of such State) under paragraph (b)(3) of this 
section, as of the deadline established in paragraph (b)(4) of this 
section.
    (b) Deductions for compliance. The Administrator will deduct TR 
SO2 Group 2 allowances available under paragraph (a) of this 
section for compliance with the TR SO2 Group 2 assurance 
provisions for a State for a control period in a given year in 
accordance with the following procedures:
    (1) By June 1, 2018 and June 1 of each year thereafter, the 
Administrator will:
    (i) Calculate, for each State (and Indian country within the borders 
of such State), the total SO2 emissions from all TR 
SO2 Group 2 units at TR SO2 Group 2 sources in the 
State (and Indian country within the borders of such State) during the 
control period in the year before the year of this calculation deadline 
and the amount, if any, by which such total SO2 emissions 
exceed the State assurance level as described in Sec. 
97.706(c)(2)(iii); and

[[Page 518]]

    (ii) Promulgate a notice of data availability of the results of the 
calculations required in paragraph (b)(1)(i) of this section, including 
separate calculations of the SO2 emissions from each TR 
SO2 Group 2 source.
    (2) For each notice of data availability required in paragraph 
(b)(1)(ii) of this section and for any State (and Indian country within 
the borders of such State) identified in such notice as having TR 
SO2 Group 2 units with total SO2 emissions 
exceeding the State assurance level for a control period in a given 
year, as described in Sec. 97.706(c)(2)(iii):
    (i) By July 1 immediately after the promulgation of such notice, the 
designated representative of each TR SO2 Group 2 source in 
each such State (and Indian country within the borders of such State) 
shall submit a statement, in a format prescribed by the Administrator, 
providing for each TR SO2 Group 2 unit (if any) at the source 
that operates during, but is not allocated an amount of TR 
SO2 Group 2 allowances for, such control period, the unit's 
allowable SO2 emission rate for such control period and, if 
such rate is expressed in lb per mmBtu, the unit's heat rate.
    (ii) By August 1 immediately after the promulgation of such notice, 
the Administrator will calculate, for each such State (and Indian 
country within the borders of such State) and such control period and 
each common designated representative for such control period for a 
group of one or more TR SO2 Group 2 sources and units in the 
State (and Indian country within the borders of such State), the common 
designated representative's share of the total SO2 emissions 
from all TR SO2 Group 2 units at TR SO2 Group 2 
sources in the State (and Indian country within the borders of such 
State), the common designated representative's assurance level, and the 
amount (if any) of TR SO2 Group 2 allowances that the owners 
and operators of such group of sources and units must hold in accordance 
with the calculation formula in Sec. 97.706(c)(2)(i) and will 
promulgate a notice of data availability of the results of these 
calculations.
    (iii) The Administrator will provide an opportunity for submission 
of objections to the calculations referenced by the notice of data 
availability required in paragraph (b)(2)(ii) of this section and the 
calculations referenced by the relevant notice of data availability 
required in paragraph (b)(1)(i) of this section.
    (A) Objections shall be submitted by the deadline specified in such 
notice and shall be limited to addressing whether the calculations 
referenced in the relevant notice required under paragraph (b)(1)(ii) of 
this section and referenced in the notice required under paragraph 
(b)(2)(ii) of this section are in accordance with Sec. 
97.706(c)(2)(iii), Sec. Sec. 97.706(b) and 97.730 through 97.735, the 
definitions of ``common designated representative'', ``common designated 
representative's assurance level'', and ``common designated 
representative's share'' in Sec. 97.702, and the calculation formula in 
Sec. 97.706(c)(2)(i).
    (B) The Administrator will adjust the calculations to the extent 
necessary to ensure that they are in accordance with the provisions 
referenced in paragraph (b)(2)(iii)(A) of this section. By October 1 
immediately after the promulgation of such notice, the Administrator 
will promulgate a notice of data availability of any adjustments that 
the Administrator determines to be necessary and the reasons for 
accepting or rejecting any objections submitted in accordance with 
paragraph (b)(2)(iii)(A) of this section.
    (3) For any State (and Indian country within the borders of such 
State) referenced in each notice of data availability required in 
paragraph (b)(2)(iii)(B) of this section as having TR SO2 
Group 2 units with total SO2 emissions exceeding the State 
assurance level for a control period in a given year, the Administrator 
will establish one assurance account for each set of owners and 
operators referenced, in the notice of data availability required under 
paragraph (b)(2)(iii)(B) of this section, as all of the owners and 
operators of a group of TR SO2 Group 2 sources and units in 
the State (and Indian country within the borders of such State) having a 
common designated representative for such control period and as being 
required to hold TR SO2 Group 2 allowances.

[[Page 519]]

    (4)(i) As of midnight of November 1 immediately after the 
promulgation of each notice of data availability required in paragraph 
(b)(2)(iii)(B) of this section, the owners and operators described in 
paragraph (b)(3) of this section shall hold in the assurance account 
established for them and for the appropriate TR SO2 Group 2 
sources, TR SO2 Group 2 units, and State (and Indian country 
within the borders of such State) under paragraph (b)(3) of this section 
a total amount of TR SO2 Group 2 allowances, available for 
deduction under paragraph (a) of this section, equal to the amount such 
owners and operators are required to hold with regard to such sources, 
units and State (and Indian country within the borders of such State) as 
calculated by the Administrator and referenced in such notice.
    (ii) Notwithstanding the allowance-holding deadline specified in 
paragraph (b)(4)(i) of this section, if November 1 is not a business 
day, then such allowance-holding deadline shall be midnight of the first 
business day thereafter.
    (5) After November 1 (or the date described in paragraph (b)(4)(ii) 
of this section) immediately after the promulgation of each notice of 
data availability required in paragraph (b)(2)(iii)(B) of this section 
and after the recordation, in accordance with Sec. 97.723, of TR 
SO2 Group 2 allowance transfers submitted by midnight of such 
date, the Administrator will determine whether the owners and operators 
described in paragraph (b)(3) of this section hold, in the assurance 
account for the appropriate TR SO2 Group 2 sources, TR 
SO2 Group 2 units, and State (and Indian country within the 
borders of such State) established under paragraph (b)(3) of this 
section, the amount of TR SO2 Group 2 allowances available 
under paragraph (a) of this section that the owners and operators are 
required to hold with regard to such sources, units, and State (and 
Indian country within the borders of such State) as calculated by the 
Administrator and referenced in the notice required in paragraph 
(b)(2)(iii)(B) of this section.
    (6) Notwithstanding any other provision of this subpart and any 
revision, made by or submitted to the Administrator after the 
promulgation of the notice of data availability required in paragraph 
(b)(2)(iii)(B) of this section for a control period in a given year, of 
any data used in making the calculations referenced in such notice, the 
amounts of TR SO2 Group 2 allowances that the owners and 
operators are required to hold in accordance with Sec. 97.706(c)(2)(i) 
for such control period shall continue to be such amounts as calculated 
by the Administrator and referenced in such notice required in paragraph 
(b)(2)(iii)(B) of this section, except as follows:
    (i) If any such data are revised by the Administrator as a result of 
a decision in or settlement of litigation concerning such data on appeal 
under part 78 of this chapter of such notice, or on appeal under section 
307 of the Clean Air Act of a decision rendered under part 78 of this 
chapter on appeal of such notice, then the Administrator will use the 
data as so revised to recalculate the amounts of TR SO2 Group 
2 allowances that owners and operators are required to hold in 
accordance with the calculation formula in Sec. 97.706(c)(2)(i) for 
such control period with regard to the TR SO2 Group 2 
sources, TR SO2 Group 2 units, and State (and Indian country 
within the borders of such State) involved, provided that such 
litigation under part 78 of this chapter, or the proceeding under part 
78 of this chapter that resulted in the decision appealed in such 
litigation under section 307 of the Clean Air Act, was initiated no 
later than 30 days after promulgation of such notice required in 
paragraph (b)(2)(iii)(B) of this section.
    (ii) If any such data are revised by the owners and operators of a 
TR SO2 Group 2 source and TR SO2 Group 2 unit 
whose designated representative submitted such data under paragraph 
(b)(2)(i) of this section, as a result of a decision in or settlement of 
litigation concerning such submission, then the Administrator will use 
the data as so revised to recalculate the amounts of TR SO2 
Group 2 allowances that owners and operators are required to hold in 
accordance with the calculation formula in Sec. 97.706(c)(2)(i) for 
such control period with regard to the TR SO2 Group

[[Page 520]]

2 sources, TR SO2 Group 2 units, and State (and Indian 
country within the borders of such State) involved, provided that such 
litigation was initiated no later than 30 days after promulgation of 
such notice required in paragraph (b)(2)(iii)(B) of this section.
    (iii) If the revised data are used to recalculate, in accordance 
with paragraphs (b)(6)(i) and (ii) of this section, the amount of TR 
SO2 Group 2 allowances that the owners and operators are 
required to hold for such control period with regard to the TR 
SO2 Group 2 sources, TR SO2 Group 2 units, and 
State (and Indian country within the borders of such State) involved--
    (A) Where the amount of TR SO2 Group 2 allowances that 
the owners and operators are required to hold increases as a result of 
the use of all such revised data, the Administrator will establish a 
new, reasonable deadline on which the owners and operators shall hold 
the additional amount of TR SO2 Group 2 allowances in the 
assurance account established by the Administrator for the appropriate 
TR SO2 Group 2 sources, TR SO2 Group 2 units, and 
State (and Indian country within the borders of such State) under 
paragraph (b)(3) of this section. The owners' and operators' failure to 
hold such additional amount, as required, before the new deadline shall 
not be a violation of the Clean Air Act. The owners' and operators' 
failure to hold such additional amount, as required, as of the new 
deadline shall be a violation of the Clean Air Act. Each TR 
SO2 Group 2 allowance that the owners and operators fail to 
hold as required as of the new deadline, and each day in such control 
period, shall be a separate violation of the Clean Air Act.
    (B) For the owners and operators for which the amount of TR 
SO2 Group 2 allowances required to be held decreases as a 
result of the use of all such revised data, the Administrator will 
record, in all accounts from which TR SO2 Group 2 allowances 
were transferred by such owners and operators for such control period to 
the assurance account established by the Administrator for the 
appropriate at TR SO2 Group 2 sources, TR SO2 
Group 2 units, and State (and Indian country within the borders of such 
State) under paragraph (b)(3) of this section, a total amount of the TR 
SO2 Group 2 allowances held in such assurance account equal 
to the amount of the decrease. If TR SO2 Group 2 allowances 
were transferred to such assurance account from more than one account, 
the amount of TR SO2 Group 2 allowances recorded in each such 
transferor account will be in proportion to the percentage of the total 
amount of TR SO2 Group 2 allowances transferred to such 
assurance account for such control period from such transferor account.
    (C) Each TR SO2 Group 2 allowance held under paragraph 
(b)(6)(iii)(A) of this section as a result of recalculation of 
requirements under the TR SO2 Group 2 assurance provisions 
for such control period must be a TR SO2 Group 2 allowance 
allocated for a control period in a year before or the year immediately 
following, or in the same year as, the year of such control period.

[76 FR 48458, Aug. 8, 2011, as amended at 77 FR 10340, Feb. 21, 2012; 79 
FR 71672, Dec. 3, 2014]



Sec. 97.726  Banking.

    (a) A TR SO2 Group 2 allowance may be banked for future 
use or transfer in a compliance account or a general account in 
accordance with paragraph (b) of this section.
    (b) Any TR SO2 Group 2 allowance that is held in a 
compliance account or a general account will remain in such account 
unless and until the TR SO2 Group 2 allowance is deducted or 
transferred under Sec. 97.711(c), Sec. 97.723, Sec. 97.724, Sec. 
97.725, Sec. 97.727, or Sec. 97.728.



Sec. 97.727  Account error.

    The Administrator may, at his or her sole discretion and on his or 
her own motion, correct any error in any Allowance Management System 
account. Within 10 business days of making such correction, the 
Administrator will notify the authorized account representative for the 
account.



Sec. 97.728  Administrator's action on submissions.

    (a) The Administrator may review and conduct independent audits 
concerning any submission under the TR SO2 Group 2 Trading 
Program and

[[Page 521]]

make appropriate adjustments of the information in the submission.
    (b) The Administrator may deduct TR SO2 Group 2 
allowances from or transfer TR SO2 Group 2 allowances to a 
compliance account or an assurance account, based on the information in 
a submission, as adjusted under paragraph (a)(1) of this section, and 
record such deductions and transfers.



Sec. 97.729  [Reserved]



Sec. 97.730  General monitoring, recordkeeping, and reporting
requirements.

    The owners and operators, and to the extent applicable, the 
designated representative, of a TR SO2 Group 2 unit, shall 
comply with the monitoring, recordkeeping, and reporting requirements as 
provided in this subpart and subparts F and G of part 75 of this 
chapter. For purposes of applying such requirements, the definitions in 
Sec. 97.702 and in Sec. 72.2 of this chapter shall apply, the terms 
``affected unit,'' ``designated representative,'' and ``continuous 
emission monitoring system'' (or ``CEMS'') in part 75 of this chapter 
shall be deemed to refer to the terms ``TR SO2 Group 2 
unit,'' ``designated representative,'' and ``continuous emission 
monitoring system'' (or ``CEMS'') respectively as defined in Sec. 
97.702, and the term ``newly affected unit'' shall be deemed to mean 
``newly affected TR SO2 Group 2 unit''. The owner or operator 
of a unit that is not a TR SO2 Group 2 unit but that is 
monitored under Sec. 75.16(b)(2) of this chapter shall comply with the 
same monitoring, recordkeeping, and reporting requirements as a TR 
SO2 Group 2 unit.
    (a) Requirements for installation, certification, and data 
accounting. The owner or operator of each TR SO2 Group 2 unit 
shall:
    (1) Install all monitoring systems required under this subpart for 
monitoring SO2 mass emissions and individual unit heat input 
(including all systems required to monitor SO2 concentration, 
stack gas moisture content, stack gas flow rate, CO2 or 
O2 concentration, and fuel flow rate, as applicable, in 
accordance with Sec. Sec. 75.11 and 75.16 of this chapter);
    (2) Successfully complete all certification tests required under 
Sec. 97.731 and meet all other requirements of this subpart and part 75 
of this chapter applicable to the monitoring systems under paragraph 
(a)(1) of this section; and
    (3) Record, report, and quality-assure the data from the monitoring 
systems under paragraph (a)(1) of this section.
    (b) Compliance deadlines. Except as provided in paragraph (e) of 
this section, the owner or operator shall meet the monitoring system 
certification and other requirements of paragraphs (a)(1) and (2) of 
this section on or before the following dates and shall record, report, 
and quality-assure the data from the monitoring systems under paragraph 
(a)(1) of this section on and after the following dates.
    (1) For the owner or operator of a TR SO2 Group 2 unit 
that commences commercial operation before July 1, 2014, January 1, 
2015.
    (2) For the owner or operator of a TR SO2 Group 2 unit 
that commences commercial operation on or after July 1, 2014, by the 
later of the following:
    (i) January 1, 2015; or
    (ii) 180 calendar days after the date on which the unit commences 
commercial operation.
    (3) The owner or operator of a TR SO2 Group 2 unit for 
which construction of a new stack or flue or installation of add-on 
SO2 emission controls is completed after the applicable 
deadline under paragraph (b)(1) or (2) of this section shall meet the 
requirements of Sec. Sec. 75.4(e)(1) through (e)(4) of this chapter, 
except that:
    (i) Such requirements shall apply to the monitoring systems required 
under Sec. 97.730 through Sec. 97.735, rather than the monitoring 
systems required under part 75 of this chapter;
    (ii) SO2 concentration, stack gas moisture content, stack 
gas volumetric flow rate, and O2 or CO2 
concentration data shall be determined and reported, rather than the 
data listed in Sec. 75.4(e)(2) of this chapter; and
    (iii) Any petition for another procedure under Sec. 75.4(e)(2) of 
this chapter shall be submitted under Sec. 97.735, rather than Sec. 
75.66.
    (c) Reporting data. The owner or operator of a TR SO2 
Group 2 unit that does not meet the applicable compliance date set forth 
in paragraph (b) of this

[[Page 522]]

section for any monitoring system under paragraph (a)(1) of this section 
shall, for each such monitoring system, determine, record, and report 
maximum potential (or, as appropriate, minimum potential) values for 
SO2 concentration, stack gas flow rate, stack gas moisture 
content, fuel flow rate, and any other parameters required to determine 
SO2 mass emissions and heat input in accordance with Sec. 
75.31(b)(2) or (c)(3) of this chapter or section 2.4 of appendix D to 
part 75 of this chapter, as applicable.
    (d) Prohibitions. (1) No owner or operator of a TR SO2 
Group 2 unit shall use any alternative monitoring system, alternative 
reference method, or any other alternative to any requirement of this 
subpart without having obtained prior written approval in accordance 
with Sec. 97.735.
    (2) No owner or operator of a TR SO2 Group 2 unit shall 
operate the unit so as to discharge, or allow to be discharged, 
SO2 to the atmosphere without accounting for all such 
SO2 in accordance with the applicable provisions of this 
subpart and part 75 of this chapter.
    (3) No owner or operator of a TR SO2 Group 2 unit shall 
disrupt the continuous emission monitoring system, any portion thereof, 
or any other approved emission monitoring method, and thereby avoid 
monitoring and recording SO2 mass discharged into the 
atmosphere or heat input, except for periods of recertification or 
periods when calibration, quality assurance testing, or maintenance is 
performed in accordance with the applicable provisions of this subpart 
and part 75 of this chapter.
    (4) No owner or operator of a TR SO2 Group 2 unit shall 
retire or permanently discontinue use of the continuous emission 
monitoring system, any component thereof, or any other approved 
monitoring system under this subpart, except under any one of the 
following circumstances:
    (i) During the period that the unit is covered by an exemption under 
Sec. 97.705 that is in effect;
    (ii) The owner or operator is monitoring emissions from the unit 
with another certified monitoring system approved, in accordance with 
the applicable provisions of this subpart and part 75 of this chapter, 
by the Administrator for use at that unit that provides emission data 
for the same pollutant or parameter as the retired or discontinued 
monitoring system; or
    (iii) The designated representative submits notification of the date 
of certification testing of a replacement monitoring system for the 
retired or discontinued monitoring system in accordance with Sec. 
97.731(d)(3)(i).
    (e) Long-term cold storage. The owner or operator of a TR 
SO2 Group 2 unit is subject to the applicable provisions of 
Sec. 75.4(d) of this chapter concerning units in long-term cold 
storage.

[76 FR 48379, Aug. 8, 2011, as amended at 79 FR 71672, Dec. 3, 2014]



Sec. 97.731  Initial monitoring system certification and 
recertification procedures.


    (a) The owner or operator of a TR SO2 Group 2 unit shall 
be exempt from the initial certification requirements of this section 
for a monitoring system under Sec. 97.730(a)(1) if the following 
conditions are met:
    (1) The monitoring system has been previously certified in 
accordance with part 75 of this chapter; and
    (2) The applicable quality-assurance and quality-control 
requirements of Sec. 75.21 of this chapter and appendices B and D to 
part 75 of this chapter are fully met for the certified monitoring 
system described in paragraph (a)(1) of this section.
    (b) The recertification provisions of this section shall apply to a 
monitoring system under Sec. 97.730(a)(1) that is exempt from initial 
certification requirements under paragraph (a) of this section.
    (c) [Reserved]
    (d) Except as provided in paragraph (a) of this section, the owner 
or operator of a TR SO2 Group 2 unit shall comply with the 
following initial certification and recertification procedures, for a 
continuous monitoring system (i.e., a continuous emission monitoring 
system and an excepted monitoring system under appendix D to part 75 of 
this chapter) under Sec. 97.730(a)(1). The owner or operator of a unit 
that qualifies to use the low mass emissions excepted monitoring 
methodology under Sec. 75.19 of this chapter or that

[[Page 523]]

qualifies to use an alternative monitoring system under subpart E of 
part 75 of this chapter shall comply with the procedures in paragraph 
(e) or (f) of this section respectively.
    (1) Requirements for initial certification. The owner or operator 
shall ensure that each continuous monitoring system under Sec. 
97.730(a)(1) (including the automated data acquisition and handling 
system) successfully completes all of the initial certification testing 
required under Sec. 75.20 of this chapter by the applicable deadline in 
Sec. 97.730(b). In addition, whenever the owner or operator installs a 
monitoring system to meet the requirements of this subpart in a location 
where no such monitoring system was previously installed, initial 
certification in accordance with Sec. 75.20 of this chapter is 
required.
    (2) Requirements for recertification. Whenever the owner or operator 
makes a replacement, modification, or change in any certified continuous 
emission monitoring system under Sec. 97.730(a)(1) that may 
significantly affect the ability of the system to accurately measure or 
record SO2 mass emissions or heat input rate or to meet the 
quality-assurance and quality-control requirements of Sec. 75.21 of 
this chapter or appendix B to part 75 of this chapter, the owner or 
operator shall recertify the monitoring system in accordance with Sec. 
75.20(b) of this chapter. Furthermore, whenever the owner or operator 
makes a replacement, modification, or change to the flue gas handling 
system or the unit's operation that may significantly change the stack 
flow or concentration profile, the owner or operator shall recertify 
each continuous emission monitoring system whose accuracy is potentially 
affected by the change, in accordance with Sec. 75.20(b) of this 
chapter. Examples of changes to a continuous emission monitoring system 
that require recertification include: Replacement of the analyzer, 
complete replacement of an existing continuous emission monitoring 
system, or change in location or orientation of the sampling probe or 
site. Any fuel flowmeter system under Sec. 97.730(a)(1) is subject to 
the recertification requirements in Sec. 75.20(g)(6) of this chapter.
    (3) Approval process for initial certification and recertification. 
For initial certification of a continuous monitoring system under Sec. 
97.730(a)(1), paragraphs (d)(3)(i) through (v) of this section apply. 
For recertifications of such monitoring systems, paragraphs (d)(3)(i) 
through (iv) of this section and the procedures in Sec. Sec. 
75.20(b)(5) and (g)(7) of this chapter (in lieu of the procedures in 
paragraph (d)(3)(v) of this section) apply, provided that in applying 
paragraphs (d)(3)(i) through (iv) of this section, the words 
``certification'' and ``initial certification'' are replaced by the word 
``recertification'' and the word ``certified'' is replaced by with the 
word ``recertified''.
    (i) Notification of certification. The designated representative 
shall submit to the appropriate EPA Regional Office and the 
Administrator written notice of the dates of certification testing, in 
accordance with Sec. 97.733.
    (ii) Certification application. The designated representative shall 
submit to the Administrator a certification application for each 
monitoring system. A complete certification application shall include 
the information specified in Sec. 75.63 of this chapter.
    (iii) Provisional certification date. The provisional certification 
date for a monitoring system shall be determined in accordance with 
Sec. 75.20(a)(3) of this chapter. A provisionally certified monitoring 
system may be used under the TR SO2 Group 2 Trading Program 
for a period not to exceed 120 days after receipt by the Administrator 
of the complete certification application for the monitoring system 
under paragraph (d)(3)(ii) of this section. Data measured and recorded 
by the provisionally certified monitoring system, in accordance with the 
requirements of part 75 of this chapter, will be considered valid 
quality-assured data (retroactive to the date and time of provisional 
certification), provided that the Administrator does not invalidate the 
provisional certification by issuing a notice of disapproval within 120 
days of the date of receipt of the complete certification application by 
the Administrator.
    (iv) Certification application approval process. The Administrator 
will issue a written notice of approval or

[[Page 524]]

disapproval of the certification application to the owner or operator 
within 120 days of receipt of the complete certification application 
under paragraph (d)(3)(ii) of this section. In the event the 
Administrator does not issue such a notice within such 120-day period, 
each monitoring system that meets the applicable performance 
requirements of part 75 of this chapter and is included in the 
certification application will be deemed certified for use under the TR 
SO2 Group 2 Trading Program.
    (A) Approval notice. If the certification application is complete 
and shows that each monitoring system meets the applicable performance 
requirements of part 75 of this chapter, then the Administrator will 
issue a written notice of approval of the certification application 
within 120 days of receipt.
    (B) Incomplete application notice. If the certification application 
is not complete, then the Administrator will issue a written notice of 
incompleteness that sets a reasonable date by which the designated 
representative must submit the additional information required to 
complete the certification application. If the designated representative 
does not comply with the notice of incompleteness by the specified date, 
then the Administrator may issue a notice of disapproval under paragraph 
(d)(3)(iv)(C) of this section.
    (C) Disapproval notice. If the certification application shows that 
any monitoring system does not meet the performance requirements of part 
75 of this chapter or if the certification application is incomplete and 
the requirement for disapproval under paragraph (d)(3)(iv)(B) of this 
section is met, then the Administrator will issue a written notice of 
disapproval of the certification application. Upon issuance of such 
notice of disapproval, the provisional certification is invalidated by 
the Administrator and the data measured and recorded by each uncertified 
monitoring system shall not be considered valid quality-assured data 
beginning with the date and hour of provisional certification (as 
defined under Sec. 75.20(a)(3) of this chapter).
    (D) Audit decertification. The Administrator may issue a notice of 
disapproval of the certification status of a monitor in accordance with 
Sec. 97.732(b).
    (v) Procedures for loss of certification. If the Administrator 
issues a notice of disapproval of a certification application under 
paragraph (d)(3)(iv)(C) of this section or a notice of disapproval of 
certification status under paragraph (d)(3)(iv)(D) of this section, 
then:
    (A) The owner or operator shall substitute the following values, for 
each disapproved monitoring system, for each hour of unit operation 
during the period of invalid data specified under Sec. 
75.20(a)(4)(iii), Sec. 75.20(g)(7), or Sec. 75.21(e) of this chapter 
and continuing until the applicable date and hour specified under Sec. 
75.20(a)(5)(i) or (g)(7) of this chapter:
    (1) For a disapproved SO2 pollutant concentration monitor 
and disapproved flow monitor, respectively, the maximum potential 
concentration of SO2 and the maximum potential flow rate, as 
defined in sections 2.1.1.1 and 2.1.4.1 of appendix A to part 75 of this 
chapter.
    (2) For a disapproved moisture monitoring system and disapproved 
diluent gas monitoring system, respectively, the minimum potential 
moisture percentage and either the maximum potential CO2 
concentration or the minimum potential O2 concentration (as 
applicable), as defined in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of 
appendix A to part 75 of this chapter.
    (3) For a disapproved fuel flowmeter system, the maximum potential 
fuel flow rate, as defined in section 2.4.2.1 of appendix D to part 75 
of this chapter.
    (B) The designated representative shall submit a notification of 
certification retest dates and a new certification application in 
accordance with paragraphs (d)(3)(i) and (ii) of this section.
    (C) The owner or operator shall repeat all certification tests or 
other requirements that were failed by the monitoring system, as 
indicated in the Administrator's notice of disapproval, no later than 30 
unit operating days after the date of issuance of the notice of 
disapproval.
    (e) The owner or operator of a unit qualified to use the low mass 
emissions (LME) excepted methodology under

[[Page 525]]

Sec. 75.19 of this chapter shall meet the applicable certification and 
recertification requirements in Sec. Sec. 75.19(a)(2) and 75.20(h) of 
this chapter. If the owner or operator of such a unit elects to certify 
a fuel flowmeter system for heat input determination, the owner or 
operator shall also meet the certification and recertification 
requirements in Sec. 75.20(g) of this chapter.
    (f) The designated representative of each unit for which the owner 
or operator intends to use an alternative monitoring system approved by 
the Administrator under subpart E of part 75 of this chapter shall 
comply with the applicable notification and application procedures of 
Sec. 75.20(f) of this chapter.



Sec. 97.732  Monitoring system out-of-control periods.

    (a) General provisions. Whenever any monitoring system fails to meet 
the quality-assurance and quality-control requirements or data 
validation requirements of part 75 of this chapter, data shall be 
substituted using the applicable missing data procedures in subpart D or 
appendix D to part 75 of this chapter.
    (b) Audit decertification. Whenever both an audit of a monitoring 
system and a review of the initial certification or recertification 
application reveal that any monitoring system should not have been 
certified or recertified because it did not meet a particular 
performance specification or other requirement under Sec. 97.731 or the 
applicable provisions of part 75 of this chapter, both at the time of 
the initial certification or recertification application submission and 
at the time of the audit, the Administrator will issue a notice of 
disapproval of the certification status of such monitoring system. For 
the purposes of this paragraph, an audit shall be either a field audit 
or an audit of any information submitted to the Administrator or any 
State or permitting authority. By issuing the notice of disapproval, the 
Administrator revokes prospectively the certification status of the 
monitoring system. The data measured and recorded by the monitoring 
system shall not be considered valid quality-assured data from the date 
of issuance of the notification of the revoked certification status 
until the date and time that the owner or operator completes 
subsequently approved initial certification or recertification tests for 
the monitoring system. The owner or operator shall follow the applicable 
initial certification or recertification procedures in Sec. 97.731 for 
each disapproved monitoring system.



Sec. 97.733  Notifications concerning monitoring.

    The designated representative of a TR SO2 Group 2 unit 
shall submit written notice to the Administrator in accordance with 
Sec. 75.61 of this chapter.



Sec. 97.734  Recordkeeping and reporting.

    (a) General provisions. The designated representative shall comply 
with all recordkeeping and reporting requirements in paragraphs (b) 
through (e) of this section, the applicable recordkeeping and reporting 
requirements in subparts F and G of part 75 of this chapter, and the 
requirements of Sec. 97.714(a).
    (b) Monitoring plans. The owner or operator of a TR SO2 
Group 2 unit shall comply with requirements of Sec. 75.62 of this 
chapter.
    (c) Certification applications. The designated representative shall 
submit an application to the Administrator within 45 days after 
completing all initial certification or recertification tests required 
under Sec. 97.731, including the information required under Sec. 75.63 
of this chapter.
    (d) Quarterly reports. The designated representative shall submit 
quarterly reports, as follows:
    (1) The designated representative shall report the SO2 
mass emissions data and heat input data for the TR SO2 Group 
2 unit, in an electronic quarterly report in a format prescribed by the 
Administrator, for each calendar quarter beginning with:
    (i) For a unit that commences commercial operation before July 1, 
2014, the calendar quarter covering January 1, 2015 through March 31, 
2015; or
    (ii) For a unit that commences commercial operation on or after July 
1, 2014, the calendar quarter corresponding to the earlier of the date 
of provisional certification or the applicable deadline for initial 
certification

[[Page 526]]

under Sec. 97.730(b), unless that quarter is the third or fourth 
quarter of 2014, in which case reporting shall commence in the quarter 
covering January 1, 2015 through March 31, 2015.
    (2) The designated representative shall submit each quarterly report 
to the Administrator within 30 days after the end of the calendar 
quarter covered by the report. Quarterly reports shall be submitted in 
the manner specified in Sec. 75.64 of this chapter.
    (3) For TR SO2 Group 2 units that are also subject to the 
Acid Rain Program, TR NOX Annual Trading Program, or TR 
NOX Ozone Season Trading Program, quarterly reports shall 
include the applicable data and information required by subparts F 
through H of part 75 of this chapter as applicable, in addition to the 
SO2 mass emission data, heat input data, and other 
information required by this subpart.
    (4) The Administrator may review and conduct independent audits of 
any quarterly report in order to determine whether the quarterly report 
meets the requirements of this subpart and part 75 of this chapter, 
including the requirement to use substitute data.
    (i) The Administrator will notify the designated representative of 
any determination that the quarterly report fails to meet any such 
requirements and specify in such notification any corrections that the 
Administrator believes are necessary to make through resubmission of the 
quarterly report and a reasonable time period within which the 
designated representative must respond. Upon request by the designated 
representative, the Administrator may specify reasonable extensions of 
such time period. Within the time period (including any such extensions) 
specified by the Administrator, the designated representative shall 
resubmit the quarterly report with the corrections specified by the 
Administrator, except to the extent the designated representative 
provides information demonstrating that a specified correction is not 
necessary because the quarterly report already meets the requirements of 
this subpart and part 75 of this chapter that are relevant to the 
specified correction.
    (ii) Any resubmission of a quarterly report shall meet the 
requirements applicable to the submission of a quarterly report under 
this subpart and part 75 of this chapter, except for the deadline set 
forth in paragraph (d)(2) of this section.
    (e) Compliance certification. The designated representative shall 
submit to the Administrator a compliance certification (in a format 
prescribed by the Administrator) in support of each quarterly report 
based on reasonable inquiry of those persons with primary responsibility 
for ensuring that all of the unit's emissions are correctly and fully 
monitored. The certification shall state that:
    (1) The monitoring data submitted were recorded in accordance with 
the applicable requirements of this subpart and part 75 of this chapter, 
including the quality assurance procedures and specifications; and
    (2) For a unit with add-on SO2 emission controls and for 
all hours where SO2 data are substituted in accordance with 
Sec. 75.34(a)(1) of this chapter, the add-on emission controls were 
operating within the range of parameters listed in the quality 
assurance/quality control program under appendix B to part 75 of this 
chapter and the substitute data values do not systematically 
underestimate SO2 emissions.

[76 FR 48379, Aug. 8, 2011, as amended at 79 FR 71672, Dec. 3, 2014]



Sec. 97.735  Petitions for alternatives to monitoring, recordkeeping,
or reporting requirements.

    (a) The designated representative of a TR SO2 Group 2 
unit may submit a petition under Sec. 75.66 of this chapter to the 
Administrator, requesting approval to apply an alternative to any 
requirement of Sec. Sec. 97.730 through 97.734.
    (b) A petition submitted under paragraph (a) of this section shall 
include sufficient information for the evaluation of the petition, 
including, at a minimum, the following information:
    (i) Identification of each unit and source covered by the petition;
    (ii) A detailed explanation of why the proposed alternative is being 
suggested in lieu of the requirement;
    (iii) A description and diagram of any equipment and procedures used 
in the proposed alternative;

[[Page 527]]

    (iv) A demonstration that the proposed alternative is consistent 
with the purposes of the requirement for which the alternative is 
proposed and with the purposes of this subpart and part 75 of this 
chapter and that any adverse effect of approving the alternative will be 
de minimis; and
    (v) Any other relevant information that the Administrator may 
require.
    (c) Use of an alternative to any requirement referenced in paragraph 
(a) of this section is in accordance with this subpart only to the 
extent that the petition is approved in writing by the Administrator and 
that such use is in accordance with such approval.



  Sec. Appendix A to Part 97--Final Section 126 Rule: EGU Allocations, 
                                2004-2007

----------------------------------------------------------------------------------------------------------------
                                                                                                  NOX allocation
           ST                          Plant                 Plant--id          Point--id            for EGUs
----------------------------------------------------------------------------------------------------------------
DC......................  BENNING........................           603  15                                   80
DC......................  BENNING........................           603  16                                  117
DE......................  CHRISTIANA SUB.................           591  11                                    5
DE......................  CHRISTIANA SUB.................           591  14                                    5
DE......................  DELAWARE CITY..................         52193  B4                                  141
DE......................  DELAWARE CITY..................         52193  ST-- 1                              155
DE......................  DELAWARE CITY..................         52193  ST-- 2                              159
DE......................  DELAWARE CITY..................         52193  ST-- 3                              158
DE......................  EDGE MOOR......................           593  3                                   234
DE......................  EDGE MOOR......................           593  4                                   401
DE......................  EDGE MOOR......................           593  5                                   602
DE......................  HAY ROAD.......................          7153  **3                                 184
DE......................  HAY ROAD.......................          7153  --1                                 235
DE......................  HAY ROAD.......................          7153  --2                                 207
DE......................  INDIAN RIVER...................           594  1                                   187
DE......................  INDIAN RIVER...................           594  2                                   194
DE......................  INDIAN RIVER...................           594  3                                   369
DE......................  INDIAN RIVER...................           594  4                                   729
DE......................  MCKEE RUN......................           599  3                                   119
DE......................  VAN SANT STATION...............          7318  **11                                  7
IN......................  ANDERSON.......................          7336  --ACT1                                5
IN......................  ANDERSON.......................          7336  --ACT2                                5
IN......................  CLIFTY CREEK...................           983  1                                   558
IN......................  CLIFTY CREEK...................           983  2                                   543
IN......................  CLIFTY CREEK...................           983  3                                   564
IN......................  CLIFTY CREEK...................           983  4                                   525
IN......................  CLIFTY CREEK...................           983  5                                   561
IN......................  CLIFTY CREEK...................           983  6                                   509
IN......................  CONNERSVILLE...................          1002  1                                     1
IN......................  CONNERSVILLE...................          1002  2                                     1
IN......................  GALLAGHER......................          1008  1                                   290
IN......................  GALLAGHER......................          1008  2                                   276
IN......................  GALLAGHER......................          1008  3                                   347
IN......................  GALLAGHER......................          1008  4                                   329
IN......................  NOBLESVILLE....................          1007  1                                    48
IN......................  NOBLESVILLE....................          1007  2                                    45
IN......................  NOBLESVILLE....................          1007  3                                    45
IN......................  RICHMOND.......................          7335  --RCT1                                5
IN......................  RICHMOND.......................          7335  --RCT2                                5
IN......................  TANNERS CREEK..................           988  U1                                  297
IN......................  TANNERS CREEK..................           988  U2                                  235
IN......................  TANNERS CREEK..................           988  U3                                  387
IN......................  TANNERS CREEK..................           988  U4                                  906
IN......................  WHITEWATER VALLEY..............          1040  1                                    74
IN......................  WHITEWATER VALLEY..............          1040  2                                   173
KY......................  BIG SANDY......................          1353  BSU1                                565
KY......................  BIG SANDY......................          1353  BSU2                              1,741
KY......................  CANE RUN.......................          1363  4                                   397
KY......................  CANE RUN.......................          1363  5                                   332
KY......................  CANE RUN.......................          1363  6                                   430
KY......................  COOPER.........................          1384  1                                   183
KY......................  COOPER.........................          1384  2                                   367
KY......................  DALE...........................          1385  3                                   161
KY......................  DALE...........................          1385  4                                   158
KY......................  E W BROWN......................          1355  1                                   193
KY......................  E W BROWN......................          1355  10                                   37
KY......................  E W BROWN......................          1355  2                                   317

[[Page 528]]

 
KY......................  E W BROWN......................          1355  3                                   863
KY......................  E W BROWN......................          1355  8                                    34
KY......................  E W BROWN......................          1355  9                                    34
KY......................  E.W. BROWN.....................          1355  11                                   21
KY......................  EAST BEND......................          6018  2                                 1,413
KY......................  GHENT..........................          1356  1                                 1,232
KY......................  GHENT..........................          1356  2                                 1,081
KY......................  GHENT..........................          1356  3                                 1,104
KY......................  GHENT..........................          1356  4                                 1,132
KY......................  H L SPURLOCK...................          6041  1                                   697
KY......................  H L SPURLOCK...................          6041  2                                 1,589
KY......................  MILL CREEK.....................          1364  1                                   528
KY......................  MILL CREEK.....................          1364  2                                   600
KY......................  MILL CREEK.....................          1364  3                                   941
KY......................  MILL CREEK.....................          1364  4                                 1,096
KY......................  PADDY'S RUN....................          1366  12                                    8
KY......................  PINEVILLE......................          1360  3                                    67
KY......................  TRIMBLE COUNTY.................          6071  1                                 1,221
KY......................  TYRONE.........................          1361  1                                     3
KY......................  TYRONE.........................          1361  2                                     3
KY......................  TYRONE.........................          1361  3                                     3
KY......................  TYRONE.........................          1361  4                                     3
KY......................  TYRONE.........................          1361  5                                   117
MD......................  BRANDON SHORES.................           602  1                                 1,827
MD......................  BRANDON SHORES.................           602  2                                 1,713
MD......................  C P CRANE......................          1552  1                                   434
MD......................  C P CRANE......................          1552  2                                   463
MD......................  CHALK POINT....................          1571  --GT2                                 1
MD......................  CHALK POINT....................          1571  --GT3                                36
MD......................  CHALK POINT....................          1571  --GT4                                39
MD......................  CHALK POINT....................          1571  --GT5                                55
MD......................  CHALK POINT....................          1571  --GT6                                60
MD......................  CHALK POINT....................          1571  --SGT1                               24
MD......................  CHALK POINT....................          1571  1                                   833
MD......................  CHALK POINT....................          1571  2                                   861
MD......................  CHALK POINT....................          1571  3                                   585
MD......................  CHALK POINT....................          1571  4                                   522
MD......................  DICKERSON......................          1572  --GT2                                36
MD......................  DICKERSON......................          1572  --GT3                                66
MD......................  DICKERSON......................          1572  1                                   447
MD......................  DICKERSON......................          1572  2                                   441
MD......................  DICKERSON......................          1572  3                                   481
MD......................  GOULD STREET...................          1553  3                                    81
MD......................  HERBERT A WAGNER...............          1554  1                                   134
MD......................  HERBERT A WAGNER...............          1554  2                                   399
MD......................  HERBERT A WAGNER...............          1554  3                                   723
MD......................  HERBERT A WAGNER...............          1554  4                                   301
MD......................  MORGANTOWN.....................          1573  --GT3                                 9
MD......................  MORGANTOWN.....................          1573  --GT4                                 9
MD......................  MORGANTOWN.....................          1573  --GT5                                 9
MD......................  MORGANTOWN.....................          1573  --GT6                                 8
MD......................  MORGANTOWN.....................          1573  1                                 1,151
MD......................  MORGANTOWN.....................          1573  2                                 1,375
MD......................  PANDA BRANDYWINE...............         54832  1                                    95
MD......................  PANDA BRANDYWINE...............         54832  2                                    84
MD......................  PERRYMAN.......................          1556  **51                                 56
MD......................  PERRYMAN.......................          1556  --GT1                                 8
MD......................  PERRYMAN.......................          1556  --GT2                                 9
MD......................  PERRYMAN.......................          1556  --GT3                                 6
MD......................  PERRYMAN.......................          1556  --GT4                                10
MD......................  R P SMITH......................          1570  11                                  143
MD......................  R P SMITH......................          1570  9                                    11
MD......................  RIVERSIDE......................          1559  --GT6                                11
MD......................  RIVERSIDE......................          1559  4                                    40
MD......................  VIENNA.........................          1564  8                                   169
MD......................  WESTPORT.......................          1560  --GT5                                28
MI......................  ADA COGEN LTD..................         10819  CA--Ltd                              23
MI......................  BELLE RIVER....................          6034  1                                 1,589
MI......................  BELLE RIVER....................          6034  2                                 1,672
MI......................  DAN E KARN.....................          1702  1                                   552
MI......................  DAN E KARN.....................          1702  2                                   530
MI......................  DAN E KARN.....................          1702  3                                   288
MI......................  DAN E KARN.....................          1702  4                                   310

[[Page 529]]

 
MI......................  ECKERT STATION.................          1831  1                                    52
MI......................  ECKERT STATION.................          1831  2                                    47
MI......................  ECKERT STATION.................          1831  3                                    65
MI......................  ECKERT STATION.................          1831  4                                   116
MI......................  ECKERT STATION.................          1831  5                                   154
MI......................  ECKERT STATION.................          1831  6                                   131
MI......................  ENDICOTT GENERATING STATION....          4259  1                                    98
MI......................  ERICKSON.......................          1832  1                                   381
MI......................  GREENWOOD......................          6035  1                                   373
MI......................  HANCOCK........................          1730  5                                     3
MI......................  HANCOCK........................          1730  6                                     3
MI......................  HARBOR BEACH...................          1731  1                                    97
MI......................  J C WEADOCK....................          1720  7                                   346
MI......................  J C WEADOCK....................          1720  8                                   342
MI......................  J R WHITING....................          1723  1                                   225
MI......................  J R WHITING....................          1723  2                                   204
MI......................  J R WHITING....................          1723  3                                   249
MI......................  JAMES DE YOUNG.................          1830  5                                    69
MI......................  MARYSVILLE.....................          1732  10                                   22
MI......................  MARYSVILLE.....................          1732  11                                   16
MI......................  MARYSVILLE.....................          1732  12                                   17
MI......................  MARYSVILLE.....................          1732  9                                    17
MI......................  MIDLAND COGENERATION VENTURE...         10745  003                                 269
MI......................  MIDLAND COGENERATION VENTURE...         10745  004                                 276
MI......................  MIDLAND COGENERATION VENTURE...         10745  005                                 271
MI......................  MIDLAND COGENERATION VENTURE...         10745  006                                 273
MI......................  MIDLAND COGENERATION VENTURE...         10745  007                                 280
MI......................  MIDLAND COGENERATION VENTURE...         10745  008                                 277
MI......................  MIDLAND COGENERATION VENTURE...         10745  009                                 273
MI......................  MIDLAND COGENERATION VENTURE...         10745  010                                 271
MI......................  MIDLAND COGENERATION VENTURE...         10745  011                                 274
MI......................  MIDLAND COGENERATION VENTURE...         10745  012                                 269
MI......................  MIDLAND COGENERATION VENTURE...         10745  013                                 275
MI......................  MIDLAND COGENERATION VENTURE...         10745  014                                 269
MI......................  MISTERSKY......................          1822  5                                    33
MI......................  MISTERSKY......................          1822  6                                   155
MI......................  MISTERSKY......................          1822  7                                    98
MI......................  MONROE.........................          1733  1                                 1,902
MI......................  MONROE.........................          1733  2                                 1,555
MI......................  MONROE.........................          1733  3                                 1,574
MI......................  MONROE.........................          1733  4                                 1,822
MI......................  RIVER ROUGE....................          1740  1                                     0
MI......................  RIVER ROUGE....................          1740  2                                   627
MI......................  RIVER ROUGE....................          1740  3                                   652
MI......................  ROUGE POWERHOUSE 1....         10272  1                                   232
MI......................  ST CLAIR.......................          1743  1                                   339
MI......................  ST CLAIR.......................          1743  2                                   304
MI......................  ST CLAIR.......................          1743  3                                   351
MI......................  ST CLAIR.......................          1743  4                                   349
MI......................  ST CLAIR.......................          1743  5                                     0
MI......................  ST CLAIR.......................          1743  6                                   646
MI......................  ST CLAIR.......................          1743  7                                   733
MI......................  TRENTON CHANNEL................          1745  16                                  132
MI......................  TRENTON CHANNEL................          1745  17                                  124
MI......................  TRENTON CHANNEL................          1745  18                                  130
MI......................  TRENTON CHANNEL................          1745  19                                  126
MI......................  TRENTON CHANNEL................          1745  9A                                  968
MI......................  WYANDOTTE......................          1866  5                                     8
MI......................  WYANDOTTE......................          1866  7                                    81
MI......................  WYANDOTTE......................          1866  8                                    36
NC......................  ASHEVILLE......................          2706  1                                   491
NC......................  ASHEVILLE......................          2706  2                                   479
NC......................  BELEWS CREEK...................          8042  1                                 2,306
NC......................  BELEWS CREEK...................          8042  2                                 2,688
NC......................  BUCK...........................          2720  5                                    59
NC......................  BUCK...........................          2720  6                                    65
NC......................  BUCK...........................          2720  7                                    69
NC......................  BUCK...........................          2720  8                                   284
NC......................  BUCK...........................          2720  9                                   300
NC......................  BUTLER WARNER GEN PL...........          1016  --1                                  40
NC......................  BUTLER WARNER GEN PL...........          1016  --2                                  40
NC......................  BUTLER WARNER GEN PL...........          1016  --3                                  40
NC......................  BUTLER WARNER GEN PL...........          1016  --6                                  42

[[Page 530]]

 
NC......................  BUTLER WARNER GEN PL...........          1016  --7                                  40
NC......................  BUTLER WARNER GEN PL...........          1016  --8                                  40
NC......................  BUTLER WARNER GEN PL...........          1016  --9                                 103
NC......................  CAPE FEAR......................          2708  5                                   255
NC......................  CAPE FEAR......................          2708  6                                   361
NC......................  CLIFFSIDE......................          2721  1                                    67
NC......................  CLIFFSIDE......................          2721  2                                    73
NC......................  CLIFFSIDE......................          2721  3                                    95
NC......................  CLIFFSIDE......................          2721  4                                   107
NC......................  CLIFFSIDE......................          2721  5                                 1,180
NC......................  COGENTRIX-ROCKY MOUNT..........         50468  ST--unt                             303
NC......................  COGENTRIX ELIZABETHTOWN........         10380  ST--OWN                             111
NC......................  COGENTRIX KENANSVILLE..........         10381  ST--LLE                             102
NC......................  COGENTRIX LUMBERTON............         10382  ST--TON                             111
NC......................  COGENTRIX ROXBORO..............         10379  ST--ORO                             166
NC......................  COGENTRIX SOUTHPORT............         10378  ST--ORT                             335
NC......................  DAN RIVER......................          2723  1                                   117
NC......................  DAN RIVER......................          2723  2                                   128
NC......................  DAN RIVER......................          2723  3                                   271
NC......................  G G ALLEN......................          2718  1                                   311
NC......................  G G ALLEN......................          2718  2                                   316
NC......................  G G ALLEN......................          2718  3                                   525
NC......................  G G ALLEN......................          2718  4                                   470
NC......................  G G ALLEN......................          2718  5                                   514
NC......................  L V SUTTON.....................          2713  1                                   162
NC......................  L V SUTTON.....................          2713  2                                   176
NC......................  L V SUTTON.....................          2713  3                                   717
NC......................  L V SUTTON.....................          2713  CT2B                                  2
NC......................  LEE............................          2709  1                                   129
NC......................  LEE............................          2709  2                                   142
NC......................  LEE............................          2709  3                                   414
NC......................  LEE............................          2709  CT4                                   1
NC......................  LINCOLN........................          7277  1                                    33
NC......................  LINCOLN........................          7277  10                                   31
NC......................  LINCOLN........................          7277  11                                   33
NC......................  LINCOLN........................          7277  12                                   31
NC......................  LINCOLN........................          7277  13                                   26
NC......................  LINCOLN........................          7277  14                                   26
NC......................  LINCOLN........................          7277  15                                   25
NC......................  LINCOLN........................          7277  16                                   25
NC......................  LINCOLN........................          7277  2                                    33
NC......................  LINCOLN........................          7277  3                                    31
NC......................  LINCOLN........................          7277  4                                    31
NC......................  LINCOLN........................          7277  5                                    29
NC......................  LINCOLN........................          7277  6                                    30
NC......................  LINCOLN........................          7277  7                                    24
NC......................  LINCOLN........................          7277  8                                    25
NC......................  LINCOLN........................          7277  9                                    32
NC......................  MARSHALL.......................          2727  1                                   899
NC......................  MARSHALL.......................          2727  2                                   940
NC......................  MARSHALL.......................          2727  3                                 1,588
NC......................  MARSHALL.......................          2727  4                                 1,570
NC......................  MAYO...........................          6250  1A                                  893
NC......................  MAYO...........................          6250  1B                                  875
NC......................  PANDA-ROSEMARY.................         50555  CT--ary                              62
NC......................  PANDA-ROSEMARY.................         50555  CW--ary                              47
NC......................  RIVERBEND......................          2732  10                                  266
NC......................  RIVERBEND......................          2732  7                                   193
NC......................  RIVERBEND......................          2732  8                                   200
NC......................  RIVERBEND......................          2732  9                                   253
NC......................  ROANOKE VALLEY.................         50254  1                                   440
NC......................  ROANOKE VALLEY.................         50254  2                                   140
NC......................  ROXBORO........................          2712  1                                   766
NC......................  ROXBORO........................          2712  2                                 1,426
NC......................  ROXBORO........................          2712  3A                                  792
NC......................  ROXBORO........................          2712  3B                                  785
NC......................  ROXBORO........................          2712  4A                                  778
NC......................  ROXBORO........................          2712  4B                                  733
NC......................  TOBACCOVILLE...................         50221  1                                    53
NC......................  TOBACCOVILLE...................         50221  2                                    53
NC......................  TOBACCOVILLE...................         50221  3                                    53
NC......................  TOBACCOVILLE...................         50221  4                                    53
NC......................  UNC--CHAPEL HILL...............         54276  ST--ill                              14

[[Page 531]]

 
NC......................  W H WEATHERSPOON...............          2716  1                                    76
NC......................  W H WEATHERSPOON...............          2716  2                                    86
NC......................  W H WEATHERSPOON...............          2716  3                                   161
NC......................  W H WEATHERSPOON...............          2716  CT-1                                  4
NC......................  W H WEATHERSPOON...............          2716  CT-2                                  3
NC......................  W H WEATHERSPOON...............          2716  CT-3                                  2
NC......................  W H WEATHERSPOON...............          2716  CT-4                                  4
NJ......................  B L ENGLAND....................          2378  1                                   353
NJ......................  B L ENGLAND....................          2378  2                                   417
NJ......................  B L ENGLAND....................          2378  3                                   114
NJ......................  BAYONNE........................         50497  1                                   139
NJ......................  BAYONNE........................         50497  2                                   143
NJ......................  BAYONNE........................         50497  3                                   140
NJ......................  BERGEN.........................          2398  1101                                152
NJ......................  BERGEN.........................          2398  1201                                157
NJ......................  BERGEN.........................          2398  1301                                155
NJ......................  BERGEN.........................          2398  1401                                152
NJ......................  BURLINGTON.....................          2399  101                                  30
NJ......................  BURLINGTON.....................          2399  102                                  34
NJ......................  BURLINGTON.....................          2399  103                                  39
NJ......................  BURLINGTON.....................          2399  104                                  47
NJ......................  BURLINGTON.....................          2399  11-1                                  2
NJ......................  BURLINGTON.....................          2399  11-2                                  2
NJ......................  BURLINGTON.....................          2399  11-3                                  2
NJ......................  BURLINGTON.....................          2399  11-4                                  2
NJ......................  BURLINGTON.....................          2399  7                                    17
NJ......................  BURLINGTON.....................          2399  9-1                                   4
NJ......................  BURLINGTON.....................          2399  9-2                                   4
NJ......................  BURLINGTON.....................          2399  9-3                                   4
NJ......................  BURLINGTON.....................          2399  9-4                                   4
NJ......................  CAMDEN.........................         10751  1                                   378
NJ......................  CARLL'S CORNER STATION.........          2379  1                                     2
NJ......................  CARLL'S CORNER STATION.........          2379  2                                    16
NJ......................  CARNEYS POINT (CCLP) NUG.......         10566  ST--NUG                             527
NJ......................  CEDAR STATION..................          2380  1E&W                                  5
NJ......................  CUMBERLAND.....................          5083  --GT1                                40
NJ......................  DEEPWATER......................          2384  1                                    49
NJ......................  DEEPWATER......................          2384  4                                     5
NJ......................  DEEPWATER......................          2384  6                                    42
NJ......................  DEEPWATER......................          2384  8                                   195
NJ......................  EDISON.........................          2400  1-1A&B                                3
NJ......................  EDISON.........................          2400  1-2A&B                                3
NJ......................  EDISON.........................          2400  1-3A&B                                3
NJ......................  EDISON.........................          2400  1-4A&B                                3
NJ......................  EDISON.........................          2400  2-1A&B                                7
NJ......................  EDISON.........................          2400  2-2A&B                                7
NJ......................  EDISON.........................          2400  2-3A&B                                7
NJ......................  EDISON.........................          2400  2-4A&B                                7
NJ......................  EDISON.........................          2400  3-1A&B                                7
NJ......................  EDISON.........................          2400  3-2A&B                                7
NJ......................  EDISON.........................          2400  3-3A&B                                7
NJ......................  EDISON.........................          2400  3-4A&B                                7
NJ......................  ESSEX..........................          2401  10-1A&B                              10
NJ......................  ESSEX..........................          2401  10-2A&B                              10
NJ......................  ESSEX..........................          2401  10-3A&B                              10
NJ......................  ESSEX..........................          2401  10-4A&B                              10
NJ......................  ESSEX..........................          2401  11-1A&B                              11
NJ......................  ESSEX..........................          2401  11-2A&B                              11
NJ......................  ESSEX..........................          2401  11-3A&B                              11
NJ......................  ESSEX..........................          2401  11-4A&B                              11
NJ......................  ESSEX..........................          2401  12-1A&B                              13
NJ......................  ESSEX..........................          2401  12-2A&B                              13
NJ......................  ESSEX..........................          2401  12-3A&B                              13
NJ......................  ESSEX..........................          2401  12-4A&B                              13
NJ......................  ESSEX..........................          2401  9                                    66
NJ......................  FORKED RIVER...................          7138  --1                                  17
NJ......................  FORKED RIVER...................          7138  --2                                  17
NJ......................  GILBERT........................          2393  03                                   47
NJ......................  GILBERT........................          2393  04                                   64
NJ......................  GILBERT........................          2393  05                                   63
NJ......................  GILBERT........................          2393  06                                   61
NJ......................  GILBERT........................          2393  07                                   63
NJ......................  GILBERT........................          2393  1                                     4

[[Page 532]]

 
NJ......................  GILBERT........................          2393  2                                     4
NJ......................  GILBERT........................          2393  CT-9                                 61
NJ......................  HUDSON.........................          2403  1                                   175
NJ......................  HUDSON.........................          2403  2                                   884
NJ......................  HUDSON.........................          2403  3                                     3
NJ......................  KEARNY.........................          2404  10                                   26
NJ......................  KEARNY.........................          2404  11                                   34
NJ......................  KEARNY.........................          2404  12-1                                  8
NJ......................  KEARNY.........................          2404  12-2                                  8
NJ......................  KEARNY.........................          2404  12-3                                  8
NJ......................  KEARNY.........................          2404  12-4                                  8
NJ......................  KEARNY.........................          2404  7                                    35
NJ......................  KEARNY.........................          2404  8                                    16
NJ......................  LINDEN.........................          2406  11                                   16
NJ......................  LINDEN.........................          2406  12                                   11
NJ......................  LINDEN.........................          2406  13                                   20
NJ......................  LINDEN.........................          2406  2                                    52
NJ......................  LINDEN.........................          2406  6                                     2
NJ......................  LINDEN.........................          2406  7                                    60
NJ......................  LINDEN.........................          2406  8                                    70
NJ......................  LINDEN COGEN...................         50006  100                                 276
NJ......................  LINDEN COGEN...................         50006  200                                 280
NJ......................  LINDEN COGEN...................         50006  300                                 274
NJ......................  LINDEN COGEN...................         50006  400                                 272
NJ......................  LINDEN COGEN...................         50006  500                                 278
NJ......................  LOGAN GENERATING PLANT.........         10043  1                                   424
NJ......................  MERCER.........................          2408  1                                   489
NJ......................  MERCER.........................          2408  2                                   558
NJ......................  MICKELTON......................          8008  1                                    28
NJ......................  MIDDLE ST......................          2382  3                                     4
NJ......................  MILFORD POWER LP...............         10616  1                                    44
NJ......................  MOBIL NUG......................          n114  CT--NUG                              40
NJ......................  NEWARK BAY COGEN...............         50385  1                                     9
NJ......................  NEWARK BAY COGEN...............         50385  2                                     9
NJ......................  NORTH JERSEY ENERGY ASSOCIATES.         10308  1                                    19
NJ......................  NORTH JERSEY ENERGY ASSOCIATES.         10308  2                                    19
NJ......................  O'BRIEN (NEWARK) COGENERATION,          50797  1                                     8
                           INC..
NJ......................  O'BRIEN (PARLIN) COGENERATION,          50799  1                                     8
                           INC..
NJ......................  O'BRIEN (PARLIN) COGENERATION,          50799  2                                     8
                           INC..
NJ......................  PEDRICKTOWN COGEN..............         10099  1                                    13
NJ......................  PRIME ENERGY LP................         50852  1                                   178
NJ......................  SALEM..........................          2410  3A&B                                  3
NJ......................  SAYREVILLE.....................          2390  07                                   40
NJ......................  SAYREVILLE.....................          2390  08                                   51
NJ......................  SAYREVILLE.....................          2390  C-1                                  16
NJ......................  SAYREVILLE.....................          2390  C-2                                  13
NJ......................  SAYREVILLE.....................          2390  C-3                                  11
NJ......................  SAYREVILLE.....................          2390  C-4                                  13
NJ......................  SEWAREN........................          2411  1                                    42
NJ......................  SEWAREN........................          2411  2                                    45
NJ......................  SEWAREN........................          2411  3                                    58
NJ......................  SEWAREN........................          2411  4                                    91
NJ......................  SEWAREN........................          2411  6                                     2
NJ......................  SHERMAN........................          7288  CT-1                                 37
NJ......................  VINELAND VCLP NUG..............         54807  GT--NUG                              40
NJ......................  WERNER.........................          2385  04                                   14
NJ......................  WERNER.........................          2385  C-1                                   7
NJ......................  WERNER.........................          2385  C-2                                   6
NJ......................  WERNER.........................          2385  C-3                                   7
NJ......................  WERNER.........................          2385  C-4                                   7
NJ......................  WEST STAT......................          6776  1                                    10
NY......................  59TH STREET....................          2503  114                                  41
NY......................  59TH STREET....................          2503  115                                  32
NY......................  74TH STREET....................          2504  120                                  70
NY......................  74TH STREET....................          2504  121                                  80
NY......................  74TH STREET....................          2504  122                                  65
NY......................  ARTHUR KILL....................          2490  20                                  524
NY......................  ARTHUR KILL....................          2490  30                                  380
NY......................  ASTORIA........................          8906  30                                  557
NY......................  ASTORIA........................          8906  40                                  505
NY......................  ASTORIA........................          8906  50                                  561
NY......................  ASTORIA........................          8906  GT2-1                                 9
NY......................  ASTORIA........................          8906  GT2-2                                 9

[[Page 533]]

 
NY......................  ASTORIA........................          8906  GT2-3                                 9
NY......................  ASTORIA........................          8906  GT2-4                                 9
NY......................  ASTORIA........................          8906  GT3-1                                 9
NY......................  ASTORIA........................          8906  GT3-2                                 9
NY......................  ASTORIA........................          8906  GT3-3                                 9
NY......................  ASTORIA........................          8906  GT3-4                                 9
NY......................  ASTORIA........................          8906  GT4-1                                 9
NY......................  ASTORIA........................          8906  GT4-2                                 9
NY......................  ASTORIA........................          8906  GT4-3                                 9
NY......................  ASTORIA........................          8906  GT4-4                                 9
NY......................  BOWLINE POINT..................          2625  1                                   749
NY......................  BOWLINE POINT..................          2625  2                                   566
NY......................  BROOKLYN NAVY YARD.............         54914  1                                   239
NY......................  BROOKLYN NAVY YARD.............         54914  2                                   220
NY......................  CHARLES POLETTI................          2491  001                                 883
NY......................  DANSKAMMER.....................          2480  1                                    34
NY......................  DANSKAMMER.....................          2480  2                                    45
NY......................  DANSKAMMER.....................          2480  3                                   229
NY......................  DANSKAMMER.....................          2480  4                                   449
NY......................  EF BARRETT.....................          2511  10                                  285
NY......................  EF BARRETT.....................          2511  20                                  287
NY......................  EAST RIVER.....................          2493  50                                   33
NY......................  EAST RIVER.....................          2493  60                                  319
NY......................  EAST RIVER.....................          2493  70                                  113
NY......................  FAR ROCKAWAY...................          2513  40                                  138
NY......................  GLENWOOD.......................          2514  40                                  151
NY......................  GLENWOOD.......................          2514  50                                  124
NY......................  GLENWOOD.......................          2514  U00020                                1
NY......................  GLENWOOD.......................          2514  U00021                                1
NY......................  HUDSON AVENUE..................          2496  100                                 162
NY......................  LOVETT.........................          2629  3                                    74
NY......................  LOVETT.........................          2629  4                                   304
NY......................  LOVETT.........................          2629  5                                   380
NY......................  NISSEQUOGUE COGEN PARTNERS.....          4931  1                                    86
NY......................  NORTHPORT......................          2516  1                                   343
NY......................  NORTHPORT......................          2516  2                                   533
NY......................  NORTHPORT......................          2516  3                                   375
NY......................  NORTHPORT......................          2516  4                                   582
NY......................  O&R HILLBURN GT................          2628  1                                     2
NY......................  O&R SHOEMAKER GT...............          2632  1                                    10
NY......................  PORT JEFFERSON.................          2517  3                                   270
NY......................  PORT JEFFERSON.................          2517  4                                   253
NY......................  RAVENSWOOD.....................          2500  10                                  299
NY......................  RAVENSWOOD.....................          2500  20                                  363
NY......................  RAVENSWOOD.....................          2500  30                                1,360
NY......................  RAVENSWOOD.....................          2500  GT2-1                                 3
NY......................  RAVENSWOOD.....................          2500  GT2-2                                 3
NY......................  RAVENSWOOD.....................          2500  GT2-3                                 3
NY......................  RAVENSWOOD.....................          2500  GT2-4                                 3
NY......................  RAVENSWOOD.....................          2500  GT3-1                                 3
NY......................  RAVENSWOOD.....................          2500  GT3-2                                 3
NY......................  RAVENSWOOD.....................          2500  GT3-3                                 3
NY......................  RAVENSWOOD.....................          2500  GT3-4                                 3
NY......................  RICHARD M FLYNN................          7314  NA1                                 246
NY......................  RICHARD M FLYNN................          7314  NA2                                  25
NY......................  ROSETON........................          8006  1                                   479
NY......................  ROSETON........................          8006  2                                   595
NY......................  TRIGEN-NDEC....................         52056  4                                   105
NY......................  WADING RIVER...................          7146  1                                     8
NY......................  WADING RIVER...................          7146  2                                     8
NY......................  WADING RIVER...................          7146  3                                     8
NY......................  WADING RIVER...................          7146  UGT013                                1
NY......................  WATERSIDE......................          2502  61                                   84
NY......................  WATERSIDE......................          2502  62                                   91
NY......................  WATERSIDE......................          2502  80                                  208
NY......................  WATERSIDE......................          2502  90                                  208
NY......................  WEST BABYLON...................          2521  1                                     2
OH......................  ASHTABULA......................          2835  10                                   75
OH......................  ASHTABULA......................          2835  11                                   80
OH......................  ASHTABULA......................          2835  7                                   333
OH......................  ASHTABULA......................          2835  8                                    70
OH......................  ASHTABULA......................          2835  9                                    66
OH......................  AVON LAKE......................          2836  10                                  139

[[Page 534]]

 
OH......................  AVON LAKE......................          2836  12                                1,040
OH......................  AVON LAKE......................          2836  9                                    41
OH......................  AVON LAKE......................          2836  CT10                                  3
OH......................  BAY SHORE......................          2878  1                                   208
OH......................  BAY SHORE......................          2878  2                                   229
OH......................  BAY SHORE......................          2878  3                                   213
OH......................  BAY SHORE......................          2878  4                                   330
OH......................  CARDINAL.......................          2828  1                                 1,030
OH......................  CARDINAL.......................          2828  2                                 1,083
OH......................  CARDINAL.......................          2828  3                                 1,079
OH......................  CONESVILLE.....................          2840  1                                   214
OH......................  CONESVILLE.....................          2840  2                                   203
OH......................  CONESVILLE.....................          2840  3                                   212
OH......................  CONESVILLE.....................          2840  4                                 1,119
OH......................  CONESVILLE.....................          2840  5                                   731
OH......................  CONESVILLE.....................          2840  6                                   736
OH......................  DICKS CREEK....................          2831  1                                     7
OH......................  EASTLAKE.......................          2837  1                                   214
OH......................  EASTLAKE.......................          2837  2                                   230
OH......................  EASTLAKE.......................          2837  3                                   251
OH......................  EASTLAKE.......................          2837  4                                   371
OH......................  EASTLAKE.......................          2837  5                                   974
OH......................  EASTLAKE.......................          2837  6                                     1
OH......................  EDGEWATER......................          2857  13                                   65
OH......................  EDGEWATER......................          2857  A                                     1
OH......................  EDGEWATER......................          2857  B                                     1
OH......................  FRANK M TAIT...................          2847  GT1                                  23
OH......................  FRANK M TAIT...................          2847  GT2                                  25
OH......................  GEN J M GAVIN..................          8102  1                                 2,744
OH......................  GEN J M GAVIN..................          8102  2                                 2,981
OH......................  HAMILTON.......................          2917  9                                   110
OH......................  J M STUART.....................          2850  1                                 1,054
OH......................  J M STUART.....................          2850  2                                 1,228
OH......................  J M STUART.....................          2850  3                                 1,074
OH......................  J M STUART.....................          2850  4                                 1,106
OH......................  KILLEN STATION.................          6031  2                                 1,706
OH......................  KYGER CREEK....................          2876  1                                   471
OH......................  KYGER CREEK....................          2876  2                                   471
OH......................  KYGER CREEK....................          2876  3                                   478
OH......................  KYGER CREEK....................          2876  4                                   465
OH......................  KYGER CREEK....................          2876  5                                   455
OH......................  LAKE SHORE.....................          2838  18                                  195
OH......................  MAD RIVER......................          2860  A                                     2
OH......................  MAD RIVER......................          2860  B                                     2
OH......................  MIAMI FORT.....................          2832  5-1                                  35
OH......................  MIAMI FORT.....................          2832  5-2                                  35
OH......................  MIAMI FORT.....................          2832  6                                   398
OH......................  MIAMI FORT.....................          2832  7                                 1,044
OH......................  MIAMI FORT.....................          2832  8                                 1,015
OH......................  MIAMI FORT.....................          2832  CT2                                   1
OH......................  MUSKINGUM RIVER................          2872  1                                   309
OH......................  MUSKINGUM RIVER................          2872  2                                   316
OH......................  MUSKINGUM RIVER................          2872  3                                   347
OH......................  MUSKINGUM RIVER................          2872  4                                   349
OH......................  MUSKINGUM RIVER................          2872  5                                 1,105
OH......................  NILES..........................          2861  1                                   212
OH......................  NILES..........................          2861  2                                   160
OH......................  NILES..........................          2861  A                                     2
OH......................  O H HUTCHINGS..................          2848  H-1                                  24
OH......................  O H HUTCHING...................          2848  H-2                                  37
OH......................  O H HUTCHINGS..................          2848  H-3                                  64
OH......................  O H HUTCHINGS..................          2848  H-4                                  68
OH......................  O H HUTCHINGS..................          2848  H-5                                  62
OH......................  O H HUTCHINGS..................          2848  H-6                                  69
OH......................  O H HUTCHINGS..................          2848  H-7                                   1
OH......................  PICWAY.........................          2843  9                                   141
OH......................  R E BURGER.....................          2864  1                                     0
OH......................  R E BURGER.....................          2864  2                                     0
OH......................  R E BURGER.....................          2864  3                                     0
OH......................  R E BURGER.....................          2864  4                                     0
OH......................  R E BURGER.....................          2864  5                                    14
OH......................  R E BURGER.....................          2864  6                                    13
OH......................  R E BURGER.....................          2864  7                                   337

[[Page 535]]

 
OH......................  R E BURGER.....................          2864  8                                   274
OH......................  RICHARD GORSUCH................          7286  1                                   146
OH......................  RICHARD GORSUCH................          7286  2                                   138
OH......................  RICHARD GORSUCH................          7286  3                                   144
OH......................  RICHARD GORSUCH................          7286  4                                   146
OH......................  W H SAMMIS.....................          2866  1                                   402
OH......................  W H SAMMIS.....................          2866  2                                   418
OH......................  W H SAMMIS.....................          2866  3                                   400
OH......................  W H SAMMIS.....................          2866  4                                   415
OH......................  W H SAMMIS.....................          2866  5                                   631
OH......................  W H SAMMIS.....................          2866  6                                 1,221
OH......................  W H SAMMIS.....................          2866  7                                 1,259
OH......................  W H ZIMMER.....................          6019  1                                 2,918
OH......................  WALTER C BECKJORD..............          2830  1                                   167
OH......................  WALTER C BECKJORD..............          2830  2                                   198
OH......................  WALTER C BECKJORD..............          2830  3                                   281
OH......................  WALTER C BECKJORD..............          2830  4                                   347
OH......................  WALTER C BECKJORD..............          2830  5                                   481
OH......................  WALTER C BECKJORD..............          2830  6                                   850
OH......................  WALTER C BECKJORD..............          2830  CT1                                   3
OH......................  WALTER C BECKJORD..............          2830  CT2                                   3
OH......................  WALTER C BECKJORD..............          2830  CT3                                   4
OH......................  WALTER C BECKJORD..............          2830  CT4                                   2
OH......................  WEST LORAIN....................          2869  1A                                    0
OH......................  WEST LORAIN....................          2869  1B                                    0
OH......................  WOODSDALE......................          7158  --GT1                                30
OH......................  WOODSDALE......................          7158  --GT2                                30
OH......................  WOODSDALE......................          7158  --GT3                                39
OH......................  WOODSDALE......................          7158  --GT4                                37
OH......................  WOODSDALE......................          7158  --GT5                                40
OH......................  WOODSDALE......................          7158  --GT6                                39
PA......................  AES BEAVER VALLEY..............         10676  032                                 144
PA......................  AES BEAVER VALLEY..............         10676  033                                 131
PA......................  AES BEAVER VALLEY..............         10676  034                                 133
PA......................  AES BEAVER VALLEY..............         10676  035                                  67
PA......................  ARMSTRONG......................          3178  1                                   363
PA......................  ARMSTRONG......................          3178  2                                   383
PA......................  BRUCE MANSFIELD................          6094  1                                 1,657
PA......................  BRUCE MANSFIELD................          6094  2                                 1,672
PA......................  BRUCE MANSFIELD................          6094  3                                 1,636
PA......................  BRUNNER ISLAND.................          3140  1                                   568
PA......................  BRUNNER ISLAND.................          3140  2                                   718
PA......................  BRUNNER ISLAND.................          3140  3                                 1,539
PA......................  BRUNOT ISLAND..................          3096  2A                                    0
PA......................  BRUNOT ISLAND..................          3096  2B                                    0
PA......................  BRUNOT ISLAND..................          3096  3                                     0
PA......................  CAMBRIA COGEN..................         10641  1                                   155
PA......................  CAMBRIA COGEN..................         10641  2                                   161
PA......................  CHESWICK.......................          8226  1                                 1,119
PA......................  COLVER POWER PROJECT...........         10143  1                                   291
PA......................  CONEMAUGH......................          3118  1                                 2,167
PA......................  CONEMAUGH......................          3118  2                                 1,995
PA......................  CROMBY.........................          3159  1                                   377
PA......................  CROMBY.........................          3159  2                                   201
PA......................  DELAWARE.......................          3160  71                                   61
PA......................  DELAWARE.......................          3160  81                                   56
PA......................  EBENSBURG POWER................         10603  1                                   191
PA......................  EDDYSTONE......................          3161  1                                   565
PA......................  EDDYSTONE......................          3161  2                                   636
PA......................  EDDYSTONE......................          3161  3                                   207
PA......................  EDDYSTONE......................          3161  4                                   237
PA......................  ELRAMA.........................          3098  1                                   214
PA......................  ELRAMA.........................          3098  2                                   209
PA......................  ELRAMA.........................          3098  3                                   208
PA......................  ELRAMA.........................          3098  4                                   428
PA......................  FOSTER WHEELER MT. CARMEL......         10343  AB--NUG                             152
PA......................  GILBERTON POWER NUG............        010113  AB--NUG                             273
PA......................  GPU GENCO WAYNE................          3134  1                                     8
PA......................  HATFIELD'S FERRY...............          3179  1                                 1,155
PA......................  HATFIELD'S FERRY...............          3179  2                                 1,029
PA......................  HATFIELD'S FERRY...............          3179  3                                 1,087
PA......................  HOLTWOOD.......................          3145  17                                  246
PA......................  HOMER CITY.....................          3122  1                                 1,471

[[Page 536]]

 
PA......................  HOMER CITY.....................          3122  2                                 1,553
PA......................  HOMER CITY.....................          3122  3                                 1,437
PA......................  HUNLOCK PWR STATION............          3176  6                                   131
PA......................  KEYSTONE.......................          3136  1                                 2,154
PA......................  KEYSTONE.......................          3136  2                                 2,133
PA......................  KIMBERLY-CLARK.................          3157  10                                  211
PA......................  MARTINS CREEK..................          3148  1                                   314
PA......................  MARTINS CREEK..................          3148  2                                   293
PA......................  MARTINS CREEK..................          3148  3                                   543
PA......................  MARTINS CREEK..................          3148  4                                   500
PA......................  MITCHELL.......................          3181  1                                    10
PA......................  MITCHELL.......................          3181  2                                     6
PA......................  MITCHELL.......................          3181  3                                     9
PA......................  MITCHELL.......................          3181  33                                  556
PA......................  MONTOUR........................          3149  1                                 1,560
PA......................  MONTOUR........................          3149  2                                 1,673
PA......................  MOUNTAIN.......................          3111  1                                     5
PA......................  MOUNTAIN.......................          3111  2                                     5
PA......................  NEW CASTLE.....................          3138  3                                   190
PA......................  NEW CASTLE.....................          3138  4                                   195
PA......................  NEW CASTLE.....................          3138  5                                   245
PA......................  NORCON POWER PARTNERS LP.......         54571  1                                   103
PA......................  NORCON POWER PARTNERS LP.......         54571  2                                   109
PA......................  NORTHAMPTION GENERATING........         50888  1                                   291
PA......................  NORTHEASTERN POWER.............         50039  .......................             188
PA......................  PANTHER CREEK..................         50776  1                                   134
PA......................  PANTHER CREEK..................         50776  2                                   130
PA......................  PECO ENERGY CROYDEN............          8012  11                                   11
PA......................  PECO ENERGY CROYDEN............          8012  12                                    9
PA......................  PECO ENERGY CROYDEN............          8012  21                                    5
PA......................  PECO ENERGY CROYDEN............          8012  22                                   11
PA......................  PECO ENERGY CROYDEN............          8012  31                                   13
PA......................  PECO ENERGY CROYDEN............          8012  32                                    6
PA......................  PECO ENERGY CROYDEN............          8012  41                                   11
PA......................  PECO ENERGY CROYDEN............          8012  42                                    9
PA......................  PECO ENERGY RICHMOND...........          3168  91                                   10
PA......................  PECO ENERGY RICHMOND...........          3168  92                                    9
PA......................  PHILLIPS POWER STATION.........          3099  3                                     0
PA......................  PHILLIPS POWER STATION.........          3099  4                                     0
PA......................  PHILLIPS POWER STATION.........          3099  5                                     0
PA......................  PHILLIPS POWER STATION.........          3099  6                                     0
PA......................  PINEY CREEK....................         54144  1                                   102
PA......................  PORTLAND.......................          3113  --5                                  48
PA......................  PORTLAND.......................          3113  1                                   266
PA......................  PORTLAND.......................          3113  2                                   412
PA......................  SCHUYLKILL.....................          3169  1                                    84
PA......................  SCHUYLKILL ENERGY RESOURCES....        880010  1                                   289
PA......................  SCHUYLKILL STATION (TURBI......         50607  AB--NUG                             701
PA......................  SCRUBGRASS GENERATING PLANT....         50974  1                                   124
PA......................  SCRUBGRASS GENERATING PLANT....         50974  2                                   123
PA......................  SEWARD.........................          3130  12                                   64
PA......................  SEWARD.........................          3130  14                                   72
PA......................  SEWARD.........................          3130  15                                  355
PA......................  SHAWVILLE......................          3131  1                                   295
PA......................  SHAWVILLE......................          3131  2                                   294
PA......................  SHAWVILLE......................          3131  3                                   380
PA......................  SHAWVILLE......................          3131  4                                   392
PA......................  SUNBURY........................          3152  1A                                  134
PA......................  SUNBURY........................          3152  1B                                  122
PA......................  SUNBURY........................          3152  2A                                  130
PA......................  SUNBURY........................          3152  2B                                  134
PA......................  SUNBURY........................          3152  3                                   263
PA......................  SUNBURY........................          3152  4                                   302
PA......................  TITUS..........................          3115  1                                   161
PA......................  TITUS..........................          3115  2                                   152
PA......................  TITUS..........................          3115  3                                   151
PA......................  TOLNA..........................          3116  1                                     3
PA......................  TOLNA..........................          3116  2                                     4
PA......................  TRIGEN ENERGY SANSOM...........        880006  1                                    12
PA......................  TRIGEN ENERGY SANSOM...........        880006  2                                    10
PA......................  TRIGEN ENERGY SANSOM...........        880006  3                                     5
PA......................  TRIGEN ENERGY SANSOM...........        880006  4                                     6
PA......................  WARREN.........................          3132  1                                    47

[[Page 537]]

 
PA......................  WARREN.........................          3132  2                                    32
PA......................  WARREN.........................          3132  3                                    40
PA......................  WARREN.........................          3132  4                                    42
PA......................  WARREN.........................          3132  CT1                                  14
PA......................  WESTWOOD ENERGY PROPERTIE......         50611  031                                  98
PA......................  WHEELABRATOR FRACKVILLE E......         50879  GEN1                                161
PA......................  WILLIAMS GEN--HAZELTON.........         10870  HRSG                                 16
PA......................  WILLIAMS GEN--HAZELTON.........         10870  TURBN                               141
VA......................  BELLMEADE......................          7696  1                                    76
VA......................  BELLMEADE......................          7696  2                                    88
VA......................  BREMO BLUFF....................          3796  3                                   137
VA......................  BREMO BLUFF....................          3796  4                                   386
VA......................  CHESAPEAKE.....................          3803  1                                   298
VA......................  CHESAPEAKE.....................          3803  2                                   308
VA......................  CHESAPEAKE.....................          3803  3                                   370
VA......................  CHESAPEAKE.....................          3803  4                                   571
VA......................  CHESAPEAKE CORP................         10017  ST--rp.                              59
VA......................  CHESTERFIELD...................          3797  --8                                 263
VA......................  CHESTERFIELD...................          3797  3                                   232
VA......................  CHESTERFIELD...................          3797  4                                   389
VA......................  CHESTERFIELD...................          3797  5                                   769
VA......................  CHESTERFIELD...................          3797  6                                 1,348
VA......................  CHESTERFIELD...................          3797  7                                   316
VA......................  CLINCH RIVER...................          3775  1                                   548
VA......................  CLINCH RIVER...................          3775  2                                   520
VA......................  CLINCH RIVER...................          3775  3                                   575
VA......................  CLOVER.........................          7213  1                                 1,033
VA......................  CLOVER.........................          7213  2                                 1,118
VA......................  COGENTRIX--HOPEWELL............         10377  ST--ell                             327
VA......................  COGENTRIX--PORTSMOUTH..........         10071  ST--uth                             356
VA......................  COGENTRIX RICHMOND 1...........         54081  ST--d 1                             299
VA......................  COGENTRIX RICHMOND 2...........         54081  ST--d 2                             209
VA......................  COMMONWEALTH ATLANTIC LP.......         52087  GT--LP                               35
VA......................  DARBYTOWN......................          7212  --1                                  29
VA......................  DARBYTOWN......................          7212  --2                                  28
VA......................  DARBYTOWN......................          7212  --3                                  30
VA......................  DARBYTOWN......................          7212  --4                                  29
VA......................  DOSWELL 1.............         52019  CA--1                       46
VA......................  DOSWELL 1.............         52019  CT--1                       94
VA......................  DOSWELL 2.............         52019  CA--2                       46
VA......................  DOSWELL 2.............         52019  CT--2                       94
VA......................  GLEN LYN.......................          3776  51                                  101
VA......................  GLEN LYN.......................          3776  52                                  110
VA......................  GLEN LYN.......................          3776  6                                   487
VA......................  GORDONSVILLE 1.................         54844  CA--e 1                              16
VA......................  GORDONSVILLE 1.................         54844  CT--e 1                              33
VA......................  GORDONSVILLE 2.................         54844  CA--Xe 2                             17
VA......................  GORDONSVILLE 2.................         54844  CT--e 2                              34
VA......................  GRAVEL NECK....................          7032  --3                                  21
VA......................  GRAVEL NECK....................          7032  --X4                                 24
VA......................  GRAVEL NECK....................          7032  --5                                  14
VA......................  GRAVEL NECK....................          7032  --6                                  18
VA......................  HOPEWELL COGEN, INC............         10633  CT--nc.                             102
VA......................  HOPEWELL COGEN, INC............         10633  CW--nc.                              53
VA......................  LG&E-WESTMORELAND ALTAVISTA....         10773  1                                    18
VA......................  LG&E-WESTMORELAND ALTAVISTA....         10773  2                                    18
VA......................  LG&E-WESTMORELAND HOPEWELL.....         10771  1                                    17
VA......................  LG&E-WESTMORELAND HOPEWELL.....         10771  2                                    16
VA......................  LG&E-WESTMORELAND SOUTHAMPTON..         10774  1                                    23
VA......................  LG&E-WESTMORELAND SOUTHAMPTON..         10774  2                                    29
VA......................  MECKLENBURG....................         52007  ST--urg                             234
VA......................  POSSUM POINT...................          3804  3                                   221
VA......................  POSSUM POINT...................          3804  4                                   528
VA......................  POSSUM POINT...................          3804  5                                   322
VA......................  POTOMAC RIVER..................          3788  1                                   203
VA......................  POTOMAC RIVER..................          3788  2                                   139
VA......................  POTOMAC RIVER..................          3788  3                                   232
VA......................  POTOMAC RIVER..................          3788  4                                   223
VA......................  POTOMAC RIVER..................          3788  5                                   222
VA......................  SEI BIRCHWOOD..................            12  1                                   305
VA......................  TASLEY.........................          3785  10                                    6
VA......................  YORKTOWN.......................          3809  1                                   386
VA......................  YORKTOWN.......................          3809  2                                   419

[[Page 538]]

 
VA......................  YORKTOWN.......................          3809  3                                   764
WV......................  ALBRIGHT.......................          3942  1                                    76
WV......................  ALBRIGHT.......................          3942  2                                    71
WV......................  ALBRIGHT.......................          3942  3                                   241
WV......................  FORT MARTIN....................          3943  1                                   887
WV......................  FORT MARTIN....................          3943  2                                   868
WV......................  GRANT TOWN.....................         10151  ST--own                             156
WV......................  HARRISON.......................          3944  1                                 1,385
WV......................  HARRISON.......................          3944  2                                 1,444
WV......................  HARRISON.......................          3944  3                                 1,505
WV......................  JOHN E AMOS....................          3935  1                                 1,254
WV......................  JOHN E AMOS....................          3935  2                                 1,198
WV......................  JOHN E AMOS....................          3935  3                                 1,859
WV......................  KAMMER.........................          3947  1                                   399
WV......................  KAMMER.........................          3947  2                                   418
WV......................  KAMMER.........................          3947  3                                   447
WV......................  KANAWHA RIVER..................          3936  1                                   336
WV......................  KANAWHA RIVER..................          3936  2                                   323
WV......................  MITCHELL.......................          3948  1                                 1,288
WV......................  MITCHELL.......................          3948  2                                 1,191
WV......................  MORGANTOWN ENERGY ASSOCIATES...            27  1                                    80
WV......................  MORGANTOWN ENERGY ASSOCIATES...            27  2                                    80
WV......................  MOUNTAINEER (1301).............          6264  1                                 1,952
WV......................  MT STORM.......................          3954  1                                 1,048
WV......................  MT STORM.......................          3954  2                                 1,127
WV......................  MT STORM.......................          3954  3                                 1,236
WV......................  NORTH BRANCH...................          7537  1A                                   51
WV......................  NORTH BRANCH...................          7537  1B                                   53
WV......................  PHIL SPORN.....................          3938  11                                  239
WV......................  PHIL SPORN.....................          3938  21                                  215
WV......................  PHIL SPORN.....................          3938  31                                  239
WV......................  PHIL SPORN.....................          3938  41                                  230
WV......................  PHIL SPORN.....................          3938  51                                  708
WV......................  PLEASANTS......................          6004  1                                 1,296
WV......................  PLEASANTS......................          6004  2                                 1,165
WV......................  RIVESVILLE.....................          3945  7                                    38
WV......................  RIVESVILLE.....................          3945  8                                    88
WV......................  WILLOW ISLAND..................          3946  1                                    79
WV......................  WILLOW ISLAND..................          3946  2                                   246
----------------------------------------------------------------------------------------------------------------


[6 FR 2727, Jan. 18, 2000, as amended at 66 FR 48575, Sept. 21, 2001]



Sec. Appendix B to Part 97--Final Section 126 Rule: Non-EGU Allocations, 
                                2004-2007

----------------------------------------------------------------------------------------------------------------
                                                                                                         NOX
    State             County                      Plant                  Plant ID       Point ID     allocation
                                                                                                    for non-EGUs
----------------------------------------------------------------------------------------------------------------
DC...........  Washington..........  GSA CENTRAL HEATING PLANT.....  0025             003                      0
DC...........  Washington..........  GSA CENTRAL HEATING PLANT.....  0025             004                      0
DC...........  Washington..........  GSA CENTRAL HEATING PLANT.....  0025             005                      0
DC...........  Washington..........  GSA CENTRAL HEATING PLANT.....  0025             006                      0
DC...........  Washington..........  GSA WEST HEATING PLANT........  0024             003                     13
DC...........  Washington..........  GSA WEST HEATING PLANT........  0024             005                     12
DE...........  Kent................  KRAFT FOODS INC...............  0007             001                      0
DE...........  New Castle..........  MOTIVA ENTERPRISES (FORMERLY    0016             002                    102
                                      STAR ENTERPRISE, DELAWARE
                                      CITY PLANT).
DE...........  New Castle..........  MOTIVA ENTERPRISES (FORMERLY    0016             012                    118
                                      STAR ENTERPRISE, DELAWARE
                                      CITY PLANT).
KY...........  Boyd................  ASHLAND OIL INC...............  0004             061                     23
KY...........  Lawrence............  KENTUCKY POWER CO.............  0003             004                      0
MD...........  Baltimore...........  BETHLEHEM STEEL...............  0147             016                     75
MD...........  Baltimore...........  BETHLEHEM STEEL...............  0147             017                     75
MD...........  Baltimore...........  BETHLEHEM STEEL...............  0147             018                     75
MD...........  Baltimore...........  BETHLEHEM STEEL...............  0147             019                     75
MD...........  Allegany............  WESTVACO......................  0011             001                    289
MD...........  Allegany............  WESTVACO......................  0011             002                    373
MI...........  Wayne...............  DETROIT EDISON CO.............  B2810            0003                    31
MI...........  Midland.............  DOW CHEMICAL USA..............  A4033            0401                     6
MI...........  Midland.............  DOW CHEMICAL USA..............  A4033            0402                     0
MI...........  Wayne...............  DSC LTD.......................  B3680            0006                    30

[[Page 539]]

 
MI...........  Genesee.............  GENERAL MOTORS CORP...........  A1178            0501                    63
MI...........  Genesee.............  GENERAL MOTORS CORP...........  A1178            0502                    47
MI...........  Oakland.............  GENERAL MOTORS CORP...........  B4031            0506                    22
MI...........  Genesee.............  GENERAL MOTORS CORP...........  A1178            0507                    20
MI...........  Oakland.............  GENERAL MOTORS CORP...........  B4032            0510                     4
MI...........  Kalamazoo...........  GEORGIA PACIFIC CORP..........  B4209            0005                     6
MI...........  Kalamazoo...........  JAMES RIVER PAPER CO INC......  B1678            0003                    90
MI...........  Wayne...............  MARATHON OIL COMPANY..........  A9831            0001                   109
MI...........  Allegan.............  MENASHA CORP..................  A0023            0024                    71
MI...........  Allegan.............  MENASHA CORP..................  A0023            0025                    69
MI...........  Ingham..............  MICHIGAN STATE UNIVERSITY.....  K3249            0053                   110
MI...........  Ingham..............  MICHIGAN STATE UNIVERSITY.....  K3249            0054                   118
MI...........  Ingham..............  MICHIGAN STATE UNIVERSITY.....  K3249            0055                    77
MI...........  Ingham..............  MICHIGAN STATE UNIVERSITY.....  K3249            0056                    73
MI...........  Washtenaw...........  THE REGENTS OF THE UNIVERSITY   M0675            0001                    40
                                      OF MICHIGAN.
MI...........  Washtenaw...........  THE REGENTS OF THE UNIVERSITY   M0675            0002                    37
                                      OF MICHIGAN.
MI...........  Oakland.............  WILLIAM BEAUMONT HOSPITAL.....  G5067            0010                     0
MI...........  Oakland.............  WILLIAM BEAUMONT HOSPITAL.....  G5067            0011                     0
NC...........  Haywood.............  BLUE RIDGE PAPER PRODUCTS INC.  0159             005                    129
NC...........  Haywood.............  CHAMPION INT CORP.............  0159             001                     98
NC...........  Haywood.............  CHAMPION INT CORP.............  0159             002                     88
NC...........  Haywood.............  CHAMPION INT CORP.............  0159             003                    200
NC...........  Haywood.............  CHAMPION INT CORP.............  0159             004                    176
NC...........  Halifax.............  CHAMPION INTERNATIONAL CORP.    0007             001                    340
                                      ROANOKE RAP.
NC...........  Guilford............  CONE MILLS CORP--WHITE OAK      0863             004                     50
                                      PLANT.
NC...........  Cabarrus............  FIELDCREST--CANNON PLT 1        0006             001                     77
                                      KANNAPOLIS.
NC...........  Columbus............  INTERNATIONAL PAPER:            0036             003                     90
                                      RIEGELWOOD.
NC...........  Columbus............  INTERNATIONAL PAPER:            0036             004                    228
                                      RIEGELWOOD.
NC...........  Martin..............  WEYERHAEUSER PAPER CO.          0069             001                    265
                                      PLYMOUTH.
NC...........  Craven..............  WEYERHAUSER COMPANY NEW BERN    0104             005                    205
                                      MILL.
NC...........  Craven..............  WEYERHAEUSER COMPANY NEW BERN   0104             006                     72
                                      MILL.
NC...........  Martin..............  WEYERHAEUSER COMPANY PLYMOUTH.  0069             009                     25
NJ...........  Middlesex...........  BALL--INCON GLASS PACKAGING...  15035            001                     46
NJ...........  Hudson..............  BEST FOODS CPC INTERNATIONAL I  10003            003                     27
NJ...........  Middlesex...........  CHEVRON U.S.A., INC...........  15023            001                     17
NJ...........  Middlesex...........  CHEVRON U.S.A., INC...........  15023            043                     55
NJ...........  Gloucester..........  COASTAL EAGLE POINT OIL COMPAN  55004            001                      3
NJ...........  Gloucester..........  COASTAL EAGLE POINT OIL COMPAN  55004            038                     11
NJ...........  Gloucester..........  COASTAL EAGLE POINT OIL COMPAN  55004            039                     11
NJ...........  Gloucester..........  COASTAL EAGLE POINT OIL COMPAN  55004            040                     11
NJ...........  Gloucester..........  COASTAL EAGLE POINT OIL COMPAN  55004            064                     38
NJ...........  Gloucester..........  COASTAL EAGLE POINT OIL COMPAN  55004            123                     37
NJ...........  Middlesex...........  DEGUSSA CORPORATION-METZ DIVIS  15305            009                     15
NJ...........  Union...............  EXXON CORPORATION.............  40003            001                     57
NJ...........  Union...............  EXXON CORPORATION.............  40003            007                     22
NJ...........  Union...............  EXXON CORPORATION.............  40003            014                     98
NJ...........  Union...............  EXXON CORPORATION.............  40003            015                     14
NJ...........  Middlesex...........  HERCULES INCORPORATED.........  15017            001                     38
NJ...........  Middlesex...........  HERCULES INCORPORATED.........  15017            002                     37
NJ...........  Warren..............  HOFFMAN LAROCHE INC...........  85010            034                     45
NJ...........  Mercer..............  HOMASCTE COMPANY..............  60018            001                    290
NJ...........  Mercer..............  HOMASCTE COMPANY..............  60018            002                    312
NJ...........  Passaic.............  INTERNATIONAL VEILING CORPORAT  30098            001                     22
NJ...........  Bergen..............  MALT PRODUCTS CORPORATION.....  00322            001                     27
NJ...........  Atlantic............  MARINA ASSOCIATES.............  70009            001                    330
NJ...........  Atlantic............  MARINA ASSOCIATES.............  70009            002                    329
NJ...........  Atlantic............  MARINA ASSOCIATES.............  70009            003                    990
NJ...........  Union...............  MERCK & CO., INC..............  40009            001                     66
NJ...........  Union...............  MERCK & CO., INC..............  40009            002                     61
NJ...........  Union...............  MERCK & CO., INC..............  40009            003                     56
NJ...........  Union...............  MERCK & CO., INC..............  40009            004                     75
NJ...........  Union...............  MERCK & CO., INC..............  40009            005                     89
NJ...........  Union...............  MERCK & CO., INC..............  40009            006                    103
NJ...........  Gloucester..........  MOBIL OIL CORPORATION.........  55006            001                     54
NJ...........  Gloucester..........  MOBIL OIL CORPORATION.........  55006            002                     54
NJ...........  Gloucester..........  MOBIL OIL CORPORATION.........  55006            003                     54
NJ...........  Gloucester..........  MOBIL OIL CORPORATION.........  55006            004                     49
NJ...........  Gloucester..........  MOBIL OIL CORPORATION.........  55006            005                     16
NJ...........  Gloucester..........  MOBIL OIL CORPORATION.........  55006            006                    105

[[Page 540]]

 
NJ...........  Gloucester..........  MOBIL OIL CORPORATION.........  55006            027                      0
NJ...........  Gloucester..........  MOBIL OIL CORPORATION.........  55006            270                     14
NJ...........  Monmouth............  NESTLE CO., INC., THE.........  20004            006                     13
NJ...........  Monmouth............  NESTLE CO., INC., THE.........  20004            007                     13
NJ...........  Middlesex...........  NEW JERSEY STEEL CORPORATION..  15076            001                     18
NJ...........  Gloucester..........  PETROLEUM RECYCLING, INC......  55180            020                    169
NJ...........  Atlantic............  SCOTT PAPER COMPANY...........  70011            002                     89
NJ...........  Atlantic............  SCOTT PAPER COMPANY...........  70011            003                     75
NJ...........  Atlantic............  SCOTT PAPER COMPANY...........  70011            004                     99
NJ...........  Mercer..............  STONY BROOK REGIONAL SEWERAGE.  60248            001                     55
NJ...........  Mercer..............  STONY BROOK REGIONAL SEWERAGE.  60248            002                     55
NY...........  Kings...............  HUDSON AVENUE.................  2496             B71                     19
NY...........  Kings...............  HUDSON AVENUE.................  2496             B72                     19
NY...........  Kings...............  HUDSON AVENUE.................  2496             B81                     19
NY...........  Kings...............  HUDSON AVENUE.................  2496             B82                     19
NY...........  Queens..............  RAVENSWOOD-A-HOUSE............  CE03             B01                     15
NY...........  Queens..............  RAVENSWOOD-A-HOUSE............  CE03             B02                     15
NY...........  Queens..............  RAVENSWOOD-A-HOUSE............  CE03             B03                     21
NY...........  Queens..............  RAVENSWOOD-A-HOUSE............  CE03             B04                     21
OH...........  Butler..............  AK STEEL (FORMERLY ARMCO STEEL  1409010006       P009                    66
                                      CO.).
OH...........  Butler..............  AK STEEL (FORMERLY ARMCO STEEL  1409010006       P010                    66
                                      CO.).
OH...........  Butler..............  AK STEEL (FORMERLY ARMCO STEEL  1409010006       P011                    66
                                      CO.).
OH...........  Butler..............  AK STEEL (FORMERLY ARMCO STEEL  1409010006       P012                    66
                                      CO.).
OH...........  Stark...............  ASHLAND PETROLEUM COMPANY.....  1576000301       B015                    18
OH...........  Lucas...............  BP OIL COMPANY, TOLEDO          0448020007       B004                    39
                                      REFINERY.
OH...........  Lucas...............  BP OIL COMPANY, TOLEDO          0448020007       B020                   102
                                      REFINERY.
OH...........  Montgomery..........  CARGILL INCORPORATED..........  0857041124       B004                   133
OH...........  Montgomery..........  CARGILL INCORPORATED..........  0857041124       B006                     1
OH...........  Butler..............  CHAMPION INTERNATIONAL CORP...  1409040212       B010                   267
OH...........  Summit..............  GOODYEAR TIRE & RUBBER COMPANY  1677010193       B001                   101
OH...........  Summit..............  GOODYEAR TIRE & RUBBER COMPANY  1677010193       B002                   108
OH...........  Hamilton............  HENKEL CORP.--EMERY GROUP.....  1431070035       B027                   209
OH...........  Cuyahoga............  LTV STEEL COMPANY, INC........  1318001613       B001                   139
OH...........  Cuyahoga............  LTV STEEL COMPANY, INC........  1318001613       B002                   150
OH...........  Cuyahoga............  LTV STEEL COMPANY, INC........  1318001613       B003                   159
OH...........  Cuyahoga............  LTV STEEL COMPANY, INC........  1318001613       B004                   158
OH...........  Cuyahoga............  LTV STEEL COMPANY, INC........  1318001613       B007                   155
OH...........  Cuyahoga............  LTV STEEL COMPANY, INC........  1318001613       B905                    14
OH...........  Ross................  MEAD CORPORATION..............  0671010028       B001                   185
OH...........  Ross................  MEAD CORPORATION..............  0671010028       B002                   208
OH...........  Ross................  MEAD CORPORATION..............  0671010028       B003                   251
OH...........  Scioto..............  NEW BOSTON COKE CORP..........  0773010004       B008                    20
OH...........  Scioto..............  NEW BOSTON COKE CORP..........  0773010004       B009                    15
OH...........  Hamilton............  PROCTER & GAMBLE CO...........  1431390903       B021                    72
OH...........  Hamilton............  PROCTER & GAMBLE CO...........  1431390903       B022                   296
OH...........  Lorain..............  REPUBLIC ENGINEERED STEELS,     0247080229       B013                   159
                                      INC. (FORMERLY USS/KOBE
                                      STEEL--LORAIN WORKS).
OH...........  Lawrence............  SOUTH POINT ETHANOL...........  0744000009       B003                   107
OH...........  Lawrence............  SOUTH POINT ETHANOL...........  0744000009       B004                   107
OH...........  Lawrence............  SOUTH POINT ETHANOL...........  0744000009       B007                   107
OH...........  Lucas...............  SUN REFINING & MARKETING CO,    0448010246       B044                    47
                                      TOLEDO REF.
OH...........  Lucas...............  SUN REFINING & MARKETING CO,    0448010246       B046                    34
                                      TOLEDO REF.
OH...........  Lucas...............  SUN REFINING & MARKETING CO,    0448010246       B047                    18
                                      TOLEDO REF.
OH...........  Trumbull............  W C I STEEL, INC..............  0278000463       B001                   113
OH...........  Trumbull............  W C I STEEL, INC..............  0278000463       B004                   142
PA...........  Northampton.........  BETHLEHEM STEEL CORP..........  0048             041                    100
PA...........  Northampton.........  BETHLEHEM STEEL CORP..........  0048             042                     66
PA...........  Northampton.........  BETHLEHEM STEEL CORP..........  0048             067                    165
PA...........  Armstrong...........  BMG ASPHALT CO................  0004             101                      0
PA...........  Erie................  GENERAL ELECTRIC..............  0009             032                     16
PA...........  York................  GLATFELTER, P. H. CO..........  0016             031                      0
PA...........  York................  GLATFELTER, P. H. CO..........  0016             034                    137
PA...........  York................  GLATFELTER, P. H. CO..........  0016             035                    112
PA...........  York................  GLATFELTER, P. H. CO..........  0016             036                    211
PA...........  Clinton.............  INTERNATIONAL PAPER: LOCKHAVEN  0008             033                    101
PA...........  Clinton.............  INTERNATIONAL PAPER: LOCKHAVEN  0008             034                     90
PA...........  Delaware............  KIMBERLY CLARK (FORMERLY SCOTT  0016             034                      1
                                      PAPER CO.).
PA...........  Delaware............  KIMBERLY CLARK (FORMERLY SCOTT  0016             035                    345
                                      PAPER CO.).
PA...........  Allegheny...........  LTV STEEL COMPANY--PITTSBURGH   0022             015                     25
                                      WORKS.
PA...........  Allegheny...........  LTV STEEL COMPANY--PITTSBURGH   0022             017                     15
                                      WORKS.

[[Page 541]]

 
PA...........  Allegheny...........  LTV STEEL COMPANY--PITTSBURGH   0022             019                     29
                                      WORKS.
PA...........  Allegheny...........  LTV STEEL COMPANY--PITTSBURGH   0022             021                     55
                                      WORKS.
PA...........  Montgomery..........  MERCK SHARP & DOHME...........  0028             039                    126
PA...........  Westmoreland........  MONESSEN INC..................  0007             031                      0
PA...........  Bucks...............  PECO..........................  0055             043                     15
PA...........  Bucks...............  PECO..........................  0055             045                     32
PA...........  Bucks...............  PECO..........................  0055             044                     77
PA...........  Wyoming.............  PROCTER & GAMBLE CO...........  0009             035                    187
PA...........  Allegheny...........  SHENANGO IRON & COKE WORKS....  0050             006                     18
PA...........  Allegheny...........  SHENANGO IRON & COKE WORKS....  0050             009                     15
PA...........  Delaware............  SUN REFINING & MARKETING CO...  0025             089                    102
PA...........  Delaware............  SUN REFINING & MARKETING CO...  0025             090                    163
PA...........  Philadelphia........  SUN REFINING AND MARKETING 1 O  1501             020                     49
PA...........  Philadelphia........  SUN REFINING AND MARKETING 1 O  1501             021                     83
PA...........  Philadelphia........  SUN REFINING AND MARKETING 1 O  1501             022                    105
PA...........  Philadelphia........  SUN REFINING AND MARKETING 1 O  1501             023                    127
PA...........  Philadelphia........  SUNOCO (FORMERLY ALLIED         1551             052                     86
                                      CHEMICAL CORP).
PA...........  Perry...............  TEXAS EASTERN GAS PIPELINE      0001             031                      0
                                      COMPANY.
PA...........  Berks...............  TEXAS EASTERN GAS PIPELINE      0087             031                     98
                                      COMPANY.
PA...........  Delaware............  TOSCO REFINING (FORMERLY BP     0030             032                     71
                                      OIL, INC.).
PA...........  Delaware............  TOSCO REFINING (FORMERLY BP     0030             033                     80
                                      OIL, INC.).
PA...........  Philadelphia........  U.S. NAVAL BASE...............  9702             016                      0
PA...........  Philadelphia........  U.S. NAVAL BASE...............  9702             017                      1
PA...........  Philadelphia........  U.S. NAVAL BASE...............  9702             098                      0
PA...........  Philadelphia........  U.S. NAVAL BASE...............  9702             099                      0
PA...........  Elk.................  WILLAMETTE INDUSTRIES           0005             040                     90
                                      (FORMERLY PENNTECH PAPERS,
                                      INC.
PA...........  Elk.................  WILLAMETTE INDUSTRIES           0005             041                     89
                                      (FORMERLY PENNTECH PAPERS,
                                      INC.
PA...........  Beaver..............  ZINC CORPORATION OF AMERICA...  0032             034                    176
PA...........  Beaver..............  ZINC CORPORATION OF AMERICA...  0032             035                    180
VA...........  Hopewell............  ALLIED-SIGNAL INC.............  0026             002                    499
VA...........  York................  AMOCO OIL CO..................  0004             001                     25
VA...........  Giles...............  CELANESE ACETATE LLC (FORMERLY  0004             007                    148
                                      HOECHST CELANESE CORP).
VA...........  Giles...............  CELANESE ACETATE LLC (FORMERLY  0004             014                     56
                                      HOECHST CELANESE CORP).
VA...........  Pittsylvania........  DAN RIVER INC. (SCHOOLFIELD     0002             003                     49
                                      DIV).
VA...........  Bedford.............  GEORGIA-PACIFIC--BIG ISLAND     0003             002                     86
                                      MILL.
VA...........  Isle Of Wight.......  INTERNATIONAL PAPER--FRANKLIN   0006             003                    272
                                      (FORMERLY UNION CAMP CORP/
                                      FINE PAPER DIV).
VA...........  Hopewell............  JAMES RIVER COGENERATION (COGE  0055             001                    511
VA...........  Hopewell............  JAMES RIVER COGENERATION (COGE  0055             002                    512
VA...........  King William........  ST. LAURENT PAPER PRODUCTS      0001             003                    253
                                      CORP..
VA...........  Alleghany...........  WESTVACO CORP.................  0003             001                    253
VA...........  Alleghany...........  WESTVACO CORP.................  0003             002                    130
VA...........  Alleghany...........  WESTVACO CORP.................  0003             003                    195
VA...........  Alleghany...........  WESTVACO CORP.................  0003             004                    373
VA...........  Alleghany...........  WESTVACO CORP.................  0003             005                    170
VA...........  Alleghany...........  WESTVACO CORP.................  0003             011                    105
WV...........  Kanawha.............  AVENTIS CROPSCIENCE...........  00007            010                    113
WV...........  Kanawha.............  AVENTIS CROPSCIENCE...........  00007            011                    102
WV...........  Kanawha.............  AVENTIS CROPSCIENCE...........  00007            012                    105
WV...........  Kanawha.............  DUPONT--BELLE.................  00001            612                     54
WV...........  Fayette.............  ELKEM METALS COMPANY L.P.--     00001            006                    116
                                      ALLOY P PLANT.
WV...........  Marshall............  PPG INDUSTRIES, INC...........  00002            001                    195
WV...........  Marshall............  PPG INDUSTRIES, INC...........  00002            003                    419
WV...........  Kanawha.............  RHONE-POLUENC.................  00007            070                      8
WV...........  Kanawha.............  RHONE-POLUENC.................  00007            071                     73
WV...........  Kanawha.............  RHONE-POLUENC.................  00007            080                      7
WV...........  Kanawha.............  RHONE-POLUENC.................  00007            081                     66
WV...........  Kanawha.............  RHONE-POLUENC.................  00007            090                      8
WV...........  Kanawha.............  RHONE-POLUENC.................  00007            091                     68
WV...........  Kanawha.............  UNION CARBIDE--SOUTH            00003            0B6                     66
                                      CHARLESTON PLANT.
WV...........  Kanawha.............  UNION CARBIDE--SOUTH            0003             0B6                     92
                                      CHARLESTON PLANT.
WV...........  Kanawha.............  UNION CARBIDE--SOUTH            0003             0B7                     45
                                      CHARLESTON PLANT.
WV...........  Hancock.............  WEIRTON STEEL CORPORATION.....  00001            030                     31
WV...........  Hancock.............  WEIRTON STEEL CORPORATION.....  00001            088                     30
WV...........  Hancock.............  WEIRTON STEEL CORPORATION.....  00001            089                      2
WV...........  Hancock.............  WEIRTON STEEL CORPORATION.....  00001            090                    110
WV...........  Hancock.............  WEIRTON STEEL CORPORATION.....  00001            091                    253

[[Page 542]]

 
WV...........  Hancock.............  WEIRTON STEEL CORPORATION.....  00001            092                    208
WV...........  Hancock.............  WEIRTON STEEL CORPORATION.....  00001            093                    200
----------------------------------------------------------------------------------------------------------------


[65 FR 2727, Jan. 18, 2000, as amended at 66 FR 48576, Sept. 21, 2001]



   Sec. Appendix C to Part 97--Final Section 126 Rule: Trading Budget

------------------------------------------------------------------------
                   ST                     F126-EGU  F126-NEGU    Total
------------------------------------------------------------------------
DC.....................................        207         26        233
DE.....................................      4,306        232      4,538
IN.....................................      7,088         82      7,170
KY.....................................     19,654         53     19,707
MD.....................................     14,519      1,013     15,532
MI.....................................     25,689      2,166     27,855
NC.....................................     31,212      2,329     33,541
NJ.....................................      9,716      4,838     14,554
NY.....................................     16,081        156     16,237
OH.....................................     45,432      4,103     49,535
PA.....................................     47,224      3,619     50,843
VA.....................................     17,091      4,104     21,195
WV.....................................     26,859      2,184     29,043
                                        --------------------------------
    Total..............................    265,078     24,905    289,983
------------------------------------------------------------------------



  Sec. Appendix D to Part 97--Final Section 126 Rule: State Compliance 
         supplement pools for the Section 126 Final Rule (Tons)

------------------------------------------------------------------------
                                                            Compliance
                          State                             supplement
                                                               pool
------------------------------------------------------------------------
Delaware................................................             168
District of Columbia....................................               0
Indiana.................................................           2,454
Kentucky................................................           7,314
Maryland................................................           3,882
Michigan................................................           9,398
New Jersey..............................................           1,550
New York................................................           1,379
North Carolina..........................................          10,737
Ohio....................................................          22,301
Pennsylvania............................................          15,763
Virginia................................................           5,504
West Virginia...........................................          16,709
                                                         ---------------
    Total...............................................          97,159
------------------------------------------------------------------------



PART 98_MANDATORY GREENHOUSE GAS REPORTING--Table of Contents



                      Subpart A_General Provisions

Sec.
98.1 Purpose and scope.
98.2 Who must report?
98.3 What are the general monitoring, reporting, recordkeeping and 
          verification requirements of this part?
98.4 Authorization and responsibilities of the designated 
          representative.
98.5 How is the report submitted?
98.6 Definitions.
98.7 What standardized methods are incorporated by reference into this 
          part?
98.8 What are the compliance and enforcement provisions of this part?
98.9 Addresses.

Table A-1 to Subpart A of Part 98--Global Warming Potentials
Table A-2 to Subpart A of Part 98--Units of Measure Conversions
Table A-3 to Subpart A of Part 98--Source Category List for Sec. 
          98.2(a)(1)
Table A-4 to Subpart A of Part 98--Source Category List for Sec. 
          98.2(a)(2)
Table A-5 to Subpart A of Part 98--Supplier Category List for Sec. 
          98.2(a)(4)
Table A-6 to Subpart A of Part 98--Data Elements That Are Inputs to 
          Emission Equations and for Which the Reporting Deadline Is 
          Changed to September 30, 2011
Table A-7 to Subpart A of Part 98--Data Elements That Are Inputs to 
          Emission Equations and for Which the Reporting Deadline Is 
          March 31, 2015

Subpart B [Reserved]

[[Page 543]]

          Subpart C_General Stationary Fuel Combustion Sources

98.30 Definition of the source category.
98.31 Reporting threshold.
98.32 GHGs to report.
98.33 Calculating GHG emissions.
98.34 Monitoring and QA/QC requirements.
98.35 Procedures for estimating missing data.
98.36 Data reporting requirements.
98.37 Records that must be retained.
98.38 Definitions.

Table C-1 to Subpart C of Part 98--Default CO2 Emission 
          Factors and High Heat Values for Various Types of Fuel
Table C-2 to Subpart C of Part 98--Default CH4 and 
          N2O Emission Factors for Various Types of Fuel

                    Subpart D_Electricity Generation

98.40 Definition of the source category.
98.41 Reporting threshold.
98.42 GHGs to report.
98.43 Calculating GHG emissions.
98.44 Monitoring and QA/QC requirements
98.45 Procedures for estimating missing data.
98.46 Data reporting requirements.
98.47 Records that must be retained.
98.48 Definitions.

                    Subpart E_Adipic Acid Production

98.50 Definition of source category.
98.51 Reporting threshold.
98.52 GHGs to report.
98.53 Calculating GHG emissions.
98.54 Monitoring and QA/QC requirements
98.55 Procedures for estimating missing data.
98.56 Data reporting requirements.
98.57 Records that must be retained.
98.58 Definitions.

                      Subpart F_Aluminum Production

98.60 Definition of the source category.
98.61 Reporting threshold.
98.62 GHGs to report.
98.63 Calculating GHG emissions.
98.64 Monitoring and QA/QC requirements.
98.65 Procedures for estimating missing data.
98.66 Data reporting requirements.
98.67 Records that must be retained.
98.68 Definitions.

Table F-1 to Subpart F of Part 98--Slope and Overvoltage Coefficients 
          for the Calculation of PFC Emissions From Aluminum Production
Table F-2 to Subpart F of Part 98--Default Data Sources for Parameters 
          Used for CO2 Emissions

                     Subpart G_Ammonia Manufacturing

98.70 Definition of source category.
98.71 Reporting threshold.
98.72 GHGs to report.
98.73 Calculating GHG emissions.
98.74 Monitoring and QA/QC requirements.
98.75 Procedures for estimating missing data.
98.76 Data reporting requirements.
98.77 Records that must be retained.
98.78 Definitions.

                       Subpart H_Cement Production

98.80 Definition of the source category.
98.81 Reporting threshold.
98.82 GHGs to report.
98.83 Calculating GHG emissions.
98.84 Monitoring and QA/QC requirements.
98.85 Procedures for estimating missing data.
98.86 Data reporting requirements.
98.87 Records that must be retained.
98.88 Definitions.

                   Subpart I_Electronics Manufacturing

98.90 Definition of the source category.
98.91 Reporting threshold.
98.92 GHGs to report.
98.93 Calculating GHG emissions.
98.94 Monitoring and QA/QC requirements.
98.95 Procedures for estimating missing data.
98.96 Data reporting requirements.
98.97 Records that must be retained.
98.98 Definitions.

Table I-1 to Subpart I of Part 98--Default Emission Factors for 
          Threshold Applicability Determination
Table I-2 to Subpart I of Part 98--Examples of Fluorinated GHGs Used by 
          the Electronics Industry
Table I-3 to Subpart I of Part 98--Default Emission Factors (1-
          Uij) for Gas Utilization Rates (Uij) and 
          By-Product Formation Rates (Bijk) for Semiconductor 
          Manufacturing for 150 mm and 200 mm Wafer Sizes
Table I-4 to Subpart I of Part 98--Default Emission Factors (1-
          Uij) for Gas Utilization Rates (Uij) and 
          By-Product Formation Rates (Bijk) for Semiconductor 
          Manufacturing for 300 mm and 450 mm Wafer Size
Table I-5 to Subpart I of Part 98--Default Emission Factors (1-
          Uij) for Gas Utilization Rates (Uij) and 
          By-Product Formation Rates (Bijk) for MEMS 
          Manufacturing
Table I-6 to Subpart I of Part 98--Default Emission Factors (1-
          Uij) for Gas Utilization Rates (Uij) and 
          By-Product Formation Rates (Bijk) for LCD 
          Manufacturing

[[Page 544]]

Table I-7 to Subpart I of Part 98-- Default Emission Factors (1-
          Uij) for Gas Utilization Rates (Uij) and 
          By-Product Formation Rates (Bijk) for PV 
          Manufacturing
Table I-8 to Subpart I of Part 98-- Default Emission Factors (1-
          UN2O,j) for N2O Utilization 
          (UN2O,j)
Table I-9 to Subpart I of Part 98--Methods and Procedures for Conducting 
          Emissions Test for Stack Systems
Table I-10 to Subpart I of Part 98--Maximum Field Detection Limits 
          Applicable to Fluorinated GHG Concentration Measurements for 
          Stack Systems
Table I-11 to Subpart I of Part 98--Default Emission Factors (1-
          Uij) for Gas Utilization Rates (Uij) and 
          By-Product Formation Rates (Bijk) for Semiconductor 
          Manufacturing for Use With the Stack Test Method (150 mm and 
          200 mm Wafers)
Table I-12 to Subpart I of Part 98--Default Emission Factors (1-
          Uij) for Gas Utilization Rates (Uij) and 
          By-Product Formation Rates (Bijk) for Semiconductor 
          Manufacturing for Use With the Stack Test Method (300 mm and 
          450 mm Wafers)
Table I-13 to Subpart I of Part 98--Default Emission Factors (1-
          Uij) for Gas Utilization Rates (Uij) and 
          By-Product Formation Rates (Bijk) for LCD 
          Manufacturing for Use With the Stack Test Method
Table I-14 to Subpart I of Part 98--Default Emission Factors (1-
          Uij) for Gas Utilization Rates (Uij) and 
          By-Product Formation Rates (Bijk) for PV 
          Manufacturing for Use With the Stack Test Method
Table I-15 to Subpart I of Part 98--Default Emission Factors (1-
          Uij) for Gas Utilization Rates (Uij) and 
          By-Product Formation Rates (Bijk) for MEMS 
          Manufacturing for Use With the Stack Test Method
Table I-16 to Subpart I of Part 98--Default Emission Destruction or 
          Removal Efficiency (DRE) Factors for Electronics Manufacturing
Table I-17 to Subpart I of Part 98--Expected and Possible By-Products 
          for Electronics Manufacturing
Appendix A to Subpart I of Part 98--Alternative Procedures for Measuring 
          Point-of-Use Abatement Device Destruction or Removal 
          Efficiency

Subpart J [Reserved]

                     Subpart K_Ferroalloy Production

98.110 Definition of the source category.
98.111 Reporting threshold.
98.112 GHGs to report.
98.113 Calculating GHG emissions.
98.114 Monitoring and QA/QC requirements.
98.115 Procedures for estimating missing data.
98.116 Data reporting requirements.
98.117 Records that must be retained.
98.118 Definitions.

Table K-1 to Subpart K of Part 98--Electric Arc Furnace (EAF) CH4 
          Emission Factors

                  Subpart L_Fluorinated Gas Production

98.120 Definition of the source category.
98.121 Reporting threshold.
98.122 GHGs to report.
98.123 Calculating GHG emissions.
98.124 Monitoring and QA/QC requirements.
98.125 Procedures for estimating missing data.
98.126 Data reporting requirements.
98.127 Records that must be retained.
98.128 Definitions.

Table L-1 to Subpart L of Part 98--Ranges of Effective Destruction 
          Efficiency
Appendix A to Subpart L of Part 98--Mass Balance Method for Fluorinated 
          Gas Production

Subpart -M [Reserved]

                       Subpart N_Glass Production

98.140 Definition of the source category.
98.141 Reporting threshold.
98.142 GHGs to report.
98.143 Calculating GHG emissions.
98.144 Monitoring and QA/QC requirements.
98.145 Procedures for estimating missing data.
98.146 Data reporting requirements.
98.147 Records that must be retained.
98.148 Definitions.

Table N-1 to Subpart N of Part 98--CO2 Emission Factors for 
          Carbonate-Based Raw Materials

           Subpart O_HCFC	22 Production and HFC	23 Destruction

98.150 Definition of the source category.
98.151 Reporting threshold.
98.152 GHGs to report.
98.153 Calculating GHG emissions.
98.154 Monitoring and QA/QC requirements.
98.155 Procedures for estimating missing data.
98.156 Data reporting requirements.
98.157 Records that must be retained.
98.158 Definitions.

Table O-1 to Subpart O of Part 98--Emission Factors for Equipment Leaks

                      Subpart P_Hydrogen Production

98.160 Definition of the source category.
98.161 Reporting threshold.

[[Page 545]]

98.162 GHGs to report.
98.163 Calculating GHG emissions.
98.164 Monitoring and QA/QC requirements.
98.165 Procedures for estimating missing data.
98.166 Data reporting requirements.
98.167 Records that must be retained.
98.168 Definitions.

                   Subpart Q_Iron and Steel Production

98.170 Definition of the source category.
98.171 Reporting threshold.
98.172 GHGs to report.
98.173 Calculating GHG emissions.
98.174 Monitoring and QA/QC requirements.
98.175 Procedures for estimating missing data.
98.176 Data reporting requirements.
98.177 Records that must be retained.
98.178 Definitions.

                        Subpart R_Lead Production

98.180 Definition of the source category.
98.181 Reporting threshold.
98.182 GHGs to report.
98.183 Calculating GHG emissions.
98.184 Monitoring and QA/QC requirements.
98.185 Procedures for estimating missing data.
98.186 Data reporting procedures.
98.187 Records that must be retained.
98.188 Definitions.

                      Subpart S_Lime Manufacturing

98.190 Definition of the source category.
98.191 Reporting threshold.
98.192 GHGs to report.
98.193 Calculating GHG emissions.
98.194 Monitoring and QA/QC requirements.
98.195 Procedures for estimating missing data.
98.196 Data reporting requirements.
98.197 Records that must be retained.
98.198 Definitions.

Table S-1 to Subpart S of Part 98--Basic Parameters for the Calculation 
          of Emission Factors for Lime Production

                     Subpart T_Magnesium Production

98.200 Definition of source category.
98.201 Reporting threshold.
98.202 GHGs to report.
98.203 Calculating GHG emissions.
98.204 Monitoring and QA/QC requirements.
98.205 Procedures for estimating missing data.
98.206 Data reporting requirements.
98.207 Records that must be retained.
98.208 Definitions.

                Subpart U_Miscellaneous Uses of Carbonate

98.210 Definition of the source category.
98.211 Reporting threshold.
98.212 GHGs to report.
98.213 Calculating GHG emissions.
98.214 Monitoring and QA/QC requirements.
98.215 Procedures for estimating missing data.
98.216 Data reporting requirements.
98.217 Records that must be retained.
98.218 Definitions.

Table U-1 to Subpart U of Part 98--CO2 Emission Factors for 
          Common Carbonates

                    Subpart V_Nitric Acid Production

98.220 Definition of source category.
98.221 Reporting threshold.
98.222 GHGs to report.
98.223 Calculating GHG emissions.
98.224 Monitoring and QA/QC requirements.
98.225 Procedures for estimating missing data.
98.226 Data reporting requirements.
98.227 Records that must be retained.
98.228 Definitions.

               Subpart W_Petroleum and Natural Gas Systems

98.230 Definition of the source category.
98.231 Reporting threshold.
98.232 GHGs to report.
98.233 Calculating GHG emissions.
98.234 Monitoring and QA/QC requirements.
98.235 Procedures for estimating missing data.
98.236 Data reporting requirements.
98.237 Records that must be retained.
98.238 Definitions.

Table W-1A to Subpart W of Part 98--Default Whole Gas Emission Factors 
          for Onshore Petroleum and Natural Gas Production Facilities 
          and Onshore Petroleum and Natural Gas Gathering and Boosting 
          Facilities
Table W-1B to Subpart W of Part 98--Default Average Component Counts for 
          Major Onshore Natural Gas Production Equipment and Onshore 
          Petroleum and Natural Gas Gathering and Boosting Equipment
Table W-1C to Subpart W of Part 98--Default Average Component Counts For 
          Major Crude Oil Production Equipment
Table W-1D to Subpart W of Part 98--Designation Of Eastern And Western 
          U.S.
Table W-2 to Subpart W of Part 98--Default Total Hydrocarbon Emission 
          Factors for Onshore Natural Gas Processing
Table W-3 to Subpart W of Part 98--Default Total Hydrocarbon Emission 
          Factors for Onshore Natural Gas Transmission Compression
Table W-4 to Subpart W of Part 98--Default Total Hydrocarbon Emission

[[Page 546]]

          Factors for Underground Natural Gas Storage
Table W-5 to Subpart W of Part 98--Default Methane Emission Factors for 
          Liquefied Natural Gas (LNG) Storage
Table W-6 to Subpart W of Part 98--Default Methane Emission Factors for 
          LNG Import and Export Equipment
Table W-7 to Subpart W of Part 98--Default Methane Emission Factors for 
          Natural Gas Distribution

                   Subpart X_Petrochemical Production

98.240 Definition of the source category.
98.241 Reporting threshold.
98.242 GHGs to report.
98.243 Calculating GHG emissions.
98.244 Monitoring and QA/QC requirements.
98.245 Procedures for estimating missing data.
98.246 Data reporting requirements.
98.247 Records that must be retained.
98.248 Definitions.

                     Subpart Y_Petroleum Refineries

98.250 Definition of source category.
98.251 Reporting threshold.
98.252 GHGs to report.
98.253 Calculating GHG emissions.
98.254 Monitoring and QA/QC requirements.
98.255 Procedures for estimating missing data.
98.256 Data reporting requirements.
98.257 Records that must be retained.
98.258 Definitions.

                  Subpart Z_Phosphoric Acid Production

98.260 Definition of the source category.
98.261 Reporting threshold.
98.262 GHGs to report.
98.263 Calculating GHG emissions.
98.264 Monitoring and QA/QC requirements.
98.265 Procedures for estimating missing data.
98.266 Data reporting requirements.
98.267 Records that must be retained.
98.268 Definitions.

Table Z-1 to Subpart Z of Part 98--Default Chemical Composition of 
          Phosphate Rock by Origin

                 Subpart AA_Pulp and Paper Manufacturing

98.270 Definition of source category.
98.271 Reporting threshold.
98.272 GHGs to report.
98.273 Calculating GHG emissions.
98.274 Monitoring and QA/QC requirements.
98.275 Procedures for estimating missing data.
98.276 Data reporting requirements.
98.277 Records that must be retained.
98.278 Definitions.

Table AA-1 to Subpart AA of Part 98--Kraft Pulping Liquor Emissions 
          Factors for Biomass-Based CO2, CH4, and 
          N2O
Table AA-2 to Subpart AA of Part 98--Kraft Lime Kiln and Calciner 
          Emissions Factors for CH4 and N2O

                  Subpart BB_Silicon Carbide Production

98.280 Definition of the source category.
98.281 Reporting threshold.
98.282 GHGs to report.
98.283 Calculating GHG emissions.
98.284 Monitoring and QA/QC requirements.
98.285 Procedures for estimating missing data.
98.286 Data reporting requirements.
98.287 Records that must be retained.
98.288 Definitions.

                    Subpart CC_Soda Ash Manufacturing

98.290 Definition of the source category.
98.291 Reporting threshold.
98.292 GHGs to report.
98.293 Calculating GHG emissions.
98.294 Monitoring and QA/QC requirements.
98.295 Procedures for estimating missing data.
98.296 Data reporting requirements.
98.297 Records that must be retained.
98.298 Definitions.

    Subpart DD_Electrical Transmission and Distribution Equipment Use

98.300 Definition of the source category.
98.301 Reporting threshold.
98.302 GHGs to report.
98.303 Calculating GHG emissions.
98.304 Monitoring and QA/QC requirements.
98.305 Procedures for estimating missing data.
98.306 Data reporting requirements.
98.307 Records that must be retained.
98.308 Definitions.

                 Subpart EE_Titanium Dioxide Production

98.310 Definition of the source category.
98.311 Reporting threshold.
98.312 GHGs to report.
98.313 Calculating GHG emissions.
98.314 Monitoring and QA/QC requirements.
98.315 Procedures for estimating missing data.
98.316 Data reporting requirements.
98.317 Records that must be retained.
98.318 Definitions.

                    Subpart FF_Underground Coal Mines

98.320 Definition of the source category.
98.321 Reporting threshold.
98.322 GHGs to report.
98.323 Calculating GHG emissions.
98.324 Monitoring and QA/QC requirements.

[[Page 547]]

98.325 Procedures for estimating missing data.
98.326 Data reporting requirements.
98.327 Records that must be retained.
98.328 Definitions.

                       Subpart GG_Zinc Production

98.330 Definition of the source category.
98.331 Reporting threshold.
98.332 GHGs to report.
98.333 Calculating GHG emissions.
98.334 Monitoring and QA/QC requirements.
98.335 Procedures for estimating missing data.
98.336 Data reporting requirements.
98.337 Records that must be retained.
98.338 Definitions.

               Subpart HH_Municipal Solid Waste Landfills

98.340 Definition of the source category.
98.341 Reporting threshold.
98.342 GHGs to report.
98.343 Calculating GHG emissions.
98.344 Monitoring and QA/QC requirements.
98.345 Procedures for estimating missing data.
98.346 Data reporting requirements.
98.347 Records that must be retained.
98.348 Definitions.

Table HH-1 to Subpart HH of Part 98--Emissions Factors, Oxidation 
          Factors and Methods
Table HH-2 to Subpart HH of Part 98--U.S. Per Capita Waste Disposal 
          Rates
Table HH-3 to Subpart HH of Part 98--Landfill Gas Collection 
          Efficiencies
Table HH-4 to Subpart HH of Part 98--Landfill Methane Oxidation 
          Fractions

               Subpart II_Industrial Wastewater Treatment

98.350 Definition of source category.
98.351 Reporting threshold.
98.352 GHGs to report.
98.353 Calculating GHG emissions.
98.354 Monitoring and QA/QC requirements.
98.355 Procedures for estimating missing data.
98.356 Data reporting requirements.
98.357 Records that must be retained.
98.358 Definitions.

Table II-1 to Subpart II of Part 98--Emission Factors
Table II-2 to Subpart II of Part 98--Collection Efficiencies of 
          Anaerobic Processes

                      Subpart JJ_Manure Management

98.360 Definition of the source category.
98.361 Reporting threshold.
98.362 GHGs to report.
98.363 Calculating GHG emissions.
98.364 Monitoring and QA/QC requirements.
98.365 Procedures for estimating missing data.
98.366 Data reporting requirements.
98.367 Records that must be retained.
98.368 Definitions.

Table JJ-1 to Subpart JJ of Part 98--Animal Population Threshold Level 
          Below which Facilities are not required to report Emissions 
          under Subpart JJ
Table JJ-2 to Subpart JJ of Part 98--Waste Characteristics Data
Table JJ-3 to Subpart JJ of Part 98--State-Specific Volatile Solids (VS) 
          and Nitrogen (N) Excretion Rates for Cattle
Table JJ-4 to Subpart JJ of Part 98--Volatile Solids and Nitrogen 
          Removal through Solids Separation
Table JJ-5 to Subpart JJ of Part 98--Methane Conversion Factors
Table JJ-6 to Subpart JJ of Part 98--Collection Efficiencies of 
          Anaerobic Digesters
Table JJ-7 to Subpart JJ of Part 98--Nitrous Oxide Emission Factors (kg 
          N2O-N/kg Kjdl N)

Subpart KK [Reserved]

             Subpart LL_Suppliers of Coal-based Liquid Fuels

98.380 Definition of the source category.
98.381 Reporting threshold.
98.382 GHGs to report.
98.383 Calculating GHG emissions.
98.384 Monitoring and QA/QC requirements.
98.385 Procedures for estimating missing data.
98.386 Data reporting requirements.
98.387 Records that must be retained.
98.388 Definitions.

               Subpart MM_Suppliers of Petroleum Products

98.390 Definition of the source category.
98.391 Reporting threshold.
98.392 GHGs to report.
98.393 Calculating GHG emissions.
98.394 Monitoring and QA/QC requirements.
98.395 Procedures for estimating missing data.
98.396 Data reporting requirements.
98.397 Records that must be retained.
98.398 Definitions.

Table MM-1 to Subpart MM of Part 98--Default CO2 Factors for 
          Petroleum Products
Table MM-2 to Subpart MM of Part 98--Default Factors for Biomass-Based 
          Fuels and Biomass

[[Page 548]]

       Subpart NN_Suppliers of Natural Gas and Natural Gas Liquids

98.400 Definition of the source category.
98.401 Reporting threshold.
98.402 GHGs to report.
98.403 Calculating GHG emissions.
98.404 Monitoring and QA/QC requirements.
98.405 Procedures for estimating missing data.
98.406 Data reporting requirements.
98.407 Records that must be retained.
98.408 Definitions.

Table NN-1 to Subpart NN of Part 98--Default Factors for Calculation 
          Methodology 1 of This Subpart
Table NN-2 to Subpart NN of Part 98--Lookup Default Values for 
          Calculation Methodology 2 of this Subpart

           Subpart OO_Suppliers of Industrial Greenhouse Gases

98.410 Definition of the source category.
98.411 Reporting threshold.
98.412 GHGs to report.
98.413 Calculating GHG emissions.
98.414 Monitoring and QA/QC requirements.
98.415 Procedures for estimating missing data.
98.416 Data reporting requirements.
98.417 Records that must be retained.
98.418 Definitions.

                 Subpart PP_Suppliers of Carbon Dioxide

98.420 Definition of the source category.
98.421 Reporting threshold.
98.422 GHGs to report.
98.423 Calculating CO2 supply.
98.424 Monitoring and QA/QC requirements.
98.425 Procedures for estimating missing data.
98.426 Data reporting requirements.
98.427 Records that must be retained.
98.428 Definitions.

   Subpart QQ_Importers and Exporters of Fluorinated Greenhouse Gases 
         Contained in Pre-Charged Equipment or Closed-Cell Foams

98.430 Definition of the source category.
98.431 Reporting threshold.
98.432 GHGs to report.
98.433 Calculating GHG emissions.
98.434 Monitoring and QA/QC requirements.
98.435 Procedures for estimating missing data.
98.436 Data reporting requirements.
98.437 Records that must be retained.
98.438 Definitions.

           Subpart RR_Geologic Sequestration of Carbon Dioxide

98.440 Definition of the source category.
98.441 Reporting threshold.
98.442 GHGs to report.
98.443 Calculating CO2 geologic sequestration.
98.444 Monitoring and QA/QC requirements.
98.445 Procedures for estimating missing data.
98.446 Data reporting requirements.
98.447 Records that must be retained.
98.448 Geologic sequestration monitoring, reporting, and verification 
          (MRV) plan.
98.449 Definitions.

      Subpart SS_Electrical Equipment Manufacture or Refurbishment

98.450 Definition of the source category.
98.451 Reporting threshold.
98.452 GHGs to report.
98.453 Calculating GHG emissions.
98.454 Monitoring and QA/QC requirements.
98.455 Procedures for estimating missing data.
98.456 Data reporting requirements.
98.457 Records that must be retained.
98.458 Definitions.

                  Subpart TT_Industrial Waste Landfills

98.460 Definition of the source category.
98.461 Reporting threshold.
98.462 GHGs to report.
98.463 Calculating GHG emissions.
98.464 Monitoring and QA/QC requirements.
98.465 Procedures for estimating missing data.
98.466 Data reporting requirements.
98.467 Records that must be retained.
98.468 Definitions.

Table TT-1 to Subpart TT of Part 98--Default DOC and Decay Rate Values 
          for Industrial Waste Landfills

                 Subpart UU_Injection of Carbon Dioxide

98.470 Definition of the source category.
98.471 Reporting threshold.
98.472 GHGs to report.
98.473 Calculating CO2 received.
98.474 Monitoring and QA/QC requirements.
98.475 Procedures for estimating missing data.
98.476 Data reporting requirements.
98.477 Records that must be retained.
98.478 Definitions.

    Authority: 42 U.S.C. 7401-7671q.

    Source: 74 FR 56374, Oct. 30, 2009, unless otherwise noted.



                       Subpart A_General Provision



Sec. 98.1  Purpose and scope.

    (a) This part establishes mandatory greenhouse gas (GHG) reporting 
requirements for owners and operators of

[[Page 549]]

certain facilities that directly emit GHG as well as for certain 
suppliers. For suppliers, the GHGs reported are the quantity that would 
be emitted from combustion or use of the products supplied.
    (b) Owners and operators of facilities and suppliers that are 
subject to this part must follow the requirements of this subpart and 
all applicable subparts of this part. If a conflict exists between a 
provision in subpart A and any other applicable subpart, the 
requirements of the applicable subpart shall take precedence.
    (c) For facilities required to report under onshore petroleum and 
natural gas production under subpart W of this part, the terms Owner and 
Operator used in subpart A have the same definition as Onshore petroleum 
and natural gas production owner or operator, as defined in Sec. 98.238 
of this part.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 39758, July 12, 2010; 
76 FR 73898, Nov. 29, 2011; 76 FR 80573, Dec. 23, 2011]



Sec. 98.2  Who must report?

    (a) The GHG reporting requirements and related monitoring, 
recordkeeping, and reporting requirements of this part apply to the 
owners and operators of any facility that is located in the United 
States or under or attached to the Outer Continental Shelf (as defined 
in 43 U.S.C. 1331) and that meets the requirements of either paragraph 
(a)(1), (a)(2), or (a)(3) of this section; and any supplier that meets 
the requirements of paragraph (a)(4) of this section:
    (1) A facility that contains any source category that is listed in 
Table A-3 of this subpart in any calendar year starting in 2010. For 
these facilities, the annual GHG report must cover stationary fuel 
combustion sources (subpart C of this part), miscellaneous use of 
carbonates (subpart U of this part), and all applicable source 
categories listed in Table A-3 and Table A-4 of this subpart.
    (2) A facility that contains any source category that is listed in 
Table A-4 of this subpart and that emits 25,000 metric tons 
CO2e or more per year in combined emissions from stationary 
fuel combustion units, miscellaneous uses of carbonate, and all 
applicable source categories that are listed in Table A-3 and Table A-4 
of this subpart. For these facilities, the annual GHG report must cover 
stationary fuel combustion sources (subpart C of this part), 
miscellaneous use of carbonates (subpart U of this part), and all 
applicable source categories listed in Table A-3 and Table A-4 of this 
subpart.
    (3) A facility that in any calendar year starting in 2010 meets all 
three of the conditions listed in this paragraph (a)(3). For these 
facilities, the annual GHG report must cover emissions from stationary 
fuel combustion sources only.
    (i) The facility does not meet the requirements of either paragraph 
(a)(1) or (a)(2) of this section.
    (ii) The aggregate maximum rated heat input capacity of the 
stationary fuel combustion units at the facility is 30 mmBtu/hr or 
greater.
    (iii) The facility emits 25,000 metric tons CO2e or more 
per year in combined emissions from all stationary fuel combustion 
sources.
    (4) A supplier that is listed in Table A-5 of this subpart. For 
these suppliers, the annual GHG report must cover all applicable 
products for which calculation methodologies are provided in the 
subparts listed in Table A-5 of this subpart.
    (5) Research and development activities are not considered to be 
part of any source category defined in this part.
    (b) To calculate GHG emissions for comparison to the 25,000 metric 
ton CO2e per year emission threshold in paragraph (a)(2) of 
this section, the owner or operator shall calculate annual 
CO2e emissions, as described in paragraphs (b)(1) through 
(b)(4) of this section.
    (1) Calculate the annual emissions of CO2, 
CH4, N2O, and each fluorinated GHG in metric tons 
from all applicable source categories listed in paragraph (a)(2) of this 
section. The GHG emissions shall be calculated using the calculation 
methodologies specified in each applicable subpart and available company 
records.
    (2) For each general stationary fuel combustion unit, calculate the 
annual CO2 emissions in metric tons using any of the four 
calculation methodologies specified in Sec. 98.33(a). Calculate the 
annual CH4 and N2O emissions from the stationary 
fuel combustion sources in

[[Page 550]]

metric tons using the appropriate equation in Sec. 98.33(c). Exclude 
carbon dioxide emissions from the combustion of biomass, but include 
emissions of CH4 and N2O from biomass combustion.
    (3) For miscellaneous uses of carbonate, calculate the annual 
CO2 emissions in metric tons using the procedures specified 
in subpart U of this part.
    (4) Sum the emissions estimates from paragraphs (b)(1), (b)(2), and 
(b)(3) of this section for each GHG and calculate metric tons of 
CO2e using Equation A-1 of this section.
[GRAPHIC] [TIFF OMITTED] TR11DE14.000

Where:

CO2e = Carbon dioxide equivalent, metric tons/year.
GHGi = Mass emissions of each greenhouse gas, metric tons/
          year.
GWPi = Global warming potential for each greenhouse gas from 
          Table A-1 of this subpart.
n = The number of greenhouse gases emitted.

    (5) For purpose of determining if an emission threshold has been 
exceeded, include in the emissions calculation any CO2 that 
is captured for transfer off site.
    (c) To calculate GHG emissions for comparison to the 25,000 metric 
ton CO2e/year emission threshold for stationary fuel 
combustion under paragraph (a)(3) of this section, calculate 
CO2, CH4, and N2O emissions from each 
stationary fuel combustion unit by following the methods specified in 
paragraph (b)(2) of this section. Then, convert the emissions of each 
GHG to metric tons CO2e per year using Equation A-1 of this 
section, and sum the emissions for all units at the facility.
    (d) To calculate GHG quantities for comparison to the 25,000 metric 
ton CO2 per year threshold for importers and exporters of 
coal-to-liquid products under paragraph (a)(4) of this section, 
calculate the mass in metric tons per year of CO2 that would 
result from the complete combustion or oxidation of the quantity of 
coal-to-liquid products that are imported during the reporting year and, 
that are exported during the reporting year. Compare the imported 
quantities and the exported quantities separately to the 25,000 metric 
ton CO2 per year threshold. Calculate the quantities using 
the methodology specified in subpart LL of this part.
    (e) To calculate GHG quantities for comparison to the 25,000 metric 
ton CO2e per year threshold for importers and exporters of 
petroleum products under paragraph (a)(4) of this section, calculate the 
mass in metric tons per year of CO2 that would result from 
the complete combustion or oxidation of the combined volume of petroleum 
products and natural gas liquids that are imported during the reporting 
year and that are exported during the reporting year. Compare the 
imported quantities and the exported quantities separately to the 25,000 
metric ton CO2 per year threshold. Calculate the quantities 
using the methodology specified in subpart MM of this part.
    (f) To calculate GHG quantities for comparison to the 25,000 metric 
ton CO2e per year threshold under paragraph (a)(4) of this 
section for importers and exporters of industrial greenhouse gases and 
for importers and exporters of CO2, the owner or operator 
shall calculate the mass in metric tons per year of CO2e 
imports and exports as described in paragraphs (f)(1) through (f)(3) of 
this section. Compare the imported quantities and the exported 
quantities separately to the 25,000 metric ton CO2 per year 
threshold.
    (1) Calculate the mass in metric tons per year of CO2, 
N2O, and each fluorinated GHG that is imported and the mass 
in metric tons per year of CO2, N2O, and each 
fluorinated GHG that is exported during the year.
    (2) Convert the mass of each imported and each GHG exported from 
paragraph (f)(1) of this section to metric tons of CO2e using 
Equation A-1 of this section.

[[Page 551]]

    (3) Sum the total annual metric tons of CO2e in paragraph 
(f)(2) of this section for all imported GHGs. Sum the total annual 
metric tons of CO2e in paragraph (f)(2) of this section for 
all exported GHGs.
    (g) If a capacity or generation reporting threshold in paragraph 
(a)(1) of this section applies, the owner or operator shall review the 
appropriate records and perform any necessary calculations to determine 
whether the threshold has been exceeded.
    (h) An owner or operator of a facility or supplier that does not 
meet the applicability requirements of paragraph (a) of this section is 
not subject to this rule. Such owner or operator would become subject to 
the rule and reporting requirements, if a facility or supplier exceeds 
the applicability requirements of paragraph (a) of this section at a 
later time pursuant to Sec. 98.3(b)(3). Thus, the owner or operator 
should reevaluate the applicability to this part (including the revising 
of any relevant emissions calculations or other calculations) whenever 
there is any change that could cause a facility or supplier to meet the 
applicability requirements of paragraph (a) of this section. Such 
changes include but are not limited to process modifications, increases 
in operating hours, increases in production, changes in fuel or raw 
material use, addition of equipment, and facility expansion.
    (i) Except as provided in this paragraph, once a facility or 
supplier is subject to the requirements of this part, the owner or 
operator must continue for each year thereafter to comply with all 
requirements of this part, including the requirement to submit annual 
GHG reports, even if the facility or supplier does not meet the 
applicability requirements in paragraph (a) of this section in a future 
year.
    (1) If reported emissions are less than 25,000 metric tons 
CO2e per year for five consecutive years, then the owner or 
operator may discontinue complying with this part provided that the 
owner or operator submits a notification to the Administrator that 
announces the cessation of reporting and explains the reasons for the 
reduction in emissions. The notification shall be submitted no later 
than March 31 of the year immediately following the fifth consecutive 
year of emissions less than 25,000 tons CO2e per year. The 
owner or operator must maintain the corresponding records required under 
Sec. 98.3(g) for each of the five consecutive years and retain such 
records for three years following the year that reporting was 
discontinued. The owner or operator must resume reporting if annual 
emissions in any future calendar year increase to 25,000 metric tons 
CO2e per year or more.
    (2) If reported emissions are less than 15,000 metric tons 
CO2e per year for three consecutive years, then the owner or 
operator may discontinue complying with this part provided that the 
owner or operator submits a notification to the Administrator that 
announces the cessation of reporting and explains the reasons for the 
reduction in emissions. The notification shall be submitted no later 
than March 31 of the year immediately following the third consecutive 
year of emissions less than 15,000 tons CO2e per year. The 
owner or operator must maintain the corresponding records required under 
Sec. 98.3(g) for each of the three consecutive years and retain such 
records for three years following the year that reporting was 
discontinued. The owner or operator must resume reporting if annual 
emissions in any future calendar year increase to 25,000 metric tons 
CO2e per year or more.
    (3) If the operations of a facility or supplier are changed such 
that all applicable GHG-emitting processes and operations listed in 
paragraphs (a)(1) through (a)(4) of this section cease to operate, then 
the owner or operator is exempt from reporting in the years following 
the year in which cessation of such operations occurs, provided that the 
owner or operator submits a notification to the Administrator that 
announces the cessation of reporting and certifies to the closure of all 
GHG-emitting processes and operations no later than March 31 of the year 
following such changes. This paragraph (i)(3) does not apply to seasonal 
or other temporary cessation of operations. This paragraph (i)(3) does 
not apply to facilities with municipal solid waste landfills or 
industrial waste landfills, or to underground coal mines.

[[Page 552]]

The owner or operator must resume reporting for any future calendar year 
during which any of the GHG-emitting processes or operations resume 
operation.
    (j) Table A-2 of this subpart provides a conversion table for some 
of the common units of measure used in part 98.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 39758, July 12, 2010; 
75 FR 57685, Sept. 22, 2010; 76 FR 73899, Nov. 29, 2011; 75 FR 74487, 
Nov. 30, 2010; 79 FR 73776, Dec. 11, 2014]



Sec. 98.3  What are the general monitoring, reporting, recordkeeping
and verification requirements of this part?

    The owner or operator of a facility or supplier that is subject to 
the requirements of this part must submit GHG reports to the 
Administrator, as specified in this section.
    (a) General. Except as provided in paragraph (d) of this section, 
follow the procedures for emission calculation, monitoring, quality 
assurance, missing data, recordkeeping, and reporting that are specified 
in each relevant subpart of this part.
    (b) Schedule. The annual GHG report for reporting year 2010 must be 
submitted no later than September 30, 2011. The annual report for 
reporting years 2011 and beyond must be submitted no later than March 31 
of each calendar year for GHG emissions in the previous calendar year, 
except as provided in paragraph (b)(1) of this section.
    (1) For reporting year 2011, facilities with one or more of the 
subparts listed in paragraphs (b)(1)(i) through (b)(1)(xi) of this 
section and suppliers listed in paragraph (b)(1)(xii) of this section 
are required to submit their annual GHG report no later than September 
28, 2012. Facilities and suppliers that are submitting their second 
annual GHG report in 2012 and that are reporting on one or more subparts 
listed in paragraphs (b)(1)(i) through (b)(1)(xii) of this section must 
notify EPA by March 31, 2012 that they are not required to submit their 
annual GHG report until September 28, 2012.
    (i) Electronics Manufacturing (subpart I).
    (ii) Fluorinated Gas Production (subpart L).
    (iii) Magnesium Production (subpart T).
    (iv) Petroleum and Natural Gas Systems (subpart W).
    (v) Use of Electric Transmission and Distribution Equipment (subpart 
DD).
    (vi) Underground Coal Mines (subpart FF).
    (vii) Industrial Wastewater Treatment (subpart II).
    (viii) Geologic Sequestration of Carbon Dioxide (subpart RR).
    (ix) Manufacture of Electric Transmission and Distribution (subpart 
SS).
    (x) Industrial Waste Landfills (subpart TT).
    (xi) Injection of Carbon Dioxide (subpart UU).
    (xii) Imports and Exports of Equipment Pre-charged with Fluorinated 
GHGs or Containing Fluorinated GHGs in Closed-cell Foams (subpart QQ).
    (2) For a new facility or supplier that begins operation on or after 
January 1, 2010 and becomes subject to the rule in the year that it 
becomes operational, report emissions beginning with the first operating 
month and ending on December 31 of that year. Each subsequent annual 
report must cover emissions for the calendar year, beginning on January 
1 and ending on December 31.
    (3) For any facility or supplier that becomes subject to this rule 
because of a physical or operational change that is made after January 
1, 2010, report emissions for the first calendar year in which the 
change occurs, beginning with the first month of the change and ending 
on December 31 of that year. For a facility or supplier that becomes 
subject to this rule solely because of an increase in hours of operation 
or level of production, the first month of the change is the month in 
which the increased hours of operation or level of production, if 
maintained for the remainder of the year, would cause the facility or 
supplier to exceed the applicable threshold. Each subsequent annual 
report must cover emissions for the calendar year, beginning on January 
1 and ending on December 31.
    (4) Unless otherwise stated, if the final day of any time period 
falls on a weekend or a federal holiday, the time period shall be 
extended to the next business day.

[[Page 553]]

    (c) Content of the annual report. Except as provided in paragraph 
(d) of this section, each annual GHG report shall contain the following 
information:
    (1) Facility name or supplier name (as appropriate), and physical 
street address of the facility or supplier, including the city, State, 
and zip code. If the facility does not have a physical street address, 
then the facility must provide the latitude and longitude representing 
the geographic centroid or center point of facility operations in 
decimal degree format. This must be provided in a comma-delimited 
``latitude, longitude'' coordinate pair reported in decimal degrees to 
at least four digits to the right of the decimal point.
    (2) Year and months covered by the report.
    (3) Date of submittal.
    (4) For facilities, except as otherwise provided in paragraph 
(c)(12) of this section, report annual emissions of CO2, 
CH4, N2O, each fluorinated GHG (as defined in 
Sec. 98.6), and each fluorinated heat transfer fluid (as defined in 
Sec. 98.98) as follows.
    (i) Annual emissions (excluding biogenic CO2) aggregated 
for all GHG from all applicable source categories, expressed in metric 
tons of CO2e calculated using Equation A-1 of this subpart. 
For electronics manufacturing (as defined in Sec. 98.90), starting in 
reporting year 2012 the CO2e calculation must include each 
fluorinated heat transfer fluid (as defined in Sec. 98.98) whether or 
not it is also a fluorinated GHG.
    (ii) Annual emissions of biogenic CO2 aggregated for all 
applicable source categories, expressed in metric tons.
    (iii) Annual emissions from each applicable source category, 
expressed in metric tons of each applicable GHG listed in paragraphs 
(c)(4)(iii)(A) through (c)(4)(iii)(E) of this section.
    (A) Biogenic CO2.
    (B) CO2 (excluding biogenic CO2).
    (C) CH4.
    (D) N2O.
    (E) Each fluorinated GHG (as defined in Sec. 98.6), except 
fluorinated gas production facilities must comply with Sec. 98.126(a) 
rather than this paragraph (c)(4)(iii)(E). If a fluorinated GHG does not 
have a chemical-specific GWP in Table A-1 of this subpart, identify and 
report the fluorinated GHG group of which that fluorinated GHG is a 
member.
    (F) For electronics manufacturing (as defined in Sec. 98.90), each 
fluorinated heat transfer fluid (as defined in Sec. 98.98) that is not 
also a fluorinated GHG as specified under (c)(4)(iii)(E) of this 
section. If a fluorinated heat transfer fluid does not have a chemical-
specific GWP in Table A-1 of this subpart, identify and report the 
fluorinated GHG group of which that fluorinated heat transfer fluid is a 
member.
    (iv) Except as provided in paragraph (c)(4)(vii) of this section, 
emissions and other data for individual units, processes, activities, 
and operations as specified in the ``Data reporting requirements'' 
section of each applicable subpart of this part.
    (v) Indicate (yes or no) whether reported emissions include 
emissions from a cogeneration unit located at the facility.
    (vi) [Reserved]
    (vii) The owner or operator of a facility is not required to report 
the data elements specified in Table A-6 of this subpart for calendar 
years 2010 through 2011 until March 31, 2013. The owner or operator of a 
facility is not required to report the data elements specified in Table 
A-7 of this subpart for calendar years 2010 through 2013 until March 31, 
2015 (as part of the annual report for reporting year 2014), except as 
otherwise specified in Table A-7 of this subpart.
    (viii) Applicable source categories means stationary fuel combustion 
sources (subpart C of this part), miscellaneous use of carbonates 
(subpart U of this part), and all of the source categories listed in 
Table A-3 and Table A-4 of this subpart present at the facility.
    (5) For suppliers, report annual quantities of CO2, 
CH4, N2O, and each fluorinated GHG (as defined in 
Sec. 98.6) that would be emitted from combustion or use of the products 
supplied, imported, and exported during the year. Calculate and report 
quantities at the following levels:
    (i) Total quantity of GHG aggregated for all GHG from all applicable 
supply categories in Table A-5 of this subpart

[[Page 554]]

and expressed in metric tons of CO2e calculated using 
Equation A-1 of this subpart.
    (ii) Quantity of each GHG from each applicable supply category in 
Table A-5 to this subpart, expressed in metric tons of each GHG.
    (iii) Any other data specified in the ``Data reporting 
requirements'' section of each applicable subpart of this part.
    (6) A written explanation, as required under Sec. 98.3(e), if you 
change emission calculation methodologies during the reporting period.
    (7) A brief description of each ``best available monitoring method'' 
used, the parameter measured using the method, and the time period 
during which the ``best available monitoring method'' was used, if 
applicable.
    (8) Each data element for which a missing data procedure was used 
according to the procedures of an applicable subpart and the total 
number of hours in the year that a missing data procedure was used for 
each data element.
    (9) A signed and dated certification statement provided by the 
designated representative of the owner or operator, according to the 
requirements of Sec. 98.4(e)(1).
    (10) NAICS code(s) that apply to the facility or supplier.
    (i) Primary NAICS code. Report the NAICS code that most accurately 
describes the facility or supplier's primary product/activity/service. 
The primary product/activity/service is the principal source of revenue 
for the facility or supplier. A facility or supplier that has two 
distinct products/activities/services providing comparable revenue may 
report a second primary NAICS code.
    (ii) Additional NAICS code(s). Report all additional NAICS codes 
that describe all product(s)/activity(s)/service(s) at the facility or 
supplier that are not related to the principal source of revenue.
    (11) Legal name(s) and physical address(es) of the highest-level 
United States parent company(s) of the owners (or operators) of the 
facility or supplier and the percentage of ownership interest for each 
listed parent company as of December 31 of the year for which data are 
being reported according to the following instructions:
    (i) If the facility or supplier is entirely owned by a single United 
States company that is not owned by another company, provide that 
company's legal name and physical address as the United States parent 
company and report 100 percent ownership.
    (ii) If the facility or supplier is entirely owned by a single 
United States company that is, itself, owned by another company (e.g., 
it is a division or subsidiary of a higher-level company), provide the 
legal name and physical address of the highest-level company in the 
ownership hierarchy as the United States parent company and report 100 
percent ownership.
    (iii) If the facility or supplier is owned by more than one United 
States company (e.g., company A owns 40 percent, company B owns 35 
percent, and company C owns 25 percent), provide the legal names and 
physical addresses of all the highest-level companies with an ownership 
interest as the United States parent companies, and report the percent 
ownership of each company.
    (iv) If the facility or supplier is owned by a joint venture or a 
cooperative, the joint venture or cooperative is its own United States 
parent company. Provide the legal name and physical address of the joint 
venture or cooperative as the United States parent company, and report 
100 percent ownership by the joint venture or cooperative.
    (v) If the facility or supplier is entirely owned by a foreign 
company, provide the legal name and physical address of the foreign 
company's highest-level company based in the United States as the United 
States parent company, and report 100 percent ownership.
    (vi) If the facility or supplier is partially owned by a foreign 
company and partially owned by one or more U.S. companies, provide the 
legal name and physical address of the foreign company's highest-level 
company based in the United States, along with the legal names and 
physical addresses of the other U.S. parent companies, and report the 
percent ownership of each of these companies.

[[Page 555]]

    (vii) If the facility or supplier is a federally owned facility, 
report ``U.S. Government'' and do not report physical address or percent 
ownership.
    (viii) The facility or supplier must refer to the reporting 
instructions of the electronic GHG reporting tool regarding standardized 
conventions for the naming of a parent company.
    (12) For the 2010 reporting year only, facilities that have ``part 
75 units'' (i.e. units that are subject to subpart D of this part or 
units that use the methods in part 75 of this chapter to quantify 
CO2 mass emissions in accordance with Sec. 98.33(a)(5)) must 
report annual GHG emissions either in full accordance with paragraphs 
(c)(4)(i) through (c)(4)(iii) of this section or in full accordance with 
paragraphs (c)(12)(i) through (c)(12)(iii) of this section. If the 
latter reporting option is chosen, you must report:
    (i) Annual emissions aggregated for all GHG from all applicable 
source categories, expressed in metric tons of CO2e 
calculated using Equation A-1 of this subpart. You must include biogenic 
CO2 emissions from part 75 units in these annual emissions, 
but exclude biogenic CO2 emissions from any non-part 75 units 
and other source categories.
    (ii) Annual emissions of biogenic CO2, expressed in 
metric tons (excluding biogenic CO2 emissions from part 75 
units), aggregated for all applicable source categories.
    (iii) Annual emissions from each applicable source category, 
expressed in metric tons of each applicable GHG listed in paragraphs 
(c)(12)(iii)(A) through (c)(12)(iii)(E) of this section.
    (A) Biogenic CO2 (excluding biogenic CO2 
emissions from part 75 units).
    (B) CO2. You must include biogenic CO2 
emissions from part 75 units in these totals and exclude biogenic 
CO2 emissions from other non-part 75 units and other source 
categories.
    (C) CH4.
    (D) N2O.
    (E) Each fluorinated GHG (including those not listed in Table A-1 of 
this subpart).
    (13) An indication of whether the facility includes one or more 
plant sites that have been assigned a ``plant code'' (as defined under 
Sec. 98.6) by either the Department of Energy's Energy Information 
Administration or by the EPA's Clean Air Markets Division.
    (d) Special provisions for reporting year 2010. (1) Best available 
monitoring methods. During January 1, 2010 through March 31, 2010, 
owners or operators may use best available monitoring methods for any 
parameter (e.g., fuel use, daily carbon content of feedstock by process 
line) that cannot reasonably be measured according to the monitoring and 
QA/QC requirements of a relevant subpart. The owner or operator must use 
the calculation methodologies and equations in the ``Calculating GHG 
Emissions'' sections of each relevant subpart, but may use the best 
available monitoring method for any parameter for which it is not 
reasonably feasible to acquire, install, and operate a required piece of 
monitoring equipment by January 1, 2010. Starting no later than April 1, 
2010, the owner or operator must discontinue using best available 
methods and begin following all applicable monitoring and QA/QC 
requirements of this part, except as provided in paragraphs (d)(2) and 
(d)(3) of this section. Best available monitoring methods means any of 
the following methods specified in this paragraph:
    (i) Monitoring methods currently used by the facility that do not 
meet the specifications of an relevant subpart.
    (ii) Supplier data.
    (iii) Engineering calculations.
    (iv) Other company records.
    (2) Requests for extension of the use of best available monitoring 
methods. The owner or operator may submit a request to the Administrator 
to use one or more best available monitoring methods beyond March 31, 
2010.
    (i) Timing of request. The extension request must be submitted to 
EPA no later than 30 days after the effective date of the GHG reporting 
rule.
    (ii) Content of request. Requests must contain the following 
information:
    (A) A list of specific item of monitoring instrumentation for which 
the request is being made and the locations where each piece of 
monitoring instrumentation will be installed.
    (B) Identification of the specific rule requirements (by rule 
subpart, section,

[[Page 556]]

and paragraph numbers) for which the instrumentation is needed.
    (C) A description of the reasons why the needed equipment could not 
be obtained and installed before April 1, 2010.
    (D) If the reason for the extension is that the equipment cannot be 
purchased and delivered by April 1, 2010, include supporting 
documentation such as the date the monitoring equipment was ordered, 
investigation of alternative suppliers and the dates by which 
alternative vendors promised delivery, backorder notices or unexpected 
delays, descriptions of actions taken to expedite delivery, and the 
current expected date of delivery.
    (E) If the reason for the extension is that the equipment cannot be 
installed without a process unit shutdown, include supporting 
documentation demonstrating that it is not practicable to isolate the 
equipment and install the monitoring instrument without a full process 
unit shutdown. Include the date of the most recent process unit 
shutdown, the frequency of shutdowns for this process unit, and the date 
of the next planned shutdown during which the monitoring equipment can 
be installed. If there has been a shutdown or if there is a planned 
process unit shutdown between promulgation of this part and April 1, 
2010, include a justification of why the equipment could not be obtained 
and installed during that shutdown.
    (F) A description of the specific actions the facility will take to 
obtain and install the equipment as soon as reasonably feasible and the 
expected date by which the equipment will be installed and operating.
    (iii) Approval criteria. To obtain approval, the owner or operator 
must demonstrate to the Administrator's satisfaction that it is not 
reasonably feasible to acquire, install, and operate a required piece of 
monitoring equipment by April 1, 2010. The use of best available methods 
will not be approved beyond December 31, 2010.
    (3) Abbreviated emissions report for facilities containing only 
general stationary fuel combustion sources. In lieu of the report 
required by paragraph (c) of this section, the owner or operator of an 
existing facility that is in operation on January 1, 2010 and that meets 
the conditions of Sec. 98.2(a)(3) may submit an abbreviated GHG report 
for the facility for GHGs emitted in 2010. The abbreviated report must 
be submitted by September 30, 2011. An owner or operator that submits an 
abbreviated report must submit a full GHG report according to the 
requirements of paragraph (c) of this section beginning in calendar year 
2012. The abbreviated facility report must include the following 
information:
    (i) Facility name and physical street address including the city, 
state and zip code.
    (ii) The year and months covered by the report.
    (iii) Date of submittal.
    (iv) Total facility GHG emissions aggregated for all stationary fuel 
combustion units calculated according to any method specified in Sec. 
98.33(a) and expressed in metric tons of CO2, CH4, 
N2O, and CO2e.
    (v) For each stationary fuel combustion source that meets the 
criteria specified in Sec. 98.36(f), report any facility operating data 
or process information used for the GHG emission calculations. A 
stationary fuel combustion source that does not meet the criteria 
specified in Sec. 98.36(f) must either report the data specified in 
this paragraph (d)(3)(v) in the annual report or use verification 
software according to Sec. 98.5(b) in lieu of reporting the data 
specified in this paragraph.
    (vi) A signed and dated certification statement provided by the 
designated representative of the owner or operator, according to the 
requirements of paragraph (e)(1) of this section.
    (e) Emission calculations. In preparing the GHG report, you must use 
the calculation methodologies specified in the relevant subparts, except 
as specified in paragraph (d) of this section. For each source category, 
you must use the same calculation methodology throughout a reporting 
period unless you provide a written explanation of why a change in 
methodology was required.
    (f) Verification. To verify the completeness and accuracy of 
reported GHG emissions, the Administrator may review the certification 
statements described in paragraphs (c)(9) and

[[Page 557]]

(d)(3)(vi) of this section and any other credible evidence, in 
conjunction with a comprehensive review of the GHG reports and periodic 
audits of selected reporting facilities. Nothing in this section 
prohibits the Administrator from using additional information to verify 
the completeness and accuracy of the reports.
    (g) Recordkeeping. An owner or operator that is required to report 
GHGs under this part must keep records as specified in this paragraph 
(g). Except as otherwise provided in this paragraph, retain all required 
records for at least 3 years from the date of submission of the annual 
GHG report for the reporting year in which the record was generated. The 
records shall be kept in an electronic or hard-copy format (as 
appropriate) and recorded in a form that is suitable for expeditious 
inspection and review. If the owner or operator of a facility is 
required under Sec. 98.5(b) to use verification software specified by 
the Administrator, then all records required for the facility under this 
part must be retained for at least 5 years from the date of submission 
of the annual GHG report for the reporting year in which the record was 
generated, starting with records for reporting year 2010. Upon request 
by the Administrator, the records required under this section must be 
made available to EPA. Records may be retained off site if the records 
are readily available for expeditious inspection and review. For records 
that are electronically generated or maintained, the equipment or 
software necessary to read the records shall be made available, or, if 
requested by EPA, electronic records shall be converted to paper 
documents. You must retain the following records, in addition to those 
records prescribed in each applicable subpart of this part:
    (1) A list of all units, operations, processes, and activities for 
which GHG emission were calculated.
    (2) The data used to calculate the GHG emissions for each unit, 
operation, process, and activity, categorized by fuel or material type. 
These data include but are not limited to the following information in 
this paragraph (g)(2):
    (i) The GHG emissions calculations and methods used. For data 
required by Sec. 98.5(b) to be entered into verification software 
specified in Sec. 98.5(b), maintain the entered data in the format 
generated by the verification software according to Sec. 98.5(b).
    (ii) Analytical results for the development of site-specific 
emissions factors.
    (iii) The results of all required analyses for high heat value, 
carbon content, and other required fuel or feedstock parameters.
    (iv) Any facility operating data or process information used for the 
GHG emission calculations.
    (3) The annual GHG reports.
    (4) Missing data computations. For each missing data event, also 
retain a record of the cause of the event and the corrective actions 
taken to restore malfunctioning monitoring equipment.
    (5) A written GHG Monitoring Plan.
    (i) At a minimum, the GHG Monitoring Plan shall include the elements 
listed in this paragraph (g)(5)(i).
    (A) Identification of positions of responsibility (i.e., job titles) 
for collection of the emissions data.
    (B) Explanation of the processes and methods used to collect the 
necessary data for the GHG calculations.
    (C) Description of the procedures and methods that are used for 
quality assurance, maintenance, and repair of all continuous monitoring 
systems, flow meters, and other instrumentation used to provide data for 
the GHGs reported under this part.
    (ii) The GHG Monitoring Plan may rely on references to existing 
corporate documents (e.g., standard operating procedures, quality 
assurance programs under appendix F to 40 CFR part 60 or appendix B to 
40 CFR part 75, and other documents) provided that the elements required 
by paragraph (g)(5)(i) of this section are easily recognizable.
    (iii) The owner or operator shall revise the GHG Monitoring Plan as 
needed to reflect changes in production processes, monitoring 
instrumentation, and quality assurance procedures; or to improve 
procedures for the maintenance and repair of monitoring systems to 
reduce the frequency of monitoring equipment downtime.

[[Page 558]]

    (iv) Upon request by the Administrator, the owner or operator shall 
make all information that is collected in conformance with the GHG 
Monitoring Plan available for review during an audit. Electronic storage 
of the information in the plan is permissible, provided that the 
information can be made available in hard copy upon request during an 
audit.
    (6) The results of all required certification and quality assurance 
tests of continuous monitoring systems, fuel flow meters, and other 
instrumentation used to provide data for the GHGs reported under this 
part.
    (7) Maintenance records for all continuous monitoring systems, flow 
meters, and other instrumentation used to provide data for the GHGs 
reported under this part.
    (h) Annual GHG report revisions. (1) The owner or operator shall 
submit a revised annual GHG report within 45 days of discovering that an 
annual GHG report that the owner or operator previously submitted 
contains one or more substantive errors. The revised report must correct 
all substantive errors.
    (2) The Administrator may notify the owner or operator in writing 
that an annual GHG report previously submitted by the owner or operator 
contains one or more substantive errors. Such notification will identify 
each such substantive error. The owner or operator shall, within 45 days 
of receipt of the notification, either resubmit the report that, for 
each identified substantive error, corrects the identified substantive 
error (in accordance with the applicable requirements of this part) or 
provide information demonstrating that the previously submitted report 
does not contain the identified substantive error or that the identified 
error is not a substantive error.
    (3) A substantive error is an error that impacts the quantity of GHG 
emissions reported or otherwise prevents the reported data from being 
validated or verified.
    (4) Notwithstanding paragraphs (h)(1) and (2) of this section, upon 
request by the owner or operator, the Administrator may provide 
reasonable extensions of the 45-day period for submission of the revised 
report or information under paragraphs (h)(1) and (2) of this section. 
If the Administrator receives a request for extension of the 45-day 
period, by email to an address prescribed by the Administrator prior to 
the expiration of the 45-day period, the extension request is deemed to 
be automatically granted for 30 days. The Administrator may grant an 
additional extension beyond the automatic 30-day extension if the owner 
or operator submits a request for an additional extension and the 
request is received by the Administrator at least 5 business days prior 
to the expiration of the automatic 30-day extension, provided the 
request demonstrates that it is not practicable to submit a revised 
report or information under paragraphs (h)(1) and (2) within 75 days. 
The Administrator will approve the extension request if the request 
demonstrates to the Administrator's satisfaction that it is not 
practicable to collect and process the data needed to resolve potential 
reporting errors identified pursuant to paragraphs (h)(1) or (2) of this 
section within 75 days.
    (5) The owner or operator shall retain documentation for 3 years to 
support any revision made to an annual GHG report.
    (i) Calibration accuracy requirements. The owner or operator of a 
facility or supplier that is subject to the requirements of this part 
must meet the applicable flow meter calibration and accuracy 
requirements of this paragraph (i). The accuracy specifications in this 
paragraph (i) do not apply where either the use of company records (as 
defined in Sec. 98.6) or the use of ``best available information'' is 
specified in an applicable subpart of this part to quantify fuel usage 
and/or other parameters. Further, the provisions of this paragraph (i) 
do not apply to stationary fuel combustion units that use the 
methodologies in part 75 of this chapter to calculate CO2 
mass emissions.
    (1) Except as otherwise provided in paragraphs (i)(4) through (i)(6) 
of this section, flow meters that measure liquid and gaseous fuel feed 
rates, process stream flow rates, or feedstock flow rates and provide 
data for the GHG emissions calculations shall be calibrated prior to 
April 1, 2010 using the

[[Page 559]]

procedures specified in this paragraph (i) when such calibration is 
specified in a relevant subpart of this part. Each of these flow meters 
shall meet the applicable accuracy specification in paragraph (i)(2) or 
(i)(3) of this section. All other measurement devices (e.g., weighing 
devices) that are required by a relevant subpart of this part, and that 
are used to provide data for the GHG emissions calculations, shall also 
be calibrated prior to April 1, 2010; however, the accuracy 
specifications in paragraphs (i)(2) and (i)(3) of this section do not 
apply to these devices. Rather, each of these measurement devices shall 
be calibrated to meet the accuracy requirement specified for the device 
in the applicable subpart of this part, or, in the absence of such 
accuracy requirement, the device must be calibrated to an accuracy 
within the appropriate error range for the specific measurement 
technology, based on an applicable operating standard, including but not 
limited to manufacturer's specifications and industry standards. The 
procedures and methods used to quality-assure the data from each 
measurement device shall be documented in the written monitoring plan, 
pursuant to paragraph (g)(5)(i)(C) of this section.
    (i) All flow meters and other measurement devices that are subject 
to the provisions of this paragraph (i) must be calibrated according to 
one of the following: You may use the manufacturer's recommended 
procedures; an appropriate industry consensus standard method; or a 
method specified in a relevant subpart of this part. The calibration 
method(s) used shall be documented in the monitoring plan required under 
paragraph (g) of this section.
    (ii) For facilities and suppliers that become subject to this part 
after April 1, 2010, all flow meters and other measurement devices (if 
any) that are required by the relevant subpart(s) of this part to 
provide data for the GHG emissions calculations shall be installed no 
later than the date on which data collection is required to begin using 
the measurement device, and the initial calibration(s) required by this 
paragraph (i) (if any) shall be performed no later than that date.
    (iii) Except as otherwise provided in paragraphs (i)(4) through 
(i)(6) of this section, subsequent recalibrations of the flow meters and 
other measurement devices subject to the requirements of this paragraph 
(i) shall be performed at one of the following frequencies:
    (A) You may use the frequency specified in each applicable subpart 
of this part.
    (B) You may use the frequency recommended by the manufacturer or by 
an industry consensus standard practice, if no recalibration frequency 
is specified in an applicable subpart.
    (2) Perform all flow meter calibration at measurement points that 
are representative of the normal operating range of the meter. Except 
for the orifice, nozzle, and venturi flow meters described in paragraph 
(i)(3) of this section, calculate the calibration error at each 
measurement point using Equation A-2 of this section. The terms ``R'' 
and ``A'' in Equation A-2 must be expressed in consistent units of 
measure (e.g., gallons/minute, ft\3\/min). The calibration error at each 
measurement point shall not exceed 5.0 percent of the reference value.
[GRAPHIC] [TIFF OMITTED] TR17DE10.000

where:

CE = Calibration error (%).
R = Reference value.
A = Flow meter response to the reference value.

    (3) For orifice, nozzle, and venturi flow meters, the initial 
quality assurance consists of in-situ calibration of the differential 
pressure (delta-P),

[[Page 560]]

total pressure, and temperature transmitters.
    (i) Calibrate each transmitter at a zero point and at least one 
upscale point. Fixed reference points, such as the freezing point of 
water, may be used for temperature transmitter calibrations. Calculate 
the calibration error of each transmitter at each measurement point, 
using Equation A-3 of this subpart. The terms ``R,'' ``A,'' and ``FS'' 
in Equation A-3 of this subpart must be in consistent units of measure 
(e.g., milliamperes, inches of water, psi, degrees). For each 
transmitter, the CE value at each measurement point shall not exceed 2.0 
percent of full-scale. Alternatively, the results are acceptable if the 
sum of the calculated CE values for the three transmitters at each 
calibration level (i.e., at the zero level and at each upscale level) 
does not exceed 6.0 percent.
[GRAPHIC] [TIFF OMITTED] TR17DE10.001

where:
CE = Calibration error (%).
R = Reference value.
A = Transmitter response to the reference value.
FS = Full-scale value of the transmitter.

    (ii) In cases where there are only two transmitters (i.e., 
differential pressure and either temperature or total pressure) in the 
immediate vicinity of the flow meter's primary element (e.g., the 
orifice plate), or when there is only a differential pressure 
transmitter in close proximity to the primary element, calibration of 
these existing transmitters to a CE of 2.0 percent or less at each 
measurement point is still required, in accordance with paragraph 
(i)(3)(i) of this section; alternatively, when two transmitters are 
calibrated, the results are acceptable if the sum of the CE values for 
the two transmitters at each calibration level does not exceed 4.0 
percent. However, note that installation and calibration of an 
additional transmitter (or transmitters) at the flow monitor location to 
measure temperature or total pressure or both is not required in these 
cases. Instead, you may use assumed values for temperature and/or total 
pressure, based on measurements of these parameters at a remote location 
(or locations), provided that the following conditions are met:
    (A) You must demonstrate that measurements at the remote location(s) 
can, when appropriate correction factors are applied, reliably and 
accurately represent the actual temperature or total pressure at the 
flow meter under all expected ambient conditions.
    (B) You must make all temperature and/or total pressure measurements 
in the demonstration described in paragraph (i)(3)(ii)(A) of this 
section with calibrated gauges, sensors, transmitters, or other 
appropriate measurement devices. At a minimum, calibrate each of these 
devices to an accuracy within the appropriate error range for the 
specific measurement technology, according to one of the following. You 
may calibrate using a manufacturer's specification or an industry 
consensus standard.
    (C) You must document the methods used for the demonstration 
described in paragraph (i)(3)(ii)(A) of this section in the written GHG 
Monitoring Plan under paragraph (g)(5)(i)(C) of this section. You must 
also include the data from the demonstration, the mathematical 
correlation(s) between the remote readings and actual flow meter 
conditions derived from the data, and any supporting engineering 
calculations in the GHG Monitoring Plan. You must maintain all of this 
information in a format suitable for auditing and inspection.
    (D) You must use the mathematical correlation(s) derived from the 
demonstration described in paragraph (i)(3)(ii)(A) of this section to 
convert the remote temperature or the total pressure readings, or both, 
to the actual temperature or total pressure at

[[Page 561]]

the flow meter, or both, on a daily basis. You shall then use the actual 
temperature and total pressure values to correct the measured flow rates 
to standard conditions.
    (E) You shall periodically check the correlation(s) between the 
remote and actual readings (at least once a year), and make any 
necessary adjustments to the mathematical relationship(s).
    (4) Fuel billing meters are exempted from the calibration 
requirements of this section and from the GHG Monitoring Plan and 
recordkeeping provisions of paragraphs (g)(5)(i)(C), (g)(6), and (g)(7) 
of this section, provided that the fuel supplier and any unit combusting 
the fuel do not have any common owners and are not owned by subsidiaries 
or affiliates of the same company. Meters used exclusively to measure 
the flow rates of fuels that are used for unit startup are also exempted 
from the calibration requirements of this section.
    (5) For a flow meter that has been previously calibrated in 
accordance with paragraph (i)(1) of this section, an additional 
calibration is not required by the date specified in paragraph (i)(1) of 
this section if, as of that date, the previous calibration is still 
active (i.e., the device is not yet due for recalibration because the 
time interval between successive calibrations has not elapsed). In this 
case, the deadline for the successive calibrations of the flow meter 
shall be set according to one of the following. You may use either the 
manufacturer's recommended calibration schedule or you may use the 
industry consensus calibration schedule.
    (6) For units and processes that operate continuously with 
infrequent outages, it may not be possible to meet the April 1, 2010 
deadline for the initial calibration of a flow meter or other 
measurement device without disrupting normal process operation. In such 
cases, the owner or operator may postpone the initial calibration until 
the next scheduled maintenance outage. The best available information 
from company records may be used in the interim. The subsequent required 
recalibrations of the flow meters may be similarly postponed. Such 
postponements shall be documented in the monitoring plan that is 
required under paragraph (g)(5) of this section.
    (7) If the results of an initial calibration or a recalibration fail 
to meet the required accuracy specification, data from the flow meter 
shall be considered invalid, beginning with the hour of the failed 
calibration and continuing until a successful calibration is completed. 
You shall follow the missing data provisions provided in the relevant 
missing data sections during the period of data invalidation.
    (j) Measurement device installation--(1) General. If an owner or 
operator required to report under subpart P, subpart X or subpart Y of 
this part has process equipment or units that operate continuously and 
it is not possible to install a required flow meter or other measurement 
device by April 1, 2010, (or by any later date in 2010 approved by the 
Administrator as part of an extension of best available monitoring 
methods per paragraph (d) of this section) without process equipment or 
unit shutdown, or through a hot tap, the owner or operator may request 
an extension from the Administrator to delay installing the measurement 
device until the next scheduled process equipment or unit shutdown. If 
approval for such an extension is granted by the Administrator, the 
owner or operator must use best available monitoring methods during the 
extension period.
    (2) Requests for extension of the use of best available monitoring 
methods for measurement device installation. The owner or operator must 
first provide the Administrator an initial notification of the intent to 
submit an extension request for use of best available monitoring methods 
beyond December 31, 2010 (or an earlier date approved by EPA) in cases 
where measurement device installation would require a process equipment 
or unit shutdown, or could only be done through a hot tap. The owner or 
operator must follow-up this initial notification with the complete 
extension request containing the information specified in paragraph 
(j)(4) of this section.
    (3) Timing of request. (i) The initial notice of intent must be 
submitted no later than January 1, 2011, or by the

[[Page 562]]

end of the approved use of best available monitoring methods extension 
in 2010, whichever is earlier. The completed extension request must be 
submitted to the Administrator no later than February 15, 2011.
    (ii) Any subsequent extensions to the original request must be 
submitted to the Administrator within 4 weeks of the owner or operator 
identifying the need to extend the request, but in any event no later 
than 4 weeks before the date for the planned process equipment or unit 
shutdown that was provided in the original or most recently approved 
request.
    (4) Content of the request. Requests must contain the following 
information:
    (i) Specific measurement device for which the request is being made 
and the location where each measurement device will be installed.
    (ii) Identification of the specific rule requirements (by rule 
subpart, section, and paragraph numbers) requiring the measurement 
device.
    (iii) A description of the reasons why the needed equipment could 
not be installed before April 1, 2010, or by the expiration date for the 
use of best available monitoring methods, in cases where an extension 
has been granted under Sec. 98.3(d).
    (iv) Supporting documentation showing that it is not practicable to 
isolate the process equipment or unit and install the measurement device 
without a full shutdown or a hot tap, and that there was no opportunity 
during 2010 to install the device. Include the date of the three most 
recent shutdowns for each relevant process equipment or unit, the 
frequency of shutdowns for each relevant process equipment or unit, and 
the date of the next planned process equipment or unit shutdown.
    (v) Include a description of the proposed best available monitoring 
method for estimating GHG emissions during the time prior to 
installation of the meter.
    (5) Approval criteria. The owner or operator must demonstrate to the 
Administrator's satisfaction that it is not reasonably feasible to 
install the measurement device before April 1, 2010 (or by the 
expiration date for the use of best available monitoring methods, in 
cases where an extension has been granted under paragraph (d) of this 
section) without a process equipment or unit shutdown, or through a hot 
tap, and that the proposed method for estimating GHG emissions during 
the time before which the measurement device will be installed is 
appropriate. The Administrator will not initially approve the use of the 
proposed best available monitoring method past December 31, 2013.
    (6) Measurement device installation deadline. Any owner or operator 
that submits both a timely initial notice of intent and a timely 
completed extension request under paragraph (j)(3) of this section to 
extend use of best available monitoring methods for measurement device 
installation must install all such devices by July 1, 2011 unless the 
extension request under this paragraph (j) is approved by the 
Administrator before July 1, 2011.
    (7) One time extension past December 31, 2013. If an owner or 
operator determines that a scheduled process equipment or unit shutdown 
will not occur by December 31, 2013, the owner or operator may re-apply 
to use best available monitoring methods for one additional time period, 
not to extend beyond December 31, 2015. To extend use of best available 
monitoring methods past December 31, 2013, the owner or operator must 
submit a new extension request by June 1, 2013 that contains the 
information required in paragraph (j)(4) of this section. The owner or 
operator must demonstrate to the Administrator's satisfaction that it 
continues to not be reasonably feasible to install the measurement 
device before December 31, 2013 without a process equipment or unit 
shutdown, or that installation of the measurement device could only be 
done through a hot tap, and that the proposed method for estimating GHG 
emissions during the time before which the measurement device will be 
installed is appropriate. An owner or operator that submits a request 
under this paragraph to extend use of best available monitoring methods 
for measurement device installation must install all such devices by 
December 31, 2013, unless the extension request under this paragraph is 
approved by the Administrator.

[[Page 563]]

    (k) Revised global warming potentials and special provisions for 
reporting year 2013 and subsequent reporting years. This paragraph (k) 
applies to owners or operators of facilities or suppliers that first 
become subject to any subpart of part 98 solely due to an amendment to 
Table A-1 of this subpart.
    (1) A facility or supplier that first becomes subject to part 98 due 
to a change in the GWP for one or more compounds in Table A-1 of this 
subpart, Global Warming Potentials, is not required to submit an annual 
GHG report for the reporting year during which the change in GWPs is 
published.
    (2) A facility or supplier that was already subject to one or more 
subparts of part 98 but becomes subject to one or more additional 
subparts due to a change in the GWP for one or more compounds in Table 
A-1 of this subpart, is not required to include those subparts to which 
the facility is subject only due to the change in the GWP in the annual 
GHG report submitted for the reporting year during which the change in 
GWPs is published.
    (3) Starting on January 1 of the year after the year during which 
the change in GWPs is published, facilities or suppliers identified in 
paragraphs (k)(1) or (2) of this section must start monitoring and 
collecting GHG data in compliance with the applicable subparts of part 
98 to which the facility is subject due to the change in the GWP for the 
annual greenhouse gas report for that reporting year, which is due by 
March 31 of the following calendar year.
    (4) A change in the GWP for one or more compounds includes the 
addition to Table A-1 of this subpart of either a chemical-specific or a 
default GWP that applies to a compound to which no chemical-specific GWP 
in Table A-1 of this subpart previously applied.
    (l) Special provision for best available monitoring methods in 2014 
and subsequent years. This paragraph (l) applies to owners or operators 
of facilities or suppliers that first become subject to any subpart of 
part 98 due to an amendment to Table A-1 of this subpart, Global Warming 
Potentials.
    (1) Best available monitoring methods. From January 1 to March 31 of 
the year after the year during which the change in GWPs is published, 
owners or operators subject to this paragraph (l) may use best available 
monitoring methods for any parameter (e.g., fuel use, feedstock rates) 
that cannot reasonably be measured according to the monitoring and QA/QC 
requirements of a relevant subpart. The owner or operator must use the 
calculation methodologies and equations in the ``Calculating GHG 
Emissions'' sections of each relevant subpart, but may use the best 
available monitoring method for any parameter for which it is not 
reasonably feasible to acquire, install, and operate a required piece of 
monitoring equipment by January 1 of the year after the year during 
which the change in GWPs is published. Starting no later than April 1 of 
the year after the year during which the change in GWPs is published, 
the owner or operator must discontinue using best available methods and 
begin following all applicable monitoring and QA/QC requirements of this 
part, except as provided in paragraph (l)(2) of this section. Best 
available monitoring methods means any of the following methods:
    (i) Monitoring methods currently used by the facility that do not 
meet the specifications of a relevant subpart.
    (ii) Supplier data.
    (iii) Engineering calculations.
    (iv) Other company records.
    (2) Requests for extension of the use of best available monitoring 
methods. The owner or operator may submit a request to the Administrator 
to use one or more best available monitoring methods beyond March 31 of 
the year after the year during which the change in GWPs is published.
    (i) Timing of request. The extension request must be submitted to 
EPA no later than January 31 of the year after the year during which the 
change in GWPs is published.
    (ii) Content of request. Requests must contain the following 
information:
    (A) A list of specific items of monitoring instrumentation for which 
the request is being made and the locations where each piece of 
monitoring instrumentation will be installed.
    (B) Identification of the specific rule requirements (by rule 
subpart, section, and paragraph numbers) for which the instrumentation 
is needed.

[[Page 564]]

    (C) A description of the reasons that the needed equipment could not 
be obtained and installed before April 1 of the year after the year 
during which the change in GWPs is published.
    (D) If the reason for the extension is that the equipment cannot be 
purchased and delivered by April 1 of the year after the year during 
which the change in GWPs is published, include supporting documentation 
such as the date the monitoring equipment was ordered, investigation of 
alternative suppliers and the dates by which alternative vendors 
promised delivery, backorder notices or unexpected delays, descriptions 
of actions taken to expedite delivery, and the current expected date of 
delivery.
    (E) If the reason for the extension is that the equipment cannot be 
installed without a process unit shutdown, include supporting 
documentation demonstrating that it is not practicable to isolate the 
equipment and install the monitoring instrument without a full process 
unit shutdown. Include the date of the most recent process unit 
shutdown, the frequency of shutdowns for this process unit, and the date 
of the next planned shutdown during which the monitoring equipment can 
be installed. If there has been a shutdown or if there is a planned 
process unit shutdown between November 29 of the year during which the 
change in GWPs is published and April 1 of the year after the year 
during which the change in GWPs is published, include a justification of 
why the equipment could not be obtained and installed during that 
shutdown.
    (F) A description of the specific actions the facility will take to 
obtain and install the equipment as soon as reasonably feasible and the 
expected date by which the equipment will be installed and operating.
    (iii) Approval criteria. To obtain approval, the owner or operator 
must demonstrate to the Administrator's satisfaction that it is not 
reasonably feasible to acquire, install, and operate a required piece of 
monitoring equipment by April 1 of the year after the year during which 
the change in GWPs is published. The use of best available methods under 
this paragraph (l) will not be approved beyond December 31 of the year 
after the year during which the change in GWPs is published.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 39758, July 12, 2010; 
75 FR 57685, Sept. 22, 2010; 75 FR 74816, Dec. 1, 2010; 75 FR 79134, 
Dec. 17, 2010; 75 FR 81344, Dec. 27, 2010; 76 FR 14818, Mar. 18, 2011; 
76 FR 53065, Aug. 25, 2011; 76 FR 73899, Nov. 29, 2011; 77 FR 51488, 
Aug. 24, 2012; 78 FR 71946, Nov. 29, 2013; 79 FR 63779, Oct. 24, 2014; 
79 FR 73777, Dec. 11, 2014; 79 FR 77391, Dec. 24, 2014]



Sec. 98.4  Authorization and responsibilities of the designated
representative.

    (a) General. Except as provided under paragraph (f) of this section, 
each facility, and each supplier, that is subject to this part, shall 
have one and only one designated representative, who shall be 
responsible for certifying, signing, and submitting GHG emissions 
reports and any other submissions for such facility and supplier 
respectively to the Administrator under this part. If the facility is 
required under any other part of title 40 of the Code of Federal 
Regulations to submit to the Administrator any other emission report 
that is subject to any requirement in 40 CFR part 75, the same 
individual shall be the designated representative responsible for 
certifying, signing, and submitting the GHG emissions reports and all 
such other emissions reports under this part.
    (b) Authorization of a designated representative. The designated 
representative of the facility or supplier shall be an individual 
selected by an agreement binding on the owners and operators of such 
facility or supplier and shall act in accordance with the certification 
statement in paragraph (i)(4)(iv) of this section.
    (c) Responsibility of the designated representative. Upon receipt by 
the Administrator of a complete certificate of representation under this 
section for a facility or supplier, the designated representative 
identified in such certificate of representation shall represent and, by 
his or her representations, actions, inactions, or submissions, legally 
bind each owner and operator of such facility or supplier in all matters 
pertaining to this part, notwithstanding any agreement between the 
designated representative and such owners and operators. The owners and

[[Page 565]]

operators shall be bound by any decision or order issued to the 
designated representative by the Administrator or a court.
    (d) Timing. No GHG emissions report or other submissions under this 
part for a facility or supplier will be accepted until the Administrator 
has received a complete certificate of representation under this section 
for a designated representative of the facility or supplier. Such 
certificate of representation shall be submitted at least 60 days before 
the deadline for submission of the facility's or supplier's initial 
emission report under this part.
    (e) Certification of the GHG emissions report. Each GHG emission 
report and any other submission under this part for a facility or 
supplier shall be certified, signed, and submitted by the designated 
representative or any alternate designated representative of the 
facility or supplier in accordance with this section and Sec. 3.10 of 
this chapter.
    (1) Each such submission shall include the following certification 
statement signed by the designated representative or any alternate 
designated representative: ``I am authorized to make this submission on 
behalf of the owners and operators of the facility or supplier, as 
applicable, for which the submission is made. I certify under penalty of 
law that I have personally examined, and am familiar with, the 
statements and information submitted in this document and all its 
attachments. Based on my inquiry of those individuals with primary 
responsibility for obtaining the information, I certify that the 
statements and information are to the best of my knowledge and belief 
true, accurate, and complete. I am aware that there are significant 
penalties for submitting false statements and information or omitting 
required statements and information, including the possibility of fine 
or imprisonment.''
    (2) The Administrator will accept a GHG emission report or other 
submission for a facility or supplier under this part only if the 
submission is certified, signed, and submitted in accordance with this 
section.
    (f) Alternate designated representative. A certificate of 
representation under this section for a facility or supplier may 
designate one alternate designated representative, who shall be an 
individual selected by an agreement binding on the owners and operators, 
and may act on behalf of the designated representative, of such facility 
or supplier. The agreement by which the alternate designated 
representative is selected shall include a procedure for authorizing the 
alternate designated representative to act in lieu of the designated 
representative.
    (1) Upon receipt by the Administrator of a complete certificate of 
representation under this section for a facility or supplier identifying 
an alternate designated representative.
    (i) The alternate designated representative may act on behalf of the 
designated representative for such facility or supplier.
    (ii) Any representation, action, inaction, or submission by the 
alternate designated representative shall be deemed to be a 
representation, action, inaction, or submission by the designated 
representative.
    (2) Except in this section, whenever the term ``designated 
representative'' is used in this part, the term shall be construed to 
include the designated representative or any alternate designated 
representative.
    (g) Changing a designated representative or alternate designated 
representative. The designated representative or alternate designated 
representative identified in a complete certificate of representation 
under this section for a facility or supplier received by the 
Administrator may be changed at any time upon receipt by the 
Administrator of another later signed, complete certificate of 
representation under this section for the facility or supplier. 
Notwithstanding any such change, all representations, actions, 
inactions, and submissions by the previous designated representative or 
the previous alternate designated representative of the facility or 
supplier before the time and date when the Administrator receives such 
later signed certificate of representation shall be binding on the new 
designated representative and the owners and operators of the facility 
or supplier.
    (h) Changes in owners and operators. In the event an owner or 
operator of

[[Page 566]]

the facility or supplier is not included in the list of owners and 
operators in the certificate of representation under this section for 
the facility or supplier, such owner or operator shall be deemed to be 
subject to and bound by the certificate of representation, the 
representations, actions, inactions, and submissions of the designated 
representative and any alternate designated representative of the 
facility or supplier, as if the owner or operator were included in such 
list. Within 90 days after any change in the owners and operators of the 
facility or supplier (including the addition of a new owner or 
operator), the designated representative or any alternate designated 
representative shall submit a certificate of representation that is 
complete under this section except that such list shall be amended to 
reflect the change. If the designated representative or alternate 
designated representative determines at any time that an owner or 
operator of the facility or supplier is not included in such list and 
such exclusion is not the result of a change in the owners and 
operators, the designated representative or any alternate designated 
representative shall submit, within 90 days of making such 
determination, a certificate of representation that is complete under 
this section except that such list shall be amended to include such 
owner or operator.
    (i) Certificate of representation. A certificate of representation 
shall be complete if it includes the following elements in a format 
prescribed by the Administrator in accordance with this section:
    (1) Identification of the facility or supplier for which the 
certificate of representation is submitted.
    (2) The name, organization name (company affiliation-employer), 
address, e-mail address (if any), telephone number, and facsimile 
transmission number (if any) of the designated representative and any 
alternate designated representative.
    (3) A list of the owners and operators of the facility or supplier 
identified in paragraph (i)(1) of this section, provided that, if the 
list includes the operators of the facility or supplier and the owners 
with control of the facility or supplier, the failure to include any 
other owners shall not make the certificate of representation 
incomplete.
    (4) The following certification statements by the designated 
representative and any alternate designated representative:
    (i) ``I certify that I was selected as the designated representative 
or alternate designated representative, as applicable, by an agreement 
binding on the owners and operators of the facility or supplier, as 
applicable.''
    (ii) ``I certify that I have all the necessary authority to carry 
out my duties and responsibilities under 40 CFR part 98 on behalf of the 
owners and operators of the facility or supplier, as applicable, and 
that each such owner and operator shall be fully bound by my 
representations, actions, inactions, or submissions.''
    (iii) ``I certify that the owners and operators of the facility or 
supplier, as applicable, shall be bound by any order issued to me by the 
Administrator or a court regarding the facility or supplier.''
    (iv) ``If there are multiple owners and operators of the facility or 
supplier, as applicable, I certify that I have given a written notice of 
my selection as the `designated representative' or `alternate designated 
representative', as applicable, and of the agreement by which I was 
selected to each owner and operator of the facility or supplier.''
    (5) The signature of the designated representative and any alternate 
designated representative and the dates signed.
    (j) Documents of agreement. Unless otherwise required by the 
Administrator, documents of agreement referred to in the certificate of 
representation shall not be submitted to the Administrator. The 
Administrator shall not be under any obligation to review or evaluate 
the sufficiency of such documents, if submitted.
    (k) Binding nature of the certificate of representation. Once a 
complete certificate of representation under this section for a facility 
or supplier has been received, the Administrator will rely on the 
certificate of representation unless and until a later signed, complete 
certificate of representation under this

[[Page 567]]

section for the facility or supplier is received by the Administrator.
    (l) Objections concerning a designated representative. (1) Except as 
provided in paragraph (g) of this section, no objection or other 
communication submitted to the Administrator concerning the 
authorization, or any representation, action, inaction, or submission, 
of the designated representative or alternate designated representative 
shall affect any representation, action, inaction, or submission of the 
designated representative or alternate designated representative, or the 
finality of any decision or order by the Administrator under this part.
    (2) The Administrator will not adjudicate any private legal dispute 
concerning the authorization or any representation, action, inaction, or 
submission of any designated representative or alternate designated 
representative.
    (m) Delegation by designated representative and alternate designated 
representative. (1) A designated representative or an alternate 
designated representative may delegate his or her own authority, to one 
or more individuals, to submit an electronic submission to the 
Administrator provided for or required under this part, except for a 
submission under this paragraph.
    (2) In order to delegate his or her own authority, to one or more 
individuals, to submit an electronic submission to the Administrator in 
accordance with paragraph (m)(1) of this section, the designated 
representative or alternate designated representative must submit 
electronically to the Administrator a notice of delegation, in a format 
prescribed by the Administrator, that includes the following elements:
    (i) The name, organization name (company affiliation-employer) 
address, e-mail address (if any), telephone number, and facsimile 
transmission number (if any) of such designated representative or 
alternate designated representative.
    (ii) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of each such individual (referred 
to as an ``agent'').
    (iii) For each such individual, a list of the type or types of 
electronic submissions under paragraph (m)(1) of this section for which 
authority is delegated to him or her.
    (iv) For each type of electronic submission listed in accordance 
with paragraph (m)(2)(iii) of this section, the facility or supplier for 
which the electronic submission may be made.
    (v) The following certification statements by such designated 
representative or alternate designated representative:
    (A) ``I agree that any electronic submission to the Administrator 
that is by an agent identified in this notice of delegation and of a 
type listed, and for a facility or supplier designated, for such agent 
in this notice of delegation and that is made when I am a designated 
representative or alternate designated representative, as applicable, 
and before this notice of delegation is superseded by another notice of 
delegation under Sec. 98.4(m)(3) shall be deemed to be an electronic 
submission certified, signed, and submitted by me.''
    (B) ``Until this notice of delegation is superseded by a later 
signed notice of delegation under Sec. 98.4(m)(3), I agree to maintain 
an e-mail account and to notify the Administrator immediately of any 
change in my e-mail address unless all delegation of authority by me 
under Sec. 98.4(m) is terminated.''
    (vi) The signature of such designated representative or alternate 
designated representative and the date signed.
    (3) A notice of delegation submitted in accordance with paragraph 
(m)(2) of this section shall be effective, with regard to the designated 
representative or alternate designated representative identified in such 
notice, upon receipt of such notice by the Administrator and until 
receipt by the Administrator of another such notice that was signed 
later by such designated representative or alternate designated 
representative, as applicable. The later signed notice of delegation may 
replace any previously identified agent, add a new agent, or eliminate 
entirely any delegation of authority.
    (4) Any electronic submission covered by the certification in 
paragraph (m)(2)(v)(A) of this section and made in accordance with a 
notice of delegation effective under paragraph (m)(3) of this

[[Page 568]]

section shall be deemed to be an electronic submission certified, 
signed, and submitted by the designated representative or alternate 
designated representative submitting such notice of delegation.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79137, Dec. 17, 2010; 
76 FR 73900, Nov. 29, 2011]



Sec. 98.5  How is the report submitted?

    (a) Each GHG report and certificate of representation for a facility 
or supplier must be submitted electronically in accordance with the 
requirements of Sec. 98.4 and in a format specified by the 
Administrator.
    (b) For reporting year 2014 and thereafter, unless a later year is 
specified in the applicable recordkeeping section, you must enter into 
verification software specified by the Administrator the data specified 
in the verification software records provision in each applicable 
recordkeeping section. For each data element entered into the 
verification software, if the software produces a warning message for 
the data value and you elect not to revise the data value, you may 
provide an explanation in the verification software of why the data 
value is not being revised.

[79 FR 63780, Oct. 24, 2014, as amended at 79 FR 73778, Dec. 11, 2014]



Sec. 98.6  Definitions.

    All terms used in this part shall have the same meaning given in the 
Clean Air Act and in this section.
    Absorbent circulation pump means a pump commonly powered by natural 
gas pressure that circulates the absorbent liquid between the absorbent 
regenerator and natural gas contactor.
    Accuracy of a measurement at a specified level (e.g., one percent of 
full scale or one percent of the value measured) means that the mean of 
repeat measurements made by a device or technique are within 95 percent 
of the range bounded by the true value plus or minus the specified 
level.
    Acid Rain Program means the program established under title IV of 
the Clean Air Act, and implemented under parts 72 through 78 of this 
chapter for the reduction of sulfur dioxide and nitrogen oxides 
emissions.
    Administrator means the Administrator of the United States 
Environmental Protection Agency or the Administrator's authorized 
representative.
    AGA means the American Gas Association
    Agricultural by-products means those parts of arable crops that are 
not used for the primary purpose of producing food. Agricultural by-
products include, but are not limited to, oat, corn and wheat straws, 
bagasse, peanut shells, rice and coconut husks, soybean hulls, palm 
kernel cake, cottonseed and sunflower seed cake, and pomace.
    Air injected flare means a flare in which air is blown into the base 
of a flare stack to induce complete combustion of gas.
    Alkali bypass means a duct between the feed end of the kiln and the 
preheater tower through which a portion of the kiln exit gas stream is 
withdrawn and quickly cooled by air or water to avoid excessive buildup 
of alkali, chloride and/or sulfur on the raw feed. This may also be 
referred to as the ``kiln exhaust gas bypass.''
    Anaerobic digester means the system where wastes are collected and 
anaerobically digested in large containment vessels or covered lagoons. 
Anaerobic digesters stabilize waste by the microbial reduction of 
complex organic compounds to CO2 and CH4, which is captured and may be 
flared or used as fuel. Anaerobic digestion systems, include but are not 
limited to covered lagoon, complete mix, plug flow, and fixed film 
digesters.
    Anaerobic lagoon, with respect to subpart JJ of this part, means a 
type of liquid storage system component that is designed and operated to 
stabilize wastes using anaerobic microbial processes. Anaerobic lagoons 
may be designed for combined stabilization and storage with varying 
lengths of retention time (up to a year or greater), depending on the 
climate region, volatile solids loading rate, and other operational 
factors.
    Anode effect is a process upset condition of an aluminum 
electrolysis cell caused by too little alumina dissolved

[[Page 569]]

in the electrolyte. The anode effect begins when the voltage rises 
rapidly and exceeds a threshold voltage, typically 8 volts.
    Anode Effect Minutes per Cell Day (24 hours) are the total minutes 
during which an electrolysis cell voltage is above the threshold 
voltage, typically 8 volts.
    ANSI means the American National Standards Institute.
    API means the American Petroleum Institute.
    ASABE means the American Society of Agricultural and Biological 
Engineers.
    ASME means the American Society of Mechanical Engineers.
    ASTM means the American Society of Testing and Materials.
    Asphalt means a dark brown-to-black cement-like material obtained by 
petroleum processing and containing bitumens as the predominant 
component. It includes crude asphalt as well as the following finished 
products: cements, fluxes, the asphalt content of emulsions (exclusive 
of water), and petroleum distillates blended with asphalt to make 
cutback asphalts.
    Aviation Gasoline means a complex mixture of volatile hydrocarbons, 
with or without additives, suitably blended to be used in aviation 
reciprocating engines. Specifications can be found in ASTM Specification 
D910-07a, Standard Specification for Aviation Gasolines (incorporated by 
reference, see Sec. 98.7).
    B0 means the maximum CH4 producing capacity of 
a waste stream, kg CH4/kg COD.
    Basic oxygen furnace means any refractory-lined vessel in which 
high-purity oxygen is blown under pressure through a bath of molten 
iron, scrap metal, and fluxes to produce steel.
    bbl means barrel.
    Biodiesel means a mono-akyl ester derived from biomass and 
conforming to ASTM D6751-08, Standard Specification for Biodiesel Fuel 
Blend Stock (B100) for Middle Distillate Fuels.
    Biogenic CO2 means carbon dioxide emissions generated as 
the result of biomass combustion from combustion units for which 
emission calculations are required by an applicable part 98 subpart.
    Biomass means non-fossilized and biodegradable organic material 
originating from plants, animals or micro-organisms, including products, 
by-products, residues and waste from agriculture, forestry and related 
industries as well as the non-fossilized and biodegradable organic 
fractions of industrial and municipal wastes, including gases and 
liquids recovered from the decomposition of non-fossilized and 
biodegradable organic material.
    Blast furnace means a furnace that is located at an integrated iron 
and steel plant and is used for the production of molten iron from iron 
ore pellets and other iron bearing materials.
    Blendstocks are petroleum products used for blending or compounding 
into finished motor gasoline. These include RBOB (reformulated 
blendstock for oxygenate blending) and CBOB (conventional blendstock for 
oxygenate blending), but exclude oxygenates, butane, and pentanes plus.
    Blendstocks--Others are products used for blending or compounding 
into finished motor gasoline that are not defined elsewhere. Excludes 
Gasoline Treated as Blendstock (GTAB), Diesel Treated as Blendstock 
(DTAB), conventional blendstock for oxygenate blending (CBOB), 
reformulated blendstock for oxygenate blending (RBOB), oxygenates (e.g. 
fuel ethanol and methyl tertiary butyl ether), butane, and pentanes 
plus.
    Blowdown mean the act of emptying or depressuring a vessel. This may 
also refer to the discarded material such as blowdown water from a 
boiler or cooling tower.
    Blowdown vent stack emissions mean natural gas and/or CO2 
released due to maintenance and/or blowdown operations including 
compressor blowdown and emergency shut-down (ESD) system testing.
    British Thermal Unit or Btu means the quantity of heat required to 
raise the temperature of one pound of water by one degree Fahrenheit at 
about 39.2 degrees Fahrenheit.
    Bulk, with respect to industrial GHG suppliers and CO2 suppliers, 
means the transfer of a product inside containers, including but not 
limited to tanks, cylinders, drums, and pressure vessels.

[[Page 570]]

    Bulk natural gas liquid or NGL refers to mixtures of hydrocarbons 
that have been separated from natural gas as liquids through the process 
of absorption, condensation, adsorption, or other methods. Generally, 
such liquids consist of ethane, propane, butanes, and pentanes plus. 
Bulk NGL is sold to fractionators or to refineries and petrochemical 
plants where the fractionation takes place.
    Butane, or n-Butane, is a paraffinic straight-chain hydrocarbon with 
molecular formula C4H10.
    Butylene, or n-Butylene, is an olefinic straight-chain hydrocarbon 
with molecular formula C4H8.
    By-product coke oven battery means a group of ovens connected by 
common walls, where coal undergoes destructive distillation under 
positive pressure to produce coke and coke oven gas from which by-
products are recovered.
    Calcination means the process of thermally treating minerals to 
decompose carbonates from ore.
    Calculation methodology means a methodology prescribed under the 
section ``Calculating GHG Emissions'' in any subpart of part 98.
    Calibrated bag means a flexible, non-elastic, anti-static bag of a 
calibrated volume that can be affixed to an emitting source such that 
the emissions inflate the bag to its calibrated volume.
    Carbon dioxide equivalent or CO2e means the number of 
metric tons of CO2 emissions with the same global warming 
potential as one metric ton of another greenhouse gas, and is calculated 
using Equation A-1 of this subpart.
    Carbon dioxide production well means any hole drilled in the earth 
for the primary purpose of extracting carbon dioxide from a geologic 
formation or group of formations which contain deposits of carbon 
dioxide.
    Carbon dioxide production well facility means one or more carbon 
dioxide production wells that are located on one or more contiguous or 
adjacent properties, which are under the control of the same entity. 
Carbon dioxide production wells located on different oil and gas leases, 
mineral fee tracts, lease tracts, subsurface or surface unit areas, 
surface fee tracts, surface lease tracts, or separate surface sites, 
whether or not connected by a road, waterway, power line, or pipeline, 
shall be considered part of the same CO2 production well 
facility if they otherwise meet the definition.
    Carbon dioxide stream means carbon dioxide that has been captured 
from an emission source (e.g. a power plant or other industrial 
facility) or extracted from a carbon dioxide production well plus 
incidental associated substances either derived from the source 
materials and the capture process or extracted with the carbon dioxide.
    Carbon share means the percent of total mass that carbon represents 
in any product.
    Carbonate means compounds containing the radical 
CO3-2. Upon calcination, the carbonate radical 
decomposes to evolve carbon dioxide (CO2). Common carbonates 
consumed in the mineral industry include calcium carbonate 
(CaCO3) or calcite; magnesium carbonate (MgCO3) or 
magnesite; and calcium-magnesium carbonate 
(CaMg(CO3)2) or dolomite.
    Carbonate-based mineral means any of the following minerals used in 
the manufacture of glass: Calcium carbonate (CaCO3), calcium 
magnesium carbonate (CaMg(CO3)2), sodium carbonate 
(Na2CO3), barium carbonate (BaCO3), 
potassium carbonate (K2CO3), lithium carbonate 
(Li2CO3), and strontium carbonate 
(SrCO3).
    Carbonate-based mineral mass fraction means the following: For 
limestone, the mass fraction of calcium carbonate (CaCO3) in 
the limestone; for dolomite, the mass fraction of calcium magnesium 
carbonate (CaMg(CO3)2) in the dolomite; for soda 
ash, the mass fraction of sodium carbonate 
(Na2CO3) in the soda ash; for barium carbonate, 
the mass fraction of barium carbonate (BaCO3) in the barium 
carbonate; for potassium carbonate, the mass fraction of potassium 
carbonate (K2CO3) in the potassium carbonate; for 
lithium carbonate, the mass fraction of lithium carbonate 
(Li2CO3); and for strontium carbonate, the mass 
fraction of strontium carbonate (SrCO3).
    Carbonate-based raw material means any of the following materials 
used in the manufacture of glass: Limestone, dolomite, soda ash, barium 
carbonate,

[[Page 571]]

potassium carbonate, lithium carbonate, and strontium carbonate.
    Carbonofluoridates means fluorinated GHGs that are composed of a -
OCF(O) group (carbonyl group with a single-bonded oxygen atom and a 
fluorine atom) that is linked on the single-bonded oxygen to another 
hydrocarbon group in which one or more of the hydrogen atoms may be 
replaced by fluorine atoms.
    Catalytic cracking unit means a refinery process unit in which 
petroleum derivatives are continuously charged and hydrocarbon molecules 
in the presence of a catalyst are fractured into smaller molecules, or 
react with a contact material suspended in a fluidized bed to improve 
feedstock quality for additional processing and the catalyst or contact 
material is continuously regenerated by burning off coke and other 
deposits. Catalytic cracking units include both fluidized bed systems, 
which are referred to as fluid catalytic cracking units (FCCU), and 
moving bed systems, which are also referred to as thermal catalytic 
cracking units. The unit includes the riser, reactor, regenerator, air 
blowers, spent catalyst or contact material stripper, catalyst or 
contact material recovery equipment, and regenerator equipment for 
controlling air pollutant emissions and for heat recovery.
    CBOB-Summer (conventional blendstock for oxygenate blending) means a 
petroleum product which, when blended with a specified type and 
percentage of oxygenate, meets the definition of Conventional-Summer.
    CBOB-Winter (conventional blendstock for oxygenate blending) means a 
petroleum product which, when blended with a specified type and 
percentage of oxygenate, meets the definition of Conventional-Winter.
    Cement kiln dust means non-calcined to fully calcined dust produced 
in the kiln or pyroprocessing line. Cement kiln dust is a fine-grained, 
solid, highly alkaline material removed from the cement kiln exhaust gas 
by scrubbers (filtration baghouses and/or electrostatic precipitators).
    Centrifugal compressor means any equipment that increases the 
pressure of a process natural gas or CO2 by centrifugal 
action, employing rotating movement of the driven shaft.
    Centrifugal compressor dry seal emissions mean natural gas or 
CO2 released from a dry seal vent pipe and/or the seal face 
around the rotating shaft where it exits one or both ends of the 
compressor case.
    Centrifugal compressor dry seals mean a series of rings around the 
compressor shaft where it exits the compressor case that operates 
mechanically under the opposing forces to prevent natural gas or 
CO2 from escaping to the atmosphere.
    Centrifugal compressor wet seal degassing vent emissions means 
emissions that occur when the high-pressure oil barriers for centrifugal 
compressors are depressurized to release absorbed natural gas or 
CO2. High-pressure oil is used as a barrier against escaping 
gas in centrifugal compressor shafts. Very little gas escapes through 
the oil barrier, but under high pressure, considerably more gas is 
absorbed by the oil. The seal oil is purged of the absorbed gas (using 
heaters, flash tanks, and degassing techniques) and recirculated. The 
separated gas is commonly vented to the atmosphere.
    Certified standards means calibration gases certified by the 
manufacturer of the calibration gases to be accurate to within 2 percent 
of the value on the label or calibration gases.
    CH4 means methane.
    Chemical recovery combustion unit means a combustion device, such as 
a recovery furnace or fluidized-bed reactor where spent pulping liquor 
from sulfite or semi-chemical pulping processes is burned to recover 
pulping chemicals.
    Chemical recovery furnace means an enclosed combustion device where 
concentrated spent liquor produced by the kraft or soda pulping process 
is burned to recover pulping chemicals and produce steam. Includes any 
recovery furnace that burns spent pulping liquor produced from both the 
kraft and soda pulping processes.
    Chloride process means a production process where titanium dioxide 
is produced using calcined petroleum coke and chlorine as raw materials.
    City gate means a location at which natural gas ownership or control 
passes

[[Page 572]]

from one party to another, neither of which is the ultimate consumer. In 
this rule, in keeping with common practice, the term refers to a point 
or measuring station at which a local gas distribution utility receives 
gas from a natural gas pipeline company or transmission system. Meters 
at the city gate station measure the flow of natural gas into the local 
distribution company system and typically are used to measure local 
distribution company system sendout to customers.
    CO2 means carbon dioxide.
    Coal means all solid fuels classified as anthracite, bituminous, 
sub-bituminous, or lignite by the American Society for Testing and 
Materials Designation ASTM D388-05 Standard Classification of Coals by 
Rank (incorporated by reference, see Sec. 98.7).
    COD means the chemical oxygen demand as determined using methods 
specified pursuant to 40 CFR part 136.
    Cogeneration unit means a unit that produces electrical energy and 
useful thermal energy for industrial, commercial, or heating or cooling 
purposes, through the sequential or simultaneous use of the original 
fuel energy.
    Coke burn-off means the coke removed from the surface of a catalyst 
by combustion during catalyst regeneration. Coke burn-off also means the 
coke combusted in fluid coking unit burner.
    Cokemaking means the production of coke from coal in either a by-
product coke oven battery or a non-recovery coke oven battery.
    Commercial applications means executing a commercial transaction 
subject to a contract. A commercial application includes transferring 
custody of a product from one facility to another if it otherwise meets 
the definition.
    Company records means, in reference to the amount of fuel consumed 
by a stationary combustion unit (or by a group of such units), a 
complete record of the methods used, the measurements made, and the 
calculations performed to quantify fuel usage. Company records may 
include, but are not limited to, direct measurements of fuel consumption 
by gravimetric or volumetric means, tank drop measurements, and 
calculated values of fuel usage obtained by measuring auxiliary 
parameters such as steam generation or unit operating hours. Fuel 
billing records obtained from the fuel supplier qualify as company 
records.
    Connector means to flanged, screwed, or other joined fittings used 
to connect pipe line segments, tubing, pipe components (such as elbows, 
reducers, ``T's'' or valves) or a pipe line and a piece of equipment or 
an instrument to a pipe, tube or piece of equipment. A common connector 
is a flange. Joined fittings welded completely around the circumference 
of the interface are not considered connectors for the purpose of this 
part.
    Container glass means glass made of soda-lime recipe, clear or 
colored, which is pressed and/or blown into bottles, jars, ampoules, and 
other products listed in North American Industry Classification System 
327213 (NAICS 327213).
    Continuous bleed means a continuous flow of pneumatic supply natural 
gas to the process control device (e.g. level control, temperature 
control, pressure control) where the supply gas pressure is modulated by 
the process condition, and then flows to the valve controller where the 
signal is compared with the process set-point to adjust gas pressure in 
the valve actuator.
    Continuous emission monitoring system or CEMS means the total 
equipment required to sample, analyze, measure, and provide, by means of 
readings recorded at least once every 15 minutes, a permanent record of 
gas concentrations, pollutant emission rates, or gas volumetric flow 
rates from stationary sources.
    Continuous glass melting furnace means a glass melting furnace that 
operates continuously except during periods of maintenance, malfunction, 
control device installation, reconstruction, or rebuilding.
    Conventional-Summer refers to finished gasoline formulated for use 
in motor vehicles, the composition and properties of which do not meet 
the requirements of the reformulated gasoline regulations promulgated by 
the U.S. Environmental Protection Agency under 40 CFR 80.40, but which 
meet summer RVP standards required under 40 CFR 80.27 or as specified by 
the state. Note: This category excludes

[[Page 573]]

conventional gasoline for oxygenate blending (CBOB) as well as other 
blendstock.
    Conventional-Winter refers to finished gasoline formulated for use 
in motor vehicles, the composition and properties of which do not meet 
the requirements of the reformulated gasoline regulations promulgated by 
the U.S. Environmental Protection Agency under 40 CFR 80.40 or the 
summer RVP standards required under 40 CFR 80.27 or as specified by the 
state. Note: This category excludes conventional blendstock for 
oxygenate blending (CBOB) as well as other blendstock.
    Crude oil means a mixture of hydrocarbons that exists in liquid 
phase in natural underground reservoirs and remains liquid at 
atmospheric pressure after passing through surface separating 
facilities. (1) Depending upon the characteristics of the crude stream, 
it may also include any of the following:
    (i) Small amounts of hydrocarbons that exist in gaseous phase in 
natural underground reservoirs but are liquid at atmospheric conditions 
(temperature and pressure) after being recovered from oil well (casing-
head) gas in lease separators and are subsequently commingled with the 
crude stream without being separately measured. Lease condensate 
recovered as a liquid from natural gas wells in lease or field 
separation facilities and later mixed into the crude stream is also 
included.
    (ii) Small amounts of non-hydrocarbons, such as sulfur and various 
metals.
    (iii) Drip gases, and liquid hydrocarbons produced from tar sands, 
oil sands, gilsonite, and oil shale.
    (iv) Petroleum products that are received or produced at a refinery 
and subsequently injected into a crude supply or reservoir by the same 
refinery owner or operator.
    (2) Liquids produced at natural gas processing plants are excluded. 
Crude oil is refined to produce a wide array of petroleum products, 
including heating oils; gasoline, diesel and jet fuels; lubricants; 
asphalt; ethane, propane, and butane; and many other products used for 
their energy or chemical content.
    Daily spread means a manure management system component in which 
manure is routinely removed from a confinement facility and is applied 
to cropland or pasture within 24 hours of excretion.
    Day means any consistently designated 24 hour period during which an 
emission unit is operated.
    Decarburization vessel means any vessel used to further refine 
molten steel with the primary intent of reducing the carbon content of 
the steel, including but not limited to vessels used for argon-oxygen 
decarburization and vacuum oxygen decarburization.
    Deep bedding systems for cattle swine means a manure management 
system in which, as manure accumulates, bedding is continually added to 
absorb moisture over a production cycle and possibly for as long as 6 to 
12 months. This manure management system also is known as a bedded pack 
manure management system and may be combined with a dry lot or pasture.
    Degasification system means the entirety of the equipment that is 
used to drain gas from underground coal mines. This includes all 
degasification wells and gob gas vent holes at the underground coal 
mine. Degasification systems include gob and premine surface drainage 
wells, gob and premine in-mine drainage wells, and in-mine gob and 
premine cross-measure borehole wells.
    Degradable organic carbon (DOC) means the fraction of the total mass 
of a waste material that can be biologically degraded.
    Dehydrator means a device in which a liquid absorbent (including 
desiccant, ethylene glycol, diethylene glycol, or triethylene glycol) 
directly contacts a natural gas stream to absorb water vapor.
    Dehydrator vent emissions means natural gas and CO2 
released from a natural gas dehydrator system absorbent (typically 
glycol) reboiler or regenerator to the atmosphere or a flare, including 
stripping natural gas and motive natural gas used in absorbent 
circulation pumps.
    Delayed coking unit means one or more refinery process units in 
which high molecular weight petroleum derivatives are thermally cracked 
and petroleum coke is produced in a series of

[[Page 574]]

closed, batch system reactors. A delayed coking unit consists of the 
coke drums and ancillary equipment associated with a single 
fractionator.
    De-methanizer means the natural gas processing unit that separates 
methane rich residue gas from the heavier hydrocarbons (e.g., ethane, 
propane, butane, pentane-plus) in feed natural gas stream.
    Density means the mass contained in a given unit volume (mass/
volume).
    Desiccant means a material used in solid-bed dehydrators to remove 
water from raw natural gas by adsorption or absorption. Desiccants 
include activated alumina, pelletized calcium chloride, lithium chloride 
and granular silica gel material. Wet natural gas is passed through a 
bed of the granular or pelletized solid adsorbent or absorbent in these 
dehydrators. As the wet gas contacts the surface of the particles of 
desiccant material, water is adsorbed on the surface or absorbed and 
dissolves the surface of these desiccant particles. Passing through the 
entire desiccant bed, almost all of the water is adsorbed onto or 
absorbed into the desiccant material, leaving the dry gas to exit the 
contactor.
    Destruction means:
    (1) With respect to landfills and manure management, the combustion 
of methane in any on-site or off-site combustion technology. Destroyed 
methane includes, but is not limited to, methane combusted by flaring, 
methane destroyed by thermal oxidation, methane combusted for use in on-
site energy or heat production technologies, methane that is conveyed 
through pipelines (including natural gas pipelines) for off-site 
combustion, and methane that is collected for any other on-site or off-
site use as a fuel.
    (2) With respect to fluorinated GHGs, the expiration of a 
fluorinated GHG to the destruction efficiency actually achieved. Such 
destruction does not result in a commercially useful end product.
    Destruction device, for the purposes of subparts II and TT of this 
part, means a flare, thermal oxidizer, boiler, turbine, internal 
combustion engine, or any other combustion unit used to destroy or 
oxidize methane contained in landfill gas or wastewater biogas.
    Destruction efficiency means the efficiency with which a destruction 
device reduces the mass of a greenhouse gas fed into the device. 
Destruction efficiency, or flaring destruction efficiency, refers to the 
fraction of the gas that leaves the flare partially or fully oxidized. 
The destruction efficiency is expressed in Equation A-2 of this section:
[GRAPHIC] [TIFF OMITTED] TR01DE10.001

where:

DE = Destruction Efficiency
tGHGiIN = The mass of GHG i fed into the destruction device
tGHGiOUT = The mass of GHG i exhausted from the destruction 
          device

    Diesel--Other is any distillate fuel oil not defined elsewhere, 
including Diesel Treated as Blendstock (DTAB).
    DIPE (diisopropyl ether, 
(CH3)2CHOCH(CH3)2) is an 
ether as described in ``Oxygenates.''
    Direct liquefaction means the conversion of coal directly into 
liquids, rather than passing through an intermediate gaseous state.
    Direct reduction furnace means a high temperature furnace typically 
fired with natural gas to produce solid iron from iron ore or iron ore 
pellets and coke, coal, or other carbonaceous materials.
    Distillate fuel oil means a classification for one of the petroleum 
fractions produced in conventional distillation operations and from 
crackers and hydrotreating process units. The generic term distillate 
fuel oil includes kerosene, kerosene-type jet fuel, diesel fuels (Diesel 
Fuels No. 1, No. 2, and No. 4), and fuel oils (Fuel Oils No. 1, No. 2, 
and No. 4).

[[Page 575]]

    Distillate Fuel No. 1 has a maximum distillation temperature of 550 
deg.F at the 90 percent recovery point and a minimum flash point of 100 
deg.F and includes fuels commonly known as Diesel Fuel No. 1 and Fuel 
Oil No. 1, but excludes kerosene. This fuel is further subdivided into 
categories of sulfur content: High Sulfur (greater than 500 ppm), Low 
Sulfur (less than or equal to 500 ppm and greater than 15 ppm), and 
Ultra Low Sulfur (less than or equal to 15 ppm).
    Distillate Fuel No. 2 has a minimum and maximum distillation 
temperature of 540  deg.F and 640  deg.F at the 90 percent recovery 
point, respectively, and includes fuels commonly known as Diesel Fuel 
No. 2 and Fuel Oil No. 2. This fuel is further subdivided into 
categories of sulfur content: High Sulfur (greater than 500 ppm), Low 
Sulfur (less than or equal to 500 ppm and greater than 15 ppm), and 
Ultra Low Sulfur (less than or equal to 15 ppm).
    Distillate Fuel No. 4 is a distillate fuel oil made by blending 
distillate fuel oil and residual fuel oil, with a minimum flash point of 
131  deg.F.
    DOCf means the fraction of DOC that actually decomposes 
under the (presumably anaerobic) conditions within the landfill.
    Dry lot means a manure management system component consisting of a 
paved or unpaved open confinement area without any significant 
vegetative cover where accumulating manure may be removed periodically.
    Electric arc furnace (EAF) means a furnace that produces molten 
alloy metal and heats the charge materials with electric arcs from 
carbon electrodes.
    Electric arc furnace steelmaking means the production of carbon, 
alloy, or specialty steels using an EAF. This definition excludes EAFs 
at steel foundries and EAFs used to produce nonferrous metals.
    Electrothermic furnace means a furnace that heats the charged 
materials with electric arcs from carbon electrodes.
    Emergency generator means a stationary combustion device, such as a 
reciprocating internal combustion engine or turbine that serves solely 
as a secondary source of mechanical or electrical power whenever the 
primary energy supply is disrupted or discontinued during power outages 
or natural disasters that are beyond the control of the owner or 
operator of a facility. An emergency generator operates only during 
emergency situations, for training of personnel under simulated 
emergency conditions, as part of emergency demand response procedures, 
or for standard performance testing procedures as required by law or by 
the generator manufacturer. A generator that serves as a back-up power 
source under conditions of load shedding, peak shaving, power 
interruptions pursuant to an interruptible power service agreement, or 
scheduled facility maintenance shall not be considered an emergency 
generator.
    Emergency equipment means any auxiliary fossil fuel-powered 
equipment, such as a fire pump, that is used only in emergency 
situations.
    ETBE (ethyl tertiary butyl ether, 
(CH3)3COC2H) is an ether as described 
in ``Oxygenates.''
    Ethane is a paraffinic hydrocarbon with molecular formula 
C2H6.
    Ethanol is an anhydrous alcohol with molecular formula 
C2H5OH.
    Ethylene is an olefinic hydrocarbon with molecular formula 
C2H4.
    Ex refinery gate means the point at which a petroleum product leaves 
the refinery.
    Experimental furnace means a glass melting furnace with the sole 
purpose of operating to evaluate glass melting processes, technologies, 
or glass products. An experimental furnace does not produce glass that 
is sold (except for further research and development purposes) or that 
is used as a raw material for non-experimental furnaces.
    Export means to transport a product from inside the United States to 
persons outside the United States, excluding any such transport on 
behalf of the United States military including foreign military sales 
under the Arms Export Control Act.
    Exporter means any person, company or organization of record that 
transfers for sale or for other benefit, domestic products from the 
United States to another country or to an affiliate in another country, 
excluding any such transfers on behalf of the United States

[[Page 576]]

military or military purposes including foreign military sales under the 
Arms Export Control Act. An exporter is not the entity merely 
transporting the domestic products, rather an exporter is the entity 
deriving the principal benefit from the transaction.
    Facility means any physical property, plant, building, structure, 
source, or stationary equipment located on one or more contiguous or 
adjacent properties in actual physical contact or separated solely by a 
public roadway or other public right-of-way and under common ownership 
or common control, that emits or may emit any greenhouse gas. Operators 
of military installations may classify such installations as more than a 
single facility based on distinct and independent functional groupings 
within contiguous military properties.
    Feed means the prepared and mixed materials, which include but are 
not limited to materials such as limestone, clay, shale, sand, iron ore, 
mill scale, cement kiln dust and flyash, that are fed to the kiln. Feed 
does not include the fuels used in the kiln to produce heat to form the 
clinker product.
    Feedstock means raw material inputs to a process that are 
transformed by reaction, oxidation, or other chemical or physical 
methods into products and by-products. Supplemental fuel burned to 
provide heat or thermal energy is not a feedstock.
    Fischer-Tropsch process means a catalyzed chemical reaction in which 
synthesis gas, a mixture of carbon monoxide and hydrogen, is converted 
into liquid hydrocarbons of various forms.
    Flare means a combustion device, whether at ground level or 
elevated, that uses an open flame to burn combustible gases with 
combustion air provided by uncontrolled ambient air around the flame.
    Flat glass means glass made of soda-lime recipe and produced into 
continuous flat sheets and other products listed in NAICS 327211.
    Flowmeter means a device that measures the mass or volumetric rate 
of flow of a gas, liquid, or solid moving through an open or closed 
conduit (e.g. flowmeters include, but are not limited to, rotameters, 
turbine meters, coriolis meters, orifice meters, ultra-sonic flowmeters, 
and vortex flowmeters).
    Fluid coking unit means one or more refinery process units in which 
high molecular weight petroleum derivatives are thermally cracked and 
petroleum coke is continuously produced in a fluidized bed system. The 
fluid coking unit includes equipment for controlling air pollutant 
emissions and for heat recovery on the fluid coking burner exhaust vent. 
There are two basic types of fluid coking units: A traditional fluid 
coking unit in which only a small portion of the coke produced in the 
unit is burned to fuel the unit and the fluid coking burner exhaust vent 
is directed to the atmosphere (after processing in a CO boiler or other 
air pollutant control equipment) and a flexicoking unit in which an 
auxiliary burner is used to partially combust a significant portion of 
the produced petroleum coke to generate a low value fuel gas that is 
used as fuel in other combustion sources at the refinery.
    Fluorinated acetates means fluorinated GHGs that are composed of an 
acetate group with one or more valence locations on the methyl group of 
the acetate occupied by fluorine atoms (e.g., CFH2C(O)O-, 
CF2HC(O)O-) and, linked to the single-bonded oxygen of the 
acetate group, another hydrocarbon group in which one or more of the 
hydrogen atoms may be replaced by fluorine atoms.
    Fluorinated alcohols other than fluorotelomer alcohols means 
fluorinated GHGs that include an alcohol functional group (-OH) and that 
do not meet the definition of fluorotelomer alcohols.
    Fluorinated formates means fluorinated GHGs that are composed of a 
formate group -OCH(O) (carbonyl group with a single-bonded oxygen, and 
with a hydrogen atom) that is linked on the single-bonded oxygen atom to 
a hydrocarbon group in which one or more of the hydrogen atoms in the 
hydrocarbon group is replaced by fluorine atoms; the typical formula for 
fluorinated formates is FnROCH(O).
    Fluorinated greenhouse gas means sulfur hexafluoride 
(SF6), nitrogen trifluoride (NF3), and any 
fluorocarbon except for controlled substances as defined at 40 CFR part 
82, subpart A and substances with vapor pressures of less than 1 mm of 
Hg absolute at 25 degrees

[[Page 577]]

C. With these exceptions, ``fluorinated GHG'' includes but is not 
limited to any hydrofluorocarbon, any perfluorocarbon, any fully 
fluorinated linear, branched or cyclic alkane, ether, tertiary amine or 
aminoether, any perfluoropolyether, and any hydrofluoropolyether.
    Fluorinated greenhouse gas (GHG) group means one of the following 
sets of fluorinated GHGs: Fully fluorinated GHGs; saturated 
hydrofluorocarbons with 2 or fewer carbon-hydrogen bonds; saturated 
hydrofluorocarbons with 3 or more carbon-hydrogen bonds; saturated 
hydrofluoroethers and hydrochlorofluoroethers with 1 carbon-hydrogen 
bond; saturated hydrofluoroethers and hydrochlorofluoroethers with 2 
carbon-hydrogen bonds; saturated hydrofluoroethers and 
hydrochlorofluoroethers with 3 or more carbon-hydrogen bonds; 
fluorinated formates; fluorinated acetates, carbonofluoridates, and 
fluorinated alcohols other than fluorotelomer alcohols; unsaturated 
PFCs, unsaturated HFCs, unsaturated HCFCs, unsaturated halogenated 
ethers, unsaturated halogenated esters, fluorinated aldehydes, and 
fluorinated ketones; fluorotelomer alcohols; fluorinated GHGs with 
carbon-iodine bonds; or other fluorinated GHGs.
    Fluorotelomer alcohols means fluorinated GHGs with the chemical 
formula CnF2n + 1CH2CH2OH.
    Fossil fuel means natural gas, petroleum, coal, or any form of 
solid, liquid, or gaseous fuel derived from such material, for purpose 
of creating useful heat.
    Fractionators means plants that produce fractionated natural gas 
liquids (NGLs) extracted from produced natural gas and separate the NGLs 
individual component products: ethane, propane, butanes and pentane-plus 
(C5 + ). Plants that only process natural gas but do not fractionate 
NGLs further into component products are not considered fractionators. 
Some fractionators do not process production gas, but instead 
fractionate bulk NGLs received from natural gas processors. Some 
fractionators both process natural gas and fractionate bulk NGLs 
received from other plants.
    Fuel means solid, liquid or gaseous combustible material.
    Fuel gas means gas generated at a petroleum refinery or 
petrochemical plant and that is combusted separately or in any 
combination with any type of gas.
    Fuel gas system means a system of compressors, piping, knock-out 
pots, mix drums, and, if necessary, units used to remove sulfur 
contaminants from the fuel gas (e.g., amine scrubbers) that collects 
fuel gas from one or more sources for treatment, as necessary, and 
transport to a stationary combustion unit. A fuel gas system may have an 
overpressure vent to a flare but the primary purpose for a fuel gas 
system is to provide fuel to the various combustion units at the 
refinery or petrochemical plant.
    Fully fluorinated GHGs means fluorinated GHGs that contain only 
single bonds and in which all available valence locations are filled by 
fluorine atoms. This includes but is not limited to: Saturated 
perfluorocarbons; SF6; NF3; 
SF5CF3; fully fluorinated linear, branched, and 
cyclic alkanes; fully fluorinated ethers; fully fluorinated tertiary 
amines; fully fluorinated aminoethers; and perfluoropolyethers.
    Furnace slag means a by-product formed in metal melting furnaces 
when slagging agents, reducing agents, and/or fluxes (e.g., coke ash, 
limestone, silicates) are added to remove impurities from the molten 
metal.
    Gas collection system or landfill gas collection system means a 
system of pipes used to collect landfill gas from different locations in 
the landfill by means of a fan or similar mechanical draft equipment to 
a single location for treatment (thermal destruction) or use. Landfill 
gas collection systems may also include knock-out or separator drums 
and/or a compressor. A single landfill may have multiple gas collection 
systems. Landfill gas collection systems do not include ``passive'' 
systems, whereby landfill gas flows naturally to the surface of the 
landfill where an opening or pipe (vent) is installed to allow for 
natural gas flow.
    Gas conditions mean the actual temperature, volume, and pressure of 
a gas sample.

[[Page 578]]

    Gas-fired unit means a stationary combustion unit that derives more 
than 50 percent of its annual heat input from the combustion of gaseous 
fuels, and the remainder of its annual heat input from the combustion of 
fuel oil or other liquid fuels.
    Gas monitor means an instrument that continuously measures the 
concentration of a particular gaseous species in the effluent of a 
stationary source.
    Gas to oil ratio (GOR) means the ratio of the volume of gas at 
standard temperature and pressure that is produced from a volume of oil 
when depressurized to standard temperature and pressure.
    Gaseous fuel means a material that is in the gaseous state at 
standard atmospheric temperature and pressure conditions and that is 
combusted to produce heat and/or energy.
    Gasification means the conversion of a solid or liquid raw material 
into a gas.
    Gasoline--Other is any gasoline that is not defined elsewhere, 
including GTAB (gasoline treated as blendstock).
    Glass melting furnace means a unit comprising a refractory-lined 
vessel in which raw materials are charged and melted at high temperature 
to produce molten glass.
    Glass produced means the weight of glass exiting a glass melting 
furnace.
    Global warming potential or GWP means the ratio of the time-
integrated radiative forcing from the instantaneous release of one 
kilogram of a trace substance relative to that of one kilogram of a 
reference gas (i.e., CO2). GWPs for each greenhouse gas are 
provided in Table A-1 of this subpart. For purposes of the calculations 
in this part, if the GHG has a chemical-specific GWP listed in Table A-
1, use that GWP. Otherwise, use the default GWP provided in Table A-1 
for the fluorinated GHG group of which the GHG is a member.
    GPA means the Gas Processors Association.
    Greenhouse gas or GHG means carbon dioxide (CO2), methane 
(CH4), nitrous oxide (N2O), sulfur hexafluoride 
(SF6), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and other 
fluorinated greenhouse gases as defined in this section.
    GTBA (gasoline-grade tertiary butyl alcohol, 
(CH3)3COH), or t-butanol, is an alcohol as 
described in ``Oxygenates.''
    Heavy Gas Oils are petroleum distillates with an approximate boiling 
range from 651  deg.F to 1,000  deg.F.
    Heel means the amount of gas that remains in a shipping container 
after it is discharged or off-loaded (that is no more than ten percent 
of the volume of the container).
    High-bleed pneumatic devices are automated, continuous bleed flow 
control devices powered by pressurized natural gas and used for 
maintaining a process condition such as liquid level, pressure, delta-
pressure and temperature. Part of the gas power stream that is regulated 
by the process condition flows to a valve actuator controller where it 
vents continuously (bleeds) to the atmosphere at a rate in excess of 6 
standard cubic feet per hour.
    High heat value or HHV means the high or gross heat content of the 
fuel with the heat of vaporization included. The water is assumed to be 
in a liquid state.
    Hydrofluorocarbons or HFCs means a class of GHGs consisting of 
hydrogen, fluorine, and carbon.
    Import means, to land on, bring into, or introduce into, any place 
subject to the jurisdiction of the United States whether or not such 
landing, bringing, or introduction constitutes an importation within the 
meaning of the customs laws of the United States, with the following 
exemptions:
    (1) Off-loading used or excess fluorinated GHGs or nitrous oxide of 
U.S. origin from a ship during servicing.
    (2) Bringing fluorinated GHGs or nitrous oxide into the U.S. from 
Mexico where the fluorinated GHGs or nitrous oxide had been admitted 
into Mexico in bond and were of U.S. origin.
    (3) Bringing fluorinated GHGs or nitrous oxide into the U.S. when 
transported in a consignment of personal or household effects or in a 
similar non-commercial situation normally exempted from U.S. Customs 
attention.
    (4) Bringing fluorinated GHGs or nitrous into U.S. jurisdiction 
exclusively for U. S. military purposes.

[[Page 579]]

    Importer means any person, company, or organization of record that 
for any reason brings a product into the United States from a foreign 
country, excluding introduction into U.S. jurisdiction exclusively for 
United States military purposes. An importer is the person, company, or 
organization primarily liable for the payment of any duties on the 
merchandise or an authorized agent acting on their behalf. The term 
includes, as appropriate:
    (1) The consignee.
    (2) The importer of record.
    (3) The actual owner.
    (4) The transferee, if the right to draw merchandise in a bonded 
warehouse has been transferred.
    Indurating furnace means a furnace where unfired taconite pellets, 
called green balls, are hardened at high temperatures to produce fired 
pellets for use in a blast furnace. Types of indurating furnaces include 
straight gate and grate kiln furnaces.
    Industrial greenhouse gases means nitrous oxide or any fluorinated 
greenhouse gas.
    In-line kiln/raw mill means a system in a portland cement production 
process where a dry kiln system is integrated with the raw mill so that 
all or a portion of the kiln exhaust gases are used to perform the 
drying operation of the raw mill, with no auxiliary heat source used. In 
this system the kiln is capable of operating without the raw mill 
operating, but the raw mill cannot operate without the kiln gases, and 
consequently, the raw mill does not generate a separate exhaust gas 
stream.
    Intermittent bleed pneumatic devices mean automated flow control 
devices powered by pressurized natural gas and used for automatically 
maintaining a process condition such as liquid level, pressure, delta-
pressure and temperature. These are snap-acting or throttling devices 
that discharge all or a portion of the full volume of the actuator 
intermittently when control action is necessary, but does not bleed 
continuously.
    Isobutane is a paraffinic branch chain hydrocarbon with molecular 
formula C4H10.
    Isobutylene is an olefinic branch chain hydrocarbon with molecular 
formula C4H8.
    Kerosene is a light petroleum distillate with a maximum distillation 
temperature of 400  deg.F at the 10-percent recovery point, a final 
maximum boiling point of 572  deg.F, a minimum flash point of 100 
deg.F, and a maximum freezing point of -22  deg.F. Included are No. 1-K 
and No. 2-K, distinguished by maximum sulfur content (0.04 and 0.30 
percent of total mass, respectively), as well as all other grades of 
kerosene called range or stove oil. Excluded is kerosene-type jet fuel 
(see definition herein).
    Kerosene-type jet fuel means a kerosene-based product used in 
commercial and military turbojet and turboprop aircraft. The product has 
a maximum distillation temperature of 400  deg.F at the 10 percent 
recovery point and a final maximum boiling point of 572  deg.F. Included 
are Jet A, Jet A-1, JP-5, and JP-8.
    Kiln means an oven, furnace, or heated enclosure used for thermally 
processing a mineral or mineral-based substance.
    Landfill means an area of land or an excavation in which wastes are 
placed for permanent disposal and that is not a land application unit, 
surface impoundment, injection well, or waste pile as those terms are 
defined under 40 CFR 257.2.
    Landfill gas means gas produced as a result of anaerobic 
decomposition of waste materials in the landfill. Landfill gas generally 
contains 40 to 60 percent methane on a dry basis, typically less than 1 
percent non-methane organic chemicals, and the remainder being carbon 
dioxide.
    Liberated means released from coal and surrounding rock strata 
during the mining process. This includes both methane emitted from the 
ventilation system and methane drained from degasification systems.
    Lime is the generic term for a variety of chemical compounds that 
are produced by the calcination of limestone or dolomite. These products 
include but are not limited to calcium oxide, high-calcium quicklime, 
calcium hydroxide, hydrated lime, dolomitic quicklime, and dolomitic 
hydrate.

[[Page 580]]

    Liquid/Slurry means a manure management component in which manure is 
stored as excreted or with some minimal addition of water to facilitate 
handling and is stored in either tanks or earthen ponds, usually for 
periods less than one year.
    Low-bleed pneumatic devices mean automated flow control devices 
powered by pressurized natural gas and used for maintaining a process 
condition such as liquid level, pressure, delta-pressure and 
temperature. Part of the gas power stream that is regulated by the 
process condition flows to a valve actuator controller where it vents 
continuously (bleeds) to the atmosphere at a rate equal to or less than 
six standard cubic feet per hour.
    Lubricants include all grades of lubricating oils, from spindle oil 
to cylinder oil to those used in greases. Petroleum lubricants may be 
produced from distillates or residues.
    Makeup chemicals means carbonate chemicals (e.g., sodium and calcium 
carbonates) that are added to the chemical recovery areas of chemical 
pulp mills to replace chemicals lost in the process.
    Manure composting means the biological oxidation of a solid waste 
including manure usually with bedding or another organic carbon source 
typically at thermophilic temperatures produced by microbial heat 
production. There are four types of composting employed for manure 
management: Static, in vessel, intensive windrow and passive windrow. 
Static composting typically occurs in an enclosed channel, with forced 
aeration and continuous mixing. In vessel composting occurs in piles 
with forced aeration but no mixing. Intensive windrow composting occurs 
in windrows with regular turning for mixing and aeration. Passive 
windrow composting occurs in windrows with infrequent turning for mixing 
and aeration.
    Maximum rated heat input capacity means the hourly heat input to a 
unit (in mmBtu/hr), when it combusts the maximum amount of fuel per hour 
that it is capable of combusting on a steady state basis, as of the 
initial installation of the unit, as specified by the manufacturer.
    Maximum rated input capacity means the maximum charging rate of a 
municipal waste combustor unit expressed in tons per day of municipal 
solid waste combusted, calculated according to the procedures under 40 
CFR 60.58b(j).
    Mcf means thousand cubic feet.
    Methane conversion factor means the extent to which the 
CH4 producing capacity (Bo) is realized in each 
type of treatment and discharge pathway and system. Thus, it is an 
indication of the degree to which the system is anaerobic.
    Methane correction factor means an adjustment factor applied to the 
methane generation rate to account for portions of the landfill that 
remain aerobic. The methane correction factor can be considered the 
fraction of the total landfill waste volume that is ultimately disposed 
of in an anaerobic state. Managed landfills that have soil or other 
cover materials have a methane correction factor of 1.
    Methanol (CH3OH) is an alcohol as described in 
``Oxygenates.''
    Midgrade gasoline has an octane rating greater than or equal to 88 
and less than or equal to 90. This definition applies to the midgrade 
categories of Conventional-Summer, Conventional-Winter, Reformulated-
Summer, and Reformulated-Winter. For midgrade categories of RBOB-Summer, 
RBOB-Winter, CBOB-Summer, and CBOB-Winter, this definition refers to the 
expected octane rating of the finished gasoline after oxygenate has been 
added to the RBOB or CBOB.
    Miscellaneous products include all refined petroleum products not 
defined elsewhere. It includes, but is not limited to, naphtha-type jet 
fuel (Jet B and JP-4), petrolatum lube refining by-products (aromatic 
extracts and tars), absorption oils, ram-jet fuel, petroleum rocket 
fuels, synthetic natural gas feedstocks, waste feedstocks, and specialty 
oils. It excludes organic waste sludges, tank bottoms, spent catalysts, 
and sulfuric acid.
    MMBtu means million British thermal units.
    Motor gasoline (finished) means a complex mixture of volatile 
hydrocarbons, with or without additives, suitably

[[Page 581]]

blended to be used in spark ignition engines. Motor gasoline includes 
conventional gasoline, reformulated gasoline, and all types of 
oxygenated gasoline. Gasoline also has seasonal variations in an effort 
to control ozone levels. This is achieved by lowering the Reid Vapor 
Pressure (RVP) of gasoline during the summer driving season. Depending 
on the region of the country the RVP is lowered to below 9.0 psi or 7.8 
psi. The RVP may be further lowered by state regulations.
    Mscf means thousand standard cubic feet.
    MTBE (methyl tertiary butyl ether, 
(CH3)3COCH3) is an ether as described 
in ``Oxygenates.''
    Municipal solid waste landfill or MSW landfill means an entire 
disposal facility in a contiguous geographical space where household 
waste is placed in or on land. An MSW landfill may also receive other 
types of RCRA Subtitle D wastes (40 CFR 257.2) such as commercial solid 
waste, nonhazardous sludge, conditionally exempt small quantity 
generator waste, and industrial solid waste. Portions of an MSW landfill 
may be separated by access roads, public roadways, or other public 
right-of-ways. An MSW landfill may be publicly or privately owned.
    Municipal solid waste or MSW means solid phase household, 
commercial/retail, and/or institutional waste. Household waste includes 
material discarded by single and multiple residential dwellings, hotels, 
motels, and other similar permanent or temporary housing establishments 
or facilities. Commercial/retail waste includes material discarded by 
stores, offices, restaurants, warehouses, non-manufacturing activities 
at industrial facilities, and other similar establishments or 
facilities. Institutional waste includes material discarded by schools, 
nonmedical waste discarded by hospitals, material discarded by non-
manufacturing activities at prisons and government facilities, and 
material discarded by other similar establishments or facilities. 
Household, commercial/retail, and institutional wastes include yard 
waste, refuse-derived fuel, and motor vehicle maintenance materials. 
Insofar as there is separate collection, processing and disposal of 
industrial source waste streams consisting of used oil, wood pallets, 
construction, renovation, and demolition wastes (which includes, but is 
not limited to, railroad ties and telephone poles), paper, clean wood, 
plastics, industrial process or manufacturing wastes, medical waste, 
motor vehicle parts or vehicle fluff, or used tires that do not contain 
hazardous waste identified or listed under 42 U.S.C. Sec. 6921, such 
wastes are not municipal solid waste. However, such wastes qualify as 
municipal solid waste where they are collected with other municipal 
solid waste or are otherwise combined with other municipal solid waste 
for processing and/or disposal.
    Municipal wastewater treatment plant means a series of treatment 
processes used to remove contaminants and pollutants from domestic, 
business, and industrial wastewater collected in city sewers and 
transported to a centralized wastewater treatment system such as a 
publicly owned treatment works (POTW).
    N2O means nitrous oxide.
    Naphthas (<401  deg.F) is a generic term applied to a petroleum 
fraction with an approximate boiling range between 122  deg.F and 400 
deg.F. The naphtha fraction of crude oil is the raw material for 
gasoline and is composed largely of paraffinic hydrocarbons.
    Natural gas means a naturally occurring mixture of hydrocarbon and 
non-hydrocarbon gases found in geologic formations beneath the earth's 
surface, of which the principal constituent is methane. Natural gas may 
be field quality or pipeline quality.
    Natural gas driven pneumatic pump means a pump that uses pressurized 
natural gas to move a piston or diaphragm, which pumps liquids on the 
opposite side of the piston or diaphragm.
    Natural gas liquids (NGLs) means those hydrocarbons in natural gas 
that are separated from the gas as liquids through the process of 
absorption, condensation, adsorption, or other methods. Generally, such 
liquids consist of ethane, propane, butanes, and pentanes plus. Bulk 
NGLs refers to mixtures of NGLs that are sold or delivered as 
undifferentiated product from natural gas processing plants.

[[Page 582]]

    Natural gasoline means a mixture of liquid hydrocarbons (mostly 
pentanes and heavier hydrocarbons) extracted from natural gas. It 
includes isopentane.
    NIST means the United States National Institute of Standards and 
Technology.
    Nitric acid production line means a series of reactors and absorbers 
used to produce nitric acid.
    Nitrogen excreted is the nitrogen that is excreted by livestock in 
manure and urine.
    Non-crude feedstocks means any petroleum product or natural gas 
liquid that enters the refinery to be further refined or otherwise used 
on site.
    Non-recovery coke oven battery means a group of ovens connected by 
common walls and operated as a unit, where coal undergoes destructive 
distillation under negative pressure to produce coke, and which is 
designed for the combustion of the coke oven gas from which by-products 
are not recovered.
    North American Industry Classification System (NAICS) code(s) means 
the six-digit code(s) that represents the product(s)/activity(s)/
service(s) at a facility or supplier as listed in the Federal Register 
and defined in ``North American Industrial Classification System Manual 
2007,'' available from the U.S. Department of Commerce, National 
Technical Information Service, Alexandria, VA 22312, phone (703) 605-
6000 or (800) 553-6847. http://www.census.gov/eos/www/naics/.
    Oil-fired unit means a stationary combustion unit that derives more 
than 50 percent of its annual heat input from the combustion of fuel 
oil, and the remainder of its annual heat input from the combustion of 
natural gas or other gaseous fuels.
    Open-ended valve or lines (OELs) means any valve, except pressure 
relief valves, having one side of the valve seat in contact with process 
fluid and one side open to atmosphere, either directly or through open 
piping.
    Operating hours means the duration of time in which a process or 
process unit is utilized; this excludes shutdown, maintenance, and 
standby.
    Operational change means, for purposes of Sec. 98.3(b), a change in 
the type of feedstock or fuel used, a change in operating hours, or a 
change in process production rate.
    Operator means any person who operates or supervises a facility or 
supplier.
    Other fluorinated GHGs means fluorinated GHGs that are none of the 
following: Fully fluorinated GHGs; saturated hydrofluorocarbons with 2 
or fewer carbon-hydrogen bonds; saturated hydrofluorocarbons with 3 or 
more carbon-hydrogen bonds; saturated hydrofluoroethers and 
hydrochlorofluoroethers with 1 carbon-hydrogen bond; saturated 
hydrofluoroethers and hydrochlorofluoroethers with 2 carbon-hydrogen 
bonds; saturated hydrofluoroethers and hydrochlorofluoroethers with 3 or 
more carbon-hydrogen bonds; fluorinated formates; fluorinated acetates, 
carbonofluoridates, and fluorinated alcohols other than fluorotelomer 
alcohols; unsaturated PFCs, unsaturated HFCs, unsaturated HCFCs, 
unsaturated halogenated ethers, unsaturated halogenated esters, 
fluorinated aldehydes, and fluorinated ketones; fluorotelomer alcohols; 
or fluorinated GHGs with carbon-iodine bonds.
    Other oils (401  deg.F) are oils with a boiling range 
equal to or greater than 401  deg.F that are generally intended for use 
as a petrochemical feedstock and are not defined elsewhere.
    Outer Continental Shelf means all submerged lands lying seaward and 
outside of the area of lands beneath navigable waters as defined in 43 
U.S.C. 1331, and of which the subsoil and seabed appertain to the United 
States and are subject to its jurisdiction and control.
    Owner means any person who has legal or equitable title to, has a 
leasehold interest in, or control of a facility or supplier, except a 
person whose legal or equitable title to or leasehold interest in the 
facility or supplier arises solely because the person is a limited 
partner in a partnership that has legal or equitable title to, has a 
leasehold interest in, or control of the facility or supplier shall not 
be considered an ``owner'' of the facility or supplier.
    Oxygenates means substances which, when added to gasoline, increase 
the oxygen content of the gasoline. Common oxygenates are ethanol, 
methyl

[[Page 583]]

tertiary butyl ether (MTBE), ethyl tertiary butyl ether (ETBE), tertiary 
amyl methyl ether (TAME), diisopropyl ether (DIPE), and methanol.
    Pasture/Range/Paddock means the manure from pasture and range 
grazing animals is allowed to lie as deposited, and is not managed.
    Pentanes plus, or C5 + , is a mixture of hydrocarbons that is a 
liquid at ambient temperature and pressure, and consists mostly of 
pentanes (five carbon chain) and higher carbon number hydrocarbons. 
Pentanes plus includes, but is not limited to, normal pentane, 
isopentane, hexanes-plus (natural gasoline), and plant condensate.
    Perfluorocarbons or PFCs means a class of greenhouse gases 
consisting on the molecular level of carbon and fluorine.
    Petrochemical means methanol, acrylonitrile, ethylene, ethylene 
oxide, ethylene dichloride, and any form of carbon black.
    Petrochemical feedstocks means feedstocks derived from petroleum for 
the manufacture of chemicals, synthetic rubber, and a variety of 
plastics. This category is usually divided into naphthas less than 401 
deg.F and other oils greater than 401  deg.F.
    Petroleum means oil removed from the earth and the oil derived from 
tar sands and shale.
    Petroleum coke means a black solid residue, obtained mainly by 
cracking and carbonizing of petroleum derived feedstocks, vacuum 
bottoms, tar and pitches in processes such as delayed coking or fluid 
coking. It consists mainly of carbon (90 to 95 percent), has low ash 
content, and may be used as a feedstock in coke ovens. This product is 
also known as marketable coke or catalyst coke.
    Petroleum product means all refined and semi-refined products that 
are produced at a refinery by processing crude oil and other petroleum-
based feedstocks, including petroleum products derived from co-
processing biomass and petroleum feedstock together, but not including 
plastics or plastic products. Petroleum products may be combusted for 
energy use, or they may be used either for non-energy processes or as 
non-energy products. The definition of petroleum product for importers 
and exporters excludes waxes.
    Physical address, with respect to a United States parent company as 
defined in this section, means the street address, city, state and zip 
code of that company's physical location.
    Pit storage below animal confinement (deep pits) means the 
collection and storage of manure typically below a slatted floor in an 
enclosed animal confinement facility. This usually occurs with little or 
no added water for periods less than one year.
    Plant code means either of the following:
    (1) The Plant ID code assigned by the Department of Energy's Energy 
Information Administration. The Energy Information Administration Plant 
ID code is also referred to as the ``ORIS code'', ``ORISPL code'', 
``Facility ID'', or ``Facility code'', among other names.
    (2) If a Plant ID code has not been assigned by the Department of 
Energy's Energy Information Administration, then plant code means a code 
beginning with ``88'' assigned by the EPA's Clean Air Markets Division 
for electronic reporting.
    Portable means designed and capable of being carried or moved from 
one location to another. Indications of portability include but are not 
limited to wheels, skids, carrying handles, dolly, trailer, or platform. 
Equipment is not portable if any one of the following conditions exists:
    (1) The equipment is attached to a foundation.
    (2) The equipment or a replacement resides at the same location for 
more than 12 consecutive months.
    (3) The equipment is located at a seasonal facility and operates 
during the full annual operating period of the seasonal facility, 
remains at the facility for at least two years, and operates at that 
facility for at least three months each year.
    (4) The equipment is moved from one location to another in an 
attempt to circumvent the portable residence time requirements of this 
definition.
    Poultry manure with litter means a manure management system 
component that is similar to cattle and swine

[[Page 584]]

deep bedding except usually not combined with a dry lot or pasture. The 
system is typically used for poultry breeder flocks and for the 
production of meat type chickens (broiler) and other fowl.
    Poultry manure without litter means a manure management system 
component that may manage manure in a liquid form, similar to open pits 
in enclosed animal confinement facilities. These systems may 
alternatively be designed and operated to dry manure as it accumulates. 
The latter is known as a high-rise manure management system and is a 
form of passive windrow manure composting when designed and operated 
properly.
    Precision of a measurement at a specified level (e.g., one percent 
of full scale or one percent of the value measured) means that 95 
percent of repeat measurements made by a device or technique are within 
the range bounded by the mean of the measurements plus or minus the 
specified level.
    Premium grade gasoline is gasoline having an antiknock index, i.e., 
octane rating, greater than 90. This definition applies to the premium 
grade categories of Conventional-Summer, Conventional-Winter, 
Reformulated-Summer, and Reformulated-Winter. For premium grade 
categories of RBOB-Summer, RBOB-Winter, CBOB-Summer, and CBOB-Winter, 
this definition refers to the expected octane rating of the finished 
gasoline after oxygenate has been added to the RBOB or CBOB.
    Pressed and blown glass means glass which is pressed, blown, or 
both, into products such as light bulbs, glass fiber, technical glass, 
and other products listed in NAICS 327212.
    Pressure relief device or pressure relief valve or pressure safety 
valve means a safety device used to prevent operating pressures from 
exceeding the maximum allowable working pressure of the process 
equipment. A common pressure relief device is but not limited to a 
spring-loaded pressure relief valve. Devices that are actuated either by 
a pressure of less than or equal to 2.5 psig or by a vacuum are not 
pressure relief devices.
    Primary fuel means the fuel that provides the greatest percentage of 
the annual heat input to a stationary fuel combustion unit.
    Process emissions means the emissions from industrial processes 
(e.g., cement production, ammonia production) involving chemical or 
physical transformations other than fuel combustion. For example, the 
calcination of carbonates in a kiln during cement production or the 
oxidation of methane in an ammonia process results in the release of 
process CO2 emissions to the atmosphere. Emissions from fuel 
combustion to provide process heat are not part of process emissions, 
whether the combustion is internal or external to the process equipment.
    Process unit means the equipment assembled and connected by pipes 
and ducts to process raw materials and to manufacture either a final 
product or an intermediate used in the onsite production of other 
products. The process unit also includes the purification of recovered 
byproducts.
    Process vent means means a gas stream that: Is discharged through a 
conveyance to the atmosphere either directly or after passing through a 
control device; originates from a unit operation, including but not 
limited to reactors (including reformers, crackers, and furnaces, and 
separation equipment for products and recovered byproducts); and 
contains or has the potential to contain GHG that is generated in the 
process. Process vent does not include safety device discharges, 
equipment leaks, gas streams routed to a fuel gas system or to a flare, 
discharges from storage tanks.
    Propane is a paraffinic hydrocarbon with molecular formula 
C3H8.
    Propylene is an olefinic hydrocarbon with molecular formula 
C3H6.
    Pulp mill lime kiln means the combustion units (e.g., rotary lime 
kiln or fluidized bed calciner) used at a kraft or soda pulp mill to 
calcine lime mud, which consists primarily of calcium carbonate, into 
quicklime, which is calcium oxide.
    Pushing means the process of removing the coke from the coke oven at 
the end of the coking cycle. Pushing begins when coke first begins to 
fall from the oven into the quench car and ends when the quench car 
enters the quench tower.

[[Page 585]]

    Raw mill means a ball and tube mill, vertical roller mill or other 
size reduction equipment, that is not part of an in-line kiln/raw mill, 
used to grind feed to the appropriate size. Moisture may be added or 
removed from the feed during the grinding operation. If the raw mill is 
used to remove moisture from feed materials, it is also, by definition, 
a raw material dryer. The raw mill also includes the air separator 
associated with the raw mill.
    RBOB-Summer (reformulated blendstock for oxygenate blending) means a 
petroleum product which, when blended with a specified type and 
percentage of oxygenate, meets the definition of Reformulated-Summer.
    RBOB-Winter (reformulated blendstock for oxygenate blending) means a 
petroleum product which, when blended with a specified type and 
percentage of oxygenate, meets the definition of Reformulated-Winter.
    Reciprocating compressor means a piece of equipment that increases 
the pressure of a process natural gas or CO2 by positive 
displacement, employing linear movement of a shaft driving a piston in a 
cylinder.
    Reciprocating compressor rod packing means a series of flexible 
rings in machined metal cups that fit around the reciprocating 
compressor piston rod to create a seal limiting the amount of compressed 
natural gas or CO2 that escapes to the atmosphere.
    Re-condenser means heat exchangers that cool compressed boil-off gas 
to a temperature that will condense natural gas to a liquid.
    Reformulated-Summer refers to finished gasoline formulated for use 
in motor vehicles, the composition and properties of which meet the 
requirements of the reformulated gasoline regulations promulgated by the 
U.S. Environmental Protection Agency under 40 CFR 80.40 and 40 CFR 
80.41, and summer RVP standards required under 40 CFR 80.27 or as 
specified by the state. Reformulated gasoline excludes Reformulated 
Blendstock for Oxygenate Blending (RBOB) as well as other blendstock.
    Reformulated-Winter refers to finished gasoline formulated for use 
in motor vehicles, the composition and properties of which meet the 
requirements of the reformulated gasoline regulations promulgated by the 
U.S. Environmental Protection Agency under 40 CFR 80.40 and 40 CFR 
80.41, but which do not meet summer RVP standards required under 40 CFR 
80.27 or as specified by the state. Note: This category includes 
Oxygenated Fuels Program Reformulated Gasoline (OPRG). Reformulated 
gasoline excludes Reformulated Blendstock for Oxygenate Blending (RBOB) 
as well as other blendstock.
    Regular grade gasoline is gasoline having an antiknock index, i.e., 
octane rating, greater than or equal to 85 and less than 88. This 
definition applies to the regular grade categories of Conventional-
Summer, Conventional-Winter, Reformulated-Summer, and Reformulated-
Winter. For regular grade categories of RBOB-Summer, RBOB-Winter, CBOB-
Summer, and CBOB-Winter, this definition refers to the expected octane 
rating of the finished gasoline after oxygenate has been added to the 
RBOB or CBOB.
    Rendered animal fat, or tallow, means fats extracted from animals 
which are generally used as a feedstock in making biodiesel.
    Research and development means those activities conducted in process 
units or at laboratory bench-scale settings whose purpose is to conduct 
research and development for new processes, technologies, or products 
and whose purpose is not for the manufacture of products for commercial 
sale, except in a de minimis manner.
    Residual Fuel Oil No. 5 (Navy Special) is a classification for the 
heavier fuel oil generally used in steam powered vessels in government 
service and inshore power plants. It has a minimum flash point of 131 
deg.F.
    Residual Fuel Oil No. 6 (a.k.a. Bunker C) is a classification for 
the heavier fuel oil generally used for the production of electric 
power, space heating, vessel bunkering and various industrial purposes. 
It has a minimum flash point of 140  deg.F.
    Residuum is residue from crude oil after distilling off all but the 
heaviest components, with a boiling range greater than 1,000  deg.F.
    Road oil is any heavy petroleum oil, including residual asphaltic 
oil used as a dust palliative and surface treatment

[[Page 586]]

on roads and highways. It is generally produced in six grades, from 0, 
the most liquid, to 5, the most viscous.
    Rotary lime kiln means a unit with an inclined rotating drum that is 
used to produce a lime product from limestone by calcination.
    Safety device means a closure device such as a pressure relief 
valve, frangible disc, fusible plug, or any other type of device which 
functions exclusively to prevent physical damage or permanent 
deformation to a unit or its air emission control equipment by venting 
gases or vapors directly to the atmosphere during unsafe conditions 
resulting from an unplanned, accidental, or emergency event. A safety 
device is not used for routine venting of gases or vapors from the vapor 
headspace underneath a cover such as during filling of the unit or to 
adjust the pressure in response to normal daily diurnal ambient 
temperature fluctuations. A safety device is designed to remain in a 
closed position during normal operations and open only when the internal 
pressure, or another relevant parameter, exceeds the device threshold 
setting applicable to the air emission control equipment as determined 
by the owner or operator based on manufacturer recommendations, 
applicable regulations, fire protection and prevention codes and 
practices, or other requirements for the safe handling of flammable, 
combustible, explosive, reactive, or hazardous materials.
    Sales oil means produced crude oil or condensate measured at the 
production lease automatic custody transfer (LACT) meter or custody 
transfer tank gauge.
    Saturated hydrochlorofluoroethers (HCFEs) means fluorinated GHGs in 
which two hydrocarbon groups are linked by an oxygen atom; in which two 
or more, but not all, of the hydrogen atoms in the hydrocarbon groups 
have been replaced by fluorine atoms and chlorine atoms; and which 
contain only single bonds.
    Saturated hydrofluorocarbons (HFCs) means fluorinated GHGs that are 
hydrofluorocarbons and that contain only single bonds.
    Saturated hydrofluoroethers (HFEs) means fluorinated GHGs in which 
two hydrocarbon groups are linked by an oxygen atom; in which one or 
more, but not all, of the hydrogen atoms in the hydrocarbon groups have 
been replaced by fluorine atoms; and which contain only single bonds.
    Semi-refined petroleum product means all oils requiring further 
processing. Included in this category are unfinished oils which are 
produced by the partial refining of crude oil and include the following: 
Naphthas and lighter oils; kerosene and light gas oils; heavy gas oils; 
and residuum, and all products that require further processing or the 
addition of blendstocks.
    Sendout means, in the context of a local distribution company, the 
total deliveries of natural gas to customers over a specified time 
interval (typically hour, day, month, or year). Sendout is the sum of 
gas received through the city gate, gas withdrawn from on-system storage 
or peak shaving plants, and gas produced and delivered into the 
distribution system; and is net of any natural gas injected into on-
system storage. It comprises gas sales, exchange, deliveries, gas used 
by company, and unaccounted for gas. Sendout is measured at the city 
gate station, and other on-system receipt points from storage, peak 
shaving, and production.
    Sensor means a device that measures a physical quantity/quality or 
the change in a physical quantity/quality, such as temperature, 
pressure, flow rate, pH, or liquid level.
    SF6 means sulfur hexafluoride.
    Shutdown means the cessation of operation of an emission source for 
any purpose.
    Silicon carbide means an artificial abrasive produced from silica 
sand or quartz and petroleum coke.
    Sinter process means a process that produces a fused aggregate of 
fine iron-bearing materials suited for use in a blast furnace. The 
sinter machine is composed of a continuous traveling grate that conveys 
a bed of ore fines and other finely divided iron-bearing material and 
fuel (typically coke breeze), a burner at the feed end of the grate for 
ignition, and a series of downdraft windboxes along the length of the 
strand to support downdraft

[[Page 587]]

combustion and heat sufficient to produce a fused sinter product.
    Site means any combination of one or more graded pad sites, gravel 
pad sites, foundations, platforms, or the immediate physical location 
upon which equipment is physically located.
    Smelting furnace means a furnace in which lead-bearing materials, 
carbon-containing reducing agents, and fluxes are melted together to 
form a molten mass of material containing lead and slag.
    Solid by-products means plant matter such as vegetable waste, animal 
materials/wastes, and other solid biomass, except for wood, wood waste, 
and sulphite lyes (black liquor).
    Solid storage is the storage of manure, typically for a period of 
several months, in unconfined piles or stacks. Manure is able to be 
stacked due to the presence of a sufficient amount of bedding material 
or loss of moisture by evaporation.
    Sour gas means any gas that contains significant concentrations of 
hydrogen sulfide. Sour gas may include untreated fuel gas, amine 
stripper off-gas, or sour water stripper gas.
    Sour natural gas means natural gas that contains significant 
concentrations of hydrogen sulfide (H2S)and/or carbon dioxide 
(CO2) that exceed the concentrations specified for 
commercially saleable natural gas delivered from transmission and 
distribution pipelines.
    Special naphthas means all finished products with the naphtha 
boiling range (290  deg. to 470  deg.F) that are generally used as paint 
thinners, cleaners or solvents. These products are refined to a 
specified flash point. Special naphthas include all commercial hexane 
and cleaning solvents conforming to ASTM Specification D1836-07, 
Standard Specification for Commercial Hexanes, and D235-02 (Reapproved 
2007), Standard Specification for Mineral Spirits (Petroleum Spirits) 
(Hydrocarbon Dry Cleaning Solvent), respectively. Naphthas to be blended 
or marketed as motor gasoline or aviation gasoline, or that are to be 
used as petrochemical and synthetic natural gas (SNG) feedstocks are 
excluded.
    Spent liquor solids means the dry weight of the solids in the spent 
pulping liquor that enters the chemical recovery furnace or chemical 
recovery combustion unit.
    Spent pulping liquor means the residual liquid collected from on-
site pulping operations at chemical pulp facilities that is subsequently 
fired in chemical recovery furnaces at kraft and soda pulp facilities or 
chemical recovery combustion units at sulfite or semi-chemical pulp 
facilities.
    Standard conditions or standard temperature and pressure (STP), for 
the purposes of this part, means either 60 or 68 degrees Fahrenheit and 
14.7 pounds per square inch absolute.
    Steam reforming means a catalytic process that involves a reaction 
between natural gas or other light hydrocarbons and steam. The result is 
a mixture of hydrogen, carbon monoxide, carbon dioxide, and water.
    Still gas means any form or mixture of gases produced in refineries 
by distillation, cracking, reforming, and other processes. The principal 
constituents are methane, ethane, ethylene, normal butane, butylene, 
propane, and propylene.
    Storage tank means a vessel (excluding sumps) that is designed to 
contain an accumulation of crude oil, condensate, intermediate 
hydrocarbon liquids, or produced water and that is constructed entirely 
of non-earthen materials (e.g., wood, concrete, steel, plastic) that 
provide structural support.
    Sulfur recovery plant means all process units which recover sulfur 
or produce sulfuric acid from hydrogen sulfide (H2S) and/or 
sulfur dioxide (SO2) from a common source of sour gas at a 
petroleum refinery. The sulfur recovery plant also includes sulfur pits 
used to store the recovered sulfur product, but it does not include 
secondary sulfur storage vessels or loading facilities downstream of the 
sulfur pits. For example, a Claus sulfur recovery plant includes: 
Reactor furnace and waste heat boiler, catalytic reactors, sulfur pits, 
and, if present, oxidation or reduction control systems, or incinerator, 
thermal oxidizer, or similar combustion device. Multiple sulfur recovery 
units are a single sulfur recovery plant only when the units share the 
same source of sour gas. Sulfur recovery units that receive source gas 
from completely

[[Page 588]]

segregated sour gas treatment systems are separate sulfur recovery 
plants.
    Supplemental fuel means a fuel burned within a petrochemical process 
that is not produced within the process itself.
    Supplier means a producer, importer, or exporter in any supply 
category included in Table A-5 to this subpart, as defined by the 
corresponding subpart of this part.
    Sweet gas is natural gas with low concentrations of hydrogen sulfide 
(H2S) and/or carbon dioxide (CO2) that does not 
require (or has already had) acid gas treatment to meet pipeline 
corrosion-prevention specifications for transmission and distribution.
    Taconite iron ore processing means an industrial process that 
separates and concentrates iron ore from taconite, a low grade iron ore, 
and heats the taconite in an indurating furnace to produce taconite 
pellets that are used as the primary feed material for the production of 
iron in blast furnaces at integrated iron and steel plants.
    TAME means tertiary amyl methyl ether, 
(CH3)2(C2H5)COCH3)
.
    Trace concentrations means concentrations of less than 0.1 percent 
by mass of the process stream.
    Transform means to use and entirely consume (except for trace 
concentrations) nitrous oxide or fluorinated GHGs in the manufacturing 
of other chemicals for commercial purposes. Transformation does not 
include burning of nitrous oxide.
    Transshipment means the continuous shipment of nitrous oxide or a 
fluorinated GHG from a foreign state of origin through the United States 
or its territories to a second foreign state of final destination, as 
long as the shipment does not enter into United States jurisdiction. A 
transshipment, as it moves through the United States or its territories, 
cannot be re-packaged, sorted or otherwise changed in condition.
    Trona means the raw material (mineral) used to manufacture soda ash; 
hydrated sodium bicarbonate carbonate (e.g., 
Na2CO3.NaHCO3.2H2O).
    Ultimate analysis means the determination of the percentages of 
carbon, hydrogen, nitrogen, sulfur, and chlorine and (by difference) 
oxygen in the gaseous products and ash after the complete combustion of 
a sample of an organic material.
    Unfinished oils are all oils requiring further processing, except 
those requiring only mechanical blending.
    United States means the 50 States, the District of Columbia, the 
Commonwealth of Puerto Rico, American Samoa, the Virgin Islands, Guam, 
and any other Commonwealth, territory or possession of the United 
States, as well as the territorial sea as defined by Presidential 
Proclamation No. 5928.
    United States parent company(s) means the highest-level United 
States company(s) with an ownership interest in the facility or supplier 
as of December 31 of the year for which data are being reported.
    Unsaturated halogenated ethers means fluorinated GHGs in which two 
hydrocarbon groups are linked by an oxygen atom; in which one or more of 
the hydrogen atoms in the hydrocarbon groups have been replaced by 
fluorine atoms; and which contain one or more bonds that are not single 
bonds. Unsaturated ethers include unsaturated HFEs.
    Unsaturated hydrochlorofluorocarbons (HCFCs) means fluorinated GHGs 
that contain only carbon, chlorine, fluorine, and hydrogen and that 
contain one or more bonds that are not single bonds.
    Unsaturated hydrofluorocarbons (HFCs) means fluorinated GHGs that 
are hydrofluorocarbons and that contain one or more bonds that are not 
single bonds.
    Unsaturated perfluorocarbons (PFCs) means fluorinated GHGs that are 
perfluorocarbons and that contain one or more bonds that are not single 
bonds.
    Unstabilized crude oil means, for the purposes of this part, crude 
oil that is pumped from the well to a pipeline or pressurized storage 
vessel for transport to the refinery without intermediate storage in a 
storage tank at atmospheric pressures. Unstabilized crude oil is 
characterized by having a true vapor pressure of 5 pounds per square 
inch absolute (psia) or greater.
    Used oil means a petroleum-derived or synthetically-derived oil 
whose physical properties have changed as a result of handling or use, 
such that the

[[Page 589]]

oil cannot be used for its original purpose. Used oil consists primarily 
of automotive oils (e.g., used motor oil, transmission oil, hydraulic 
fluids, brake fluid, etc.) and industrial oils (e.g., industrial engine 
oils, metalworking oils, process oils, industrial grease, etc).
    Valve means any device for halting or regulating the flow of a 
liquid or gas through a passage, pipeline, inlet, outlet, or orifice; 
including, but not limited to, gate, globe, plug, ball, butterfly and 
needle valves.
    Vapor recovery system means any equipment located at the source of 
potential gas emissions to the atmosphere or to a flare, that is 
composed of piping, connections, and, if necessary, flow-inducing 
devices, and that is used for routing the gas back into the process as a 
product and/or fuel.
    Vaporization unit means a process unit that performs controlled heat 
input to vaporize LNG to supply transmission and distribution pipelines 
or consumers with natural gas.
    Vegetable oil means oils extracted from vegetation that are 
generally used as a feedstock in making biodiesel.
    Ventilation hole or shaft means a vent hole or shaft employed at an 
underground coal mine to serve as the outlet or conduit to move air from 
the ventilation system out of the mine.
    Ventilation system means a system that is used to control the 
concentration of methane and other gases within mine working areas 
through mine ventilation, rather than a mine degasification system. A 
ventilation system consists of fans that move air through the mine 
workings to dilute methane concentrations.
    Volatile solids are the organic material in livestock manure and 
consist of both biodegradable and non-biodegradable fractions.
    Waelz kiln means an inclined rotary kiln in which zinc-containing 
materials are charged together with a carbon reducing agent (e.g., 
petroleum coke, metallurgical coke, or anthracite coal).
    Waxes means a solid or semi-solid material at 77  deg.F consisting 
of a mixture of hydrocarbons obtained or derived from petroleum 
fractions, or through a Fischer-Tropsch type process, in which the 
straight chained paraffin series predominates. This includes all 
marketable wax, whether crude or refined, with a congealing point 
between 80 (or 85) and 240  deg.F and a maximum oil content of 50 weight 
percent.
    Well completions means the process that allows for the flow of 
petroleum or natural gas from newly drilled wells to expel drilling and 
reservoir fluids and test the reservoir flow characteristics, steps 
which may vent produced gas to the atmosphere via an open pit or tank. 
Well completion also involves connecting the well bore to the reservoir, 
which may include treating the formation or installing tubing, 
packer(s), or lifting equipment, steps that do not significantly vent 
natural gas to the atmosphere. This process may also include high-rate 
flowback of injected gas, water, oil, and proppant used to fracture and 
prop open new fractures in existing lower permeability gas reservoirs, 
steps that may vent large quantities of produced gas to the atmosphere.
    Well workover means the process(es) of performing one or more of a 
variety of remedial operations on producing petroleum and natural gas 
wells to try to increase production. This process also includes high-
rate flowback of injected gas, water, oil, and proppant used to re-
fracture and prop-open new fractures in existing low permeability gas 
reservoirs, steps that may vent large quantities of produced gas to the 
atmosphere.
    Wellhead means the piping, casing, tubing and connected valves 
protruding above the earth's surface for an oil and/or natural gas well. 
The wellhead ends where the flow line connects to a wellhead valve. 
Wellhead equipment includes all equipment, permanent and portable, 
located on the improved land area (i.e. well pad) surrounding one or 
multiple wellheads.
    Wet natural gas means natural gas in which water vapor exceeds the 
concentration specified for commercially saleable natural gas delivered 
from transmission and distribution pipelines. This input stream to a 
natural gas dehydrator is referred to as ``wet gas.''

[[Page 590]]

    Wood residuals means materials recovered from three principal 
sources: Municipal solid waste (MSW); construction and demolition 
debris; and primary timber processing. Wood residuals recovered from MSW 
include wooden furniture, cabinets, pallets and containers, scrap lumber 
(from sources other than construction and demolition activities), and 
urban tree and landscape residues. Wood residuals from construction and 
demolition debris originate from the construction, repair, remodeling 
and demolition of houses and non-residential structures. Wood residuals 
from primary timber processing include bark, sawmill slabs and edgings, 
sawdust, and peeler log cores. Other sources of wood residuals include, 
but are not limited to, railroad ties, telephone and utility poles, pier 
and dock timbers, wastewater process sludge from paper mills, trim, 
sander dust, and sawdust from wood products manufacturing (including 
resinated wood product residuals), and logging residues.
    Wool fiberglass means fibrous glass of random texture, including 
fiberglass insulation, and other products listed in NAICS 327993.
    Working capacity, for the purposes of subpart TT of this part, means 
the maximum volume or mass of waste that is actually placed in the 
landfill from an individual or representative type of container (such as 
a tank, truck, or roll-off bin) used to convey wastes to the landfill, 
taking into account that the container may not be able to be 100 percent 
filled and/or 100 percent emptied for each load.
    You means an owner or operator subject to Part 98.
    Zinc smelters means a facility engaged in the production of zinc 
metal, zinc oxide, or zinc alloy products from zinc sulfide ore 
concentrates, zinc calcine, or zinc-bearing scrap and recycled materials 
through the use of pyrometallurgical techniques involving the reduction 
and volatization of zinc-bearing feed materials charged to a furnace.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 39759, July 12, 2010; 
75 FR 57686, Sept. 22, 2010; 75 FR 66457, Oct. 28, 2010; 75 FR 74487, 
Nov. 30, 2010; 75 FR 74816, Dec. 1, 2010; 75 FR 79137, Dec. 17, 2010; 76 
FR 73900, Nov. 29, 2011; 76 FR 80573, Dec. 23, 2011; 78 FR 71948, Nov. 
29, 2013; 79 FR 70385, Nov. 25, 2014; 79 FR 73778, Dec. 11, 2014]



Sec. 98.7  What standardized methods are incorporated by reference 
into this part?

    The materials listed in this section are incorporated by reference 
in the corresponding sections noted. These incorporations by reference 
were approved by the Director of Federal Register in accordance with 5 
U.S.C. 552(a) and 1 CFR part 51. These materials are incorporated as 
they exist on the date of approval, and a notice of any change in the 
materials will be published in the Federal Register. The materials are 
available for purchase at the corresponding address in this section. The 
materials are available for inspection at the EPA Docket Center, Public 
Reading Room, EPA West Building, Room 3334, 1301 Constitution Avenue, 
NW., Washington, DC, phone (202) 566-1744 and at the National Archives 
and Records Administration (NARA). For information on the availability 
of this material at NARA, call 202-741-6030, or go to: http://
www.archives.gov/federal--register/code--of--federal--regulations/ibr--
locations.html.
    (a)-(b) [Reserved]
    (c) The following material is available for purchase from the ASM 
International, 9639 Kinsman Road, Materials Park, OH 44073, (440) 338-
5151, http://www.asminternational.org.
    (1) ASM CS-104 UNS No. G10460--Alloy Digest April 1985 (Carbon Steel 
of Medium Carbon Content), incorporation by reference (IBR) approved for 
Sec. 98.174(b).
    (2) [Reserved]
    (d) The following material is available for purchase from the 
American Society of Mechanical Engineers (ASME), Three Park Avenue, New 
York, NY 10016-5990, (800) 843-2763, http://www.asme.org.
    (1) ASME MFC-3M-2004 Measurement of Fluid Flow in Pipes Using 
Orifice,

[[Page 591]]

Nozzle, and Venturi, incorporation by reference (IBR) approved for Sec. 
98.124(m)(1), Sec. 98.324(e), Sec. 98.354(d), Sec. 98.354(h), Sec. 
98.344(c) and Sec. 98.364(e).
    (2) ASME MFC-4M-1986 (Reaffirmed 1997) Measurement of Gas Flow by 
Turbine Meters, IBR approved for Sec. 98.124(m)(2), Sec. 98.324(e), 
Sec. 98.344(c), Sec. 98.354(h), and Sec. 98.364(e).
    (3) ASME MFC-5M-1985 (Reaffirmed 1994) Measurement of Liquid Flow in 
Closed Conduits Using Transit-Time Ultrasonic Flow Meters, IBR approved 
for Sec. 98.124(m)(3) and Sec. 98.354(d).
    (4) ASME MFC-6M-1998 Measurement of Fluid Flow in Pipes Using Vortex 
Flowmeters, IBR approved for Sec. 98.124(m)(4), Sec. 98.324(e), Sec. 
98.344(c), Sec. 98.354(h), and Sec. 98.364(e).
    (5) ASME MFC-7M-1987 (Reaffirmed 1992) Measurement of Gas Flow by 
Means of Critical Flow Venturi Nozzles, IBR approved for Sec. 
98.124(m)(5), Sec. 98.324(e), Sec. 98.344(c), Sec. 98.354(h), and 
Sec. 98.364(e).
    (6) ASME MFC-9M-1988 (Reaffirmed 2001) Measurement of Liquid Flow in 
Closed Conduits by Weighing Method, IBR approved for Sec. 98.124(m)(6).
    (7) ASME MFC-11M-2006 Measurement of Fluid Flow by Means of Coriolis 
Mass Flowmeters, IBR approved for Sec. 98.124(m)(7), Sec. 98.324(e), 
Sec. 98.344(c), and Sec. 98.354(h).
    (8) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore 
Precision Orifice Meters, IBR approved for Sec. 98.124(m)(8), Sec. 
98.324(e), Sec. 98.344(c), Sec. 98.354(h), and Sec. 98.364(e).
    (9) ASME MFC-16-2007 Measurement of Liquid Flow in Closed Conduits 
with Electromagnetic Flow Meters, IBR approved for Sec. 98.354(d).
    (10) ASME MFC-18M-2001 Measurement of Fluid Flow Using Variable Area 
Meters, IBR approved for Sec. 98.324(e), Sec. 98.344(c), Sec. 
98.354(h), and Sec. 98.364(e).
    (e) The following material is available for purchase from the 
American Society for Testing and Material (ASTM), 100 Barr Harbor Drive, 
P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-
1373, http://www.astm.org.
    (1) ASTM C25-06 Standard Test Method for Chemical Analysis of 
Limestone, Quicklime, and Hydrated Lime, incorporation by reference 
(IBR) approved for Sec. 98.114(b), Sec. 98.174(b), Sec. 98.184(b), 
Sec. 98.194(c), and Sec. 98.334(b).
    (2) ASTM C114-09 Standard Test Methods for Chemical Analysis of 
Hydraulic Cement, IBR approved for Sec. 98.84(a), Sec. 98.84(b), and 
Sec. 98.84(c).
    (3) ASTM D235-02 (Reapproved 2007) Standard Specification for 
Mineral Spirits (Petroleum Spirits) (Hydrocarbon Dry Cleaning Solvent), 
IBR approved for Sec. 98.6.
    (4) ASTM D240-02 (Reapproved 2007) Standard Test Method for Heat of 
Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter, IBR approved 
for Sec. 98.254(e).
    (5) ASTM D388-05 Standard Classification of Coals by Rank, IBR 
approved for Sec. 98.6.
    (6) ASTM D910-07a Standard Specification for Aviation Gasolines, IBR 
approved for Sec. 98.6.
    (7) [Reserved]
    (8) ASTM D1826-94 (Reapproved 2003) Standard Test Method for 
Calorific (Heating) Value of Gases in Natural Gas Range by Continuous 
Recording Calorimeter, IBR approved for Sec. 98.254(e).
    (9) ASTM D1836-07 Standard Specification for Commercial Hexanes, IBR 
approved for Sec. 98.6.
    (10) ASTM D1945-03 Standard Test Method for Analysis of Natural Gas 
by Gas Chromatography, IBR approved for Sec. 98.74(c), Sec. 98.164(b), 
Sec. 98.244(b), Sec. 98.254(d), Sec. 98.324(d), Sec. 98.354(g), and 
Sec. 98.344(b).
    (11) ASTM D1946-90 (Reapproved 2006) Standard Practice for Analysis 
of Reformed Gas by Gas Chromatography, IBR approved for Sec. 98.74(c), 
Sec. 98.164(b), Sec. 98.254(d), Sec. 98.324(d), Sec. 98.344(b), 
Sec. 98.354(g), and Sec. 98.364(c).
    (12) ASTM D2013-07 Standard Practice for Preparing Coal Samples for 
Analysis, IBR approved for Sec. 98.164(b).
    (13) ASTM D2234/D2234M-07 Standard Practice for Collection of a 
Gross Sample of Coal, IBR approved for Sec. 98.164(b).
    (14) ASTM D2502-04 Standard Test Method for Estimation of Mean 
Relative Molecular Mass of Petroleum Oils From Viscosity Measurements, 
IBR approved for Sec. 98.74(c).

[[Page 592]]

    (15) ASTM D2503-92 (Reapproved 2007) Standard Test Method for 
Relative Molecular Mass (Molecular Weight) of Hydrocarbons by 
Thermoelectric Measurement of Vapor Pressure, IBR approved for Sec. 
98.74(c) and Sec. 98.254(d)(6).
    (16) ASTM D2505-88 (Reapproved 2004)e1 Standard Test Method for 
Ethylene, Other Hydrocarbons, and Carbon Dioxide in High-Purity Ethylene 
by Gas Chromatography, IBR approved for Sec. 98.244(b).
    (17) ASTM D2597-94 (Reapproved 2004) Standard Test Method for 
Analysis of Demethanized Hydrocarbon Liquid Mixtures Containing Nitrogen 
and Carbon Dioxide by Gas Chromatography, IBR approved for Sec. 
98.164(b).
    (18) ASTM D3176-89 (Reapproved 2002) Standard Practice for Ultimate 
Analysis of Coal and Coke, IBR approved for Sec. 98.74(c), Sec. 
98.164(b), Sec. 98.244(b), Sec. 98.254(i), Sec. 98.284(c), Sec. 
98.284(d), Sec. 98.314(c), Sec. 98.314(d), and Sec. 98.314(f).
    (19) ASTM D3238-95 (Reapproved 2005) Standard Test Method for 
Calculation of Carbon Distribution and Structural Group Analysis of 
Petroleum Oils by the n-d-M Method, IBR approved for Sec. 98.74(c) and 
Sec. 98.164(b).
    (20) ASTM D3588-98 (Reapproved 2003) Standard Practice for 
Calculating Heat Value, Compressibility Factor, and Relative Density of 
Gaseous Fuels, IBR approved for Sec. 98.254(e).
    (21) ASTM D3682-01 (Reapproved 2006) Standard Test Method for Major 
and Minor Elements in Combustion Residues from Coal Utilization 
Processes, IBR approved for Sec. 98.144(b).
    (22) ASTM D4057-06 Standard Practice for Manual Sampling of 
Petroleum and Petroleum Products, IBR approved for Sec. 98.164(b).
    (23) ASTM D4177-95 (Reapproved 2005) Standard Practice for Automatic 
Sampling of Petroleum and Petroleum Products, IBR approved for Sec. 
98.164(b).
    (24) ASTM D4809-06 Standard Test Method for Heat of Combustion of 
Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method), IBR 
approved for Sec. 98.254(e).
    (25) ASTM D4891-89 (Reapproved 2006) Standard Test Method for 
Heating Value of Gases in Natural Gas Range by Stoichiometric 
Combustion, IBR approved for Sec. 98.254(e) and Sec. 98.324(d).
    (26) ASTM D5291-02 (Reapproved 2007) Standard Test Methods for 
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in 
Petroleum Products and Lubricants, IBR approved for Sec. 98.74(c), 
Sec. 98.164(b), Sec. 98.244(b), and Sec. 98.254(i).
    (27) ASTM D5373-08 Standard Test Methods for Instrumental 
Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of 
Coal, IBR approved for Sec. 98.74(c), Sec. 98.114(b), Sec. 98.164(b), 
Sec. 98.174(b), Sec. 98.184(b), Sec. 98.244(b), Sec. 98.254(i), 
Sec. 98.274(b), Sec. 98.284(c), Sec. 98.284(d), Sec. 98.314(c), 
Sec. 98.314(d), Sec. 98.314(f), and Sec. 98.334(b).
    (28) [Reserved]
    (29) ASTM D6060-96 (Reapproved 2001) Standard Practice for Sampling 
of Process Vents With a Portable Gas Chromatograph, IBR approved for 
Sec. 98.244(b).
    (30) ASTM D6348-03 Standard Test Method for Determination of Gaseous 
Compounds by Extractive Direct Interface Fourier Transform Infrared 
(FTIR) Spectroscopy, IBR approved for Sec. 98.54(b), Table I-9 to 
subpart I of this part, Sec. 98.224(b), and Sec. 98.414(n).
    (31) ASTM D6609-08 Standard Guide for Part-Stream Sampling of Coal, 
IBR approved for Sec. 98.164(b).
    (32) ASTM D6751-08 Standard Specification for Biodiesel Fuel Blend 
Stock (B100) for Middle Distillate Fuels, IBR approved for Sec. 98.6.
    (33) ASTM D6866-08 Standard Test Methods for Determining the 
Biobased Content of Solid, Liquid, and Gaseous Samples Using Radiocarbon 
Analysis, IBR approved for Sec. 98.34(d), Sec. 98.34(e), and Sec. 
98.36(e).
    (34) ASTM D6883-04 Standard Practice for Manual Sampling of 
Stationary Coal from Railroad Cars, Barges, Trucks, or Stockpiles, IBR 
approved for Sec. 98.164(b).
    (35) ASTM D7430-08ae1 Standard Practice for Mechanical Sampling of 
Coal, IBR approved for Sec. 98.164(b).
    (36) ASTM D7459-08 Standard Practice for Collection of Integrated 
Samples for the Speciation of Biomass (Biogenic) and Fossil-Derived 
Carbon Dioxide Emitted from Stationary Emissions Sources, IBR approved 
for Sec. 98.34(d), Sec. 98.34(e), and Sec. 98.36(e).
    (37) ASTM E359-00 (Reapproved 2005)e1 Standard Test Methods for

[[Page 593]]

Analysis of Soda Ash (Sodium Carbonate), IBR approved for Sec. 
98.294(a) and Sec. 98.294(b).
    (38) ASTM E1019-08 Standard Test Methods for Determination of 
Carbon, Sulfur, Nitrogen, and Oxygen in Steel, Iron, Nickel, and Cobalt 
Alloys by Various Combustion and Fusion Techniques, IBR approved for 
Sec. 98.174(b).
    (39) [Reserved]
    (40) ASTM E1915-07a Standard Test Methods for Analysis of Metal 
Bearing Ores and Related Materials by Combustion Infrared-Absorption 
Spectrometry, IBR approved for Sec. 98.174(b).
    (41) ASTM E1941-04 Standard Test Method for Determination of Carbon 
in Refractory and Reactive Metals and Their Alloys, IBR approved for 
Sec. 98.114(b), Sec. 98.184(b), Sec. 98.334(b).
    (42) ASTM UOP539-97 Refinery Gas Analysis by Gas Chromatography, IBR 
approved for Sec. 98.164(b), Sec. 98.244(b), Sec. 98.254(d), Sec. 
98.324(d), Sec. 98.344(b), and Sec. 98.354(g).
    (43) ASTM D1941-91 (Reapproved 2007) Standard Test Method for Open 
Channel Flow Measurement of Water with the Parshall Flume, approved June 
15, 2007, IBR approved for Sec. 98.354(d).
    (44) ASTM D5614-94 (Reapproved 2008) Standard Test Method for Open 
Channel Flow Measurement of Water with Broad-Crested Weirs, approved 
October 1, 2008, IBR approved for Sec. 98.354(d).
    (45) ASTM D6349-09 Standard Test Method for Determination of Major 
and Minor Elements in Coal, Coke, and Solid Residues from Combustion of 
Coal and Coke by Inductively Coupled Plasma--Atomic Emission 
Spectrometry, IBR approved for Sec. 98.144(b).
    (46) ASTM D2879-97 (Reapproved 2007) Standard Test Method for Vapor 
Pressure-Temperature Relationship and Initial Decomposition Temperature 
of Liquids by Isoteniscope (ASTM D2879), approved May 1, 2007, IBR 
approved for Sec. 98.128.
    (47) ASTM D7359-08 Standard Test Method for Total Fluorine, Chlorine 
and Sulfur in Aromatic Hydrocarbons and Their Mixtures by Oxidative 
Pyrohydrolytic Combustion followed by Ion Chromatography Detection 
(Combustion Ion Chromatography-CIC) (ASTM D7359), approved October 15, 
2008, IBR approved for Sec. 98.124(e)(2).
    (48) ASTM D2593-93 (Reapproved 2009) Standard Test Method for 
Butadiene Purity and Hydrocarbon Impurities by Gas Chromatography, 
approved July 1, 2009, IBR approved for Sec. 98.244(b)(4)(xi).
    (49) ASTM D7633-10 Standard Test Method for Carbon Black--Carbon 
Content, approved May 15, 2010, IBR approved for Sec. 
98.244(b)(4)(xii).
    (f) The following material is available for purchase from the Gas 
Processors Association (GPA), 6526 East 60th Street, Tulsa, Oklahoma 
74143, (918) 493-3872, http://www.gasprocessors.com.
    (1) [Reserved]
    (2) GPA 2261-00 Analysis for Natural Gas and Similar Gaseous 
Mixtures by Gas Chromatography, IBR approved for Sec. 98.164(b), Sec. 
98.254(d), Sec. 98.344(b), and Sec. 98.354(g).
    (g) The following material is available for purchase from the 
International Standards Organization (ISO), 1, ch. de la Voie-Creuse, 
Case postale 56, CH-1211 Geneva 20, Switzerland, + 41 22 749 01 11, 
http://www.iso.org/iso/home.htm.
    (1) ISO 3170: Petroleum liquids--Manual sampling--Third Edition 
2004-02-01, IBR approved for Sec. 98.164(b).
    (2) ISO 3171: Petroleum Liquids--Automatic pipeline sampling--Second 
Edition 1988-12-01, IBR approved for Sec. 98.164(b).
    (3) [Reserved]
    (4) ISO/TR 15349-1: 1998, Unalloyed steel--Determination of low 
carbon content. Part 1: Infrared absorption method after combustion in 
an electric resistance furnace (by peak separation) (1998-10-15)--First 
Edition, IBR approved for Sec. 98.174(b).
    (5) ISO/TR 15349-3: 1998, Unalloyed steel--Determination of low 
carbon content. Part 3: Infrared absorption method after combustion in 
an electric resistance furnace (with preheating) (1998-10-15)--First 
Edition, IBR approved for Sec. 98.174(b).
    (h) The following material is available for purchase from the 
National Lime Association (NLA), 200 North Glebe Road, Suite 800, 
Arlington, Virginia 22203, (703) 243-5463, http://www.lime.org.
    (1) CO2 Emissions Calculation Protocol for the Lime 
Industry--English

[[Page 594]]

Units Version, February 5, 2008 Revision--National Lime Association, 
incorporation by reference (IBR) approved for Sec. 98.194(c) and Sec. 
98.194(e).
    (2) [Reserved]
    (i) The following material is available for purchase from the 
National Institute of Standards and Technology (NIST), 100 Bureau Drive, 
Stop 1070, Gaithersburg, MD 20899-1070, (800) 877-8339, http://
www.nist.gov/index.html.
    (1) Specifications, Tolerances, and Other Technical Requirements For 
Weighing and Measuring Devices, NIST Handbook 44 (2009), incorporation 
by reference (IBR) approved for Sec. 98.244(b), Sec. 98.254(h), and 
Sec. 98.344(a).
    (2) [Reserved]
    (j) The following material is available for purchase from the 
Technical Association of the Pulp and Paper Industry (TAPPI), 15 
Technology Parkway South, Norcross, GA 30092, (800) 332-8686, http://
www.tappi.org.
    (1) T650 om-05 Solids Content of Black Liquor, TAPPI, incorporation 
by reference (IBR) approved for Sec. 98.276(c) and Sec. 98.277(d).
    (2) T684 om-06 Gross Heating Value of Black Liquor, TAPPI, 
incorporation by reference (IBR) approved for Sec. 98.274(b).
    (k) The following material is available for purchase from Standard 
Methods, at http://www.standardmethods.org, (877) 574-1233; or, through 
a joint publication agreement from the American Public Health 
Association (APHA), P.O. Box 933019, Atlanta, GA 31193-3019, (888) 320-
APHA (2742), http://www.apha.org/publications/pubscontact/.
    (1) Method 2540G Total, Fixed, and Volatile Solids in Solid and 
Semisolid Samples, IBR approved for Sec. 98.464(b).
    (2) [Reserved]
    (l) The following material is available from the U.S. Department of 
Labor, Mine Safety and Health Administration, 1100 Wilson Boulevard, 
21st Floor, Arlington, VA 22209-3939, (202) 693-9400, http://
www.msha.gov.
    (1) General Coal Mine Inspection Procedures and Inspection Tracking 
System, Handbook Number: PH-08-V-1, January 1, 2008, IBR approved for 
Sec. 98.324(b).
    (2) [Reserved]
    (m) The following material is available from the U.S. Environmental 
Protection Agency, 1200 Pennsylvania Avenue, NW., Washington, DC 20460, 
(202) 272-0167, http://www.epa.gov.
    (1) NPDES Compliance Inspection Manual, Chapter 5, Sampling, EPA 
305-X-04-001, July 2004, http://www.epa.gov/compliance/monitoring/
programs/cwa/npdes.html, IBR approved for Sec. 98.354(c).
    (2) U.S. EPA NPDES Permit Writers' Manual, Section 7.1.3, Sample 
Collection Methods, EPA 833-B-96-003, December 1996, http://www.epa.gov/
npdes/pubs/owm0243.pdf, IBR approved for Sec. 98.354(c).
    (3) Protocol for Measuring Destruction or Removal Efficiency (DRE) 
of Fluorinated Greenhouse Gas Abatement Equipment in Electronics 
Manufacturing, Version 1, EPA-430-R-10-003, March 2010 (EPA 430-R-10-
003), http://www.epa.gov/semiconductor-pfc/documents/dre--protocol.pdf, 
IBR approved for Sec. 98.94(f)(4)(i), Sec. 98.94(g)(3), Sec. 
98.97(d)(4), Sec. 98.98, Appendix A to subpart I of this part, Sec. 
98.124(e)(2), and Sec. 98.414(n)(1).
    (4) Emissions Inventory Improvement Program, Volume II: Chapter 16, 
Methods for Estimating Air Emissions from Chemical Manufacturing 
Facilities, August 2007, Final, http://www.epa.gov/ttnchie1/eiip/
techreport/volume02/index.html, IBR approved for Sec. 
98.123(c)(1)(i)(A).
    (5) Protocol for Equipment Leak Emission Estimates, EPA-453/R-95-
017, November 1995 (EPA-453/R-95-017), http://www.epa.gov/ttnchie1/
efdocs/equiplks.pdf, IBR approved for Sec. 98.123(d)(1)(i), Sec. 
98.123(d)(1)(ii), Sec. 98.123(d)(1)(iii), and Sec. 98.124(f)(2).
    (6) Tracer Gas Protocol for the Determination of Volumetric Flow 
Rate Through the Ring Pipe of the Xact Multi-Metals Monitoring System, 
also known as Other Test Method 24 (Tracer Gas Protocol), Eli Lilly and 
Company Tippecanoe Laboratories, September 2006, http://www.epa.gov/ttn/
emc/prelim/otm24.pdf, IBR approved for Sec. 98.124(e)(1)(ii).
    (7) Approved Alternative Method 012: An Alternate Procedure for 
Stack Gas Volumetric Flow Rate Determination (Tracer Gas) (ALT-012), 
U.S. Environmental Protection Agency Emission Measurement Center, May 
23, 1994, http://www.epa.gov/ttn/emc/approalt/alt-012.pdf, IBR approved 
for Sec. 98.124(e)(1)(ii).

[[Page 595]]

    (8) Protocol for Measurement of Tetrafluoromethane (CF4) 
and Hexafluoroethane (C2F6) Emissions from Primary 
Aluminum Production (2008), http://www.epa.gov/highgwp/aluminum-pfc/
documents/measureprotocol.pdf, IBR approved for Sec. 98.64(a).
    (9) AP 42, Section 5.2, Transportation and Marketing of Petroleum 
Liquids, July 2008, (AP 42, Section 5.2); http://www.epa.gov/ttn/chief/
ap42/ch05/final/c05s02.pdf; in Chapter 5, Petroleum Industry, of AP 42, 
Compilation of Air Pollutant Emission Factors, 5th Edition, Volume I, 
IBR approved for Sec. 98.253(n).
    (10) Method 9060A, Total Organic Carbon, Revision 1, November 2004 
(Method 9060A), http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/
9060a.pdf; in EPA Publication No. SW-846, ``Test Methods for Evaluating 
Solid Waste, Physical/Chemical Methods,'' Third Edition, IBR approved 
for Sec. 98.244(b)(4)(viii).
    (11) Method 8031, Acrylonitrile By Gas Chromatography, Revision 0, 
September 1994 (Method 8031), http://www.epa.gov/osw/hazard/testmethods/
sw846/pdfs/8031.pdf; in EPA Publication No. SW-846, ``Test Methods for 
Evaluating Solid Waste, Physical/Chemical Methods,'' Third Edition, IBR 
approved for Sec. 98.244(b)(4)(viii).
    (12) Method 8021B, Aromatic and Halogenated Volatiles By Gas 
Chromatography Using Photoionization and/or Electrolytic Conductivity 
Detectors, Revision 2, December 1996 (Method 8021B). http://www.epa.gov/
osw/hazard/testmethods/sw846/pdfs/8021b.pdf; in EPA Publication No. SW-
846, ``Test Methods for Evaluating Solid Waste, Physical/Chemical 
Methods,'' Third Edition, IBR approved for Sec. 98.244(b)(4)(viii).
    (13) Method 8015C, Nonhalogenated Organics By Gas Chromatography, 
Revision 3, February 2007 (Method 8015C). http://www.epa.gov/osw/hazard/
testmethods/sw846/pdfs/8015c.pdf; in EPA Publication No. SW-846, ``Test 
Methods for Evaluating Solid Waste, Physical/Chemical Methods,'' Third 
Edition, IBR approved for Sec. 98.244(b)(4)(viii).
    (14) AP 42, Section 7.1, Organic Liquid Storage Tanks, November 2006 
(AP 42, Section 7.1), http://www.epa.gov/ttn/chief/ap42/ch07/final/
c07s01.pdf; in Chapter 7, Liquid Storage Tanks, of AP 42, Compilation of 
Air Pollutant Emission Factors, 5th Edition, Volume I, IBR approved for 
Sec. 98.253(m)(1) and Sec. 98.256(o)(2)(i).
    (n)-(o) [Reserved]
    (p) The following material is available for purchase from the 
American Association of Petroleum Geologists, 1444 South Boulder Avenue, 
Tulsa, Oklahoma 74119, (918) 584-2555, http://www.aapg.org.
    (1) Geologic Note: AAPG-CSD Geologic Provinces Code Map: AAPG 
Bulletin, Prepared by Richard F. Meyer, Laure G. Wallace, and Fred J. 
Wagner, Jr., Volume 75, Number 10 (October 1991), pages 1644-1651, IBR 
approved for Sec. 98.238.
    (2) Alaska Geological Province Boundary Map, Compiled by the 
American Association of Petroleum Geologists Committee on Statistics of 
Drilling in cooperation with the USGS, 1978, IBR approved for Sec. 
98.238.
    (q) The following material is available from the Energy Information 
Administration (EIA), 1000 Independence Ave., SW., Washington, DC 20585, 
(202) 586-8800, http://www.eia.doe.gov/pub/oil--gas/natural--gas/data--
publications/field--code--master--list/current/pdf/fcml--all.pdf.
    (1) Oil and Gas Field Code Master List 2008, DOE/EIA0370(08), 
January 2009, IBR approved for Sec. 98.238.
    (2) [Reserved]

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 39759, July 12, 2010; 
75 FR 66458, Oct. 28, 2010; 75 FR 74488, Nov. 30, 2010; 75 FR 74816, 
Dec. 1, 2010; 75 FR 79138, Dec. 17, 2010; 78 FR 68202, Nov. 13, 2013; 78 
FR 71948, Nov. 29, 2013]



Sec. 98.8  What are the compliance and enforcement provisions of 
this part?

    Any violation of any requirement of this part shall be a violation 
of the Clean Air Act, including section 114 (42 U.S.C. 7414). A 
violation includes but is not limited to failure to report GHG 
emissions, failure to collect data needed to calculate GHG emissions, 
failure to continuously monitor and test as required, failure to retain 
records needed to verify the amount of GHG emissions, and failure to 
calculate GHG emissions following the methodologies specified in this 
part. Each day of a violation constitutes a separate violation.

[[Page 596]]



Sec. 98.9  Addresses.

    All requests, notifications, and communications to the Administrator 
pursuant to this part must be submitted electronically and in a format 
as specified by the Administrator. For example, any requests, 
notifications and communications that can be submitted through the 
electronic GHG reporting tool, must be submitted through that tool. If 
not specified, requests, notifications or communications shall be 
submitted to the following address:
    (a) For U.S. mail. Director, Climate Change Division, 1200 
Pennsylvania Ave., NW., Mail Code: 6207J, Washington, DC 20460.
    (b) For package deliveries. Director, Climate Change Division, 1310 
L St, NW., Washington, DC 20005.

[74 FR 56374, Oct. 30, 2009, as amended at 76 FR 73900, Nov. 29, 2011]



    Sec. Table A-1 to Subpart A of Part 98--Global Warming Potentials

                                             [100-Year Time Horizon]
----------------------------------------------------------------------------------------------------------------
                                                                                                  Global warming
                     Name                           CAS No.             Chemical formula          potential (100
                                                                                                       yr.)
----------------------------------------------------------------------------------------------------------------
                                             Chemical-Specific GWPs
----------------------------------------------------------------------------------------------------------------
Carbon dioxide................................        124-38-9  CO2.............................               1
Methane.......................................         74-82-8  CH4.............................          \a\ 25
Nitrous oxide.................................      10024-97-2  N2O.............................         \a\ 298
----------------------------------------------------------------------------------------------------------------
                                             Fully Fluorinated GHGs
----------------------------------------------------------------------------------------------------------------
Sulfur hexafluoride...........................       2551-62-4  SF6.............................      \a\ 22,800
Trifluoromethyl sulphur pentafluoride.........        373-80-8  SF5CF3..........................          17,700
Nitrogen trifluoride..........................       7783-54-2  NF3.............................          17,200
PFC-14 (Perfluoromethane).....................         75-73-0  CF4.............................       \a\ 7,390
PFC-116 (Perfluoroethane).....................         76-16-4  C2F6............................      \a\ 12,200
PFC-218 (Perfluoropropane)....................         76-19-7  C3F8............................       \a\ 8,830
Perfluorocyclopropane.........................        931-91-9  C-C3F6..........................          17,340
PFC-3-1-10 (Perfluorobutane)..................        355-25-9  C4F10...........................       \a\ 8,860
PFC-318 (Perfluorocyclobutane)................        115-25-3  C-C4F8..........................      \a\ 10,300
PFC-4-1-12 (Perfluoropentane).................        678-26-2  C5F12...........................       \a\ 9,160
PFC-5-1-14 (Perfluorohexane, FC-72)...........        355-42-0  C6F14...........................       \a\ 9,300
PFC-6-1-12....................................        335-57-9  C7F16; CF3(CF2)5CF3.............       \b\ 7,820
PFC-7-1-18....................................        307-34-6  C8F18; CF3(CF2)6CF3.............       \b\ 7,620
PFC-9-1-18....................................        306-94-5  C10F18..........................           7,500
PFPMIE (HT-70)................................              NA  CF3OCF(CF3)CF2OCF2OCF3..........          10,300
Perfluorodecalin (cis)........................      60433-11-6  Z-C10F18........................       \b\ 7,236
Perfluorodecalin (trans)......................      60433-12-7  E-C10F18........................       \b\ 6,288
----------------------------------------------------------------------------------------------------------------
                   Saturated Hydrofluorocarbons (HFCs) With Two or Fewer Carbon-Hydrogen Bonds
----------------------------------------------------------------------------------------------------------------
HFC-23........................................         75-46-7  CHF3............................      \a\ 14,800
HFC-32........................................         75-10-5  CH2F2...........................         \a\ 675
HFC-125.......................................        354-33-6  C2HF5...........................       \a\ 3,500
HFC-134.......................................        359-35-3  C2H2F4..........................       \a\ 1,100
HFC-134a......................................        811-97-2  CH2FCF3.........................       \a\ 1,430
HFC-227ca.....................................       2252-84-8  CF3CF2CHF2......................        \b\ 2640
HFC-227ea.....................................        431-89-0  C3HF7...........................       \a\ 3,220
HFC-236cb.....................................        677-56-5  CH2FCF2CF3......................           1,340
HFC-236ea.....................................        431-63-0  CHF2CHFCF3......................           1,370
HFC-236fa.....................................        690-39-1  C3H2F6..........................       \a\ 9,810
HFC-329p......................................        375-17-7  CHF2CF2CF2CF3...................        \b\ 2360
HFC-43-10mee..................................     138495-42-8  CF3CFHCFHCF2CF3.................       \a\ 1,640
----------------------------------------------------------------------------------------------------------------
                  Saturated Hydrofluorocarbons (HFCs) With Three or More Carbon-Hydrogen Bonds
----------------------------------------------------------------------------------------------------------------
HFC-41........................................        593-53-3  CH3F............................          \a\ 92
HFC-143.......................................        430-66-0  C2H3F3..........................         \a\ 353
HFC-143a......................................        420-46-2  C2H3F3..........................       \a\ 4,470
HFC-152.......................................        624-72-6  CH2FCH2F........................              53
HFC-152a......................................         75-37-6  CH3CHF2.........................         \a\ 124
HFC-161.......................................        353-36-6  CH3CH2F.........................              12
HFC-245ca.....................................        679-86-7  C3H3F5..........................         \a\ 693
HFC-245cb.....................................       1814-88-6  CF3CF2CH3.......................        \b\ 4620

[[Page 597]]

 
HFC-245ea.....................................      24270-66-4  CHF2CHFCHF2.....................         \b\ 235
HFC-245eb.....................................        431-31-2  CH2FCHFCF3......................         \b\ 290
HFC-245fa.....................................        460-73-1  CHF2CH2CF3......................           1,030
HFC-263fb.....................................        421-07-8  CH3CH2CF3.......................          \b\ 76
HFC-272ca.....................................        420-45-1  CH3CF2CH3.......................         \b\ 144
HFC-365mfc....................................        406-58-6  CH3CF2CH2CF3....................             794
----------------------------------------------------------------------------------------------------------------
      Saturated Hydrofluoroethers (HFEs) and Hydrochlorofluoroethers (HCFEs) With One Carbon-Hydrogen Bond
----------------------------------------------------------------------------------------------------------------
HFE-125.......................................       3822-68-2  CHF2OCF3........................          14,900
HFE-227ea.....................................       2356-62-9  CF3CHFOCF3......................           1,540
HFE-329mcc2...................................     134769-21-4  CF3CF2OCF2CHF2..................             919
HFE-329me3....................................     428454-68-6  CF3CFHCF2OCF3...................       \b\ 4,550
1,1,1,2,2,3,3-Heptafluoro-3-(1,2,2,2-                3330-15-2  CF3CF2CF2OCHFCF3................       \b\ 6,490
 tetrafluoroethoxy)-propane.
----------------------------------------------------------------------------------------------------------------
                             Saturated HFEs and HCFEs With Two Carbon-Hydrogen Bonds
----------------------------------------------------------------------------------------------------------------
HFE-134 (HG-00)...............................       1691-17-4  CHF2OCHF2.......................           6,320
HFE-236ca.....................................      32778-11-3  CHF2OCF2CHF2....................       \b\ 4,240
HFE-236ca12 (HG-10)...........................      78522-47-1  CHF2OCF2OCHF2...................           2,800
HFE-236ea2 (Desflurane).......................      57041-67-5  CHF2OCHFCF3.....................             989
HFE-236fa.....................................      20193-67-3  CF3CH2OCF3......................             487
HFE-338mcf2...................................     156053-88-2  CF3CF2OCH2CF3...................             552
HFE-338mmz1...................................      26103-08-2  CHF2OCH(CF3)2...................             380
HFE-338pcc13 (HG-01)..........................     188690-78-0  CHF2OCF2CF2OCHF2................           1,500
HFE-43-10pccc (H-Galden 1040x, HG-11).........        E1730133  CHF2OCF2OC2F4OCHF2..............           1,870
HCFE-235ca2 (Enflurane).......................      13838-16-9  CHF2OCF2CHFCl...................         \b\ 583
HCFE-235da2 (Isoflurane)......................      26675-46-7  CHF2OCHClCF3....................             350
HG-02.........................................     205367-61-9  HF2C-(OCF2CF2)2-OCF2H...........       \b\ 3,825
HG-03.........................................     173350-37-3  HF2C-(OCF2CF2)3-OCF2H...........       \b\ 3,670
HG-20.........................................     249932-25-0  HF2C-(OCF2)2-OCF2H..............       \b\ 5,300
HG-21.........................................     249932-26-1  HF2C-OCF2CF2OCF2OCF2O-CF2H......       \b\ 3,890
HG-30.........................................     188690-77-9  HF2C-(OCF2)3-OCF2H..............       \b\ 7,330
1,1,3,3,4,4,6,6,7,7,9,9,10,10,12,12,13,13,15,1     173350-38-4  HCF2O(CF2CF2O)4CF2H.............       \b\ 3,630
 5-eicosafluoro-2,5,8,11,14-
 Pentaoxapentadecane.
1,1,2-Trifluoro-2-(trifluoromethoxy)-ethane...      84011-06-3  CHF2CHFOCF3.....................       \b\ 1,240
Trifluoro(fluoromethoxy)methane...............       2261-01-0  CH2FOCF3........................         \b\ 751
----------------------------------------------------------------------------------------------------------------
                        Saturated HFEs and HCFEs With Three or More Carbon-Hydrogen Bonds
----------------------------------------------------------------------------------------------------------------
HFE-143a......................................        421-14-7  CH3OCF3.........................             756
HFE-245cb2....................................      22410-44-2  CH3OCF2CF3......................             708
HFE-245fa1....................................      84011-15-4  CHF2CH2OCF3.....................             286
HFE-245fa2....................................       1885-48-9  CHF2OCH2CF3.....................             659
HFE-254cb2....................................        425-88-7  CH3OCF2CHF2.....................             359
HFE-263fb2....................................        460-43-5  CF3CH2OCH3......................              11
HFE-263m1; R-E-143a...........................        690-22-2  CF3OCH2CH3......................          \b\ 29
HFE-347mcc3 (HFE-7000)........................        375-03-1  CH3OCF2CF2CF3...................             575
HFE-347mcf2...................................     171182-95-9  CF3CF2OCH2CHF2..................             374
HFE-347mmy1...................................      22052-84-2  CH3OCF(CF3)2....................             343
HFE-347mmz1 (Sevoflurane).....................      28523-86-6  (CF3)2CHOCH2F...................         \c\ 216
HFE-347pcf2...................................        406-78-0  CHF2CF2OCH2CF3..................             580
HFE-356mec3...................................        382-34-3  CH3OCF2CHFCF3...................             101
HFE-356mff2...................................        333-36-8  CF3CH2OCH2CF3...................          \b\ 17
HFE-356mmz1...................................      13171-18-1  (CF3)2CHOCH3....................              27
HFE-356pcc3...................................     160620-20-2  CH3OCF2CF2CHF2..................             110
HFE-356pcf2...................................      50807-77-7  CHF2CH2OCF2CHF2.................             265
HFE-356pcf3...................................      35042-99-0  CHF2OCH2CF2CHF2.................             502
HFE-365mcf2...................................      22052-81-9  CF3CF2OCH2CH3...................          \b\ 58
HFE-365mcf3...................................        378-16-5  CF3CF2CH2OCH3...................              11
HFE-374pc2....................................        512-51-6  CH3CH2OCF2CHF2..................             557
HFE-449s1 (HFE-7100) Chemical blend...........     163702-07-6  C4F9OCH3........................             297
                                                   163702-08-7  (CF3)2CFCF2OCH3.................
HFE-569sf2 (HFE-7200) Chemical blend..........     163702-05-4  C4F9OC2H5.......................              59
                                                   163702-06-5  (CF3)2CFCF2OC2H5................
HG'-01........................................      73287-23-7  CH3OCF2CF2OCH3..................         \b\ 222
HG'-02........................................     485399-46-0  CH3O(CF2CF2O)2CH3...............         \b\ 236
HG'-03........................................     485399-48-2  CH3O(CF2CF2O)3CH3...............         \b\ 221

[[Page 598]]

 
Difluoro(methoxy)methane......................        359-15-9  CH3OCHF2........................         \b\ 144
2-Chloro-1,1,2-trifluoro-1-methoxyethane......        425-87-6  CH3OCF2CHFCl....................         \b\ 122
1-Ethoxy-1,1,2,2,3,3,3-heptafluoropropane.....      22052-86-4  CF3CF2CF2OCH2CH3................          \b\ 61
2-Ethoxy-3,3,4,4,5-pentafluorotetrahydro-2,5-      920979-28-8  C12H5F19O2......................          \b\ 56
 bis[1,2,2,2-tetrafluoro-1-
 (trifluoromethyl)ethyl]-furan.
1-Ethoxy-1,1,2,3,3,3-hexafluoropropane........        380-34-7  CF3CHFCF2OCH2CH3................          \b\ 23
Fluoro(methoxy)methane........................        460-22-0  CH3OCH2F........................          \b\ 13
1,1,2,2-Tetrafluoro-3-methoxy-propane; Methyl       60598-17-6  CHF2CF2CH2OCH3..................         \b\ 0.5
 2,2,3,3-tetrafluoropropyl ether.
1,1,2,2-Tetrafluoro-1-(fluoromethoxy)ethane...      37031-31-5  CH2FOCF2CF2H....................         \b\ 871
Difluoro(fluoromethoxy)methane................        461-63-2  CH2FOCHF2.......................         \b\ 617
Fluoro(fluoromethoxy)methane..................        462-51-1  CH2FOCH2F.......................         \b\ 130
----------------------------------------------------------------------------------------------------------------
                                              Fluorinated Formates
----------------------------------------------------------------------------------------------------------------
Trifluoromethyl formate.......................      85358-65-2  HCOOCF3.........................         \b\ 588
Perfluoroethyl formate........................     313064-40-3  HCOOCF2CF3......................         \b\ 580
1,2,2,2-Tetrafluoroethyl formate..............     481631-19-0  HCOOCHFCF3......................         \b\ 470
Perfluorobutyl formate........................     197218-56-7  HCOOCF2CF2CF2CF3................         \b\ 392
Perfluoropropyl formate.......................     271257-42-2  HCOOCF2CF2CF3...................         \b\ 376
1,1,1,3,3,3-Hexafluoropropan-2-yl formate.....     856766-70-6  HCOOCH(CF3)2....................         \b\ 333
2,2,2-Trifluoroethyl formate..................      32042-38-9  HCOOCH2CF3......................          \b\ 33
3,3,3-Trifluoropropyl formate.................    1344118-09-7  HCOOCH2CH2CF3...................          \b\ 17
----------------------------------------------------------------------------------------------------------------
                                              Fluorinated Acetates
----------------------------------------------------------------------------------------------------------------
Methyl 2,2,2-trifluoroacetate.................        431-47-0  CF3COOCH3.......................          \b\ 52
1,1-Difluoroethyl 2,2,2-trifluoroacetate......    1344118-13-3  CF3COOCF2CH3....................          \b\ 31
Difluoromethyl 2,2,2-trifluoroacetate.........       2024-86-4  CF3COOCHF2......................          \b\ 27
2,2,2-Trifluoroethyl 2,2,2-trifluoroacetate...        407-38-5  CF3COOCH2CF3....................           \b\ 7
Methyl 2,2-difluoroacetate....................        433-53-4  HCF2COOCH3......................           \b\ 3
Perfluoroethyl acetate........................     343269-97-6  CH3COOCF2CF3....................         \b\ 2.1
Trifluoromethyl acetate.......................      74123-20-9  CH3COOCF3.......................         \b\ 2.0
Perfluoropropyl acetate.......................    1344118-10-0  CH3COOCF2CF2CF3.................         \b\ 1.8
Perfluorobutyl acetate........................     209597-28-4  CH3COOCF2CF2CF2CF3..............         \b\ 1.6
Ethyl 2,2,2-trifluoroacetate..................        383-63-1  CF3COOCH2CH3....................         \b\ 1.3
----------------------------------------------------------------------------------------------------------------
                                               Carbonofluoridates
----------------------------------------------------------------------------------------------------------------
Methyl carbonofluoridate......................       1538-06-3  FCOOCH3.........................          \b\ 95
1,1-Difluoroethyl carbonofluoridate...........    1344118-11-1  FCOOCF2CH3......................          \b\ 27
----------------------------------------------------------------------------------------------------------------
                             Fluorinated Alcohols Other Than Fluorotelomer Alcohols
----------------------------------------------------------------------------------------------------------------
Bis(trifluoromethyl)-methanol.................        920-66-1  (CF3)2CHOH......................             195
(Octafluorotetramethy-lene) hydroxymethyl                   NA  X-(CF2)4CH(OH)-X................              73
 group.
2,2,3,3,3-Pentafluoropropanol.................        422-05-9  CF3CF2CH2OH.....................              42
2,2,3,3,4,4,4-Heptafluorobutan-1-ol...........        375-01-9  C3F7CH2OH.......................          \b\ 25
2,2,2-Trifluoroethanol........................         75-89-8  CF3CH2OH........................          \b\ 20
2,2,3,4,4,4-Hexafluoro-1-butanol..............        382-31-0  CF3CHFCF2CH2OH..................          \b\ 17
2,2,3,3-Tetrafluoro-1-propanol................         76-37-9  CHF2CF2CH2OH....................          \b\ 13
2,2-Difluoroethanol...........................        359-13-7  CHF2CH2OH.......................           \b\ 3
2-Fluoroethanol...............................        371-62-0  CH2FCH2OH.......................         \b\ 1.1
4,4,4-Trifluorobutan-1-ol.....................        461-18-7  CF3(CH2)2CH2OH..................        \b\ 0.05
----------------------------------------------------------------------------------------------------------------
                                       Unsaturated Perfluorocarbons (PFCs)
----------------------------------------------------------------------------------------------------------------
PFC-1114; TFE.................................        116-14-3  CF2 = CF2; C2F4.................       \b\ 0.004
PFC-1216; Dyneon HFP..........................        116-15-4  C3F6; CF3CF = CF2...............        \b\ 0.05
PFC C-1418....................................        559-40-0  c-C5F8..........................        \b\ 1.97
Perfluorobut-2-ene............................        360-89-4  CF3CF = CFCF3...................        \b\ 1.82
Perfluorobut-1-ene............................        357-26-6  CF3CF2CF = CF2..................        \b\ 0.10
Perfluorobuta-1,3-diene.......................        685-63-2  CF2 = CFCF = CF2................       \b\ 0.003
----------------------------------------------------------------------------------------------------------------
                   Unsaturated Hydrofluorocarbons (HFCs) and Hydrochlorofluorocarbons (HCFCs)
----------------------------------------------------------------------------------------------------------------
HFC-1132a; VF2................................         75-38-7  C2H2F2 , CF2 = CH2..............        \b\ 0.04
HFC-1141; VF..................................         75-02-5  C2H3F, CH2 = CHF................        \b\ 0.02
(E)-HFC-1225ye................................       5595-10-8  CF3CF = CHF(E)..................        \b\ 0.06
(Z)-HFC-1225ye................................       5528-43-8  CF3CF = CHF(Z)..................        \b\ 0.22

[[Page 599]]

 
Solstice 1233zd(E)............................     102687-65-0  C3H2ClF3; CHCl = CHCF3..........        \b\ 1.34
HFC-1234yf; HFO-1234yf........................        754-12-1  C3H2F4; CF3CF = CH2.............        \b\ 0.31
HFC-1234ze(E).................................       1645-83-6  C3H2F4; trans-CF3CH = CHF.......        \b\ 0.97
HFC-1234ze(Z).................................      29118-25-0  C3H2F4; cis-CF3CH = CHF; CF3CH =        \b\ 0.29
                                                                 CHF.
HFC-1243zf; TFP...............................        677-21-4  C3H3F3, CF3CH = CH2.............        \b\ 0.12
(Z)-HFC-1336..................................        692-49-9  CF3CH = CHCF3(Z)................        \b\ 1.58
HFC-1345zfc...................................        374-27-6  C2F5CH = CH2....................        \b\ 0.09
Capstone 42-U.................................      19430-93-4  C6H3F9, CF3(CF2)3CH = CH2.......        \b\ 0.16
Capstone 62-U.................................      25291-17-2  C8H3F13, CF3(CF2)5CH = CH2......        \b\ 0.11
Capstone 82-U.................................      21652-58-4  C10H3F17, CF3(CF2)7CH = CH2.....        \b\ 0.09
----------------------------------------------------------------------------------------------------------------
                                         Unsaturated Halogenated Ethers
----------------------------------------------------------------------------------------------------------------
PMVE; HFE-216.................................       1187-93-5  CF3OCF = CF2....................        \b\ 0.17
Fluoroxene....................................        406-90-6  CF3CH2OCH = CH2.................        \b\ 0.05
----------------------------------------------------------------------------------------------------------------
                                              Fluorinated Aldehydes
----------------------------------------------------------------------------------------------------------------
3,3,3-Trifluoro-propanal......................        460-40-2  CF3CH2CHO.......................        \b\ 0.01
----------------------------------------------------------------------------------------------------------------
                                               Fluorinated Ketones
----------------------------------------------------------------------------------------------------------------
Novec 1230 (perfluoro (2-methyl-3-pentanone)).        756-13-8  CF3CF2C(O)CF (CF3)2.............         \b\ 0.1
----------------------------------------------------------------------------------------------------------------
                                             Fluorotelomer Alcohols
----------------------------------------------------------------------------------------------------------------
3,3,4,4,5,5,6,6,7,7,7-Undecafluoroheptan-1-ol.     185689-57-0  CF3(CF2)4CH2CH2OH...............        \b\ 0.43
3,3,3-Trifluoropropan-1-ol....................       2240-88-2  CF3CH2CH2OH.....................        \b\ 0.35
3,3,4,4,5,5,6,6,7,7,8,8,9,9,9-                        755-02-2  CF3(CF2)6CH2CH2OH...............        \b\ 0.33
 Pentadecafluorononan-1-ol.
3,3,4,4,5,5,6,6,7,7,8,8,9,9,10,10,11,11,11-         87017-97-8  CF3(CF2)8CH2CH2OH...............        \b\ 0.19
 Nonadecafluoroundecan-1-ol.
----------------------------------------------------------------------------------------------------------------
                                   Fluorinated GHGs With Carbon-Iodine Bond(s)
----------------------------------------------------------------------------------------------------------------
Trifluoroiodomethane..........................       2314-97-8  CF3I............................         \b\ 0.4
----------------------------------------------------------------------------------------------------------------
                                           Other Fluorinated Compounds
----------------------------------------------------------------------------------------------------------------
Dibromodifluoromethane (Halon 1202)...........         75-61-6  CBR2F2..........................         \b\ 231
2-Bromo-2-chloro-1,1,1-trifluoroethane (Halon-        151-67-7  CHBrClCF3.......................          \b\ 41
 2311/Halothane).
----------------------------------------------------------------------------------------------------------------


 
                                                          Global warming
                Fluorinated GHG Group \d\                 potential (100
                                                               yr.)
------------------------------------------------------------------------
   Default GWPs for Compounds for Which Chemical-Specific GWPs Are Not
                              Listed Above
------------------------------------------------------------------------
Fully fluorinated GHGs..................................          10,000
Saturated hydrofluorocarbons (HFCs) with 2 or fewer                3,700
 carbon-hydrogen bonds..................................
Saturated HFCs with 3 or more carbon-hydrogen bonds.....             930
Saturated hydrofluoroethers (HFEs) and                             5,700
 hydrochlorofluoroethers (HCFEs) with 1 carbon-hydrogen
 bond...................................................
Saturated HFEs and HCFEs with 2 carbon-hydrogen bonds...           2,600
Saturated HFEs and HCFEs with 3 or more carbon-hydrogen              270
 bonds..................................................
Fluorinated formates....................................             350
Fluorinated acetates, carbonofluoridates, and                         30
 fluorinated alcohols other than fluorotelomer alcohols.
Unsaturated perfluorocarbons (PFCs), unsaturated HFCs,                 1
 unsaturated hydrochlorofluorocarbons (HCFCs),
 unsaturated halogenated ethers, unsaturated halogenated
 esters, fluorinated aldehydes, and fluorinated ketones.
Fluorotelomer alcohols..................................               1
Fluorinated GHGs with carbon-iodine bond(s).............               1
Other fluorinated GHGs..................................           2,000
------------------------------------------------------------------------
\a\ The GWP for this compound was updated in the final rule published on
  November 29, 2013 [78 FR 71904] and effective on January 1, 2014.
\b\ This compound was added to Table A-1 in the final rule published on
  December 11, 2014, and effective on January 1, 2015.
\c\ The GWP for this compound was updated in the final rule published on
  December 11, 2014, and effective on January 1, 2015 .
\d\ For electronics manufacturing (as defined in Sec. 98.90), the term
  ``fluorinated GHGs'' in the definition of each fluorinated GHG group
  in Sec. 98.6 shall include fluorinated heat transfer fluids (as
  defined in Sec. 98.98), whether or not they are also fluorinated
  GHGs.


[[Page 600]]


[79 FR 73779, Dec. 11, 2014]



  Sec. Table A-2 to Subpart A of Part 98--Units of Measure Conversions

----------------------------------------------------------------------------------------------------------------
             To convert from                             To                             Multiply by
----------------------------------------------------------------------------------------------------------------
Kilograms (kg)..........................  Pounds (lbs)...................  2.20462
Pounds (lbs)............................  Kilograms (kg).................  0.45359
Pounds (lbs)............................  Metric tons....................  4.53592 x 10-4
Short tons..............................  Pounds (lbs)...................  2,000
Short tons..............................  Metric tons....................  0.90718
Metric tons.............................  Short tons.....................  1.10231
Metric tons.............................  Kilograms (kg).................  1,000
Cubic meters (m\3\).....................  Cubic feet (ft\3\).............  35.31467
Cubic feet (ft\3\)......................  Cubic meters (m\3\)............  0.028317
Gallons (liquid, US)....................  Liters (l).....................  3.78541
Liters (l)..............................  Gallons (liquid, US)...........  0.26417
Barrels of Liquid Fuel (bbl)............  Cubic meters (m\3\)............  0.15891
Cubic meters (m\3\).....................  Barrels of Liquid Fuel (bbl)...  6.289
Barrels of Liquid Fuel (bbl)............  Gallons (liquid, US)...........  42
Gallons (liquid, US)....................  Barrels of Liquid Fuel (bbl)...  0.023810
Gallons (liquid, US)....................  Cubic meters (m\3\)............  0.0037854
Liters (l)..............................  Cubic meters (m\3\)............  0.001
Feet (ft)...............................  Meters (m).....................  0.3048
Meters (m)..............................  Feet (ft)......................  3.28084
Miles (mi)..............................  Kilometers (km)................  1.60934
Kilometers (km).........................  Miles (mi).....................  0.62137
Square feet (ft\2\).....................  Acres..........................  2.29568 x 10-5
Square meters (m\2\)....................  Acres..........................  2.47105 x 10-4
Square miles (mi\2\)....................  Square kilometers (km\2\)......  2.58999
Degrees Celsius ( deg.C)................  Degrees Fahrenheit ( deg.F)....   deg.C = (\5/9\) x ( deg.F -32)
Degrees Fahrenheit ( deg.F).............  Degrees Celsius ( deg.C).......   deg.F = (\9/5\) x  deg.C + 32
Degrees Celsius ( deg.C)................  Kelvin (K).....................  K =  deg.C + 273.15
Kelvin (K)..............................  Degrees Rankine ( deg.R).......  1.8
Joules..................................  Btu............................  9.47817 x 10-4
Btu.....................................  MMBtu..........................  1 x 10-6
Pascals (Pa)............................  Inches of Mercury (in Hg)......  2.95334 x 10-4
Inches of Mercury (inHg)................  Pounds per square inch (psi)...  0.49110
Pounds per square inch (psi)............  Inches of Mercury (in Hg)......  2.03625
----------------------------------------------------------------------------------------------------------------



 Sec. Table A-3 to Subpart A of Part 98--Source Category List for Sec. 
                               98.2(a)(1)

               Source Category List for Sec. 98.2(a)(1)
------------------------------------------------------------------------
 
-------------------------------------------------------------------------
Source Categories\a\ Applicable in 2010 and Future Years
    Electricity generation units that report CO2 mass emissions year
     round through 40 CFR part 75 (subpart D).
    Adipic acid production (subpart E).
    Aluminum production (subpart F).
    Ammonia manufacturing (subpart G).
    Cement production (subpart H).
    HCFC-22 production (subpart O).
    HFC-23 destruction processes that are not collocated with a HCFC-22
     production facility and that destroy more than 2.14 metric tons of
     HFC-23 per year (subpart O).
    Lime manufacturing (subpart S).
    Nitric acid production (subpart V).
    Petrochemical production (subpart X).
    Petroleum refineries (subpart Y).
    Phosphoric acid production (subpart Z).
    Silicon carbide production (subpart BB).
    Soda ash production (subpart CC).
    Titanium dioxide production (subpart EE).
    Municipal solid waste landfills that generate CH4 in amounts
     equivalent to 25,000 metric tons CO2e or more per year, as
     determined according to subpart HH of this part.
    Manure management systems with combined CH4 and N2O emissions in
     amounts equivalent to 25,000 metric tons CO2e or more per year, as
     determined according to subpart JJ of this part.
Additional Source Categories \a\ Applicable in 2011 and Future Years
Electrical transmission and distribution equipment use at facilities
 where the total nameplate capacity of SF6 and PFC containing equipment
 exceeds 17,820 pounds, as determined under Sec. 98.301 (subpart DD).
Underground coal mines liberating 36,500,000 actual cubic feet of CH4 or
 more per year (subpart FF).
Geologic sequestration of carbon dioxide (subpart RR).
    Electrical transmission and distribution equipment manufacture or
     refurbishment (subpart SS).
Injection of carbon dioxide (subpart UU).
------------------------------------------------------------------------
\a\ Source categories are defined in each applicable subpart.


[[Page 601]]


[75 FR 39760, July 12, 2010, as amended at 75 FR 74817, 75078, Dec. 1, 
2010; 76 FR 73900, Nov. 29, 2011]



 Sec. Table A-4 to Subpart A of Part 98--Source Category List for Sec. 
                               98.2(a)(2)

------------------------------------------------------------------------
 
-------------------------------------------------------------------------
Source Categories \a\ Applicable in 2010 and Future Years
    Ferroalloy production (subpart K).
    Glass production (subpart N).
    Hydrogen production (subpart P).
    Iron and steel production (subpart Q).
    Lead production (subpart R).
    Pulp and paper manufacturing (subpart AA).
    Zinc production (subpart GG).
Additional Source Categories \a\ Applicable in 2011 and Future Years
Electronics manufacturing (subpart I)
Fluorinated gas production (subpart L)
    Magnesium production (subpart T).
    Petroleum and Natural Gas Systems (subpart W)
    Industrial wastewater treatment (subpart II).
    Industrial waste landfills (subpart TT).
------------------------------------------------------------------------
\a\ Source categories are defined in each applicable subpart.


[75 FR 39760, July 12, 2010, as amended at 75 FR 74488, Nov. 30, 2010; 
75 FR 74817, Dec. 1, 2010]



Sec. Table A-5 to Subpart A of Part 98--Supplier Category List for Sec. 
                               98.2(a)(4)

------------------------------------------------------------------------
 
-------------------------------------------------------------------------
Supplier Categories \a\ Applicable in 2010 and Future Years
    Coal-to-liquids suppliers (subpart LL):
        (A) All producers of coal-to-liquid products.
        (B) Importers of an annual quantity of coal-to-liquid products
         that is equivalent to 25,000 metric tons CO2e or more.
        (C) Exporters of an annual quantity of coal-to-liquid products
         that is equivalent to 25,000 metric tons CO2e or more.
    Petroleum product suppliers (subpart MM):
 
        (A) All petroleum refineries that distill crude oil.
        (B) Importers of an annual quantity of petroleum products and
         natural gas liquids that is equivalent to 25,000 metric tons
         CO2e or more.
        (C) Exporters of an annual quantity of petroleum products and
         natural gas liquids that is equivalent to 25,000 metric tons
         CO2e or more.
    Natural gas and natural gas liquids suppliers (subpart NN):
        (A) All fractionators.
        (B) Local natural gas distribution companies that deliver
         460,000 thousand standard cubic feet or more of natural gas per
         year.
    Industrial greenhouse gas suppliers (subpart OO):
        (A) All producers of industrial greenhouse gases.
        (B) Importers of industrial greenhouse gases with annual bulk
         imports of N2O, fluorinated GHG, and CO2 that in combination
         are equivalent to 25,000 metric tons CO2e or more.
        (C) Exporters of industrial greenhouse gases with annual bulk
         exports of N2O, fluorinated GHG, and CO2 that in combination
         are equivalent to 25,000 metric tons CO2e or more.
    Carbon dioxide suppliers (subpart PP):
        (A) All producers of CO2.
        (B) Importers of CO2 with annual bulk imports of N2O,
         fluorinated GHG, and CO2 that in combination are equivalent to
         25,000 metric tons CO2e or more.
        (C) Exporters of CO2 with annual bulk exports of N2O,
         fluorinated GHG, and CO2 that in combination are equivalent to
         25,000 metric tons CO2e or more.
Additional Supplier Categories Applicable \a\ in 2011 and Future Years
Importers and exporters of fluorinated greenhouse gases contained in pre-
 charged equipment or closed-cell foams (subpart QQ):
    (A) Importers of an annual quantity of fluorinated greenhouse gases
     contained in pre-charged equipment or closed-cell foams that is
     equivalent to 25,000 metric tons CO2e or more.
    (B) Exporters of an annual quantity of fluorinated greenhouse gases
     contained in pre-charged equipment or closed-cell foams that is
     equivalent to 25,000 metric tons CO2e or more.
------------------------------------------------------------------------
\a\ Suppliers are defined in each applicable subpart.


[75 FR 39760, July 12, 2010, as amended at 75 FR 74817, Dec. 1, 2010; 75 
FR 79140, Dec. 17, 2010; 76 FR 73901, Nov. 29, 2011]

[[Page 602]]



Sec. Table A-6 to Subpart A of Part 98--Data Elements That Are Inputs to 
  Emission Equations and for Which the Reporting Deadline Is March 31, 
                                  2013

------------------------------------------------------------------------
                                                        Specific data
                                                     elements for which
                                                      reporting date is
                                                       March 31, 2013
                                                     (``All'' means all
    Subpart       Rule citation (40 CFR part 98)    data elements in the
                                                     cited paragraph are
                                                     not required to be
                                                    reported until March
                                                          31, 2013)
------------------------------------------------------------------------
C.............  98.36(d)(1)(iv)...................  All.
C.............  98.36(d)(2)(ii)(G)................  All.
C.............  98.36(d)(2)(iii)(G)...............  All.
C.............  98.36(e)(2)(iv)(G)................  All.
C.............  98.36(e)(2)(viii)(A)..............  All.
C.............  98.36(e)(2)(viii)(B)..............  All.
C.............  98.36(e)(2)(viii)(C)..............  All.
C.............  98.36(e)(2)(x)(A).................  All.
C.............  98.36(e)(2)(xi)...................  All.
DD............  98.306(a)(2)......................  All.
DD............  98.306(a)(3)......................  All.
DD............  98.306(d).........................  All.
DD............  98.306(e).........................  All.
DD............  98.306(f).........................  All.
DD............  98.306(g).........................  All.
DD............  98.306(h).........................  All.
DD............  98.306(i).........................  All.
DD............  98.306(j).........................  All.
DD............  98.306(k).........................  All.
DD............  98.306(l).........................  All.
FF............  98.326(a).........................  All.
FF............  98.326(b).........................  All.
FF............  98.326(c).........................  All.
FF............  98.326(f).........................  Only quarterly
                                                     volumetric flow
                                                     rate.
FF............  98.326(g).........................  Only quarterly CH4
                                                     concentration.
FF............  98.326(h).........................  Only weekly
                                                     volumetric flow
                                                     used to calculate
                                                     CH4 liberated from
                                                     degasification
                                                     systems.
FF............  98.326(j).........................  All.
FF............  98.326(k).........................  All.
FF............  98.326(o).........................  All.
FF............  98.326(p).........................  Only assumed
                                                     destruction
                                                     efficiency for the
                                                     primary destruction
                                                     device and assumed
                                                     destruction
                                                     efficiency for the
                                                     backup destruction
                                                     device.
HH............  98.346(a).........................  Only year in which
                                                     landfill first
                                                     accepted waste,
                                                     last year the
                                                     landfill accepted
                                                     waste (if used as
                                                     an input in
                                                     Equation HH-3),
                                                     capacity of the
                                                     landfill (if used
                                                     as an input in
                                                     Equation HH-3), and
                                                     waste disposal
                                                     quantity for each
                                                     year of
                                                     landfilling.
HH............  98.346(b).........................  Only quantity of
                                                     waste determined
                                                     using the methods
                                                     in Sec.
                                                     98.343(a)(3)(i),
                                                     quantity of waste
                                                     determined using
                                                     the methods in Sec.
                                                       98.343(a)(3)(ii),
                                                     population served
                                                     by the landfill for
                                                     each year, and the
                                                     value of landfill
                                                     capacity (LFC) used
                                                     in the calculation.
HH............  98.346(c).........................  All.
HH............  98.346(d)(1)......................  Only degradable
                                                     organic carbon
                                                     (DOC) value, and
                                                     fraction of DOC
                                                     dissimilated (DOCF)
                                                     values.
HH............  98.346(d)(2)......................  All.
HH............  98.346(e).........................  Only fraction of CH4
                                                     in landfill gas and
                                                     methane correction
                                                     factor (MCF)
                                                     values.
HH............  98.346(f).........................  Only surface area
                                                     associated with
                                                     each cover type.
HH............  98.346(g).........................  All.
HH............  98.346(i)(5)......................  Only annual
                                                     operating hours for
                                                     the destruction
                                                     devices located at
                                                     the landfill
                                                     facility, and the
                                                     destruction
                                                     efficiency for the
                                                     destruction devices
                                                     associated with
                                                     that measurement
                                                     location.
HH............  98.346(i)(6)......................  All.
HH............  98.346(i)(7)......................  Only surface area
                                                     specified in Table
                                                     HH-3, estimated gas
                                                     collection system
                                                     efficiency, and
                                                     annual operating
                                                     hours of the gas
                                                     collection system
                                                     for each
                                                     measurement
                                                     locations.
HH............  98.346(i)(9)......................  Only CH4 generation
                                                     value.
II............  98.356(b)(1)......................  All.
II............  98.356(b)(2)......................  All.
II............  98.356(b)(3)......................  All.
II............  98.356(b)(4)......................  All.
II............  98.356(b)(5)......................  All.
II............  98.356(d)(1)......................  All.
II............  98.356(d)(7)......................  All.
II............  98.356(d)(8)......................  Only annual
                                                     operating hours for
                                                     the primary
                                                     destruction device,
                                                     annual operating
                                                     hours for the
                                                     backup destruction
                                                     device, destruction
                                                     efficiency of the
                                                     primary destruction
                                                     device, and
                                                     destruction
                                                     efficiency of the
                                                     backup destruction
                                                     device.
SS............  98.456(a).........................  All.

[[Page 603]]

 
SS............  98.456(b).........................  All.
SS............  98.456(c).........................  All.
SS............  98.456(d).........................  All.
SS............  98.456(e).........................  All.
SS............  98.456(f).........................  All.
SS............  98.456(g).........................  All.
SS............  98.456(h).........................  All.
SS............  98.456(i).........................  All.
SS............  98.456(j).........................  All.
SS............  98.456(m).........................  All.
SS............  98.456(n).........................  All.
SS............  98.456(o).........................  All.
SS............  98.456(q).........................  All.
SS............  98.456(r).........................  All.
SS............  98.456(s).........................  All.
SS............  98.456(t).........................  Only for any missing
                                                     data the substitute
                                                     parameters used to
                                                     estimate emissions
                                                     in their absence.
TT............  98.466(a)(2)......................  All.
TT............  98.466(a)(3)......................  Only last year the
                                                     landfill accepted
                                                     waste (for closed
                                                     landfills using
                                                     Equation TT-4).
TT............  98.466(a)(4)......................  Only capacity of the
                                                     landfill in metric
                                                     tons (for closed
                                                     landfills using
                                                     Equation TT-4).
TT............  98.466(b)(3)......................  Only fraction of CH4
                                                     in landfill gas.
TT............  98.466(b)(4)......................  Only the methane
                                                     correction factor
                                                     (MCF) value used in
                                                     the calculations.
TT............  98.466(c)(4)(i)...................  All.
TT............  98.466(c)(4)(ii)..................  All.
TT............  98.466(c)(4)(iii).................  All.
TT............  98.466(d)(2)......................  All.
TT............  98.466(d)(3)......................  Only degradable
                                                     organic carbon
                                                     (DOCx) value for
                                                     each waste stream
                                                     used in
                                                     calculations.
TT............  98.466(e)(2)......................  Only surface area
                                                     (in square meters)
                                                     at the start of the
                                                     reporting year for
                                                     the landfill
                                                     sections that
                                                     contain waste and
                                                     that are associated
                                                     with the selected
                                                     cover type (for
                                                     facilities using a
                                                     landfill gas
                                                     collection system).
TT............  98.466(f).........................  All.
------------------------------------------------------------------------


[76 FR 53065, Aug. 25, 2011, as amended at 77 FR 48088, Aug. 13, 2012; 
78 FR 71949, Nov. 29, 2013]



Sec. Table A-7 to Subpart A of Part 98--Data Elements That Are Inputs to 
  Emission Equations and for Which the Reporting Deadline Is March 31, 
                                  2015

------------------------------------------------------------------------
                                                 Specific data elements
                                                for which reporting date
                                                   is March 31, 2015
                        Rule citation (40 CFR   (``All'' means all data
        Subpart                part 98)          elements in the cited
                                                   paragraph are not
                                                required to be reported
                                                 until March 31, 2015)
------------------------------------------------------------------------
A.....................  98.3(d)(3)(v)........  All.\a\
C.....................  98.36(b)(9)(iii).....  Only estimate of the heat
                                                input.\a\
C.....................  98.36(c)(2)(ix)......  Only estimate of the heat
                                                input from each type of
                                                fuel listed in Table C-
                                                2.\a\
C.....................  98.36(e)(2)(i).......  All.\a\
C.....................  98.36(e)(2)(ii)(A)...  All.\a\
C.....................  98.36(e)(2)(ii)(C)...  Only HHV value for each
                                                calendar month in which
                                                HHV determination is
                                                required.\a\
C.....................  98.36(e)(2)(ii)(D)...  All.\a\
C.....................  98.36(e)(2)(iv)(A)...  All.\a\
C.....................  98.36(e)(2)(iv)(C)...  All.\a\
C.....................  98.36(e)(2)(iv)(F)...  All.\a\
C.....................  98.36(e)(2)(ix)(D)...  All.\a\
C.....................  98.36(e)(2)(ix)(E)...  All.\a\
C.....................  98.36(e)(2)(ix)(F)...  All.\a\
E.....................  98.56(g).............  All.
E.....................  98.56(h).............  All.
E.....................  98.56(j)(4)..........  All.
E.....................  98.56(j)(5)..........  All.
E.....................  98.56(j)(6)..........  All.
E.....................  98.56(l).............  All.
H.....................  98.86(b)(11).........  All.
H.....................  98.86(b)(13).........  Name of raw kiln feed or
                                                raw material.
O.....................  98.156(d)(2).........  All.
O.....................  98.156(d)(3).........  All.

[[Page 604]]

 
O.....................  98.156(d)(4).........  All.
Q.....................  98.176(f)(1).........  All.
W.....................  98.236(c)(1)(i)......  All.
W.....................  98.236(c)(1)(ii).....  All.
W.....................  98.236(c)(1)(iii)....  All.
W.....................  98.236(c)(2)(i)......  All.
W.....................  98.236(c)(3)(i)......  All.
W.....................  98.236(c)(3)(ii).....  Only Calculation
                                                Methodology 2.
W.....................  98.236(c)(3)(iii)....  All.
W.....................  98.236(c)(3)(iv).....  All.
W.....................  98.236(c)(4)(i)(A)...  All.
W.....................  98.236(c)(4)(i)(B)...  All.
W.....................  98.236(c)(4)(i)(C)...  All.
W.....................  98.236(c)(4)(i)(D)...  All.
W.....................  98.236(c)(4)(i)(E)...  All.
W.....................  98.236(c)(4)(i)(F)...  All.
W.....................  98.236(c)(4)(i)(G)...  All.
W.....................  98.236(c)(4)(i)(H)...  All.
W.....................  98.236(c)(4)(ii)(A)..  All.
W.....................  98.236(c)(5)(i)(D)...  All.
W.....................  98.236(c)(5)(ii)(C)..  All.
W.....................  98.236(c)(6)(i)(B)...  All.\b\
W.....................  98.236(c)(6)(i)(D)...  All.\b\
W.....................  98.236(c)(6)(i)(E)...  All.\b\
W.....................  98.236(c)(6)(i)(F)...  All.\b\
W.....................  98.236(c)(6)(i)(G)...  Only the amount of
                                                natural gas required.
W.....................  98.236(c)(6)(i)(H)...  Only the amount of
                                                natural gas required.
W.....................  98.236(c)(6)(ii)(A)..  All.
W.....................  98.236(c)(6)(ii)(B)..  All.
W.....................  98.236(c)(7)(i)(A)...  Only for Equation W-14A.
W.....................  98.236(c)(8)(i)(F)...  All.\b\
W.....................  98.236(c)(8)(i)(K)...  All.
W.....................  98.236(c)(8)(ii)(A)..  All.\b\
W.....................  98.236(c)(8)(ii)(H)..  All.
W.....................  98.236(c)(8)(iii)(A).  All.
W.....................  98.236(c)(8)(iii)(B).  All.
W.....................  98.236(c)(8)(iii)(G).  All.
W.....................  98.236(c)(12)(ii)....  All.
W.....................  98.236(c)(12)(v).....  All.
W.....................  98.236(c)(13)(i)(E)..  All.
W.....................  98.236(c)(13)(i)(F)..  All.
W.....................  98.236(c)(13)(ii)(A).  All.
W.....................  98.236(c)(13)(ii)(B).  All.
W.....................  98.236(c)(13)(iii)(A)  All.
W.....................  98.236(c)(13)(iii)(B)  All.
W.....................  98.236(c)(13)(v)(A)..  All.
W.....................  98.236(c)(14)(i)(B)..  All.
W.....................  98.236(c)(14)(ii)(A).  All.
W.....................  98.236(c)(14)(ii)(B).  All.
W.....................  98.236(c)(14)(iii)(A)  All.
W.....................  98.236(c)(14)(iii)(B)  All.
W.....................  98.236(c)(14)(v)(A)..  All.
W.....................  98.236(c)(15)(ii)(A).  All.
W.....................  98.236(c)(15)(ii)(B).  All.
W.....................  98.236(c)(16)(viii)..  All.
W.....................  98.236(c)(16)(ix)....  All.
W.....................  98.236(c)(16)(x).....  All.
W.....................  98.236(c)(16)(xi)....  All.
W.....................  98.236(c)(16)(xii)...  All.
W.....................  98.236(c)(16)(xiii)..  All.
W.....................  98.236(c)(16)(xiv)...  All.
W.....................  98.236(c)(16)(xv)....  All.
W.....................  98.236(c)(16)(xvi)...  All.
W.....................  98.236(c)(17)(ii)....  All.
W.....................  98.236(c)(17)(iii)...  All.
W.....................  98.236(c)(17)(iv)....  All.
W.....................  98.236(c)(18)(i).....  All.
W.....................  98.236(c)(18)(ii)....  All.
W.....................  98.236(c)(19)(iv)....  All.
W.....................  98.236(c)(19)(vii)...  All.
Y.....................  98.256(h)(5)(i)......  Only value of the
                                                correction.
Y.....................  98.256(k)(4).........  Only mole fraction of
                                                methane in coking gas.

[[Page 605]]

 
Y.....................  98.256(n)(3).........  All (if used in Equation
                                                Y-21 to calculate
                                                emissions from equipment
                                                leaks).
Y.....................  98.256(o)(4)(vi).....  Only tank-specific
                                                methane composition data
                                                and gas generation rate
                                                data.
AA....................  98.276(e)............  All.
CC....................  98.296(b)(10)(i).....  All.
CC....................  98.296(b)(10)(ii)....  All.
CC....................  98.296(b)(10)(iii)...  All.
CC....................  98.296(b)(10)(iv)....  All.
CC....................  98.296(b)(10)(v).....  All.
CC....................  98.296(b)(10)(vi)....  All.
II....................  98.356(d)(2).........  All (if conducting weekly
                                                sampling).
II....................  98.356(d)(3).........  All (if conducting weekly
                                                sampling).
II....................  98.356(d)(4).........  Only weekly average
                                                temperature (if
                                                conducting weekly
                                                sampling).
II....................  98.356(d)(5).........  Only weekly average
                                                moisture content (if
                                                conducting weekly
                                                sampling).
II....................  98.356(d)(6).........  Only weekly average
                                                pressure (if conducting
                                                weekly sampling).
------------------------------------------------------------------------
\a\ Required to be reported only by: (1) Stationary fuel combustion
  sources (e.g., individual units, aggregations of units, common pipes,
  or common stacks) subject to subpart C of this part that contain at
  least one combustion unit connected to a fuel-fired electric generator
  owned or operated by an entity that is subject to regulation of
  customer billing rates by the PUC (excluding generators connected to
  combustion units subject to 40 CFR part 98, subpart D) and that are
  located at a facility for which the sum of the nameplate capacities
  for all such electric generators is greater than or equal to 1
  megawatt electric output; and (2) stationary fuel combustion sources
  (e.g., individual units, aggregations of units, common pipes, or
  common stacks) subject to subpart C of this part that do not meet the
  criteria in (1) of this footnote that elect to report these data
  elements, as provided in Sec. 98.36(a), for reporting year 2014.
\b\ This rule citation provides an option to delay reporting of this
  data element for certain wildcat wells and/or delineation wells.


[79 FR 73783, Dec. 11, 2014]

Subpart B [Reserved]



          Subpart C_General Stationary Fuel Combustion Sources



Sec. 98.30  Definition of the source category.

    (a) Stationary fuel combustion sources are devices that combust 
solid, liquid, or gaseous fuel, generally for the purposes of producing 
electricity, generating steam, or providing useful heat or energy for 
industrial, commercial, or institutional use, or reducing the volume of 
waste by removing combustible matter. Stationary fuel combustion sources 
include, but are not limited to, boilers, simple and combined-cycle 
combustion turbines, engines, incinerators, and process heaters.
    (b) This source category does not include:
    (1) Portable equipment, as defined in Sec. 98.6.
    (2) Emergency generators and emergency equipment, as defined in 
Sec. 98.6.
    (3) Irrigation pumps at agricultural operations.
    (4) Flares, unless otherwise required by provisions of another 
subpart of this part to use methodologies in this subpart.
    (5) Electricity generating units that are subject to subpart D of 
this part.
    (c) For a unit that combusts hazardous waste (as defined in Sec. 
261.3 of this chapter), reporting of GHG emissions is not required 
unless either of the following conditions apply:
    (1) Continuous emission monitors (CEMS) are used to quantify 
CO2 mass emissions.
    (2) Any fuel listed in Table C-1 of this subpart is also combusted 
in the unit. In this case, report GHG emissions from combustion of all 
fuels listed in Table C-1 of this subpart.
    (d) You are not required to report GHG emissions from pilot lights. 
A pilot light is a small auxiliary flame that ignites the burner of a 
combustion device when the control valve opens.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79140, Dec. 17, 2010]



Sec. 98.31  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains one or more stationary fuel combustion sources and the facility 
meets the applicability requirements of either Sec. Sec. 98.2(a)(1), 
98.2(a)(2), or 98.2(a)(3).

[[Page 606]]



Sec. 98.32  GHGs to report.

    You must report CO2, CH4, and N2O 
mass emissions from each stationary fuel combustion unit, except as 
otherwise indicated in this subpart.

[75 FR 79140, Dec. 17, 2010]



Sec. 98.33  Calculating GHG emissions.

    You must calculate CO2 emissions according to paragraph 
(a) of this section, and calculate CH4 and N2O 
emissions according to paragraph (c) of this section.
    (a) CO2 emissions from fuel combustion. Calculate CO2 
mass emissions by using one of the four calculation methodologies in 
paragraphs (a)(1) through (a)(4) of this section, subject to the 
applicable conditions, requirements, and restrictions set forth in 
paragraph (b) of this section. Alternatively, for units that meet the 
conditions of paragraph (a)(5) of this section, you may use 
CO2 mass emissions calculation methods from part 75 of this 
chapter, as described in paragraph (a)(5) of this section. For units 
that combust both biomass and fossil fuels, you must calculate and 
report CO2 emissions from the combustion of biomass 
separately using the methods in paragraph (e) of this section, except as 
otherwise provided in paragraphs (a)(5)(iv) and (e) of this section and 
in Sec. 98.36(d).
    (1) Tier 1 Calculation Methodology. Calculate the annual 
CO2 mass emissions for each type of fuel by using Equation C-
1, C-1a, or C-1b of this section (as applicable).
    (i) Use Equation C-1 except when natural gas billing records are 
used to quantify fuel usage and gas consumption is expressed in units of 
therms or million Btu. In that case, use Equation C-1a or C-1b, as 
applicable.
[GRAPHIC] [TIFF OMITTED] TR17DE10.015

where:

CO2 = Annual CO2 mass emissions for the specific 
          fuel type (metric tons).
Fuel = Mass or volume of fuel combusted per year, from company records 
          as defined in Sec. 98.6 (express mass in short tons for solid 
          fuel, volume in standard cubic feet for gaseous fuel, and 
          volume in gallons for liquid fuel).
HHV = Default high heat value of the fuel, from Table C-1 of this 
          subpart (mmBtu per mass or mmBtu per volume, as applicable).
EF = Fuel-specific default CO2 emission factor, from Table C-
          1 of this subpart (kg CO2/mmBtu).
1 x 10-3 = Conversion factor from kilograms to metric tons.

    (ii) If natural gas consumption is obtained from billing records and 
fuel usage is expressed in therms, use Equation C-1a.
[GRAPHIC] [TIFF OMITTED] TR17DE10.016

where:

CO2 = Annual CO2 mass emissions from natural gas 
          combustion (metric tons).
Gas = Annual natural gas usage, from billing records (therms).
EF = Fuel-specific default CO2 emission factor for natural 
          gas, from Table C-1 of this subpart (kg CO2/mmBtu).
0.1 = Conversion factor from therms to mmBtu
1 x 10-3 = Conversion factor from kilograms to metric tons.

    (iii) If natural gas consumption is obtained from billing records 
and fuel usage is expressed in mmBtu, use Equation C-1b.
[GRAPHIC] [TIFF OMITTED] TR17DE10.017


[[Page 607]]


where:

CO2 = Annual CO2 mass emissions from natural gas 
          combustion (metric tons).
Gas = Annual natural gas usage, from billing records (mmBtu).
EF = Fuel-specific default CO2 emission factor for natural 
          gas, from Table C-1 of this subpart (kg CO2/mmBtu).
1 x 10-3 = Conversion factor from kilograms to metric tons.

    (2) Tier 2 Calculation Methodology. Calculate the annual 
CO2 mass emissions for each type of fuel by using either 
Equation C2a or C2c of this section, as appropriate.
    (i) Equation C-2a of this section applies to any type of fuel listed 
in Table C-1 of the subpart, except for municipal solid waste (MSW). For 
MSW combustion, use Equation C-2c of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.005

Where:

CO2 = Annual CO2 mass emissions for a specific 
          fuel type (metric tons).
Fuel = Mass or volume of the fuel combusted during the year, from 
          company records as defined in Sec. 98.6 (express mass in 
          short tons for solid fuel, volume in standard cubic feet for 
          gaseous fuel, and volume in gallons for liquid fuel).
HHV = Annual average high heat value of the fuel (mmBtu per mass or 
          volume). The average HHV shall be calculated according to the 
          requirements of paragraph (a)(2)(ii) of this section.
EF = Fuel-specific default CO2 emission factor, from Table C-
          1 of this subpart (kg CO2/mmBtu).
1 x 10-3 = Conversion factor from kilograms to metric tons.

    (ii) The minimum required sampling frequency for determining the 
annual average HHV (e.g., monthly, quarterly, semi-annually, or by lot) 
is specified in Sec. 98.34. The method for computing the annual average 
HHV is a function of unit size and how frequently you perform or receive 
from the fuel supplier the results of fuel sampling for HHV. The method 
is specified in paragraph (a)(2)(ii)(A) or (a)(2)(ii)(B) of this 
section, as applicable.
    (A) If the results of fuel sampling are received monthly or more 
frequently, then for each unit with a maximum rated heat input capacity 
greater than or equal to 100 mmBtu/hr (or for a group of units that 
includes at least one unit of that size), the annual average HHV shall 
be calculated using Equation C-2b of this section. If multiple HHV 
determinations are made in any month, average the values for the month 
arithmetically.
[GRAPHIC] [TIFF OMITTED] TR30OC09.006

Where:

(HHV)annual = Weighted annual average high heat value of the 
          fuel (mmBtu per mass or volume).
(HHV)I = Measured high heat value of the fuel, for month 
          ``i'' (which may be the arithmetic average of multiple 
          determinations), or, if applicable, an appropriate substitute 
          data value (mmBtu per mass or volume).
(Fuel)I = Mass or volume of the fuel combusted during month 
          ``i,'' from company records (express mass in short tons for 
          solid fuel, volume in standard cubic feet for gaseous fuel, 
          and volume in gallons for liquid fuel).
n = Number of months in the year that the fuel is burned in the unit.


[[Page 608]]


    (B) If the results of fuel sampling are received less frequently 
than monthly, or, for a unit with a maximum rated heat input capacity 
less than 100 mmBtu/hr (or a group of such units) regardless of the HHV 
sampling frequency, the annual average HHV shall either be computed 
according to paragraph (a)(2)(ii)(A) of this section or as the 
arithmetic average HHV for all values for the year (including valid 
samples and substitute data values under Sec. 98.35).
    (iii) For units that combust municipal solid waste (MSW) and that 
produce steam, use Equation C-2c of this section. Equation C-2c of this 
section may also be used for any other solid fuel listed in Table C-1 of 
this subpart provided that steam is generated by the unit.
[GRAPHIC] [TIFF OMITTED] TR30OC09.007

Where:

CO2 = Annual CO2 mass emissions from MSW or solid 
          fuel combustion (metric tons).
Steam = Total mass of steam generated by MSW or solid fuel combustion 
          during the reporting year (lb steam).
B = Ratio of the boiler's maximum rated heat input capacity to its 
          design rated steam output capacity (mmBtu/lb steam).
EF = Fuel-specific default CO2 emission factor, from Table C-
          1 of this subpart (kg CO2/mmBtu).
1 x 10-3 = Conversion factor from kilograms to metric tons.

    (3) Tier 3 Calculation Methodology. Calculate the annual 
CO2 mass emissions for each fuel by using either Equation C3, 
C4, or C5 of this section, as appropriate.
    (i) For a solid fuel, use Equation C-3 of this section.
    [GRAPHIC] [TIFF OMITTED] TR30OC09.008
    
Where:

CO2 = Annual CO2 mass emissions from the 
          combustion of the specific solid fuel (metric tons).
Fuel = Annual mass of the solid fuel combusted, from company records as 
          defined in Sec. 98.6 (short tons).
CC = Annual average carbon content of the solid fuel (percent by weight, 
          expressed as a decimal fraction, e.g., 95% = 0.95). The annual 
          average carbon content shall be determined using the same 
          procedures as specified for HHV in paragraph (a)(2)(ii) of 
          this section.
44/12 = Ratio of molecular weights, CO2 to carbon.
0.91 = Conversion factor from short tons to metric tons.

    (ii) For a liquid fuel, use Equation C-4 of this section.
    [GRAPHIC] [TIFF OMITTED] TR30OC09.009
    
Where:

CO2 = Annual CO2 mass emissions from the 
          combustion of the specific liquid fuel (metric tons).
Fuel = Annual volume of the liquid fuel combusted (gallons). The volume 
          of fuel combusted must be measured directly, using fuel flow 
          meters calibrated according to Sec. 98.3(i). Fuel billing 
          meters may be used

[[Page 609]]

          for this purpose. Tank drop measurements may also be used.
CC = Annual average carbon content of the liquid fuel (kg C per gallon 
          of fuel). The annual average carbon content shall be 
          determined using the same procedures as specified for HHV in 
          paragraph (a)(2)(ii) of this section.
44/12 = Ratio of molecular weights, CO2 to carbon.
0.001 = Conversion factor from kg to metric tons.

    (iii) For a gaseous fuel, use Equation C-5 of this section.
    [GRAPHIC] [TIFF OMITTED] TR30OC09.010
    
Where:

CO2 = Annual CO2 mass emissions from combustion of 
          the specific gaseous fuel (metric tons).
Fuel = Annual volume of the gaseous fuel combusted (scf). The volume of 
          fuel combusted must be measured directly, using fuel flow 
          meters calibrated according to Sec. 98.3(i). Fuel billing 
          meters may be used for this purpose.
CC = Annual average carbon content of the gaseous fuel (kg C per kg of 
          fuel). The annual average carbon content shall be determined 
          using the same procedures as specified for HHV in paragraph 
          (a)(2)(ii) of this section.
MW = Annual average molecular weight of the gaseous fuel (kg/kg-mole). 
          The annual average molecular weight shall be determined using 
          the same procedures as specified for HHV in paragraph 
          (a)(2)(ii) of this section.
MVC = Molar volume conversion factor at standard conditions, as defined 
          in Sec. 98.6. Use 849.5 scf per kg mole if you select 68 
          deg.F as standard temperature and 836.6 scf per kg mole if you 
          select 60  deg.F as standard temperature.
44/12 = Ratio of molecular weights, CO2 to carbon.
0.001 = Conversion factor from kg to metric tons.

    (iv) Fuel flow meters that measure mass flow rates may be used for 
liquid or gaseous fuels, provided that the fuel density is used to 
convert the readings to volumetric flow rates. The density shall be 
measured at the same frequency as the carbon content. You must measure 
the density using one of the following appropriate methods. You may use 
a method published by a consensus-based standards organization, if such 
a method exists, or you may use industry standard practice. Consensus-
based standards organizations include, but are not limited to, the 
following: ASTM International (100 Barr Harbor Drive, P.O. Box CB700, 
West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373, http://
www.astm.org), the American National Standards Institute (ANSI, 1819 L 
Street, NW., 6th floor, Washington, DC 20036, (202) 293-8020, http://
www.ansi.org), the American Gas Association (AGA), 400 North Capitol 
Street, NW., 4th Floor, Washington, DC 20001, (202) 824-7000, http://
www.aga.org), the American Society of Mechanical Engineers (ASME, Three 
Park Avenue, New York, NY 10016-5990, (800) 843-2763, http://
www.asme.org), the American Petroleum Institute (API, 1220 L Street, 
NW., Washington, DC 20005-4070, (202) 682-8000, http://www.api.org), and 
the North American Energy Standards Board (NAESB, 801 Travis Street, 
Suite 1675, Houston, TX 77002, (713) 356-0060, http://www.api.org). The 
method(s) used shall be documented in the GHG Monitoring Plan required 
under Sec. 98.3(g)(5).
    (v) The following default density values may be used for fuel oil, 
in lieu of using the methods in paragraph (a)(3)(iv) of this section: 
6.8 lb/gal for No. 1 oil; 7.2 lb/gal for No. 2 oil; 8.1 lb/gal for No. 6 
oil.
    (4) Tier 4 Calculation Methodology. Calculate the annual 
CO2 mass emissions from all fuels combusted in a unit, by 
using quality-assured data from continuous emission monitoring systems 
(CEMS).
    (i) This methodology requires a CO2 concentration monitor 
and a stack gas volumetric flow rate monitor, except as otherwise 
provided in paragraph (a)(4)(iv) of this section. Hourly measurements of 
CO2 concentration and stack gas flow rate are converted to 
CO2 mass emission rates in metric tons per hour.

[[Page 610]]

    (ii) When the CO2 concentration is measured on a wet 
basis, Equation C-6 of this section is used to calculate the hourly 
CO2 emission rates:
[GRAPHIC] [TIFF OMITTED] TR30OC09.011

Where:

CO2 = CO2 mass emission rate (metric tons/hr).
CCO2 = Hourly average CO2 concentration (% 
          CO2).
Q = Hourly average stack gas volumetric flow rate (scfh).
5.18 x 10-7 = Conversion factor (metric tons/scf/% 
          CO2).

    (iii) If the CO2 concentration is measured on a dry 
basis, a correction for the stack gas moisture content is required. You 
shall either continuously monitor the stack gas moisture content using a 
method described in Sec. 75.11(b)(2) of this chapter or use an 
appropriate default moisture percentage. For coal, wood, and natural gas 
combustion, you may use the default moisture values specified in Sec. 
75.11(b)(1) of this chapter. Alternatively, for any type of fuel, you 
may determine an appropriate site-specific default moisture value (or 
values), using measurements made with EPA Method 4--Determination Of 
Moisture Content In Stack Gases, in appendix A-3 to part 60 of this 
chapter. Moisture data from the relative accuracy test audit (RATA) of a 
CEMS may be used for this purpose. If this option is selected, the site-
specific moisture default value(s) must represent the fuel(s) or fuel 
blends that are combusted in the unit during normal, stable operation, 
and must account for any distinct difference(s) in the stack gas 
moisture content associated with different process operating conditions. 
For each site-specific default moisture percentage, at least nine Method 
4 runs are required, except where the option to use moisture data from a 
RATA is selected, and the applicable regulation allows a single moisture 
determination to represent two or more RATA runs. In that case, you may 
base the site-specific moisture percentage on the number of moisture 
runs allowed by the RATA regulation. Calculate each site-specific 
default moisture value by taking the arithmetic average of the Method 4 
runs. Each site-specific moisture default value shall be updated 
whenever the owner or operator believes the current value is non-
representative, due to changes in unit or process operation, but in any 
event no less frequently than annually. Use the updated moisture value 
in the subsequent CO2 emissions calculations. For each unit 
operating hour, a moisture correction must be applied to Equation C-6 of 
this section as follows:
[GRAPHIC] [TIFF OMITTED] TR17DE10.002

where:

CO2* = Hourly CO2 mass emission rate, corrected 
          for moisture (metric tons/hr).
CO2 = Hourly CO2 mass emission rate from Equation 
          C-6 of this section, uncorrected (metric tons/hr).
%H2O = Hourly moisture percentage in the stack gas (measured 
          or default value, as appropriate).

    (iv) An oxygen (O2) concentration monitor may be used in 
lieu of a CO2 concentration monitor to determine the hourly 
CO2 concentrations, in accordance with Equation F-14a or F-
14b (as applicable) in appendix F to part 75 of this chapter, if the 
effluent gas stream monitored by the CEMS consists solely of combustion 
products (i.e., no process CO2 emissions or CO2 
emissions from sorbent are mixed with the combustion products) and if 
only fuels that are listed in Table 1 in section 3.3.5 of appendix F to 
part 75 of this chapter are combusted in the unit. If the O2 
monitoring option is selected, the F-factors used in Equations F-14a and 
F-14b shall be determined according to section 3.3.5 or section 3.3.6 of 
appendix F to part 75 of this chapter, as applicable. If Equation F-14b 
is used, the hourly moisture percentage in the

[[Page 611]]

stack gas shall be determined in accordance with paragraph (a)(4)(iii) 
of this section.
    (v) Each hourly CO2 mass emission rate from Equation C-6 
or C-7 of this section is multiplied by the operating time to convert it 
from metric tons per hour to metric tons. The operating time is the 
fraction of the hour during which fuel is combusted (e.g., the unit 
operating time is 1.0 if the unit operates for the whole hour and is 0.5 
if the unit operates for 30 minutes in the hour). For common stack 
configurations, the operating time is the fraction of the hour during 
which effluent gases flow through the common stack.
    (vi) The hourly CO2 mass emissions are then summed over 
each calendar quarter and the quarterly totals are summed to determine 
the annual CO2 mass emissions.
    (vii) If both biomass and fossil fuel are combusted during the year, 
determine and report the biogenic CO2 mass emissions 
separately, as described in paragraph (e) of this section.
    (viii) If a portion of the flue gases generated by a unit subject to 
Tier 4 (e.g., a slip stream) is continuously diverted from the main flue 
gas exhaust system for the purpose of heat recovery or some other 
similar process, and then exhausts through a stack that is not equipped 
with the continuous emission monitors to measure CO2 mass 
emissions, CO2 emissions shall be determined as follows:
    (A) At least once a year, use EPA Methods 2 and 3A, and (if 
necessary) Method 4 in appendices A-2 and A-3 to part 60 of this chapter 
to perform emissions testing at a set point that best represents normal, 
stable process operating conditions. A minimum of three one-hour Method 
3A tests are required, to determine the CO2 concentration. A 
Method 2 test shall be performed during each Method 3A run, to determine 
the stack gas volumetric flow rate. If moisture correction is necessary, 
a Method 4 run shall also be performed during each Method 3A run. 
Important parametric information related to the stack gas flow rate 
(e.g., damper positions, fan settings, etc.) shall also be recorded 
during the test.
    (B) Calculate a CO2 mass emission rate (in metric tons/
hr) from the stack test data, using a version of Equation C-6 in 
paragraph (a)(4)(ii) of this section, modified as follows. In the 
Equation C-6 nomenclature, replace the words ``Hourly average'' in the 
definitions of ``CCO2'' and ``Q'' with the words ``3-run 
average''. Substitute the arithmetic average values of CO2 
concentration and stack gas flow rate from the emission testing into 
modified Equation C-6. If CO2 is measured on a dry basis, a 
moisture correction of the calculated CO2 mass emission rate 
is required. Use Equation C-7 in paragraph (a)(4)(ii) of this section to 
make this correction; replace the word ``Hourly'' with the words ``3-run 
average'' in the equation nomenclature.
    (C) The results of each annual stack test shall be used in the GHG 
emissions calculations for the year of the test.
    (D) If, for the majority of the operating hours during the year, the 
diverted stream is withdrawn at a steady rate at or near the tested set 
point (as evidenced by fan and damper settings and/or other parameters), 
you may use the calculated CO2 mass emission rate from 
paragraph (a)(4)(viii)(B) of this section to estimate the CO2 
mass emissions for all operating hours in which flue gas is diverted 
from the main exhaust system. Otherwise, you must account for the 
variation in the flow rate of the diverted stream, as described in 
paragraph (c)(4)(viii)(E) of this section.
    (E) If the flow rate of the diverted stream varies significantly 
throughout the year, except as provided below, repeat the stack test and 
emission rate calculation procedures described in paragraphs 
(c)(4)(viii)(A) and (c)(4)(viii)(B) of this section at a minimum of two 
more set points across the range of typical operating conditions to 
develop a correlation between CO2 mass emission rate and the 
parametric data. If additional testing is not feasible, use the 
following approach to develop the necessary correlation. Assume that the 
average CO2 concentration obtained in the annual stack test 
is the same at all operating set points. Then, beginning with the 
measured flow rate from the stack test and the associated parametric 
data, perform an engineering analysis to estimate the

[[Page 612]]

stack gas flow rate at two or more additional set points. Calculate the 
CO2 mass emission rate at each set point.
    (F) Calculate the annual CO2 mass emissions for the 
diverted stream as follows. For a steady-state process, multiply the 
number of hours in which flue gas was diverted from the main exhaust 
system by the CO2 mass emission rate from the stack test. 
Otherwise, using the best available information and engineering 
judgment, apply the most representative CO2 mass emission 
rate from the correlation in paragraph (c)(4)(viii)(E) of this section 
to determine the CO2 mass emissions for each hour in which 
flue gas was diverted, and sum the results. To simplify the 
calculations, you may count partial operating hours as full hours.
    (G) Finally, add the CO2 mass emissions from 
paragraph(c)(4)(viii)(F) of this section to the annual CO2 
mass emissions measured by the CEMS at the main stack. Report this sum 
as the total annual CO2 mass emissions for the unit.
    (H) The exact method and procedures used to estimate the 
CO2 mass emissions for the diverted portion of the flue gas 
exhaust stream shall be documented in the Monitoring Plan required under 
Sec. 98.3(g)(5).
    (5) Alternative methods for certain units subject to Part 75 of this 
chapter. Certain units that are not subject to subpart D of this part 
and that report data to EPA according to part 75 of this chapter may 
qualify to use the alternative methods in this paragraph (a)(5), in lieu 
of using any of the four calculation methodology tiers.
    (i) For a unit that combusts only natural gas and/or fuel oil, is 
not subject to subpart D of this part, monitors and reports heat input 
data year-round according to appendix D to part 75 of this chapter, but 
is not required by the applicable part 75 program to report 
CO2 mass emissions data, calculate the annual CO2 
mass emissions for the purposes of this part as follows:
    (A) Use the hourly heat input data from appendix D to part 75 of 
this chapter, together with Equation G-4 in appendix G to part 75 of 
this chapter to determine the hourly CO2 mass emission rates, 
in units of tons/hr;
    (B) Use Equations F-12 and F-13 in appendix F to part 75 of this 
chapter to calculate the quarterly and cumulative annual CO2 
mass emissions, respectively, in units of short tons; and
    (C) Divide the cumulative annual CO2 mass emissions value 
by 1.1 to convert it to metric tons.
    (ii) For a unit that combusts only natural gas and/or fuel oil, is 
not subject to subpart D of this part, monitors and reports heat input 
data year-round according to Sec. 75.19 of this chapter but is not 
required by the applicable part 75 program to report CO2 mass 
emissions data, calculate the annual CO2 mass emissions for 
the purposes of this part as follows:
    (A) Calculate the hourly CO2 mass emissions, in units of 
short tons, using Equation LM-11 in Sec. 75.19(c)(4)(iii) of this 
chapter.
    (B) Sum the hourly CO2 mass emissions values over the 
entire reporting year to obtain the cumulative annual CO2 
mass emissions, in units of short tons.
    (C) Divide the cumulative annual CO2 mass emissions value 
by 1.1 to convert it to metric tons.
    (iii) For a unit that is not subject to subpart D of this part, uses 
flow rate and CO2 (or O2) CEMS to report heat 
input data year-round according to part 75 of this chapter, but is not 
required by the applicable part 75 program to report CO2 mass 
emissions data, calculate the annual CO2 mass emissions as 
follows:
    (A) Use Equation F-11 or F-2 (as applicable) in appendix F to part 
75 of this chapter to calculate the hourly CO2 mass emission 
rates from the CEMS data. If an O2 monitor is used, convert 
the hourly average O2 readings to CO2 using 
Equation F-14a or F-14b in appendix F to part 75 of this chapter (as 
applicable), before applying Equation F-11 or F-2.
    (B) Use Equations F-12 and F-13 in appendix F to part 75 of this 
chapter to calculate the quarterly and cumulative annual CO2 
mass emissions, respectively, in units of short tons.
    (C) Divide the cumulative annual CO2 mass emissions value 
by 1.1 to convert it to metric tons.
    (iv) For units that qualify to use the alternative CO2 
emissions calculation

[[Page 613]]

methods in paragraphs (a)(5)(i) through (a)(5)(iii) of this section, if 
both biomass and fossil fuel are combusted during the year, separate 
calculation and reporting of the biogenic CO2 mass emissions 
(as described in paragraph (e) of this section) is optional, only for 
the 2010 reporting year, as provided in Sec. 98.3(c)(12).
    (b) Use of the four tiers. Use of the four tiers of CO2 
emissions calculation methodologies described in paragraph (a) of this 
section is subject to the following conditions, requirements, and 
restrictions:
    (1) The Tier 1 Calculation Methodology:
    (i) May be used for any fuel listed in Table C-1 of this subpart 
that is combusted in a unit with a maximum rated heat input capacity of 
250 mmBtu/hr or less.
    (ii) May be used for MSW in a unit of any size that does not produce 
steam, if the use of Tier 4 is not required.
    (iii) May be used for solid, gaseous, or liquid biomass fuels in a 
unit of any size provided that the fuel is listed in Table C-1 of this 
subpart.
    (iv) May not be used if you routinely perform fuel sampling and 
analysis for the fuel high heat value (HHV) or routinely receive the 
results of HHV sampling and analysis from the fuel supplier at the 
minimum frequency specified in Sec. 98.34(a), or at a greater 
frequency. In such cases, Tier 2 shall be used. This restriction does 
not apply to paragraphs (b)(1)(ii), (b)(1)(v), (b)(1)(vi), and 
(b)(1)(vii) of this section.
    (v) May be used for natural gas combustion in a unit of any size, in 
cases where the annual natural gas consumption is obtained from fuel 
billing records in units of therms or mmBtu.
    (vi) May be used for MSW combustion in a small, batch incinerator 
that burns no more than 1,000 tons per year of MSW.
    (vii) May be used for the combustion of MSW and/or tires in a unit, 
provided that no more than 10 percent of the unit's annual heat input is 
derived from those fuels, combined. Notwithstanding this requirement, if 
a unit combusts both MSW and tires and the reporter elects not to 
separately calculate and report biogenic CO2 emissions from 
the combustion of tires, Tier 1 may be used for the MSW combustion, 
provided that no more than 10 percent of the unit's annual heat input is 
derived from MSW.
    (viii) May be used for the combustion of a fuel listed in Table C-1 
if the fuel is combusted in a unit with a maximum rated heat input 
capacity greater than 250 mmBtu/hr (or, pursuant to Sec. 98.36(c)(3), 
in a group of units served by a common supply pipe, having at least one 
unit with a maximum rated heat input capacity greater than 250 mmBtu/
hr), provided that both of the following conditions apply:
    (A) The use of Tier 4 is not required.
    (B) The fuel provides less than 10 percent of the annual heat input 
to the unit, or if Sec. 98.36(c)(3) applies, to the group of units 
served by a common supply pipe.
    (2) The Tier 2 Calculation Methodology:
    (i) May be used for the combustion of any type of fuel in a unit 
with a maximum rated heat input capacity of 250 mmBtu/hr or less 
provided that the fuel is listed in Table C-1 of this subpart.
    (ii) May be used in a unit with a maximum rated heat input capacity 
greater than 250 mmBtu/hr for the combustion of natural gas and/or 
distillate fuel oil.
    (iii) May be used for MSW in a unit of any size that produces steam, 
if the use of Tier 4 is not required.
    (3) The Tier 3 Calculation Methodology:
    (i) May be used for a unit of any size that combusts any type of 
fuel listed in Table C-1 of this subpart (except for MSW), unless the 
use of Tier 4 is required.
    (ii) Shall be used for a unit with a maximum rated heat input 
capacity greater than 250 mmBtu/hr that combusts any type of fuel listed 
in Table C-1 of this subpart (except MSW), unless either of the 
following conditions apply:
    (A) The use of Tier 1 or 2 is permitted, as described in paragraphs 
(b)(1)(iii), (b)(1)(v), (b)(1)(viii), and (b)(2)(ii) of this section.
    (B) The use of Tier 4 is required.
    (iii) Shall be used for a fuel not listed in Table C-1 of this 
subpart if the fuel

[[Page 614]]

is combusted in a unit with a maximum rated heat input capacity greater 
than 250 mmBtu/hr (or, pursuant to Sec. 98.36(c)(3), in a group of 
units served by a common supply pipe, having at least one unit with a 
maximum rated heat input capacity greater than 250 mmBtu/hr), provided 
that both of the following conditions apply:
    (A) The use of Tier 4 is not required.
    (B) The fuel provides 10% or more of the annual heat input to the 
unit or, if Sec. 98.36(c)(3) applies, to the group of units served by a 
common supply pipe.
    (iv) Shall be used when specified in another applicable subpart of 
this part, regardless of unit size.
    (4) The Tier 4 Calculation Methodology:
    (i) May be used for a unit of any size, combusting any type of fuel. 
Tier 4 may also be used for any group of stationary fuel combustion 
units, process units, or manufacturing units that share a common stack 
or duct.
    (ii) Shall be used if the unit meets all six of the conditions 
specified in paragraphs (b)(4)(ii)(A) through (b)(4)(ii)(F) of this 
section:
    (A) The unit has a maximum rated heat input capacity greater than 
250 mmBtu/hr, or if the unit combusts municipal solid waste and has a 
maximum rated input capacity greater than 600 tons per day of MSW.
    (B) The unit combusts solid fossil fuel or MSW as the primary fuel.
    (C) The unit has operated for more than 1,000 hours in any calendar 
year since 2005.
    (D) The unit has installed CEMS that are required either by an 
applicable Federal or State regulation or the unit's operating permit.
    (E) The installed CEMS include a gas monitor of any kind or a stack 
gas volumetric flow rate monitor, or both and the monitors have been 
certified, either in accordance with the requirements of part 75 of this 
chapter, part 60 of this chapter, or an applicable State continuous 
monitoring program.
    (F) The installed gas or stack gas volumetric flow rate monitors are 
required, either by an applicable Federal or State regulation or by the 
unit's operating permit, to undergo periodic quality assurance testing 
in accordance with either appendix B to part 75 of this chapter, 
appendix F to part 60 of this chapter, or an applicable State continuous 
monitoring program.
    (iii) Shall be used for a unit with a maximum rated heat input 
capacity of 250 mmBtu/hr or less and for a unit that combusts municipal 
solid waste with a maximum rated input capacity of 600 tons of MSW per 
day or less, if the unit meets all of the following three conditions:
    (A) The unit has both a stack gas volumetric flow rate monitor and a 
CO2 concentration monitor.
    (B) The unit meets the conditions specified in paragraphs 
(b)(4)(ii)(B) through (b)(4)(ii)(D) of this section.
    (C) The CO2 and stack gas volumetric flow rate monitors 
meet the conditions specified in paragraphs (b)(4)(ii)(E) and 
(b)(4)(ii)(F) of this section.
    (iv) May apply to common stack or duct configurations where:
    (A) The combined effluent gas streams from two or more stationary 
fuel combustion units are vented through a monitored common stack or 
duct. In this case, Tier 4 shall be used if all of the conditions in 
paragraph (b)(4)(iv)(A)(1) of this section or if the conditions in 
paragraph (b)(4)(iv)(A)(2) of this section are met.
    (1) At least one of the units meets the requirements of paragraphs 
(b)(4)(ii)(A) through (b)(4)(ii)(C) of this section, and the CEMS 
installed at the common stack (or duct) meet the requirements of 
paragraphs (b)(4)(ii)(D) through (b)(4)(ii)(F) of this section.
    (2) At least one of the units and the monitors installed at the 
common stack or duct meet the requirements of paragraph (b)(4)(iii) of 
this section.
    (B) The combined effluent gas streams from a process or 
manufacturing unit and a stationary fuel combustion unit are vented 
through a monitored common stack or duct. In this case, Tier 4 shall be 
used if the combustion unit and the monitors installed at the common 
stack or duct meet the applicability criteria specified in paragraph 
(b)(4)(iv)(A)(1), or (b)(4)(iv)(A)(2) of this section.
    (C) The combined effluent gas streams from two or more manufacturing 
or process units are vented through a common stack or duct. In this 
case, if any of the units is required

[[Page 615]]

by an applicable subpart of this part to use Tier 4, the CO2 
mass emissions may be monitored at each individual unit, or the combined 
CO2 mass emissions may be monitored at the common stack or 
duct. However, if it is not feasible to monitor the individual units, 
the combined CO2 mass emissions shall be monitored at the 
common stack or duct.
    (5) The Tier 4 Calculation Methodology shall be used:
    (i) Starting on January 1, 2010, for a unit that is required to 
report CO2 mass emissions beginning on that date, if all of 
the monitors needed to measure CO2 mass emissions have been 
installed and certified by that date.
    (ii) No later than January 1, 2011, for a unit that is required to 
report CO2 mass emissions beginning on January 1, 2010, if 
all of the monitors needed to measure CO2 mass emissions have 
not been installed and certified by January 1, 2010. In this case, you 
may use Tier 2 or Tier 3 to report GHG emissions for 2010. However, if 
the required CEMS are certified some time in 2010, you need not wait 
until January 1, 2011 to begin using Tier 4. Rather, you may switch from 
Tier 2 or Tier 3 to Tier 4 as soon as CEMS certification testing is 
successfully completed. If this reporting option is chosen, you must 
document the change in CO2 calculation methodology in the 
Monitoring Plan required under Sec. 98.3(g)(5) and in the GHG emissions 
report under Sec. 98.3(c). Data recorded by the CEMS during a 
certification test period in 2010 may be used for reporting under this 
part, provided that the following two conditions are met:
    (A) The certification tests are passed in sequence, with no test 
failures.
    (B) No unscheduled maintenance or repair of the CEMS is performed 
during the certification test period.
    (iii) No later than 180 days following the date on which a change is 
made that triggers Tier 4 applicability under paragraph (b)(4)(ii) or 
(b)(4)(iii) of this section (e.g., a change in the primary fuel, manner 
of unit operation, or installed continuous monitoring equipment).
    (6) You may elect to use any applicable higher tier for one or more 
of the fuels combusted in a unit. For example, if a 100 mmBtu/hr unit 
combusts natural gas and distillate fuel oil, you may elect to use Tier 
1 for natural gas and Tier 3 for the fuel oil, even though Tier 1 could 
have been used for both fuels. However, for units that use either the 
Tier 4 or the alternative calculation methodology specified in paragraph 
(a)(5)(iii) of this section, CO2 emissions from the 
combustion of all fuels shall be based solely on CEMS measurements.
    (c) Calculation of CH4 and N2O emissions from stationary combustion 
sources. You must calculate annual CH4 and N2O 
mass emissions only for units that are required to report CO2 
emissions using the calculation methodologies of this subpart and for 
only those fuels that are listed in Table C-2 of this subpart.
    (1) Use Equation C-8 of this section to estimate CH4 and 
N2O emissions for any fuels for which you use the Tier 1 or 
Tier 3 calculation methodologies for CO2, except when natural 
gas usage in units of therms or mmBtu is obtained from gas billing 
records. In that case, use Equation C-8a in paragraph (c)(1)(i) of this 
section or Equation C-8b in paragraph (c)(1)(ii) of this section (as 
applicable). For Equation C-8, use the same values for fuel consumption 
that you use for the Tier 1 or Tier 3 calculation.
[GRAPHIC] [TIFF OMITTED] TR30OC09.013

Where:

CH4 or N2O = Annual CH4 or 
          N2O emissions from the combustion of a particular 
          type of fuel (metric tons).
Fuel = Mass or volume of the fuel combusted, either from company records 
          or directly measured by a fuel flow meter, as applicable (mass 
          or volume per year).

[[Page 616]]

HHV = Default high heat value of the fuel from Table C-1 of this 
          subpart; alternatively, for Tier 3, if actual HHV data are 
          available for the reporting year, you may average these data 
          using the procedures specified in paragraph (a)(2)(ii) of this 
          section, and use the average value in Equation C-8 (mmBtu per 
          mass or volume).
EF = Fuel-specific default emission factor for CH4 or 
          N2O, from Table C-2 of this subpart (kg 
          CH4 or N2O per mmBtu).
1 x 10-3 = Conversion factor from kilograms to metric tons.

    (i) Use Equation C-8a to calculate CH4 and N2O 
emissions when natural gas usage is obtained from gas billing records in 
units of therms.
[GRAPHIC] [TIFF OMITTED] TR17DE10.018

where:

CH4 or N2O = Annual CH4 or 
          N2O emissions from the combustion of natural gas 
          (metric tons).
Fuel = Annual natural gas usage, from gas billing records (therms).
EF = Fuel-specific default emission factor for CH4 or 
          N2O, from Table C-2 of this subpart (kg 
          CH4 or N2O per mmBtu).
0.1 = Conversion factor from therms to mmBtu
1 x 10-3 = Conversion factor from kilograms to metric tons.

    (ii) Use Equation C-8b to calculate CH4 and 
N2O emissions when natural gas usage is obtained from gas 
billing records in units of mmBtu.
    CH4 or N2O = 1 x 10-3 * Fuel * EF 
(Eq. C-8b)

where:

CH4 or N2O = Annual CH4 or 
          N2O emissions from the combustion of natural gas 
          (metric tons).
Fuel = Annual natural gas usage, from gas billing records (mmBtu).
EF = Fuel-specific default emission factor for CH4 or 
          N2O, from Table C-2 of this subpart (kg 
          CH4 or N2O per mmBtu).
1 x 10-3 = Conversion factor from kilograms to metric tons.

    (2) Use Equation C-9a of this section to estimate CH4 and 
N2O emissions for any fuels for which you use the Tier 2 
Equation C-2a of this section to estimate CO2 emissions. Use 
the same values for fuel consumption and HHV that you use for the Tier 2 
calculation.
[GRAPHIC] [TIFF OMITTED] TR30OC09.014

Where:

CH4 or N2O = Annual CH4 or 
          N2O emissions from the combustion of a particular 
          type of fuel (metric tons).
Fuel = Mass or volume of the fuel combusted during the reporting year.
HHV = High heat value of the fuel, averaged for all valid measurements 
          for the reporting year (mmBtu per mass or volume).
EF = Fuel-specific default emission factor for CH4 or 
          N2O, from Table C-2 of this subpart (kg 
          CH4 or N2O per mmBtu).
1 x 10-3 = Conversion factor from kilograms to metric tons.

    (3) Use Equation C-9b of this section to estimate CH4 and 
N2O emissions for any fuels for which you use Equation C-2c 
of this section to calculate the CO2 emissions. Use the same 
values for steam generation and the ratio ``B'' that you use for 
Equation C-2c.
[GRAPHIC] [TIFF OMITTED] TR30OC09.015


[[Page 617]]


Where:

CH4 or N2O = Annual CH4 or 
          N2O emissions from the combustion of a solid fuel 
          (metric tons).
Steam = Total mass of steam generated by solid fuel combustion during 
          the reporting year (lb steam).
B = Ratio of the boiler's maximum rated heat input capacity to its 
          design rated steam output (mmBtu/lb steam).
EF = Fuel-specific emission factor for CH4 or N2O, 
          from Table C-2 of this subpart (kg CH4 or 
          N2O per mmBtu).
1 x 10-3 = Conversion factor from kilograms to metric tons.

    (4) Use Equation C-10 of this section for: units subject to subpart 
D of this part; units that qualify for and elect to use the alternative 
CO2 mass emissions calculation methodologies described in 
paragraph (a)(5) of this section; and units that use the Tier 4 
Calculation Methodology.
[GRAPHIC] [TIFF OMITTED] TR30OC09.016

Where:

CH4 or N2O = Annual CH4 or 
          N2O emissions from the combustion of a particular 
          type of fuel (metric tons).
(HI)A = Cumulative annual heat input from combustion of the 
          fuel (mmBtu).
EF = Fuel-specific emission factor for CH4 or N2O, 
          from Table C-2 of this section (kg CH4 or 
          N2O per mmBtu).
0.001 = Conversion factor from kg to metric tons.

    (i) If only one type of fuel listed in Table C-2 of this subpart is 
combusted during the reporting year, substitute the cumulative annual 
heat input from combustion of the fuel into Equation C-10 of this 
section to calculate the annual CH4 or N2O 
emissions. For units in the Acid Rain Program and units that report heat 
input data to EPA year-round according to part 75 of this chapter, 
obtain the cumulative annual heat input directly from the electronic 
data reports required under Sec. 75.64 of this chapter. For Tier 4 
units, use the best available information, as described in paragraph 
(c)(4)(ii)(C) of this section, to estimate the cumulative annual heat 
input (HI)A.
    (ii) If more than one type of fuel listed in Table C-2 of this 
subpart is combusted during the reporting year, use Equation C-10 of 
this section separately for each type of fuel, except as provided in 
paragraph (c)(4)(ii)(B) of this section. Determine the appropriate 
values of (HI)A as follows:
    (A) For units in the Acid Rain Program and other units that report 
heat input data to EPA year-round according to part 75 of this chapter, 
obtain (HI)A for each type of fuel from the electronic data 
reports required under Sec. 75.64 of this chapter, except as otherwise 
provided in paragraphs (c)(4)(ii)(B) and (c)(4)(ii)(D) of this section.
    (B) For a unit that uses CEMS to monitor hourly heat input according 
to part 75 of this chapter, the value of (HI)A obtained from 
the electronic data reports under Sec. 75.64 of this chapter may be 
attributed exclusively to the fuel with the highest F-factor, when the 
reporting option in 3.3.6.5 of appendix F to part 75 of this chapter is 
selected and implemented.
    (C) For Tier 4 units, use the best available information (e.g., fuel 
feed rate measurements, fuel heating values, engineering analysis) to 
estimate the value of (HI)A for each type of fuel. 
Instrumentation used to make these estimates is not subject to the 
calibration requirements of Sec. 98.3(i) or to the QA requirements of 
Sec. 98.34.
    (D) Units in the Acid Rain Program and other units that report heat 
input data to EPA year-round according to part 75 of this chapter may 
use the best available information described in paragraph (c)(4)(ii)(C) 
of this section, to estimate (HI)A for each fuel type, 
whenever fuel-specific heat input values cannot be directly obtained 
from the electronic data reports under Sec. 75.64 of this chapter.
    (5) When multiple fuels are combusted during the reporting year, sum 
the fuel-specific results from Equations C-8, C-8a, C-8b, C-9a, C-9b, or 
C-10 of this section (as applicable) to obtain the total annual 
CH4 and N2O emissions, in metric tons.

[[Page 618]]

    (6) Calculate the annual CH4 and N2O mass 
emissions from the combustion of blended fuels as follows:
    (i) If the mass or volume of each component fuel in the blend is 
measured before the fuels are mixed and combusted, calculate and report 
CH4 and N2O emissions separately for each 
component fuel, using the applicable procedures in this paragraph (c).
    (ii) If the mass or volume of each component fuel in the blend is 
not measured before the fuels are mixed and combusted, a reasonable 
estimate of the percentage composition of the blend, based on best 
available information, is required. Perform the following calculations 
for each component fuel ``i'' that is listed in Table C-2:
    (A) Multiply (% Fuel)i, the estimated mass or volume 
percentage (decimal fraction) of component fuel ``i'', by the total 
annual mass or volume of the blended fuel combusted during the reporting 
year, to obtain an estimate of the annual consumption of component 
``i'';
    (B) Multiply the result from paragraph (c)(6)(ii)(A) of this section 
by the HHV of the fuel (default value or, if available, the measured 
annual average value), to obtain an estimate of the annual heat input 
from component ``i'';
    (C) Calculate the annual CH4 and N2O emissions 
from component ``i'', using Equation C-8, C-8a, C-8b, C-9a, or C-10 of 
this section, as applicable;
    (D) Sum the annual CH4 emissions across all component 
fuels to obtain the annual CH4 emissions for the blend. 
Similarly sum the annual N2O emissions across all component 
fuels to obtain the annual N2O emissions for the blend. 
Report these annual emissions totals.
    (d) Calculation of CO2 from sorbent. (1) When a unit is a fluidized 
bed boiler, is equipped with a wet flue gas desulfurization system, or 
uses other acid gas emission controls with sorbent injection to remove 
acid gases, if the chemical reaction between the acid gas and the 
sorbent produces CO2 emissions, use Equation C-11 of this 
section to calculate the CO2 emissions from the sorbent, 
except when those CO2 emissions are monitored by CEMS. When a 
sorbent other than CaCO3 is used, determine site-specific 
values of R and MWS.
[GRAPHIC] [TIFF OMITTED] TR30OC09.017

Where:

CO2 = CO2 emitted from sorbent for the reporting 
          year (metric tons).
S = Limestone or other sorbent used in the reporting year, from company 
          records (short tons).
R = The number of moles of CO2 released upon capture of one 
          mole of the acid gas species being removed (R = 1.00 when the 
          sorbent is CaCO3 and the targeted acid gas species 
          is SO2).
MWCO2 = Molecular weight of carbon dioxide (44).
MWS = Molecular weight of sorbent (100 if calcium carbonate).
0.91 = Conversion factor from short tons to metric tons.

    (2) The total annual CO2 mass emissions reported for the 
unit shall include the CO2 emissions from the combustion 
process and the CO2 emissions from the sorbent.
    (e) Biogenic CO2 emissions from combustion of biomass with other 
fuels. Use the applicable procedures of this paragraph (e) to estimate 
biogenic CO2 emissions from units that combust a combination 
of biomass and fossil fuels (i.e., either co-fired or blended fuels). 
Separate reporting of biogenic CO2 emissions from the 
combined combustion of biomass and fossil fuels is required for those 
biomass fuels listed in Table C-1 of this section and for municipal 
solid waste. In addition, when a biomass fuel that is not listed in 
Table C-1 is combusted in a unit that has a maximum rated heat input 
greater than 250 mmBtu/hr, if the biomass fuel accounts for 10% or more 
of the annual heat input to the unit, and if the unit does not use CEMS 
to quantify its annual CO2 mass emissions, then, pursuant to 
Sec. 98.33(b)(3)(iii),

[[Page 619]]

Tier 3 must be used to determine the carbon content of the biomass fuel 
and to calculate the biogenic CO2 emissions from combustion 
of the fuel. Notwithstanding these requirements, in accordance with 
Sec. 98.3(c)(12), separate reporting of biogenic CO2 
emissions is optional for the 2010 reporting year for units subject to 
subpart D of this part and for units that use the CO2 mass 
emissions calculation methodologies in part 75 of this chapter, pursuant 
to paragraph (a)(5) of this section. However, if the owner or operator 
opts to report biogenic CO2 emissions separately for these 
units, the appropriate method(s) in this paragraph (e) shall be used. 
Separate reporting of biogenic CO2 emissions from the 
combustion of tires is also optional, but may be reported by following 
the provisions of paragraph (e)(3) of this section.
    (1) You may use Equation C-1 of this subpart to calculate the annual 
CO2 mass emissions from the combustion of the biomass fuels 
listed in Table C-1 of this subpart (except MSW and tires), in a unit of 
any size, including units equipped with a CO2 CEMS, except 
when the use of Tier 2 is required as specified in paragraph (b)(1)(iv) 
of this section. Determine the quantity of biomass combusted using one 
of the following procedures in this paragraph (e)(1), as appropriate, 
and document the selected procedures in the Monitoring Plan under Sec. 
98.3(g):
    (i) Company records.
    (ii) The procedures in paragraph (e)(4) of this section.
    (iii) The best available information for premixed fuels that contain 
biomass and fossil fuels (e.g., liquid fuel mixtures containing 
biodiesel).
    (2) You may use the procedures of this paragraph if the following 
three conditions are met: First, a CO2 CEMS (or a surrogate 
O2 monitor) and a stack gas flow rate monitor are used to 
determine the annual CO2 mass emissions (either according to 
part 75 of this chapter, the Tier 4 Calculation Methodology, or the 
alternative calculation methodology specified in paragraph (a)(5)(iii) 
of this section); second, neither MSW nor tires is combusted in the unit 
during the reporting year; and third, the CO2 emissions 
consist solely of combustion products (i.e., no process or sorbent 
emissions included).
    (i) For each operating hour, use Equation C-12 of this section to 
determine the volume of CO2 emitted.
[GRAPHIC] [TIFF OMITTED] TR30OC09.018

Where:

VCO2h = Hourly volume of CO2 emitted (scf).
(%CO2)h = Hourly average CO2 
          concentration, measured by the CO2 concentration 
          monitor, or, if applicable, calculated from the hourly average 
          O2 concentration (%CO2).
Qh = Hourly average stack gas volumetric flow rate, measured 
          by the stack gas volumetric flow rate monitor (scfh).
th = Source operating time (decimal fraction of the hour 
          during which the source combusts fuel, i.e., 1.0 for a full 
          operating hour, 0.5 for 30 minutes of operation, etc.).
100 = Conversion factor from percent to a decimal fraction.

    (ii) Sum all of the hourly VCO2h values for the reporting 
year, to obtain Vtotal, the total annual volume of 
CO2 emitted.
    (iii) Calculate the annual volume of CO2 emitted from 
fossil fuel combustion using Equation C-13 of this section. If two or 
more types of fossil fuel are combusted during the year, perform a 
separate calculation with Equation C-13 of this section for each fuel 
and sum the results.
[GRAPHIC] [TIFF OMITTED] TR30OC09.019

Where:

Vff = Annual volume of CO2 emitted from combustion 
          of a particular fossil fuel (scf).
Fuel = Total quantity of the fossil fuel combusted in the reporting 
          year, from company records, as defined in Sec. 98.6 (lb for

[[Page 620]]

          solid fuel, gallons for liquid fuel, and scf for gaseous 
          fuel).
Fc = Fuel-specific carbon based F-factor, either a default 
          value from Table 1 in section 3.3.5 of appendix F to part 75 
          of this chapter, or a site-specific value determined under 
          section 3.3.6 of appendix F to part 75 (scf CO2/
          mmBtu).
HHV = High heat value of the fossil fuel, from fuel sampling and 
          analysis (annual average value in Btu/lb for solid fuel, Btu/
          gal for liquid fuel and Btu/scf for gaseous fuel, sampled as 
          specified (e.g., monthly, quarterly, semi-annually, or by lot) 
          in Sec. 98.34(a)(2)). The average HHV shall be calculated 
          according to the requirements of paragraph (a)(2)(ii) of this 
          section.
10\6\ = Conversion factor, Btu per mmBtu.

    (iv) Subtract Vff from Vtotal to obtain 
Vbio, the annual volume of CO2 from the combustion 
of biomass.
    (v) Calculate the biogenic percentage of the annual CO2 
emissions,expressed as a decimal fraction, using Equation C-14 of this 
section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.020

    (vi) Calculate the annual biogenic CO2 mass emissions, in 
metric tons, by multiplying the results obtained from Equation C-14 of 
this section by the annual CO2 mass emissions in metric tons, 
as determined:
    (A) Under paragraph (a)(4)(vi) of this section, for units using the 
Tier 4 Calculation Methodology.
    (B) Under paragraph (a)(5)(iii)(B) of this section, for units using 
the alternative calculation methodology specified in paragraph 
(a)(5)(iii).
    (C) From the electronic data report required under Sec. 75.64 of 
this chapter, for units in the Acid Rain Program and other units using 
CEMS to monitor and report CO2 mass emissions according to 
part 75 of this chapter. However, before calculating the annual biogenic 
CO2 mass emissions, multiply the cumulative annual 
CO2 mass emissions by 0.91 to convert from short tons to 
metric tons.
    (3) You must use the procedures in paragraphs (e)(3)(i) through 
(e)(3)(iii) of this section to determine the annual biogenic 
CO2 emissions from the combustion of MSW, except as otherwise 
provided in paragraph (e)(3)(iv) of this section. These procedures also 
may be used for any unit that co-fires biomass and fossil fuels, 
including units equipped with a CO2 CEMS, and units for which 
optional separate reporting of biogenic CO2 emissions from 
the combustion of tires is selected.
    (i) Use an applicable CO2 emissions calculation method in 
this section to quantify the total annual CO2 mass emissions 
from the unit.
    (ii) Determine the relative proportions of biogenic and non-biogenic 
CO2 emissions in the flue gas on a quarterly basis using the 
method specified in Sec. 98.34(d) (for units that combust MSW as the 
primary fuel or as the only fuel with a biogenic component) or in Sec. 
98.34(e) (for other units, including units that combust tires).
    (iii) Determine the annual biogenic CO2 mass emissions 
from the unit by multiplying the total annual CO2 mass 
emissions by the annual average biogenic decimal fraction obtained from 
Sec. 98.34(d) or Sec. 98.34(e), as applicable.
    (iv) If the combustion of MSW and/or tires provides no more than 10 
percent of the annual heat input to a unit, or if a small, batch 
incinerator combusts no more than 1,000 tons per year of MSW, you may 
estimate the annual biogenic CO2 emissions as follows, in 
lieu of following the procedures in paragraphs (e)(3)(i) through 
(e)(3)(iii) of this section:
    (A) Calculate the total annual CO2 emissions from 
combustion of MSW and/or tires in the unit, using the Tier 1 calculation 
methodology in paragraph (a)(1) of this section.
    (B) Multiply the result from paragraph (e)(3)(iv)(A) of this section 
by the appropriate default factor to determine the annual biogenic 
CO2 emissions, in metric tons. For MSW, use a default factor 
of 0.60 and for tires, use a default factor of 0.20.
    (4) If Equation C-1 or Equation C-2a of this section is selected to 
calculate the annual biogenic mass emissions for wood, wood waste, or 
other solid biomass-derived fuel, Equation C-15 of this section may be 
used to quantify biogenic fuel consumption, provided that all of the 
required input parameters are accurately quantified. Similar equations 
and calculation methodologies based on steam generation

[[Page 621]]

and boiler efficiency may be used, provided that they are documented in 
the GHG Monitoring Plan required by Sec. 98.3(g)(5).
[GRAPHIC] [TIFF OMITTED] TR30OC09.021

Where:

(Fuel)p = Quantity of biomass consumed during the measurement 
          period ``p'' (tons/year or tons/month, as applicable).
H = Average enthalpy of the boiler steam for the measurement period 
          (Btu/lb).
S = Total boiler steam production for the measurement period (lb/month 
          or lb/year, as applicable).
(HI)nb = Heat input from co-fired fossil fuels and non-
          biomass-derived fuels for the measurement period, based on 
          company records of fuel usage and default or measured HHV 
          values (Btu/month or Btu/year, as applicable).
(HHV)bio = Default or measured high heat value of the biomass 
          fuel (Btu/lb).
(Eff)bio = Percent efficiency of biomass-to-energy 
          conversion, expressed as a decimal fraction.
2000 = Conversion factor (lb/ton).
    (5) For units subject to subpart D of this part and for units that 
use the methods in part 75 of this chapter to quantify CO2 
mass emissions in accordance with paragraph (a)(5) of this section, you 
may calculate biogenic CO2 emissions from the combustion of 
biomass fuels listed in Table C-1 of this subpart using Equation C-15a. 
This equation may not be used to calculate biogenic CO2 
emissions from the combustion of tires or MSW; the methods described in 
paragraph (e)(3) of this section must be used for those fuels. Whenever 
(HI)A, the annual heat input from combustion of biomass fuel 
in Equation C-15a, cannot be determined solely from the information in 
the electronic emissions reports under Sec. 75.64 of this chapter 
(e.g., in cases where a unit uses CEMS in combination with multiple F-
factors, a worst-case F-factor, or a prorated F-factor to report heat 
input rather than reporting heat input based on fuel type), use the best 
available information (as described in Sec. Sec. 98.33(c)(4)(ii)(C) and 
(c)(4)(ii)(D)) to determine (HI)A.

    CO2 = 0.001 * (HI)A * EF (Eq. C-15a)

where:

CO2 = Annual CO2 mass emissions from the 
          combustion of a particular type of biomass fuel listed in 
          Table C-1 (metric tons)
(HI)A = Annual heat input from the biomass fuel, obtained, 
          where feasible, from the electronic emissions reports required 
          under Sec. 75.64 of this chapter. Where this is not feasible 
          use best available information, as described in Sec. Sec. 
          98.33(c)(4)(ii)(C) and (c)(4)(ii)(D) (mmBtu)
EF = CO2 emission factor for the biomass fuel, from Table C-1 
          (kg CO2/mmBtu)
0.001 = Conversion factor from kg to metric tons

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79140, Dec. 17, 2010; 
78 FR 71950, Nov. 29, 2013]




Sec. 98.34  Monitoring and QA/QC requirements.

    The CO2 mass emissions data for stationary fuel 
combustion sources shall be monitored as follows:
    (a) For the Tier 2 Calculation Methodology:
    (1) All fuel samples shall be taken at a location in the fuel 
handling system that provides a sample representative of the fuel 
combusted. The fuel sampling and analysis may be performed by either the 
owner or operator or the supplier of the fuel.
    (2) The minimum required frequency of the HHV sampling and analysis 
for each type of fuel or fuel mixture (blend) is specified in this 
paragraph. When the specified frequency for a particular fuel or blend 
is based on a specified time period (e.g., week, month, quarter, or 
half-year), fuel sampling and analysis is required only for those time 
periods in which the fuel or blend is combusted. The owner or operator 
may perform fuel sampling and analysis more often than the minimum 
required frequency, in order to obtain a more representative annual 
average HHV.

[[Page 622]]

    (i) For natural gas, semiannual sampling and analysis is required 
(i.e., twice in a calendar year, with consecutive samples taken at least 
four months apart).
    (ii) For coal and fuel oil, and for any other solid or liquid fuel 
that is delivered in lots, analysis of at least one representative 
sample from each fuel lot is required. For fuel oil, as an alternative 
to sampling each fuel lot, a sample may be taken upon each addition of 
oil to the unit's storage tank. Flow proportional sampling, continuous 
drip sampling, or daily manual oil sampling may also be used, in lieu of 
sampling each fuel lot. If the daily manual oil sampling option is 
selected, sampling from a particular tank is required only on days when 
oil from the tank is combusted by the unit (or units) served by the 
tank. If you elect to sample from the storage tank upon each addition of 
oil to the tank, you must take at least one sample from each tank that 
is currently in service and whenever oil is added to the tank, for as 
long as the tank remains in service. You need not take any samples from 
a storage tank while it is out of service. Rather, take a sample when 
the tank is brought into service and whenever oil is added to the tank, 
for as long as the tank remains in service. If multiple additions of oil 
are made to a particular in-service tank on a given day (e.g., from 
multiple deliveries), one sample taken after the final addition of oil 
is sufficient. For the purposes of this section, a fuel lot is defined 
as a shipment or delivery of a single type of fuel (e.g., ship load, 
barge load, group of trucks, group of railroad cars, oil delivery via 
pipeline from a tank farm, etc.). However, if multiple deliveries of a 
particular type of fuel are received from the same supply source in a 
given calendar month, the deliveries for that month may be considered, 
collectively, to comprise a fuel lot, requiring only one representative 
sample, subject to the following conditions:
    (A) For coal, the ``type'' of fuel means the rank of the coal (i.e., 
anthracite, bituminous, sub-bituminous, or lignite). For fuel oil, the 
``type'' of fuel means the grade number or classification of the oil 
(e.g., No. 1 oil, No. 2 oil, kerosene, Jet A fuel, etc.).
    (B) The owner or operator shall document in the monitoring plan 
under Sec. 98.3(g)(5) how the monthly sampling of each type of fuel is 
performed.
    (iii) For liquid fuels other than fuel oil, and for gaseous fuels 
other than natural gas (including biogas), sampling and analysis is 
required at least once per calendar quarter. To the extent practicable, 
consecutive quarterly samples shall be taken at least 30 days apart.
    (iv) For other solid fuels (except MSW), weekly sampling is required 
to obtain composite samples, which are then analyzed monthly.
    (v) For fuel blends that are received already mixed, or that are 
mixed on-site without measuring the exact amount of each component, as 
described in paragraph (a)(3)(ii) of this section, determine the HHV of 
the blend as follows. For blends of solid fuels (except MSW), weekly 
sampling is required to obtain composite samples, which are analyzed 
monthly. For blends of liquid or gaseous fuels, sampling and analysis is 
required at least once per calendar quarter. More frequent sampling is 
recommended if the composition of the blend varies significantly during 
the year.
    (3) Special considerations for blending of fuels. In situations 
where different types of fuel listed in Table C-1 of this subpart (for 
example, different ranks of coal or different grades of fuel oil) are in 
the same state of matter (i.e., solid, liquid, or gas), and are blended 
prior to combustion, use the following procedures to determine the 
appropriate CO2 emission factor and HHV for the blend.
    (i) If the fuels to be blended are received separately, and if the 
quantity (mass or volume) of each fuel is measured before the fuels are 
mixed and combusted, then, for each component of the blend, calculate 
the CO2 mass emissions separately. Substitute into Equation 
C-2a of this subpart the total measured mass or volume of the component 
fuel (from company records), together with the appropriate default 
CO2 emission factor from Table C-1, and the annual average 
HHV, calculated according to Sec. 98.33(a)(2)(ii). In this case, the 
fact that the fuels are blended prior to combustion is of no 
consequence.

[[Page 623]]

    (ii) If the fuel is received as a blend (i.e., already mixed) or if 
the components are mixed on site without precisely measuring the mass or 
volume of each one individually, a reasonable estimate of the relative 
proportions of the components of the blend must be made, using the best 
available information (e.g., the approximate annual average mass or 
volume percentage of each fuel, based on the typical or expected range 
of values). Determine the appropriate CO2 emission factor and 
HHV for use in Equation C-2a of this subpart, as follows:
    (A) Consider the blend to be the ``fuel type,'' measure its HHV at 
the frequency prescribed in paragraph (a)(2)(v) of this section, and 
determine the annual average HHV value for the blend according to Sec. 
98.33(a)(2)(ii).
    (B) Calculate a heat-weighted CO2 emission factor, 
(EF)B, for the blend, using Equation C-16 of this section. 
The heat-weighting in Equation C-16 is provided by the default HHVs 
(from Table C-1) and the estimated mass or volume percentages of the 
components of the blend.
    (C) Substitute into Equation C-2a of this subpart, the annual 
average HHV for the blend (from paragraph (a)(3)(ii)(A) of this section) 
and the calculated value of (EF)B, along with the total mass 
or volume of the blend combusted during the reporting year, to determine 
the annual CO2 mass emissions from combustion of the blend.
[GRAPHIC] [TIFF OMITTED] TR17DE10.003

where:

(EF)B = Heat-weighted CO2 emission factor for the 
          blend (kg CO2/mmBtu)
(HHV)i = Default high heat value for fuel ``i'' in the blend, 
          from Table C-1 (mmBtu per mass or volume)
(%Fuel)i = Estimated mass or volume percentage of fuel ``i'' 
          (mass % or volume %, as applicable, expressed as a decimal 
          fraction; e.g., 25% = 0.25)
(EF)i = Default CO2 emission factor for fuel ``i'' 
          from Table C-1 (mmBtu per mass or volume)
(HHV)B = Annual average high heat value for the blend, 
          calculated according to Sec. 98.33(a)(2)(ii) (mmBtu per mass 
          or volume)

    (iii) Note that for the case described in paragraph (a)(3)(ii) of 
this section, if measured HHV values for the individual fuels in the 
blend or for the blend itself are not routinely received at the minimum 
frequency prescribed in paragraph (a)(2) of this section (or at a 
greater frequency), and if the unit qualifies to use Tier 1, calculate 
(HHV)B*, the heat-weighted default HHV for the blend, using 
Equation C-17 of this section. Then, use Equation C-16 of this section, 
replacing the term (HHV)B with (HHV)B* in the 
denominator, to determine the heat-weighted CO2 emission 
factor for the blend. Finally, substitute into Equation C-1 of this 
subpart, the calculated values of (HHV)B* and 
(EF)B, along with the total mass or volume of the blend 
combusted during the reporting year, to determine the annual 
CO2 mass emissions from combustion of the blend.
[GRAPHIC] [TIFF OMITTED] TR17DE10.004


[[Page 624]]


where:

(HHV)B* = Heat-weighted default high heat value for the blend 
          (mmBtu per mass or Volume)
(HHV)i = Default high heat value for fuel ``i'' in the blend, 
          from Table C-1 (mmBtu per mass or volume)
(%Fuel)i = Estimated mass or volume percentage of fuel ``i'' 
          in the blend (mass % or volume %, as applicable, expressed as 
          a decimal fraction)

    (iv) If the fuel blend described in paragraph (a)(3)(ii) of this 
section consists of a mixture of fuel(s) listed in Table C-1 of this 
subpart and one or more fuels not listed in Table C-1, calculate 
CO2 and other GHG emissions only for the Table C-1 fuel(s), 
using the best available estimate of the mass or volume percentage(s) of 
the Table C-1 fuel(s) in the blend. In this case, Tier 1 shall be used, 
with the following modifications to Equations C-17 and C-1, to account 
for the fact that not all of the fuels in the blend are listed in Table 
C-1:
    (A) In Equation C-17, apply the term (Fuel)i only to the 
Table C-1 fuels. For each Table C-1 fuel, (Fuel)i will be the 
estimated mass or volume percentage of the fuel in the blend, divided by 
the sum of the mass or volume percentages of the Table C-1 fuels. For 
example, suppose that a blend consists of two Table C-1 fuels (``A'' and 
``B'') and one fuel type (``C'') not listed in the Table, and that the 
volume percentages of fuels A, B, and C in the blend, expressed as 
decimal fractions, are, respectively, 0.50, 0.30, and 0.20. The term 
(Fuel)i in Equation C-17 for fuel A will be 0.50/(0.50 + 
0.30) = 0.625, and for fuel B, (Fuel)i will be 0.30/(0.50 + 
0.30) = 0.375.
    (B) In Equation C-1, the term ``Fuel'' will be equal to the total 
mass or volume of the blended fuel combusted during the year multiplied 
by the sum of the mass or volume percentages of the Table C-1 fuels in 
the blend. For the example in paragraph (a)(3)(iv)(A) of this section, 
``Fuel'' = (Annual volume of the blend combusted)(0.80).
    (4) If, for a particular type of fuel, HHV sampling and analysis is 
performed more often than the minimum frequency specified in paragraph 
(a)(2) of this section, the results of all valid fuel analyses shall be 
used in the GHG emission calculations.
    (5) If, for a particular type of fuel, valid HHV values are obtained 
at less than the minimum frequency specifed in paragraph (a)(2) of this 
section, appropriate substitute data values shall be used in the 
emissions calculations, in accordance with missing data procedures of 
Sec. 98.35.
    (6) You must use one of the following appropriate fuel sampling and 
analysis methods. The HHV may be calculated using chromatographic 
analysis together with standard heating values of the fuel constituents, 
provided that the gas chromatograph is operated, maintained, and 
calibrated according to the manufacturer's instructions. Alternatively, 
you may use a method published by a consensus-based standards 
organization if such a method exists, or you may use industry standard 
practice to determine the high heat values. Consensus-based standards 
organizations include, but are not limited to, the following: ASTM 
International (100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, 
Pennsylvania 19428-B2959, (800) 262-1373, http://www.astm.org), the 
American National Standards Institute (ANSI, 1819 L Street, NW., 6th 
floor, Washington, DC 20036, (202) 293-8020, http://www.ansi.org), the 
American Gas Association (AGA, 400 North Capitol Street, NW., 4th Floor, 
Washington, DC 20001, (202) 824-7000, http://www.aga.org), the American 
Society of Mechanical Engineers (ASME, Three Park Avenue, New York, NY 
10016-5990, (800) 843-2763, http://www.asme.org), the American Petroleum 
Institute (API, 1220 L Street, NW., Washington, DC 20005-4070, (202) 
682-8000, http://www.api.org), and the North American Energy Standards 
Board (NAESB, 801 Travis Street, Suite 1675, Houston, TX 77002, (713) 
356-0060, http://www.api.org). The method(s) used shall be documented in 
the Monitoring Plan required under Sec. 98.3(g)(5).
    (b) For the Tier 3 Calculation Methodology:
    (1) You must calibrate each oil and gas flow meter according to 
Sec. 98.3(i) and the provisions of this paragraph (b)(1).
    (i) Perform calibrations using any of the test methods and 
procedures in this paragraph (b)(1)(i). The method(s) used shall be 
documented in the Monitoring Plan required under Sec. 98.3(g)(5).

[[Page 625]]

    (A) You may use the calibration procedures specified by the flow 
meter manufacturer.
    (B) You may use an appropriate flow meter calibration method 
published by a consensus-based standards organization, if such a method 
exists. Consensus-based standards organizations include, but are not 
limited to, the following: ASTM International (100 Barr Harbor Drive, 
P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-
1373, http://www.astm.org), the American National Standards Institute 
(ANSI, 1819 L Street, NW., 6th floor, Washington, DC 20036, (202) 293-
8020, http://www.ansi.org), the American Gas Association (AGA, 400 North 
Capitol Street, NW., 4th Floor, Washington, DC 20001, (202) 824-7000, 
http://www.aga.org), the American Society of Mechanical Engineers (ASME, 
Three Park Avenue, New York, NY 10016-5990, (800) 843-2763, http://
www.asme.org), the American Petroleum Institute (API, 1220 L Street, 
NW., Washington, DC 20005-4070, (202) 682-8000, http://www.api.org), and 
the North American Energy Standards Board (NAESB, 801 Travis Street, 
Suite 1675, Houston, TX 77002, (713) 356-0060, http://www.api.org).
    (C) You may use an industry-accepted practice.
    (ii) In addition to the initial calibration required by Sec. 
98.3(i), recalibrate each fuel flow meter (except as otherwise provided 
in paragraph (b)(1)(iii) of this section) according to one of the 
following. You may recalibrate annually, at the minimum frequency 
specified by the manufacturer, or at the interval specified by industry 
standard practice.
    (iii) Fuel billing meters are exempted from the initial and ongoing 
calibration requirements of this paragraph and from the Monitoring Plan 
and recordkeeping requirements of Sec. Sec. 98.3(g)(5)(i)(C), (g)(6), 
and (g)(7), provided that the fuel supplier and the unit combusting the 
fuel do not have any common owners and are not owned by subsidiaries or 
affiliates of the same company. Meters used exclusively to measure the 
flow rates of fuels that are only used for unit startup are also 
exempted from the initial and ongoing calibration requirements of this 
paragraph.
    (iv) For the initial calibration of an orifice, nozzle, or venturi 
meter; in-situ calibration of the transmitters is sufficient. A primary 
element inspection (PEI) shall be performed at least once every three 
years.
    (v) For the continuously-operating units and processes described in 
Sec. 98.3(i)(6), the required flow meter recalibrations and, if 
necessary, the PEIs may be postponed until the next scheduled 
maintenance outage.
    (vi) If a mixture of liquid or gaseous fuels is transported by a 
common pipe, you may either separately meter each of the fuels prior to 
mixing, using flow meters calibrated according to Sec. 98.3(i), or 
consider the fuel mixture to be the ``fuel type'' and meter the mixed 
fuel, using a flow meter calibrated according to Sec. 98.3(i).
    (2) Oil tank drop measurements (if used to determine liquid fuel use 
volume) shall be performed according to any an appropriate method 
published by a consensus-based standards organization (e.g., the 
American Petroleum Institute).
    (3) The carbon content and, if applicable, molecular weight of the 
fuels shall be determined according to the procedures in this paragraph 
(b)(3).
    (i) All fuel samples shall be taken at a location in the fuel 
handling system that provides a sample representative of the fuel 
combusted. The fuel sampling and analysis may be performed by either the 
owner or operator or by the supplier of the fuel.
    (ii) For each type of fuel, the minimum required frequency for 
collecting and analyzing samples for carbon content and (if applicable) 
molecular weight is specified in this paragraph. When the sampling 
frequency is based on a specified time period (e.g., week, month, 
quarter, or half-year), fuel sampling and analysis is required for only 
those time periods in which the fuel is combusted.
    (A) For natural gas, semiannual sampling and analysis is required 
(i.e., twice in a calendar year, with consecutive samples taken at least 
four months apart).

[[Page 626]]

    (B) For coal and fuel oil and for any other solid or liquid fuel 
that is delivered in lots, analysis of at least one representative 
sample from each fuel lot is required. For fuel oil, as an alternative 
to sampling each fuel lot, a sample may be taken upon each addition of 
oil to the storage tank. Flow proportional sampling, continuous drip 
sampling, or daily manual oil sampling may also be used, in lieu of 
sampling each fuel lot. If the daily manual oil sampling option is 
selected, sampling from a particular tank is required only on days when 
oil from the tank is combusted by the unit (or units) served by the 
tank. If you elect to sample from the storage tank upon each addition of 
oil to the tank, you must take at least one sample from each tank that 
is currently in service and whenever oil is added to the tank, for as 
long as the tank remains in service. You need not take any samples from 
a storage tank while it is out of service. Rather, take a sample when 
the tank is brought into service and whenever oil is added to the tank, 
for as long as the tank remains in service. If multiple additions of oil 
are made to a particular in service tank on a given day (e.g., from 
multiple deliveries), one sample taken after the final addition of oil 
is sufficient. For the purposes of this section, a fuel lot is defined 
as a shipment or delivery of a single type of fuel (e.g., ship load, 
barge load, group of trucks, group of railroad cars, oil delivery via 
pipeline from a tank farm, etc.). However, if multiple deliveries of a 
particular type of fuel are received from the same supply source in a 
given calendar month, the deliveries for that month may be considered, 
collectively, to comprise a fuel lot, requiring only one representative 
sample, subject to the following conditions:
    (1) For coal, the ``type'' of fuel means the rank of the coal (i.e., 
anthracite, bituminous, sub-bituminous, or lignite). For fuel oil, the 
``type'' of fuel means the grade number or classification of the oil 
(e.g., No. 1 oil, No. 2 oil, kerosene, Jet A fuel, etc.).
    (2) The owner or operator shall document in the monitoring plan 
under Sec. 98.3(g)(5) how the monthly sampling of each type of fuel is 
performed.
    (C) For liquid fuels other than fuel oil and for biogas, sampling 
and analysis is required at least once per calendar quarter. To the 
extent practicable, consecutive quarterly samples shall be taken at 
least 30 days apart.
    (D) For other solid fuels (except MSW), weekly sampling is required 
to obtain composite samples, which are then analyzed monthly.
    (E) For gaseous fuels other than natural gas and biogas (e.g., 
process gas), daily sampling and analysis to determine the carbon 
content and molecular weight of the fuel is required if continuous, on-
line equipment, such as a gas chromatograph, is in place to make these 
measurements. Otherwise, weekly sampling and analysis shall be 
performed.
    (F) For mixtures (blends) of solid fuels, weekly sampling is 
required to obtain composite samples, which are analyzed monthly. For 
blends of liquid fuels, and for gas mixtures consisting only of natural 
gas and biogas, sampling and analysis is required at least once per 
calendar quarter. For gas mixtures that contain gases other than natural 
gas (including biogas), daily sampling and analysis to determine the 
carbon content and molecular weight of the fuel is required if 
continuous, on-line equipment is in place to make these measurements. 
Otherwise, weekly sampling and analysis shall be performed.
    (iii) If, for a particular type of fuel, sampling and analysis for 
carbon content and molecular weight is performed more often than the 
minimum frequency specified in paragraph (b)(3) of this section, the 
results of all valid fuel analyses shall be used in the GHG emission 
calculations.
    (iv) If, for a particular type of fuel, sampling and analysis for 
carbon content and molecular weight is performed at less than the 
minimum frequency specified in paragraph (b)(3) of this section, 
appropriate substitute data values shall be used in the emissions 
calculations, in accordance with the missing data procedures of Sec. 
98.35.
    (v) To calculate the CO2 mass emissions from combustion 
of a blend of fuels in the same state of matter (solid, liquid, or gas), 
you may either:

[[Page 627]]

    (A) Apply Equation C-3, C-4 or C-5 of this subpart (as applicable) 
to each component of the blend, if the mass or volume, the carbon 
content, and (if applicable), the molecular weight of each component are 
accurately measured prior to blending; or
    (B) Consider the blend to be the ``fuel type.'' Then, at the 
frequency specified in paragraph (b)(3)(ii)(F) of this section, measure 
the carbon content and, if applicable, the molecular weight of the blend 
and calculate the annual average value of each parameter in the manner 
described in Sec. 98.33(a)(2)(ii). Also measure the mass or volume of 
the blended fuel combusted during the reporting year. Substitute these 
measured values into Equation C-3, C-4, or C-5 of this subpart (as 
applicable).
    (4) You must use one of the following appropriate fuel sampling and 
analysis methods. The results of chromatographic analysis of the fuel 
may be used, provided that the gas chromatograph is operated, 
maintained, and calibrated according to the manufacturer's instructions. 
Alternatively, you may use a method published by a consensus-based 
standards organization if such a method exists, or you may use industry 
standard practice to determine the carbon content and molecular weight 
(for gaseous fuel) of the fuel. Consensus-based standards organizations 
include, but are not limited to, the following: ASTM International (100 
Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 
19428-B2959, (800) 262-1373, http://www.astm.org), the American National 
Standards Institute (ANSI, 1819 L Street, NW., 6th floor, Washington, DC 
20036, (202) 293-8020, http://www.ansi.org), the American Gas 
Association (AGA, 400 North Capitol Street, NW., 4th Floor, Washington, 
DC 20001, (202) 824-7000, http://www.aga.org), the American Society of 
Mechanical Engineers (ASME, Three Park Avenue, New York, NY 10016-5990, 
(800) 843-2763, http://www.asme.org), the American Petroleum Institute 
(API, 1220 L Street, NW., Washington, DC 20005-4070, (202) 682-8000, 
http://www.api.org), and the North American Energy Standards Board 
(NAESB, 801 Travis Street, Suite 1675, Houston, TX 77002, (713) 356-
0060, http://www.api.org). The method(s) used shall be documented in the 
Monitoring Plan required under Sec. 98.3(g)(5).
    (c) For the Tier 4 Calculation Methodology, the CO2, flow 
rate, and (if applicable) moisture monitors must be certified prior to 
the applicable deadline specified in Sec. 98.33(b)(5).
    (1) For initial certification, you may use any one of the following 
three procedures in this paragraph.
    (i) Sec. Sec. 75.20(c)(2), (c)(4), and (c)(5) through (c)(7) of 
this chapter and appendix A to part 75 of this chapter.
    (ii) The calibration drift test and relative accuracy test audit 
(RATA) procedures of Performance Specification 3 in appendix B to part 
60 of this chapter (for the CO2 concentration monitor) and 
Performance Specification 6 in appendix B to part 60 of this chapter 
(for the continuous emission rate monitoring system (CERMS)).
    (iii) The provisions of an applicable State continuous monitoring 
program.
    (2) If an O2 concentration monitor is used to determine 
CO2 concentrations, the applicable provisions of part 75 of 
this chapter, part 60 of this chapter, or an applicable State continuous 
monitoring program shall be followed for initial certification and on-
going quality assurance, and all required RATAs of the monitor shall be 
done on a percent CO2 basis.
    (3) For ongoing quality assurance, follow the applicable procedures 
in either appendix B to part 75 of this chapter, appendix F to part 60 
of this chapter, or an applicable State continuous monitoring program. 
If appendix F to part 60 of this chapter is selected for on-going 
quality assurance, perform daily calibration drift assessments for both 
the CO2 monitor (or surrogate O2 monitor) and the 
flow rate monitor, conduct cylinder gas audits of the CO2 
concentration monitor in three of the four quarters of each year (except 
for non-operating quarters), and perform annual RATAs of the 
CO2 concentration monitor and the CERMS.
    (4) For the purposes of this part, the stack gas volumetric flow 
rate monitor RATAs required by appendix B to part 75 of this chapter and 
the annual RATAs of the CERMS required by appendix F to part 60 of this 
chapter need only be done at one operating level, representing normal 
load or normal

[[Page 628]]

process operating conditions, both for initial certification and for 
ongoing quality assurance.
    (5) If, for any source operating hour, quality assured data are not 
obtained with a CO2 monitor (or surrogate O2 
monitor), flow rate monitor, or (if applicable) moisture monitor, use 
appropriate substitute data values in accordance with the missing data 
provisions of Sec. 98.35.
    (6) For certain applications where combined process emissions and 
combustion emissions are measured, the CO2 concentrations in 
the flue gas may be considerably higher than for combustion emissions 
alone. In such cases, the span of the CO2 monitor may, if 
necessary, be set higher than the specified levels in the applicable 
regulations. If the CO2 span value is set higher than 20 
percent CO2, the cylinder gas audits of the CO2 
monitor under appendix F to part 60 of this chapter may be performed at 
40 to 60 percent and 80 to 100 percent of span, in lieu of the 
prescribed calibration levels of 5 to 8 percent CO2 and 10 to 
14 percent CO2.
    (7) Hourly average data from the CEMS shall be validated in a manner 
consistent with one of the following: Sec. Sec. 60.13(h)(2)(i) through 
(h)(2)(vi) of this chapter; Sec. 75.10(d)(1) of this chapter; or the 
hourly data validation requirements of an applicable State CEM 
regulation.
    (d) Except as otherwise provided in Sec. 98.33 (b)(1)(vi) and 
(b)(1)(vii), when municipal solid waste (MSW) is either the primary fuel 
combusted in a unit or the only fuel with a biogenic component combusted 
in the unit, determine the biogenic portion of the CO2 
emissions using ASTM D6866-08 Standard Test Methods for Determining the 
Biobased Content of Solid, Liquid, and Gaseous Samples Using Radiocarbon 
Analysis (incorporated by reference, see Sec. 98.7) and ASTM D7459-08 
Standard Practice for Collection of Integrated Samples for the 
Speciation of Biomass (Biogenic) and Fossil-Derived Carbon Dioxide 
Emitted from Stationary Emissions Sources (incorporated by reference, 
see Sec. 98.7). Perform the ASTM D7459-08 sampling and the ASTM D6866-
08 analysis at least once in every calendar quarter in which MSW is 
combusted in the unit. Collect each gas sample during normal unit 
operating conditions for at least 24 total (not necessarily consecutive) 
hours, or longer if the facility deems it necessary to obtain a 
representative sample. Notwithstanding this requirement, if the types of 
fuels combusted and their relative proportions are consistent throughout 
the year, the minimum required sampling time may be reduced to 8 hours 
if at least two 8-hour samples and one 24-hour sample are collected 
under normal operating conditions, and arithmetic average of the 
biogenic fraction of the flue gas from the 8-hour samples (expressed as 
a decimal) is within 5 percent of the biogenic 
fraction from the 24-hour test. There must be no overlapping of the 8-
hour and 24-hour test periods. Document the results of the demonstration 
in the unit's monitoring plan. If the types of fuels and their relative 
proportions are not consistent throughout the year, an optional sampling 
approach that facilities may wish to consider to obtain a more 
representative sample is to collect an integrated sample by extracting a 
small amount of flue gas (e.g., 1 to 5 cc) in each unit operating hour 
during the quarter. Separate the total annual CO2 emissions 
into the biogenic and non-biogenic fractions using the average 
proportion of biogenic emissions of all samples analyzed during the 
reporting year. Express the results as a decimal fraction (e.g., 0.30, 
if 30 percent of the CO2 is biogenic). When MSW is the 
primary fuel for multiple units at the facility, and the units are fed 
from a common fuel source, testing at only one of the units is 
sufficient.
    (e) For other units that combust combinations of biomass fuel(s) (or 
heterogeneous fuels that have a biomass component, e.g., tires) and 
fossil (or other non-biogenic) fuel(s), in any proportions, ASTM D6866-
08 (incorporated by reference, see Sec. 98.7) and ASTM D7459-08 
(incorporated by reference, see Sec. 98.7) may be used to determine the 
biogenic portion of the CO2 emissions in every calendar 
quarter in which biomass and non-biogenic fuels are co-fired in the 
unit. Follow the procedures in paragraph (d) of this section. If the 
primary fuel for multiple units at the facility consists of tires, and 
the

[[Page 629]]

units are fed from a common fuel source, testing at only one of the 
units is sufficient.
    (f) The records required under Sec. 98.3(g)(2)(i) shall include an 
explanation of how the following parameters are determined from company 
records (or, if applicable, from the best available information):
    (1) Fuel consumption, when the Tier 1 and Tier 2 Calculation 
Methodologies are used, including cases where Sec. 98.36(c)(4) applies.
    (2) Fuel consumption, when solid fuel is combusted and the Tier 3 
Calculation Methodology is used.
    (3) Fossil fuel consumption when Sec. 98.33(e)(2) applies to a unit 
that uses CEMS to quantify CO2 emissions and that combusts 
both fossil and biomass fuels.
    (4) Sorbent usage, when Sec. 98.33(d) applies.
    (5) Quantity of steam generated by a unit when Sec. 
98.33(a)(2)(iii) applies.
    (6) Biogenic fuel consumption and high heating value, as applicable, 
under Sec. Sec. 98.33(e)(5) and (e)(6).
    (7) Fuel usage for CH4 and N2O emissions 
calculations under Sec. 98.33(c)(4)(ii).
    (8) Mass of biomass combusted, for premixed fuels that contain 
biomass and fossil fuels under Sec. 98.33(e)(1)(iii).

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79146, Dec. 17, 2010]



Sec. 98.35  Procedures for estimating missing data.

    Whenever a quality-assured value of a required parameter is 
unavailable (e.g., if a CEMS malfunctions during unit operation or if a 
required fuel sample is not taken), a substitute data value for the 
missing parameter shall be used in the calculations.
    (a) For all units subject to the requirements of the Acid Rain 
Program, and all other stationary combustion units subject to the 
requirements of this part that monitor and report emissions and heat 
input data year-round in accordance with part 75 of this chapter, the 
missing data substitution procedures in part 75 of this chapter shall be 
followed for CO2 concentration, stack gas flow rate, fuel 
flow rate, high heating value, and fuel carbon content.
    (b) For units that use the Tier 1, Tier 2, Tier 3, and Tier 4 
Calculation Methodologies, perform missing data substitution as follows 
for each parameter:
    (1) For each missing value of the high heating value, carbon 
content, or molecular weight of the fuel, substitute the arithmetic 
average of the quality-assured values of that parameter immediately 
preceding and immediately following the missing data incident. If the 
``after'' value has not been obtained by the time that the GHG emissions 
report is due, you may use the ``before'' value for missing data 
substitution or the best available estimate of the parameter, based on 
all available process data (e.g., electrical load, steam production, 
operating hours). If, for a particular parameter, no quality-assured 
data are available prior to the missing data incident, the substitute 
data value shall be the first quality-assured value obtained after the 
missing data period.
    (2) For missing records of CO2 concentration, stack gas 
flow rate, percent moisture, fuel usage, and sorbent usage, the 
substitute data value shall be the best available estimate of the 
parameter, based on all available process data (e.g., electrical load, 
steam production, operating hours, etc.). You must document and retain 
records of the procedures used for all such estimates.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79150, Dec. 17, 2010]



Sec. 98.36  Data reporting requirements.

    (a) In addition to the facility-level information required under 
Sec. 98.3, the annual GHG emissions report shall contain the unit-level 
or process-level data specified in paragraphs (b) through (f) of this 
section, as applicable, for each stationary fuel combustion source 
(e.g., individual unit, aggregation of units, common pipe, or common 
stack) except as otherwise provided in this paragraph (a). For the data 
specified in paragraphs (b)(9)(iii), (c)(2)(ix), (e)(2)(i), 
(e)(2)(ii)(A), (e)(2)(ii)(C), (e)(2)(ii)(D), (e)(2)(iv)(A), 
(e)(2)(iv)(C), (e)(2)(iv)(F), and (e)(2)(ix)(D) through (F) of this 
section, the owner or operator of a stationary fuel combustion source 
that does not meet the criteria specified in paragraph (f) of this 
section may elect either to report the data specified in this

[[Page 630]]

sentence in the annual report or to use verification software according 
to Sec. 98.5(b) in lieu of reporting these data. If you elect to use 
this verification software, you must use the verification software 
according to Sec. 98.5(b) for all of these data that apply to the 
stationary fuel combustion source.
    (b) Units that use the four tiers. You shall report the following 
information for stationary combustion units that use the Tier 1, Tier 2, 
Tier 3, or Tier 4 methodology in Sec. 98.33(a) to calculate 
CO2 emissions, except as otherwise provided in paragraphs (c) 
and (d) of this section:
    (1) The unit ID number.
    (2) A code representing the type of unit.
    (3) Maximum rated heat input capacity of the unit, in mmBtu/hr.
    (4) Each type of fuel combusted in the unit during the report year.
    (5) The methodology (i.e., tier) used to calculate the 
CO2 emissions for each type of fuel combusted (i.e., Tier 1, 
2, 3, or 4).
    (6) The methodology start date, for each fuel type.
    (7) The methodology end date, for each fuel type.
    (8) For a unit that uses Tiers 1, 2, or 3:
    (i) The annual CO2 mass emissions (including biogenic 
CO2), and the annual CH4, and N2O mass 
emissions for each type of fuel combusted during the reporting year, 
expressed in metric tons of each gas and in metric tons of 
CO2e; and
    (ii) Metric tons of biogenic CO2 emissions (if 
applicable).
    (9) For a unit that uses Tier 4:
    (i) If the total annual CO2 mass emissions measured by 
the CEMS consists entirely of non-biogenic CO2 (i.e., 
CO2 from fossil fuel combustion plus, if applicable, 
CO2 from sorbent and/or process CO2), report the 
total annual CO2 mass emissions, expressed in metric tons. 
You are not required to report the combustion CO2 emissions 
by fuel type.
    (ii) Report the total annual CO2 mass emissions measured 
by the CEMS. If this total includes both biogenic and non-biogenic 
CO2, separately report the annual non-biogenic CO2 
mass emissions and the annual CO2 mass emissions from biomass 
combustion, each expressed in metric tons. You are not required to 
report the combustion CO2 emissions by fuel type.
    (iii) An estimate of the heat input from each type of fuel listed in 
Table C-2 of this subpart that was combusted in the unit during the 
report year.
    (iv) The annual CH4 and N2O emissions for each 
type of fuel listed in Table C-2 of this subpart that was combusted in 
the unit during the report year, expressed in metric tons of each gas 
and in metric tons of CO2e.
    (10) Annual CO2 emissions from sorbent (if calculated 
using Equation C-11 of this subpart), expressed in metric tons.
    (11) If applicable, the plant code (as defined in Sec. 98.6).
    (c) Reporting alternatives for units using the four Tiers. You may 
use any of the applicable reporting alternatives of this paragraph to 
simplify the unit-level reporting required under paragraph (b) of this 
section:
    (1) Aggregation of units. If a facility contains two or more units 
(e.g., boilers or combustion turbines), each of which has a maximum 
rated heat input capacity of 250 mmBtu/hr or less, you may report the 
combined GHG emissions for the group of units in lieu of reporting GHG 
emissions from the individual units, provided that the use of Tier 4 is 
not required or elected for any of the units and the units use the same 
tier for any common fuels combusted. If this option is selected, the 
following information shall be reported instead of the information in 
paragraph (b) of this section:
    (i) Group ID number, beginning with the prefix ``GP''.
    (ii)-(iii) [Reserved]
    (iv) The highest maximum rated heat input capacity of any unit in 
the group (mmBtu/hr).
    (v) Each type of fuel combusted in the group of units during the 
reporting year.
    (vi) Annual CO2 mass emissions and annual CH4, 
and N2O mass emissions, aggregated for each type of fuel 
combusted in the group of units during the report year, expressed in 
metric tons of each gas and in metric tons of CO2e. If any of 
the units burn both fossil fuels and biomass, report also the annual

[[Page 631]]

CO2 emissions from combustion of all fossil fuels combined 
and annual CO2 emissions from combustion of all biomass fuels 
combined, expressed in metric tons.
    (vii) The methodology (i.e., tier) used to calculate the 
CO2 mass emissions for each type of fuel combusted in the 
units (i.e., Tier 1, Tier 2, or Tier 3).
    (viii) The methodology start date, for each fuel type.
    (ix) The methodology end date, for each fuel type.
    (x) The calculated CO2 mass emissions (if any) from 
sorbent expressed in metric tons.
    (xi) If applicable, the plant code (as defined in Sec. 98.6).
    (2) Monitored common stack or duct configurations. When the flue 
gases from two or more stationary fuel combustion units at a facility 
are combined together in a common stack or duct before exiting to the 
atmosphere and if CEMS are used to continuously monitor CO2 
mass emissions at the common stack or duct according to the Tier 4 
Calculation Methodology, you may report the combined emissions from the 
units sharing the common stack or duct, in lieu of separately reporting 
the GHG emissions from the individual units. This monitoring and 
reporting alternative may also be used when process off-gases or a 
mixture of combustion products and process gases are combined together 
in a common stack or duct before exiting to the atmosphere. Whenever the 
common stack or duct monitoring option is applied, the following 
information shall be reported instead of the information in paragraph 
(b) of this section:
    (i) Common stack or duct identification number, beginning with the 
prefix ``CS''.
    (ii) Number of units sharing the common stack or duct. Report ``1'' 
when the flue gas flowing through the common stack or duct includes 
combustion products and/or process off-gases, and all of the effluent 
comes from a single unit (e.g., a furnace, kiln, petrochemical 
production unit, or smelter).
    (iii) Combined maximum rated heat input capacity of the units 
sharing the common stack or duct (mmBtu/hr). This data element is 
required only when all of the units sharing the common stack are 
stationary fuel combustion units.
    (iv) Each type of fuel combusted in the units during the year.
    (v) The methodology (tier) used to calculate the CO2 mass 
emissions, i.e., Tier 4.
    (vi) The methodology start date.
    (vii) The methodology end date.
    (viii) Total annual CO2 mass emissions measured by the 
CEMS, expressed in metric tons. If any of the units burn both fossil 
fuels and biomass, separately report the annual non-biogenic 
CO2 mass emissions (i.e., CO2 from fossil fuel 
combustion plus, if applicable, CO2 from sorbent and/or 
process CO2) and the annual CO2 mass emissions 
from biomass combustion, each expressed in metric tons.
    (ix) An estimate of the heat input from each type of fuel listed in 
Table C-2 of this subpart that was combusted in the units sharing the 
common stack or duct during the report year.
    (x) For each type of fuel listed in Table C-2 of this subpart that 
was combusted during the report year in the units sharing the common 
stack or duct during the report year, the annual CH4 and 
N2O mass emissions from the units sharing the common stack or 
duct, expressed in metric tons of each gas and in metric tons of 
CO2e.
    (xi) If applicable, the plant code (as defined in Sec. 98.6).
    (3) Common pipe configurations. When two or more stationary 
combustion units at a facility combust the same type of liquid or 
gaseous fuel and the fuel is fed to the individual units through a 
common supply line or pipe, you may report the combined emissions from 
the units served by the common supply line, in lieu of separately 
reporting the GHG emissions from the individual units, provided that the 
total amount of fuel combusted by the units is accurately measured at 
the common pipe or supply line using a fuel flow meter, or, for natural 
gas, the amount of fuel combusted may be obtained from gas billing 
records. For Tier 3 applications, the flow meter shall be calibrated in 
accordance with Sec. 98.34(b). If a portion of the fuel measured (or 
obtained from gas billing records) at the main supply line is diverted 
to either: A flare; or another

[[Page 632]]

stationary fuel combustion unit (or units), including units that use a 
CO2 mass emissions calculation method in part 75 of this 
chapter; or a chemical or industrial process (where it is used as a raw 
material but not combusted), and the remainder of the fuel is 
distributed to a group of combustion units for which you elect to use 
the common pipe reporting option, you may use company records to 
subtract out the diverted portion of the fuel from the fuel measured (or 
obtained from gas billing records) at the main supply line prior to 
performing the GHG emissions calculations for the group of units using 
the common pipe option. If the diverted portion of the fuel is 
combusted, the GHG emissions from the diverted portion shall be 
accounted for in accordance with the applicable provisions of this part. 
When the common pipe option is selected, the applicable tier shall be 
used based on the maximum rated heat input capacity of the largest unit 
served by the common pipe configuration, except where the applicable 
tier is based on criteria other than unit size. For example, if the 
maximum rated heat input capacity of the largest unit is greater than 
250 mmBtu/hr, Tier 3 will apply, unless the fuel transported through the 
common pipe is natural gas or distillate oil, in which case Tier 2 may 
be used, in accordance with Sec. 98.33(b)(2)(ii). As a second example, 
in accordance with Sec. 98.33(b)(1)(v), Tier 1 may be used regardless 
of unit size when natural gas is transported through the common pipe, if 
the annual fuel consumption is obtained from gas billing records in 
units of therms or mmBtu. When the common pipe reporting option is 
selected, the following information shall be reported instead of the 
information in paragraph (b) of this section:
    (i) Common pipe identification number, beginning with the prefix 
``CP''.
    (ii) [Reserved]
    (iii) The highest maximum rated heat input capacity of any unit 
served by the common pipe (mmBtu/hr).
    (iv) The fuels combusted in the units during the reporting year.
    (v) The methodology used to calculate the CO2 mass 
emissions (i.e., Tier 1, Tier 2, or Tier 3).
    (vi) If the any of the units burns both fossil fuels and biomass, 
the annual CO2 mass emissions from combustion of all fossil 
fuels and annual CO2 emissions from combustion of all biomass 
fuels from the units served by the common pipe, expressed in metric 
tons.
    (vii) Annual CO2 mass emissions and annual CH4 
and N2O emissions from each fuel type for the units served by 
the common pipe, expressed in metric tons of each gas and in metric tons 
of CO2e.
    (viii) Methodology start date.
    (ix) Methodology end date.
    (x) If applicable, the plant code (as defined in Sec. 98.6).
    (4) The following alternative reporting option applies to facilities 
at which a common liquid or gaseous fuel supply is shared between one or 
more large combustion units, such as boilers or combustion turbines 
(including units subject to subpart D of this part and other units 
subject to part 75 of this chapter) and small combustion sources, 
including, but not limited to, space heaters, hot water heaters, and lab 
burners. In this case, you may simplify reporting by attributing all of 
the GHG emissions from combustion of the shared fuel to the large 
combustion unit(s), provided that:
    (i) The total quantity of the fuel combusted during the report year 
in the units sharing the fuel supply is measured, either at the ``gate'' 
to the facility or at a point inside the facility, using a fuel flow 
meter, billing meter, or tank drop measurements (as applicable);
    (ii) On an annual basis, at least 95 percent (by mass or volume) of 
the shared fuel is combusted in the large combustion unit(s), and the 
remainder is combusted in the small combustion sources. Company records 
may be used to determine the percentage distribution of the shared fuel 
to the large and small units; and
    (iii) The use of this reporting option is documented in the 
Monitoring Plan required under Sec. 98.3(g)(5). Indicate in the 
Monitoring Plan which units share the common fuel supply and the method 
used to demonstrate that this alternative reporting option applies. For 
the small combustion sources, a description of the types of units and 
the

[[Page 633]]

approximate number of units is sufficient.
    (d) Units subject to part 75 of this chapter. (1) For stationary 
combustion units that are subject to subpart D of this part, you shall 
report the following unit-level information:
    (i) Unit or stack identification numbers. Use exact same unit, 
common stack, common pipe, or multiple stack identification numbers that 
represent the monitored locations (e.g., 1, 2, CS001, MS1A, CP001, etc.) 
that are reported under Sec. 75.64 of this chapter.
    (ii) Annual CO2 emissions at each monitored location, 
expressed in both short tons and metric tons. Separate reporting of 
biogenic CO2 emissions under Sec. 98.3(c)(4)(ii) and Sec. 
98.3(c)(4)(iii)(A) is optional only for the 2010 reporting year, as 
provided in Sec. 98.3(c)(12).
    (iii) Annual CH4 and N2O emissions at each 
monitored location, for each fuel type listed in Table C-2 that was 
combusted during the year (except as otherwise provided in Sec. 
98.33(c)(4)(ii)(B)), expressed in metric tons of CO2e.
    (iv) The total heat input from each fuel listed in Table C-2 that 
was combusted during the year (except as otherwise provided in Sec. 
98.33(c)(4)(ii)(B)), expressed in mmBtu.
    (v) Identification of the Part 75 methodology used to determine the 
CO2 mass emissions.
    (vi) Methodology start date.
    (vii) Methodology end date.
    (viii) Acid Rain Program indicator.
    (ix) Annual CO2 mass emissions from the combustion of 
biomass, expressed in metric tons of CO2e, except where the 
reporting provisions of Sec. Sec. 98.3(c)(12)(i) through (c)(12)(iii) 
are implemented for the 2010 reporting year.
    (x) If applicable, the plant code (as defined in Sec. 98.6).
    (2) For units that use the alternative CO2 mass emissions 
calculation methods provided in Sec. 98.33(a)(5), you shall report the 
following unit-level information:
    (i) Unit, stack, or pipe ID numbers. Use exact same unit, common 
stack, common pipe, or multiple stack identification numbers that 
represent the monitored locations (e.g., 1, 2, CS001, MS1A, CP001, etc.) 
that are reported under Sec. 75.64 of this chapter.
    (ii) For units that use the alternative methods specified in Sec. 
98.33(a)(5)(i) and (ii) to monitor and report heat input data year-round 
according to appendix D to part 75 of this chapter or Sec. 75.19 of 
this chapter:
    (A) Each type of fuel combusted in the unit during the reporting 
year.
    (B) The methodology used to calculate the CO2 mass 
emissions for each fuel type.
    (C) Methodology start date.
    (D) Methodology end date.
    (E) A code or flag to indicate whether heat input is calculated 
according to appendix D to part 75 of this chapter or Sec. 75.19 of 
this chapter.
    (F) Annual CO2 emissions at each monitored location, 
across all fuel types, expressed in metric tons of CO2e.
    (G) Annual heat input from each type of fuel listed in Table C-2 of 
this subpart that was combusted during the reporting year, expressed in 
mmBtu.
    (H) Annual CH4 and N2O emissions at each 
monitored location, from each fuel type listed in Table C-2 of this 
subpart that was combusted during the reporting year (except as 
otherwise provided in Sec. 98.33(c)(4)(ii)(D)), expressed in metric 
tons CO2e.
    (I) Annual CO2 mass emissions from the combustion of 
biomass, expressed in metric tons CO2e, except where the 
reporting provisions of Sec. Sec. 98.3(c)(12)(i) through (c)(12)(iii) 
are implemented for the 2010 reporting year.
    (J) If applicable, the plant code (as defined in Sec. 98.6).
    (iii) For units with continuous monitoring systems that use the 
alternative method for units with continuous monitoring systems in Sec. 
98.33(a)(5)(iii) to monitor heat input year-round according to part 75 
of this chapter:
    (A) Each type of fuel combusted during the reporting year.
    (B) Methodology used to calculate the CO2 mass emissions.
    (C) Methodology start date.
    (D) Methodology end date.
    (E) A code or flag to indicate that the heat input data is derived 
from CEMS measurements.
    (F) The total annual CO2 emissions at each monitored 
location, expressed in metric tons of CO2e.

[[Page 634]]

    (G) Annual heat input from each type of fuel listed in Table C-2 of 
this subpart that was combusted during the reporting year, expressed in 
mmBtu.
    (H) Annual CH4 and N2O emissions at each 
monitored location, from each fuel type listed in Table C-2 of this 
subpart that was combusted during the reporting year (except as 
otherwise provided in Sec. 98.33(c)(4)(ii)(B)), expressed in metric 
tons CO2e.
    (I) Annual CO2 mass emissions from the combustion of 
biomass, expressed in metric tons CO2e, except where the 
reporting provisions of Sec. Sec. 98.3(c)(12)(i) through (c)(12)(iii) 
are implemented for the 2010 reporting year.
    (J) If applicable, the plant code (as defined in Sec. 98.6).
    (e) Verification data. You must keep on file, in a format suitable 
for inspection and auditing, sufficient data to verify the reported GHG 
emissions. This data and information must, where indicated in this 
paragraph (e), be included in the annual GHG emissions report.
    (1) The applicable verification data specified in this paragraph (e) 
are not required to be kept on file or reported for units that meet any 
one of the three following conditions:
    (i) Are subject to the Acid Rain Program.
    (ii) Use the alternative methods for units with continuous 
monitoring systems provided in Sec. 98.33(a)(5).
    (iii) Are not in the Acid Rain Program, but are required to monitor 
and report CO2 mass emissions and heat input data year-round, 
in accordance with part 75 of this chapter.
    (2) For stationary combustion sources using the Tier 1, Tier 2, Tier 
3, and Tier 4 Calculation Methodologies in Sec. 98.33(a) to quantify 
CO2 emissions, the following additional information shall be 
kept on file and included in the GHG emissions report, where indicated:
    (i) For the Tier 1 Calculation Methodology, report the total 
quantity of each type of fuel combusted in the unit or group of 
aggregated units (as applicable) during the reporting year, in short 
tons for solid fuels, gallons for liquid fuels and standard cubic feet 
for gaseous fuels, or, if applicable, therms or mmBtu for natural gas.
    (ii) For the Tier 2 Calculation Methodology, report:
    (A) The total quantity of each type of fuel combusted in the unit or 
group of aggregated units (as applicable) during each month of the 
reporting year. Express the quantity of each fuel combusted during the 
measurement period in short tons for solid fuels, gallons for liquid 
fuels, and scf for gaseous fuels.
    (B) The frequency of the HHV determinations (e.g., once a month, 
once per fuel lot).
    (C) The high heat values used in the CO2 emissions 
calculations for each type of fuel combusted during the reporting year, 
in mmBtu per short ton for solid fuels, mmBtu per gallon for liquid 
fuels, and mmBtu per scf for gaseous fuels. Report a HHV value for each 
calendar month in which HHV determination is required. If multiple 
values are obtained in a given month, report the arithmetic average 
value for the month.
    (D) If Equation C-2c of this subpart is used to calculate 
CO2 mass emissions, report the total quantity (i.e., pounds) 
of steam produced from MSW or solid fuel combustion during each month of 
the reporting year, and the ratio of the maximum rate heat input 
capacity to the design rated steam output capacity of the unit, in mmBtu 
per lb of steam.
    (E) For each HHV used in the CO2 emissions calculations 
for each type of fuel combusted during the reporting year, indicate 
whether the HHV is a measured value or a substitute data value.
    (iii) For the Tier 2 Calculation Methodology, keep records of the 
methods used to determine the HHV for each type of fuel combusted and 
the date on which each fuel sample was taken, except where fuel sampling 
data are received from the fuel supplier. In that case, keep records of 
the dates on which the results of the fuel analyses for HHV are 
received.
    (iv) For the Tier 3 Calculation Methodology, report:
    (A) The quantity of each type of fuel combusted in the unit or group 
of units (as applicable) during each month of the reporting year, in 
short tons for solid fuels, gallons for liquid fuels, and scf for 
gaseous fuels.

[[Page 635]]

    (B) The frequency of carbon content and, if applicable, molecular 
weight determinations for each type of fuel for the reporting year 
(e.g., daily, weekly, monthly, semiannually, once per fuel lot).
    (C) The carbon content and, if applicable, gas molecular weight 
values used in the emission calculations (including both valid and 
substitute data values). For each calendar month of the reporting year 
in which carbon content and, if applicable, molecular weight 
determination is required, report a value of each parameter. If multiple 
values of a parameter are obtained in a given month, report the 
arithmetic average value for the month. Express carbon content as a 
decimal fraction for solid fuels, kg C per gallon for liquid fuels, and 
kg C per kg of fuel for gaseous fuels. Express the gas molecular weights 
in units of kg per kg-mole.
    (D) The total number of valid carbon content determinations and, if 
applicable, molecular weight determinations made during the reporting 
year, for each fuel type.
    (E) The number of substitute data values used for carbon content 
and, if applicable, molecular weight used in the annual GHG emissions 
calculations.
    (F) The annual average HHV, when measured HHV data, rather than a 
default HHV from Table C-1 of this subpart, are used to calculate 
CH4 and N2O emissions for a Tier 3 unit, in 
accordance with Sec. 98.33(c)(1).
    (G) The value of the molar volume constant (MVC) used in Equation C-
5 (if applicable).
    (v) For the Tier 3 Calculation Methodology, keep records of the 
following:
    (A) For liquid and gaseous fuel combustion, the dates and results of 
the initial calibrations and periodic recalibrations of the required 
fuel flow meters.
    (B) For fuel oil combustion, the method from Sec. 98.34(b) used to 
make tank drop measurements (if applicable).
    (C) The methods used to determine the carbon content and (if 
applicable) the molecular weight of each type of fuel combusted.
    (D) The methods used to calibrate the fuel flow meters).
    (E) The date on which each fuel sample was taken, except where fuel 
sampling data are received from the fuel supplier. In that case, keep 
records of the dates on which the results of the fuel analyses for 
carbon content and (if applicable) molecular weight are received.
    (vi) For the Tier 4 Calculation Methodology, report:
    (A) The total number of source operating hours in the reporting 
year.
    (B) The cumulative CO2 mass emissions in each quarter of 
the reporting year, i.e., the sum of the hourly values calculated from 
Equation C-6 or C-7 of this subpart (as applicable), in metric tons.
    (C) For CO2 concentration, stack gas flow rate, and (if 
applicable) stack gas moisture content, the percentage of source 
operating hours in which a substitute data value of each parameter was 
used in the emissions calculations.
    (vii) For the Tier 4 Calculation Methodology, keep records of:
    (A) Whether the CEMS certification and quality assurance procedures 
of part 75 of this chapter, part 60 of this chapter, or an applicable 
State continuous monitoring program were used.
    (B) The dates and results of the initial certification tests of the 
CEMS.
    (C) The dates and results of the major quality assurance tests 
performed on the CEMS during the reporting year, i.e., linearity checks, 
cylinder gas audits, and relative accuracy test audits (RATAs).
    (viii) If CO2 emissions that are generated from acid gas 
scrubbing with sorbent injection are not captured using CEMS, report:
    (A) The total amount of sorbent used during the report year, in 
short tons.
    (B) The molecular weight of the sorbent.
    (C) The ratio (``R'') in Equation C-11 of this subpart.
    (ix) For units that combust both fossil fuel and biomass, when 
biogenic CO2 is determined according to Sec. 98.33(e)(2), 
you shall report the following additional information, as applicable:
    (A) The annual volume of CO2 emitted from the combustion 
of all fuels,i.e., Vtotal, in scf.

[[Page 636]]

    (B) The annual volume of CO2 emitted from the combustion 
of fossil fuels, i.e., Vff, in scf. If more than one type of 
fossil fuel was combusted, report the combustion volume of 
CO2 for each fuel separately as well as the total.
    (C) The annual volume of CO2 emitted from the combustion 
of biomass,i.e., Vbio, in scf.
    (D) The carbon-based F-factor used in Equation C-13 of this subpart, 
for each type of fossil fuel combusted, in scf CO2 per mmBtu.
    (E) The annual average HHV value used in Equation C-13 of this 
subpart, for each type of fossil fuel combusted, in Btu/lb, Btu/gal, or 
Btu/scf, as appropriate.
    (F) The total quantity of each type of fossil fuel combusted during 
the reporting year, in lb, gallons, or scf, as appropriate.
    (G) Annual biogenic CO2 mass emissions, in metric tons.
    (x) When ASTM methods D7459-08 (incorporated by reference, see Sec. 
98.7) and D6866-08 (incorporated by reference, see Sec. 98.7) are used 
to determine the biogenic portion of the annual CO2 emissions 
from MSW combustion, as described in Sec. 98.34(d), report:
    (A) The results of each quarterly sample analysis, expressed as a 
decimal fraction (e.g., if the biogenic fraction of the CO2 
emissions from MSW combustion is 30 percent, report 0.30).
    (B) The annual biogenic CO2 mass emissions from MSW 
combustion, in metric tons.
    (xi) When ASTM methods D7459-08 (incorporated by reference, see 
Sec. 98.7) and D6866-08 (incorporated by reference, see Sec. 98.7) are 
used in accordance with Sec. 98.34(e) to determine the biogenic portion 
of the annual CO2 emissions from a unit that co-fires 
biogenic fuels (or partly-biogenic fuels, including tires if you are 
electing to report biogenic CO2 emissions from tire 
combustion) and non-biogenic fuels, you shall report the results of each 
quarterly sample analysis, expressed as a decimal fraction (e.g., if the 
biogenic fraction of the CO2 emissions is 30 percent, report 
0.30).
    (3) Within 30 days of receipt of a written request from the 
Administrator, you shall submit explanations of the following:
    (i) An explanation of how company records are used to quantify fuel 
consumption, if the Tier 1 or Tier 2 Calculation Methodology is used to 
calculate CO2 emissions.
    (ii) An explanation of how company records are used to quantify fuel 
consumption, if solid fuel is combusted and the Tier 3 Calculation 
Methodology is used to calculate CO2 emissions.
    (iii) An explanation of how sorbent usage is quantified.
    (iv) An explanation of how company records are used to quantify 
fossil fuel consumption in units that uses CEMS to quantify 
CO2 emissions and combusts both fossil fuel and biomass.
    (v) An explanation of how company records are used to measure steam 
production, when it is used to calculate CO2 mass emissions 
under Sec. 98.33(a)(2)(iii) or to quantify solid fuel usage under Sec. 
98.33(c)(3).
    (4) Within 30 days of receipt of a written request from the 
Administrator, you shall submit the verification data and information 
described in paragraphs (e)(2)(iii), (e)(2)(v), and (e)(2)(vii) of this 
section.
    (f) Each stationary fuel combustion source (e.g., individual unit, 
aggregation of units, common pipe, or common stack) subject to reporting 
under paragraph (b) or (c) of this section must indicate if both of the 
following two conditions are met:
    (1) The stationary fuel combustion source contains at least one 
combustion unit connected to a fuel-fired electric generator owned or 
operated by an entity that is subject to regulation of customer billing 
rates by the public utility commission (excluding generators that are 
connected to combustion units that are subject to subpart D of this 
part).
    (2) The stationary fuel combustion source is located at a facility 
for which the sum of the nameplate capacities for all electric 
generators specified in paragraph (f)(1) of this section is greater than 
or equal to 1 megawatt electric output.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79151, Dec. 17, 2010; 
78 FR 71950, Nov. 29, 2013; 79 FR 63782, Oct. 24, 2014]

[[Page 637]]



Sec. 98.37  Records that must be retained.

    In addition to the requirements of Sec. 98.3(g), you must retain:
    (a) The applicable records specified in Sec. Sec. 98.34(f) and (g), 
98.35(b), and 98.36(e).
    (b) Verification software records. For each stationary fuel 
combustion source that elects to use the verification software specified 
in Sec. 98.5(b) rather than report data specified in paragraphs 
(b)(9)(iii), (c)(2)(ix), (e)(2)(i), (e)(2)(ii)(A), (e)(2)(ii)(C), 
(e)(2)(ii)(D), (e)(2)(iv)(A), (e)(2)(iv)(C), (e)(2)(iv)(F), and 
(e)(2)(ix)(D) through (F) of this section, you must keep a record of the 
file generated by the verification software for the applicable data 
specified in paragraphs (b)(1) through (36) of this section. Retention 
of this file satisfies the recordkeeping requirement for the data in 
paragraphs (b)(1) through (36) of this section.
    (1) Mass of each solid fuel combusted (tons/year) (Equation C-1 of 
Sec. 98.33).
    (2) Volume of each liquid fuel combusted (gallons/year) (Equation C-
1).
    (3) Volume of each gaseous fuel combusted (scf/year) (Equation C-1).
    (4) Annual natural gas usage (therms/year) (Equation C-1a of Sec. 
98.33).
    (5) Annual natural gas usage (mmBtu/year) (Equation C-1b of Sec. 
98.33).
    (6) Mass of each solid fuel combusted (tons/year) (Equation C-2a of 
Sec. 98.33).
    (7) Volume of each liquid fuel combusted (gallons/year) (Equation C-
2a).
    (8) Volume of each gaseous fuel combusted (scf/year) (Equation C-
2a).
    (9) Measured high heat value of each solid fuel, for month (which 
may be the arithmetic average of multiple determinations), or, if 
applicable, an appropriate substitute data value (mmBtu per ton) 
(Equation C-2b of Sec. 98.33).
    (10) Measured high heat value of each liquid fuel, for month (which 
may be the arithmetic average of multiple determinations), or, if 
applicable, an appropriate substitute data value (mmBtu per gallons) 
(Equation C-2b).
    (11) Measured high heat value of each gaseous fuel, for month (which 
may be the arithmetic average of multiple determinations), or, if 
applicable, an appropriate substitute data value (mmBtu per scf) 
(Equation C-2b).
    (12) Mass of each solid fuel combusted during month (tons) (Equation 
C-2b).
    (13) Volume of each liquid fuel combusted during month (gallons) 
(Equation C-2b).
    (14) Volume of each gaseous fuel combusted during month (scf) 
(Equation C-2b).
    (15) Total mass of steam generated by municipal solid waste or each 
solid fuel combustion during the reporting year (pounds steam) (Equation 
C-2c of Sec. 98.33).
    (16) Ratio of the boiler's maximum rated heat input capacity to its 
design rated steam output capacity (MMBtu/pounds steam) (Equation C-2c).
    (17) Annual mass of each solid fuel combusted (short tons/year) 
(Equation C-3 of Sec. 98.33).
    (18) Annual average carbon content of each solid fuel (percent by 
weight, expressed as a decimal fraction) (Equation C-3).
    (19) Annual volume of each liquid fuel combusted (gallons/year) 
(Equation C-4 of Sec. 98.33).
    (20) Annual average carbon content of each liquid fuel (kg C per 
gallon of fuel) (Equation C-4).
    (21) Annual volume of each gaseous fuel combusted (scf/year) 
(Equation C-5 of Sec. 98.33).
    (22) Annual average carbon content of each gaseous fuel (kg C per kg 
of fuel) (Equation C-5).
    (23) Annual average molecular weight of each gaseous fuel (kg/kg-
mole) (Equation C-5).
    (24) Molar volume conversion factor at standard conditions, as 
defined in Sec. 98.6 (scf per kg-mole) (Equation C-5).
    (25) Identify for each fuel if you will use the default high heat 
value from Table C-1 of this subpart, or actual high heat value data 
(Equation C-8 of Sec. 98.33).
    (26) High heat value of each solid fuel (mmBtu/tons) (Equation C-8).
    (27) High heat value of each liquid fuel (mmBtu/gallon) (Equation C-
8).
    (28) High heat value of each gaseous fuel (mmBtu/scf) (Equation C-
8).
    (29) Cumulative annual heat input from combustion of each fuel 
(mmBtu) (Equation C-10 of Sec. 98.33).
    (30) Total quantity of each solid fossil fuel combusted in the 
reporting year, as defined in Sec. 98.6 (pounds) (Equation C-13 of 
Sec. 98.33).

[[Page 638]]

    (31) Total quantity of each liquid fossil fuel combusted in the 
reporting year, as defined in Sec. 98.6 (gallons) (Equation C-13).
    (32) Total quantity of each gaseous fossil fuel combusted in the 
reporting year, as defined in Sec. 98.6 (scf) (Equation C-13).
    (33) High heat value of the each solid fossil fuel (Btu/lb) 
(Equation C-13).
    (34) High heat value of the each liquid fossil fuel (Btu/gallons) 
(Equation C-13).
    (35) High heat value of the each gaseous fossil fuel (Btu/scf) 
(Equation C-13).
    (36) Fuel-specific carbon based F-factor per fuel (scf 
CO2/mmBtu) (Equation C-13).

[79 FR 63783, Oct. 24, 2014]



Sec. 98.38  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.



Sec. Table C-1 to Subpart C of Part 98--Default CO2 Emission 
         Factors and High Heat Values for Various Types of Fuel

 Default CO2 Emission Factors and High Heat Values for Various Types of
                                  Fuel
------------------------------------------------------------------------
                                  Default high heat       Default CO2
           Fuel type                    value           emission factor
------------------------------------------------------------------------
         Coal and coke             mmBtu/short ton        kg CO2/mmBtu
------------------------------------------------------------------------
Anthracite....................  25.09                             103.69
Bituminous....................  24.93                              93.28
Subbituminous.................  17.25                              97.17
Lignite.......................  14.21                              97.72
Coal Coke.....................  24.80                             113.67
Mixed (Commercial sector).....  21.39                              94.27
Mixed (Industrial coking).....  26.28                              93.90
Mixed (Industrial sector).....  22.35                              94.67
Mixed (Electric Power sector).  19.73                              95.52
------------------------------------------------------------------------
          Natural gas                 mmBtu/scf           kg CO2/mmBtu
------------------------------------------------------------------------
(Weighted U.S. Average)             1.026 x 10-\3\           53.06
------------------------------------------------------------------------
      Petroleum products             mmBtu/gallon         kg CO2/mmBtu
------------------------------------------------------------------------
Distillate Fuel Oil No. 1.....  0.139                              73.25
Distillate Fuel Oil No. 2.....  0.138                              73.96
Distillate Fuel Oil No. 4.....  0.146                              75.04
Residual Fuel Oil No. 5.......  0.140                              72.93
Residual Fuel Oil No. 6.......  0.150                              75.10
Used Oil......................  0.138                              74.00
Kerosene......................  0.135                              75.20
Liquefied petroleum gases       0.092                              61.71
 (LPG) \1\.
Propane \1\...................  0.091                              62.87
Propylene \2\.................  0.091                              67.77
Ethane \1\....................  0.068                              59.60
Ethanol.......................  0.084                              68.44
Ethylene \2\..................  0.058                              65.96
Isobutane \1\.................  0.099                              64.94
Isobutylene \1\...............  0.103                              68.86
Butane \1\....................  0.103                              64.77
Butylene \1\..................  0.105                              68.72
Naphtha (<401 deg F)..........  0.125                              68.02
Natural Gasoline..............  0.110                              66.88
Other Oil (401 deg   0.139                              76.22
 F).
Pentanes Plus.................  0.110                              70.02
Petrochemical Feedstocks......  0.125                              71.02
Petroleum Coke................  0.143                             102.41
Special Naphtha...............  0.125                              72.34
Unfinished Oils...............  0.139                              74.54
Heavy Gas Oils................  0.148                              74.92
Lubricants....................  0.144                              74.27
Motor Gasoline................  0.125                              70.22
Aviation Gasoline.............  0.120                              69.25
Kerosene-Type Jet Fuel........  0.135                              72.22

[[Page 639]]

 
Asphalt and Road Oil..........  0.158                              75.36
Crude Oil.....................  0.138                              74.54
------------------------------------------------------------------------
      Other fuels--solid           mmBtu/short ton        kg CO2/mmBtu
------------------------------------------------------------------------
Municipal Solid Waste.........  9.95 \3\                            90.7
Tires.........................  28.00                              85.97
Plastics......................  38.00                              75.00
Petroleum Coke................  30.00                             102.41
------------------------------------------------------------------------
     Other fuels--gaseous             mmBtu/scf           kg CO2/mmBtu
------------------------------------------------------------------------
Blast Furnace Gas.............  0.092 x 10-\3\                    274.32
Coke Oven Gas.................  0.599 x 10-\3\                     46.85
Propane Gas...................  2.516 x 10-\3\                     61.46
Fuel Gas \4\..................  1.388 x 10-\3\                     59.00
------------------------------------------------------------------------
     Biomass fuels--solid          mmBtu/short ton        kg CO2/mmBtu
------------------------------------------------------------------------
Wood and Wood Residuals (dry    17.48                              93.80
 basis) \5\.
------------------------------------------------------------------------
Agricultural Byproducts.......  8.25                              118.17
Peat..........................  8.00                              111.84
Solid Byproducts..............  10.39                             105.51
------------------------------------------------------------------------
    Biomass fuels--gaseous            mmBtu/scf           kg CO2/mmBtu
------------------------------------------------------------------------
Landfill Gas..................  0.485 x 10-\3\                     52.07
Other Biomass Gases...........  0.655 x 10-\3\                     52.07
------------------------------------------------------------------------
     Biomass Fuels--Liquid           mmBtu/gallon         kg CO2/mmBtu
------------------------------------------------------------------------
Ethanol.......................  0.084                              68.44
Biodiesel (100%)..............  0.128                              73.84
Rendered Animal Fat...........  0.125                              71.06
Vegetable Oil.................  0.120                              81.55
------------------------------------------------------------------------
\1\ The HHV for components of LPG determined at 60  deg.F and saturation
  pressure with the exception of ethylene.
\2\ Ethylene HHV determined at 41  deg.F (5  deg.C) and saturation
  pressure.
\3\ Use of this default HHV is allowed only for: (a) Units that combust
  MSW, do not generate steam, and are allowed to use Tier 1; (b) units
  that derive no more than 10 percent of their annual heat input from
  MSW and/or tires; and (c) small batch incinerators that combust no
  more than 1,000 tons of MSW per year.
\4\ Reporters subject to subpart X of this part that are complying with
  Sec. 98.243(d) or subpart Y of this part may only use the default
  HHV and the default CO2 emission factor for fuel gas combustion under
  the conditions prescribed in Sec. 98.243(d)(2)(i) and (d)(2)(ii) and
  Sec. 98.252(a)(1) and (a)(2), respectively. Otherwise, reporters
  subject to subpart X or subpart Y shall use either Tier 3 (Equation C-
  5) or Tier 4.
\5\ Use the following formula to calculate a wet basis HHV for use in
  Equation C-1: HHVw = ((100 - M)/100)*HHVd where HHVw = wet basis HHV,
  M = moisture content (percent) and HHVd = dry basis HHV from Table C-
  1.


[78 FR 71950, Nov. 29, 2013]



   Sec. Table C-2 to Subpart C of Part 98--Default CH4 and 
        N2O Emission Factors for Various Types of Fuel

------------------------------------------------------------------------
                              Default CH4 emission  Default N2O emission
          Fuel type              factor (kg CH4/       factor (kg N2O/
                                     mmBtu)                mmBtu)
------------------------------------------------------------------------
Coal and Coke (All fuel       1.1 x 10-\02\         1.6 x 10-\03\
 types in Table C-1).
Natural Gas.................  1.0 x 10-\03\         1.0 x 10-\04\
Petroleum (All fuel types in  3.0 x 10-\03\         6.0 x 10-\04\
 Table C-1).
Fuel Gas....................  3.0 x 10-\03\         6.0 x 10-\04\
Municipal Solid Waste.......  3.2 x 10-\02\         4.2 x 10-\03\
Tires.......................  3.2 x 10-\02\         4.2 x 10-\03\
Blast Furnace Gas...........  2.2 x 10-\05\         1.0 x 10-\04\
Coke Oven Gas...............  4.8 x 10-\04\         1.0 x 10-\04\
Biomass Fuels--Solid (All     3.2 x 10-\02\         4.2 x 10-\03\
 fuel types in Table C-1,
 except wood and wood
 residuals).
Wood and wood residuals.....  7.2 x 10-\03\         3.6 x 10-\03\
Biomass Fuels--Gaseous (All   3.2 x 10-\03\         6.3 x 10-\04\
 fuel types in Table C-1).

[[Page 640]]

 
Biomass Fuels--Liquid (All    1.1 x 10-\03\         1.1 x 10-\04\
 fuel types in Table C-1).
------------------------------------------------------------------------
Note: Those employing this table are assumed to fall under the IPCC
  definitions of the ``Energy Industry'' or ``Manufacturing Industries
  and Construction''. In all fuels except for coal the values for these
  two categories are identical. For coal combustion, those who fall
  within the IPCC ``Energy Industry'' category may employ a value of 1g
  of CH4/mmBtu.


[78 FR 71952, Nov. 29, 2013]



                    Subpart D_Electricity Generation



Sec. 98.40  Definition of the source category.

    (a) The electricity generation source category comprises electricity 
generating units that are subject to the requirements of the Acid Rain 
Program and any other electricity generating units that are required to 
monitor and report to EPA CO2 mass emissions year-round 
according to 40 CFR part 75.
    (b) This source category does not include portable equipment, 
emergency equipment, or emergency generators, as defined in Sec. 98.6.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79155, Dec. 17, 2010]



Sec. 98.41  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains one or more electricity generating units and the facility meets 
the requirements of Sec. 98.2(a)(1).



Sec. 98.42  GHGs to report.

    (a) For each electricity generating unit that is subject to the 
requirements of the Acid Rain Program or is otherwise required to 
monitor and report to EPA CO2 emissions year-round according 
to 40 CFR part 75, you must report under this subpart the annual mass 
emissions of CO2, N2O, and CH4 by 
following the requirements of this subpart.
    (b) For each electricity generating unit that is not subject to the 
Acid Rain Program or otherwise required to monitor and report to EPA 
CO2 emissions year-round according to 40 CFR part 75, you 
must report under subpart C of this part (General Stationary Fuel 
Combustion Sources) the emissions of CO2, CH4, and 
N2O by following the requirements of subpart C.
    (c) For each stationary fuel combustion unit that does not generate 
electricity, you must report under subpart C of this part (General 
Stationary Fuel Combustion Sources) the emissions of CO2, 
CH4, and N2O by following the requirements of 
subpart C of this part.



Sec. 98.43  Calculating GHG emissions.

    (a) Except as provided in paragraph (b) of this section, continue to 
monitor and report CO2 mass emissions as required under Sec. 
75.13 or section 2.3 of appendix G to 40 CFR part 75, and Sec. 75.64. 
Calculate CO2, CH4, and N2O emissions 
as follows:
    (1) Convert the cumulative annual CO2 mass emissions 
reported in the fourth quarter electronic data report required under 
Sec. 75.64 from units of short tons to metric tons. To convert tons to 
metric tons, divide by 1.1023.
    (2) Calculate and report annual CH4 and N2O 
mass emissions under this subpart by following the applicable method 
specified in Sec. 98.33(c).
    (b) Calculate and report biogenic CO2 emissions under 
this subpart by following the applicable methods specified in Sec. 
98.33(e). The CO2 emissions (excluding biogenic 
CO2) for units subject to this subpart that are reported 
under Sec. Sec. 98.3(c)(4)(i) and (c)(4)(iii)(B) shall be calculated by 
subtracting the biogenic CO2 mass emissions calculated 
according to Sec. 98.33(e) from the cumulative annual CO2 
mass emissions from paragraph (a)(1) of this section. Separate 
calculation and reporting of biogenic CO2 emissions is 
optional only for the 2010 reporting year pursuant to Sec. 98.3(c)(12) 
and required every year thereafter.

[75 FR 79155, Dec. 17, 2010]

[[Page 641]]



Sec. 98.44  Monitoring and QA/QC requirements.

    Follow the applicable quality assurance procedures for 
CO2 emissions in appendices B, D, and G to 40 CFR part 75.



Sec. 98.45  Procedures for estimating missing data.

    Follow the applicable missing data substitution procedures in 40 CFR 
part 75 for CO2 concentration, stack gas flow rate, fuel flow 
rate, high heating value, and fuel carbon content.



Sec. 98.46  Data reporting requirements.

    The annual report shall comply with the data reporting requirements 
specified in Sec. 98.36(d)(1).

[75 FR 79155, Dec. 17, 2010]



Sec. 98.47  Records that must be retained.

    You shall comply with the recordkeeping requirements of Sec. Sec. 
98.3(g) and 98.37. Records retained under Sec. 75.57(h) of this chapter 
for missing data events satisfy the recordkeeping requirements of Sec. 
98.3(g)(4) for those same events.

[75 FR 79155, Dec. 17, 2010]



Sec. 98.48  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.



                    Subpart E_Adipic Acid Production



Sec. 98.50  Definition of source category.

    The adipic acid production source category consists of all adipic 
acid production facilities that use oxidation to produce adipic acid.



Sec. 98.51  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains an adipic acid production process and the facility meets the 
requirements of either Sec. 98.2(a)(1) or (2).



Sec. 98.52  GHGs to report.

    (a) You must report N2O process emissions at the facility 
level.
    (b) You must report under subpart C of this part (General Stationary 
Fuel Combustion Sources) the emissions of CO2, 
CH4, and N2O from each stationary combustion unit 
following the requirements of subpart C.



Sec. 98.53  Calculating GHG emissions.

    (a) You must determine annual N2O emissions from adipic 
acid production according to paragraphs (a)(1) or (2) of this section.
    (1) Use a site-specific emission factor and production data 
according to paragraphs (b) through (i) of this section.
    (2) Request Administrator approval for an alternative method of 
determining N2O emissions according to paragraphs (a)(2)(i) 
and (ii) of this section.
    (i) You must submit the request within 45 days following 
promulgation of this subpart or within the first 30 days of each 
subsequent reporting year.
    (ii) If the Administrator does not approve your requested 
alternative method within 150 days of the end of the reporting year, you 
must determine the N2O emissions for the current reporting 
period using the procedures specified in paragraphs (b) through (h) of 
this section.
    (b) You must conduct an annual performance test according to 
paragraphs (b)(1) through (3) of this section.
    (1) You must conduct the test on the vent stream from the nitric 
acid oxidation step of the process, referred to as the test point, 
according to the methods specified in Sec. 98.54(b) through (f). If 
multiple adipic acid production units exhaust to a common abatement 
technology and/or emission point, you must sample each process in the 
ducts before the emissions are combined, sample each process when only 
one process is operating, or sample the combined emissions when multiple 
processes are operating and base the site-specific emission factor on 
the combined production rate of the multiple adipic acid production 
units.
    (2) You must conduct the performance test under normal process 
operating conditions.
    (3) You must measure the adipic acid production rate during the test 
and calculate the production rate for the test period in tons per hour.
    (c) Using the results of the performance test in paragraph (b) of 
this section, you must calculate an emission

[[Page 642]]

factor for each adipic acid unit according to Equation E-1 of this 
section:
[GRAPHIC] [TIFF OMITTED] TR28OC10.018

where:

EFN2O,z = Average facility-specific N2O 
          emission factor for each adipic acid production unit ``z'' (lb 
          N2O/ton adipic acid produced).
CN2O = N2O concentration per test run 
          during the performance test (ppm N2O).
1.14 x 10-7 = Conversion factor (lb/dscf-ppm N2O).
Q = Volumetric flow rate of effluent gas per test run during the 
          performance test (dscf/hr).
P = Production rate per test run during the performance test (tons 
          adipic acid produced/hr).
n = Number of test runs.

    (d) If the adipic acid production unit exhausts to any 
N2O abatement technology ``N'', you must determine the 
destruction efficiency according to paragraphs (d)(1), (d)(2), or (d)(3) 
of this section.
    (1) Use the manufacturer's specified destruction efficiency.
    (2) Estimate the destruction efficiency through process knowledge. 
Examples of information that could constitute process knowledge include 
calculations based on material balances, process stoichiometry, or 
previous test results provided the results are still relevant to the 
current vent stream conditions. You must document how process knowledge 
was used to determine the destruction efficiency.
    (3) Calculate the destruction efficiency by conducting an additional 
performance test on the vent stream following the N2O 
abatement technology.
    (e) If the adipic acid production unit exhausts to any 
N2O abatement technology ``N'', you must determine the annual 
amount of adipic acid produced while N2O abatement technology 
``N'' is operating according to Sec. 98.54(f). Then you must calculate 
the abatement factor for N2O abatement technology ``N'' 
according to Equation E-2 of this section.
[GRAPHIC] [TIFF OMITTED] TR29NO13.012

    (f) You must determine the annual amount of adipic acid produced 
according to Sec. 98.54(f).
    (g) You must calculate N2O emissions according to 
paragraph (g)(1), (2), (3), or (4) of this section for each adipic acid 
production unit.
    (1) If one N2O abatement technology ``N'' is located 
after your test point, you must use the emissions factor (determined in 
Equation E-1 of this section), the destruction efficiency (determined in 
paragraph (d) of this section), the annual adipic acid production 
(determined in paragraph (f) of this section), and the abatement 
utilization factor (determined in paragraph (e) of this section), 
according to Equation E-3a of this section:

[[Page 643]]

[GRAPHIC] [TIFF OMITTED] TR28OC10.020

where:

Ea,z = Annual N2O mass emissions from adipic acid 
          production unit ``z'' according to this Equation E-3a (metric 
          tons).
EFN2Oz = N2O emissions factor for unit 
          ``z'' (lb N2O/ton adipic acid produced).
Pz = Annual adipic acid produced from unit ``z'' (tons).
DF = Destruction efficiency of N2O abatement technology ``N'' 
          (decimal fraction of N2O removed from vent stream).
AF = Abatement utilization factor of N2O abatement technology 
          ``N'' (decimal fraction of time that the abatement technology 
          is operating).
2205 = Conversion factor (lb/metric ton).

    (2) If multiple N2O abatement technologies are located in 
series after your test point, you must use the emissions factor 
(determined in Equation E-1 of this section), the destruction efficiency 
(determined in paragraph (d) of this section), the annual adipic acid 
production (determined in paragraph (f) of this section), and the 
abatement utilization factor (determined in paragraph (e) of this 
section), according to Equation E-3b of this section:
[GRAPHIC] [TIFF OMITTED] TR28OC10.021

where:

Eb,z = Annual N2O mass emissions from adipic acid 
          production unit ``z'' according to this Equation E-3b (metric 
          tons).
EFN2O,z = N2O emissions factor for unit 
          ``z'' (lb N2O/ton adipic acid produced).
Pz = Annual adipic acid produced from unit ``z'' (tons).
DF1 = Destruction efficiency of N2O abatement 
          technology 1 (decimal fraction of N2O removed from 
          vent stream).
AF1 = Abatement utilization factor of N2O 
          abatement technology 1 (decimal fraction of time that 
          abatement technology 1 is operating).
DF2 = Destruction efficiency of N2O abatement 
          technology 2 (decimal fraction of N2O removed from 
          vent stream).
AF2 = Abatement utilization factor of N2O 
          abatement technology 2 (decimal fraction of time that 
          abatement technology 2 is operating).
DFN = Destruction efficiency of N2O abatement 
          technology ``N'' (decimal fraction of N2O removed 
          from vent stream).
AFN = Abatement utilization factor of N2O 
          abatement technology ``N'' (decimal fraction of time that 
          abatement technology N is operating).
2205 = Conversion factor (lb/metric ton).
N = Number of different N2O abatement technologies.

    (3) If multiple N2O abatement technologies are located in 
parallel after your test point, you must use the emissions factor 
(determined in Equation E-1 of this section), the destruction efficiency 
(determined in paragraph (d) of this section), the annual adipic acid 
production (determined in paragraph (f) of this section), and the 
abatement utilization factor (determined in paragraph (e) of this 
section), according to Equation E-3c of this section:
[GRAPHIC] [TIFF OMITTED] TR28OC10.022

where:

Ec,z = Annual N2O mass emissions from adipic acid 
          production unit ``z'' according to this Equation E-3c (metric 
          tons).

[[Page 644]]

EFN2O,z = N2O emissions factor for unit 
          ``z'' (lb N2O/ton adipic acid produced).
Pz = Annual adipic acid produced from unit ``z'' (tons).
DFN = Destruction efficiency of N2O abatement 
          technology ``N'' (decimal fraction of N2O removed 
          from vent stream).
AFN = Abatement utilization factor of N2O 
          abatement technology ``N'' (decimal fraction of time that the 
          abatement technology is operating).
FCN = Fraction control factor of N2O abatement 
          technology ``N'' (decimal fraction of total emissions from 
          unit ``z'' that are sent to abatement technology ``N'').
2205 = Conversion factor (lb/metric ton).
N = Number of different N2O abatement technologies with a 
          fraction control factor.

    (4) If no N2O abatement technologies are located after 
your test point, you must use the emissions factor (determined using 
Equation E-1 of this section) and the annual adipic acid production 
(determined in paragraph (f) of this section) according to Equation E-3d 
of this section for each adipic acid production unit.
[GRAPHIC] [TIFF OMITTED] TR28OC10.023

where:

Ed,z = Annual N2O mass emissions from adipic acid 
          production for unit ``z'' according to this Equation E-3d 
          (metric tons).
EFN2O = N2O emissions factor for unit 
          ``z'' (lb N2O/ton adipic acid produced).
PZ = Annual adipic acid produced from unit ``z'' (tons).
2205 = Conversion factor (lb/metric ton).

    (h) You must determine the emissions for the facility by summing the 
unit level emissions according to Equation E-4 of this section.
[GRAPHIC] [TIFF OMITTED] TR28OC10.024

where:

Ea,z = Annual N2O mass emissions from adipic acid 
          production unit ``z'' according to Equation E-3a of this 
          section (metric tons).
Eb,z = Annual N2O mass emissions from adipic acid 
          production unit ``z'' according to Equation E-3b of this 
          section (metric tons).
Ec,z = Annual N2O mass emissions from adipic acid 
          production unit ``z'' according to Equation E-3c of this 
          section (metric tons).
Ed,z = Annual N2O mass emissions from adipic acid 
          production unit ``z'' according to Equation E-3d of this 
          section (metric tons).
M = Total number of adipic acid production units.

    (i) You must determine the amount of process N2O 
emissions that is sold or transferred off site (if applicable). You can 
determine the amount using existing process flow meters and 
N2O analyzers.

[75 FR 66458, Oct. 28, 2010, as amended at 78 FR 71952, Nov. 29, 2013]



Sec. 98.54  Monitoring and QA/QC requirements.

    (a) You must conduct a new performance test and calculate a new 
emissions factor for each adipic acid production unit according to the 
frequency specified in paragraphs (a)(1) through (3) of this section.
    (1) Conduct the performance test annually. The test must be 
conducted at a point during production that is representative of the 
average emissions rate from your process. You must document the methods 
used to determine the representative point.
    (2) Conduct the performance test when your adipic acid production 
process is changed either by altering the ratio of cyclohexanone to 
cyclohexanol or by installing abatement equipment.
    (3) If you requested Administrator approval for an alternative 
method of determining N2O emissions under Sec. 98.53(a)(2), 
you must conduct the performance test if your request has not been 
approved by the Administrator within 150 days of the end of the 
reporting year in which it was submitted.

[[Page 645]]

    (b) You must measure the N2O concentration during the 
performance test using one of the methods in paragraphs (b)(1) through 
(b)(3) of this section.
    (1) EPA Method 320, Measurement of Vapor Phase Organic and Inorganic 
Emissions by Extractive Fourier Transform Infrared (FTIR) Spectroscopy 
in 40 CFR part 63, Appendix A;
    (2) ASTM D6348-03 Standard Test Method for Determination of Gaseous 
Compounds by Extractive Direct Interface Fourier Transform Infrared 
(FTIR) Spectroscopy (incorporated by reference, see Sec. 98.7); or
    (3) An equivalent method, with Administrator approval.
    (c) You must determine the adipic acid production rate during the 
performance test according to paragraph (c)(1) or (c)(2) of this 
section.
    (1) Direct measurement (such as using flow meters or weigh scales).
    (2) Existing plant procedures used for accounting purposes.
    (d) You must determine the volumetric flow rate during the 
performance test in conjunction with the applicable EPA methods in 40 
CFR part 60, appendices A-1 through A-4. Conduct three emissions test 
runs of 1 hour each. All QA/QC procedures specified in the reference 
test methods and any associated performance specifications apply. For 
each test, the facility must prepare an emissions factor determination 
report that must include the items in paragraphs (d)(1) through (d)(3) 
of this section:
    (1) Analysis of samples, determination of emissions, and raw data.
    (2) All information and data used to derive the emissions factor.
    (3) The production rate(s) during the performance test and how each 
production rate was determined.
    (e) You must determine the monthly amount of adipic acid produced. 
You must also determine the monthly amount of adipic acid produced 
during which N2O abatement technology is operating. These 
monthly amounts are determined according to the methods in paragraphs 
(c)(1) or (c)(2) of this section.
    (f) You must determine the annual amount of adipic acid produced. 
You must also determine the annual amount of adipic acid produced during 
which N2O abatement technology is operating. These are 
determined by summing the respective monthly adipic acid production 
quantities determined in paragraph (e) of this section.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66460, Oct. 28, 2010; 
78 FR 71953, Nov. 29, 2013]



Sec. 98.55  Procedures for estimating missing data.

    A complete record of all measured parameters used in the GHG 
emissions calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable, a substitute data 
value for the missing parameter shall be used in the calculations as 
specified in paragraphs (a) and (b) of this section.
    (a) For each missing value of monthly adipic acid production, the 
substitute data shall be the best available estimate based on all 
available process data or data used for accounting purposes (such as 
sales records).
    (b) For missing values related to the performance test, including 
emission factors, production rate, and N2O concentration, you 
must conduct a new performance test according to the procedures in Sec. 
98.54 (a) through (d).



Sec. 98.56  Data reporting requirements.

    In addition to the information required by Sec. 98.3(c), each 
annual report must contain the information specified in paragraphs (a) 
through (n) of this section at the facility level.
    (a) Annual process N2O emissions from adipic acid 
production (metric tons).
    (b)-(c) [Reserved]
    (d) Annual process N2O emissions from adipic acid 
production facility that is sold or transferred off site (metric tons).
    (e) Number of abatement technologies (if applicable).
    (f) Types of abatement technologies used (if applicable).
    (g) Abatement technology destruction efficiency for each abatement 
technology (percent destruction).
    (h) Abatement utilization factor for each abatement technology 
(fraction of annual production that abatement technology is operating).

[[Page 646]]

    (i) Number of times in the reporting year that missing data 
procedures were followed to measure adipic acid production (months).
    (j) If you conducted a performance test and calculated a site-
specific emissions factor according to Sec. 98.53(a)(1), each annual 
report must also contain the information specified in paragraphs (j)(1) 
through (7) of this section for each adipic acid production unit.
    (1) [Reserved]
    (2) Test method used for performance test.
    (3) [Reserved]
    (4) N2O concentration per test run during performance 
test (ppm N2O).
    (5) Volumetric flow rate per test run during performance test (dscf/
hr).
    (6) Number of test runs.
    (7) Number of times in the reporting year that a performance test 
had to be repeated (number).
    (k) If you requested Administrator approval for an alternative 
method of determining N2O emissions under Sec. 98.53(a)(2), 
each annual report must also contain the information specified in 
paragraphs (k)(1) through (4) of this section for each adipic acid 
production facility.
    (1) Name of alternative method.
    (2) Description of alternative method.
    (3) Request date.
    (4) Approval date.
    (l) Fraction control factor for each abatement technology (percent 
of total emissions from the production unit that are sent to the 
abatement technology) if equation E-3c is used.
    (m) If only cyclohexane is oxidized to produce adipic acid and the 
quantity is known, report the information specified in paragraph (m)(1) 
of this section. If materials other than cyclohexane are oxidized to 
produce adipic acid, report the information specified in paragraph 
(m)(2) of this section.
    (1) Annual quantity of cyclohexane (tons) used to produce adipic 
acid.
    (2) Annual quantity of cyclohexanone and cyclohexanol mixture (tons) 
used to produce adipic acid.
    (n) Annual percent N2O emission reduction for all 
production units combined.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66460, Oct. 28, 2010; 
79 FR 63784, Oct. 24, 2014]



Sec. 98.57  Records that must be retained.

    In addition to the information required by Sec. 98.3(g), you must 
retain the records specified in paragraphs (a) through (i) of this 
section at the facility level:
    (a) Annual adipic acid production capacity (tons).
    (b) Records of significant changes to process.
    (c) Number of facility and unit operating hours in calendar year.
    (d) Documentation of how accounting procedures were used to estimate 
production rate.
    (e) Documentation of how process knowledge was used to estimate 
abatement technology destruction efficiency.
    (f) Performance test reports.
    (g) Measurements, records and calculations used to determine 
reported parameters.
    (h) Documentation of the procedures used to ensure the accuracy of 
the measurements of all reported parameters, including but not limited 
to, calibration of weighing equipment, flow meters, and other 
measurement devices. The estimated accuracy of measurements made with 
these devices must also be recorded, and the technical basis for these 
estimates must be provided.
    (i) Verification software records. You must keep a record of the 
file generated by the verification software specified in Sec. 98.5(b) 
for the applicable data specified in paragraphs (i)(1) through (3) of 
this section. Retention of this file satisfies the recordkeeping 
requirement for the data in paragraphs (i)(1) through (3) of this 
section.
    (1) Annual adipic acid production from each adipic acid production 
unit (tons) (Equations E-2, E-3a, E-3b, E-3c, and E-3d of Sec. 98.53).
    (2) Production rate per test run during the performance test for 
each production unit test run (tons adipic acid produced/hr) (Equation 
E-1 of Sec. 98.53).
    (3) Annual adipic acid production per N2O abatement 
technology during which N2O abatement technology was used 
(tons adipic acid produced) (Equation E-2).

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66461, Oct. 28, 2010; 
79 FR 63784, Oct. 24, 2014]

[[Page 647]]



Sec. 98.58  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.



                      Subpart F_Aluminum Production



Sec. 98.60  Definition of the source category.

    (a) A primary aluminum production facility manufactures primary 
aluminum using the Hall-H[eacute]roult manufacturing process. The 
primary aluminum manufacturing process comprises the following 
operations:
    (1) Electrolysis in prebake and S[oslash]derberg cells.
    (2) Anode baking for prebake cells.
    (b) This source category does not include experimental cells or 
research and development process units.



Sec. 98.61  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains an aluminum production process and the facility meets the 
requirements of either Sec. 98.2(a)(1) or (a)(2).



Sec. 98.62  GHGs to report.

    You must report:
    (a) Perfluoromethane (CF4), and perfluoroethane 
(C2F6) emissions from anode effects in all prebake 
and S[oslash]derberg electrolysis cells.
    (b) CO2 emissions from anode consumption during 
electrolysis in all prebake and S[oslash]derberg electrolysis cells.
    (c) CO2 emissions from on-site anode baking.
    (d) You must report under subpart C of this part (General Stationary 
Fuel Combustion Sources) the emissions of CO2, 
N2O, and CH4 emissions from each stationary fuel 
combustion unit by following the requirements of subpart C.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79155, Dec. 17, 2010]



Sec. 98.63  Calculating GHG emissions.

    (a) The annual value of each PFC compound (CF4, 
C2F6) shall be estimated from the sum of monthly 
values using Equation F-1 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.025

Where:

EPFC = Annual emissions of each PFC compound from aluminum 
          production (metric tons PFC).
Em = Emissions of the individual PFC compound from aluminum 
          production for the month ``m'' (metric tons PFC).

    (b) Use Equation F-2 of this section to estimate CF4 
emissions from anode effect duration or Equation F-3 of this section to 
estimate CF4 emissions from overvoltage, and use Equation F-4 
of this section to estimate C2F6 emissions from 
anode effects from each prebake and S[oslash]derberg electrolysis cell.
[GRAPHIC] [TIFF OMITTED] TR30OC09.026

Where:

ECF4 = Monthly CF4 emissions from aluminum 
          production (metric tons CF4).
SCF4 = The slope coefficient ((kg CF4/metric ton 
          Al)/(AE-Mins/cell-day)).
AEM = The anode effect minutes per cell-day (AE-Mins/cell-day).
MP = Metal production (metric tons Al), where AEM and MP are calculated 
          monthly.
          [GRAPHIC] [TIFF OMITTED] TR30OC09.027
          
Where:

ECF4 = Monthly CF4 emissions from aluminum 
          production (metric tons CF4).
EFCF4 = The overvoltage emission factor (kg CF4/
          metric ton Al).
MP = Metal production (metric tons Al), where MP is calculated monthly.

[[Page 648]]

[GRAPHIC] [TIFF OMITTED] TR30OC09.028

Where:

EC2F6 = Monthly C2F6 emissions from 
          aluminum production (metric tons C2F6).
ECF4 = CF4 emissions from aluminum production (kg 
          CF4).
FC2F6/CF4 = The weight fraction of 
          C2F6/CF4 (kg 
          C2F6/kg CF4).
0.001 = Conversion factor from kg to metric tons, where ECF4 
          is calculated monthly.

    (c) You must calculate and report the annual process CO2 
emissions from anode consumption during electrolysis and anode baking of 
prebake cells using either the procedures in paragraph (d) of this 
section, the procedures in paragraphs (e) and (f) of this section, or 
the procedures in paragraph (g) of this section.
    (d) Calculate and report under this subpart the process 
CO2 emissions by operating and maintaining CEMS according to 
the Tier 4 Calculation Methodology in Sec. 98.33(a)(4) and all 
associated requirements for Tier 4 in subpart C of this part (General 
Stationary Fuel Combustion Sources).
    (e) Use the following procedures to calculate CO2 
emissions from anode consumption during electrolysis:
    (1) For Prebake cells: you must calculate CO2 emissions 
from anode consumption using Equation F-5 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.029

Where:

ECO2 = Annual CO2 emissions from prebaked anode 
          consumption (metric tons CO2).
NAC = Net annual prebaked anode consumption per metric ton Al (metric 
          tons C/metric tons Al).
MP = Annual metal production (metric tons Al).
Sa = Sulfur content in baked anode (percent weight).
Asha = Ash content in baked anode (percent weight).
44/12 = Ratio of molecular weights, CO2 to carbon.

    (2) For S[oslash]derberg cells you must calculate CO2 
emissions using Equation F-6 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.030

Where:

ECO2 = Annual CO2 emissions from paste consumption 
          (metric ton CO2).
PC = Annual paste consumption (metric ton/metric ton Al).
MP = Annual metal production (metric ton Al).
CSM = Annual emissions of cyclohexane soluble matter (kg/metric ton Al).
BC = Binder content of paste (percent weight).
Sp = Sulfur content of pitch (percent weight).
Ashp = Ash content of pitch (percent weight).
Hp = Hydrogen content of pitch (percent weight).
Sc = Sulfur content in calcined coke (percent weight).
Ashc = Ash content in calcined coke (percent weight).
CD = Carbon in skimmed dust from S[oslash]derberg cells (metric ton C/
          metric ton Al).
44/12 = Ratio of molecular weights, CO2 to carbon.


[[Page 649]]


    (f) Use the following procedures to calculate CO2 
emissions from anode baking of prebake cells:
    (1) Use Equation F-7 of this section to calculate emissions from 
pitch volatiles combustion.
[GRAPHIC] [TIFF OMITTED] TR30OC09.031

Where:

ECO2PV = Annual CO2 emissions from pitch volatiles 
          combustion (metric tons CO2).
GA = Initial weight of green anodes (metric tons).
Hw = Annual hydrogen content in green anodes (metric tons).
BA = Annual baked anode production (metric tons).
WT = Annual waste tar collected (metric tons).
44/12 = Ratio of molecular weights, CO2 to carbon.

    (2) Use Equation F-8 of this section to calculate emissions from 
bake furnace packing material.
[GRAPHIC] [TIFF OMITTED] TR30OC09.032

Where:

ECO2PC = Annual CO2 emissions from bake furnace 
          packing material (metric tons CO2).
PCC = Annual packing coke consumption (metric tons/metric ton baked 
          anode).
BA = Annual baked anode production (metric tons).
Spc = Sulfur content in packing coke (percent weight).
Ashpc = Ash content in packing coke (percent weight).
44/12 = Ratio of molecular weights, CO2 to carbon.

    (g) If process CO2 emissions from anode consumption 
during electrolysis or anode baking of prebake cells are vented through 
the same stack as any combustion unit or process equipment that reports 
CO2 emissions using a CEMS that complies with the Tier 4 
Calculation Methodology in subpart C of this part (General Stationary 
Fuel Combustion Sources), then the calculation methodology in paragraphs 
(d) and (e) of this section shall not be used to calculate those process 
emissions. The owner or operation shall report under this subpart the 
combined stack emissions according to the Tier 4 Calculation Methodology 
in Sec. 98.33(a)(4) and all associated requirements for Tier 4 in 
subpart C of this part (General Stationary Fuel Combustion Sources).

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79155, Dec. 17, 2010]



Sec. 98.64  Monitoring and QA/QC requirements.

    (a) Effective December 31, 2010 for smelters with no prior 
measurement or effective December 31, 2012, for facilities with historic 
measurements, the smelter-specific slope coefficients, overvoltage 
emission factors, and weight fractions used in Equations F-2, F-3, and 
F-4 of this subpart must be measured in accordance with the 
recommendations of the EPA/IAI Protocol for Measurement of 
Tetrafluoromethane (CF4) and Hexafluoroethane 
(C2F6) Emissions from Primary Aluminum Production 
(2008) (incorporated by reference, see Sec. 98.7), except the minimum 
frequency of measurement shall be every 10 years unless a change occurs 
in the control algorithm that affects the mix of types of anode effects 
or the nature of the anode effect termination routine.Facilities which 
operate at less than 0.2 anode effect minutes per cell day or operate 
with less than 1.4mV anode effect overvoltage can use either smelter-
specific slope coefficients or

[[Page 650]]

the technology specific default values in Table F-1 of this subpart.
    (b) The minimum frequency of the measurement and analysis is 
annually except as follows:
    (1) Monthly for anode effect minutes per cell day (or anode effect 
overvoltage and current efficiency).
    (2) Monthly for aluminum production.
    (3) Smelter-specific slope coefficients, overvoltage emission 
factors, and weight fractions according to paragraph (a) of this 
section.
    (c) Sources may use either smelter-specific values from annual 
measurements of parameters needed to complete the equations in Sec. 
98.63 (e.g., sulfur, ash, and hydrogen contents) or the default values 
shown in Table F-2 of this subpart.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79155, Dec. 17, 2010]



Sec. 98.65  Procedures for estimating missing data.

    A complete record of all measured parameters used in the GHG 
emissions calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable (e.g., if a meter 
malfunctions during unit operation or if a required sample measurement 
is not taken), a substitute data value for the missing parameter shall 
be used in the calculations, according to the following requirements:
    (a) Where anode or paste consumption data are missing, 
CO2 emissions can be estimated from aluminum production per 
Equation F-8 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.033

Where:

ECO2 = CO2 emissions from anode and/or paste 
          consumption, metric tons CO2.
EFp = Prebake technology specific emission factor (1.6 metric 
          tons CO2/metric ton aluminum produced).
MPp = Metal production from prebake process (metric tons Al).
EFs = S[oslash]derberg technology specific emission factor 
          (1.7 metric tons CO2/metric ton Al produced).
MPs = Metal production from S[oslash]derberg process (metric 
          tons Al).

    (b) For other parameters, use the average of the two most recent 
data points after the missing data.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79156, Dec. 17, 2010]



Sec. 98.66  Data reporting requirements.

    In addition to the information required by Sec. 98.3(c), you must 
report the following information at the facility level:
    (a) [Reserved]
    (b) Type of smelter technology used.
    (c) The following PFC-specific information on an annual basis:
    (1) Perfluoromethane emissions and perfluoroethane emissions from 
anode effects in all prebake and all S[oslash]derberg electrolysis cells 
combined.
    (2) [Reserved]
    (3) The last date when the smelter-specific-slope coefficients (or 
overvoltage emission factors) were measured.
    (d) Method used to measure the frequency and duration of anode 
effects (or overvoltage).
    (e) The following CO2-specific information for prebake 
cells:
    (1) Annual anode consumption if using the method in Sec. 98.63(g).
    (2) Annual CO2 emissions from the smelter.
    (f) The following CO2-specific information for 
S[oslash]derberg cells:
    (1) Annual paste consumption if using the method in Sec. 98.63(g).
    (2) Annual CO2 emissions from the smelter.
    (g) [Reserved]
    (h) Exact data elements required will vary depending on smelter 
technology (e.g., point-feed prebake or S[oslash]derberg)

[[Page 651]]

and process control technology (e.g., Pechiney or other).

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79156, Dec. 17, 2010; 
79 FR 63784, Oct. 24, 2014]



Sec. 98.67  Records that must be retained.

    In addition to the information required by Sec. 98.3(g), you must 
retain the following records:
    (a) Monthly aluminum production in metric tons.
    (b) Type of smelter technology used.
    (c) The following PFC-specific information on a monthly basis:
    (1) Perfluoromethane and perfluoroethane emissions from anode 
effects in prebake and S[oslash]derberg electolysis cells.
    (2) Anode effect minutes per cell-day (AE-mins/cell-day), anode 
effect frequency (AE/cell-day), anode effect duration (minutes). (Or 
anode effect overvoltage factor ((kg CF4/metric ton Al)/(mV/
cell day)), potline overvoltage (mV/cell day), current efficiency (%).))
    (3) Smelter-specific slope coefficients and the last date when the 
smelter-specific-slope coefficients were measured.
    (d) Method used to measure the frequency and duration of anode 
effects (or to measure anode effect overvoltage and current efficiency).
    (e) The following CO2-specific information for prebake 
cells:
    (1) Annual anode consumption.
    (2) Annual CO2 emissions from the smelter.
    (f) The following CO2-specific information for 
S[oslash]derberg cells:
    (1) Annual paste consumption.
    (2) Annual CO2 emissions from the smelter.
    (g) Smelter-specific inputs to the CO2 process equations 
(e.g., levels of sulfur and ash) that were used in the calculation, on 
an annual basis.
    (h) Exact data elements required will vary depending on smelter 
technology (e.g., point-feed prebake or S[oslash]derberg) and process 
control technology (e.g., Pechiney or other).
    (i) Verification software records. You must keep a record of the 
file generated by the verification software specified in Sec. 98.5(b) 
for the applicable data specified in paragraphs (i)(1) through (30) of 
this section. Retention of this file satisfies the recordkeeping 
requirement for the data in paragraphs (i)(1) through (30) of this 
section.
    (1) Slope coefficient per potline per month (kg CF4/
metric ton Al)/(AE-Mins/cell-day)) (Equation F-2 of Sec. 98.63).
    (2) Anode effect minutes per cell-day per potline per month (AE-
Mins/cell-day) (Equation F-2).
    (3) Anode effect frequency per potline per month (AE/cell-day) 
(Equation F-2).
    (4) Anode effect duration per potline per month (minutes) (Equation 
F-2).
    (5) Metal production of aluminum per potline per month (metric tons) 
(Equation F-2).
    (6) Overvoltage emission factor per potline per month (kg CF4/metric 
ton Al) (Equation F-3 of Sec. 98.63).
    (7) Metal production of aluminum per potline per month (metric tons) 
(Equation F-3).
    (8) Weight fraction of C2F6/CF4 per potline 
per month (kg C2F6/kg CF4) (Equation F-
4 of Sec. 98.63).
    (9) Net annual prebaked anode consumption (metric tons C/metric tons 
Al) (Equation F-5 of Sec. 98.63).
    (10) Annual metal production of aluminum (metric tons) (Equation F-
5).
    (11) Sulfur content in baked anode (weight percent) (Equation F-5).
    (12) Ash content in baked anode (weight percent) (Equation F-5).
    (13) Annual paste consumption (metric ton/metric ton Al) (Equation 
F-6 of Sec. 98.63).
    (14) Annual metal production of aluminum (metric tons) (Equation F-
6).
    (15) Annual emissions of cyclohexane soluble matter (kg/metric ton 
Al) (Equation F-6).
    (16) Binder content of paste (weight percent) (Equation F-6).
    (17) Sulfur content of pitch (weight percent) (Equation F-6).
    (18) Ash content of pitch (weight percent) (Equation F-6).
    (19) Hydrogen content of pitch (weight percent) (Equation F-6).
    (20) Sulfur content in calcined coke (weight percent) (Equation F-
6).
    (21) Ash content in calcined coke (weight percent) (Equation F-6).
    (22) Carbon in skimmed dust from S[oslash]derberg cells (metric ton 
C/metric ton Al) (Equation F-6).
    (23) Initial weight of green anodes (metric tons) (Equation F-7 of 
Sec. 98.63).

[[Page 652]]

    (24) Annual hydrogen content in green anodes (metric tons) (Equation 
F-7).
    (25) Annual baked anode production (metric tons) (Equation F-7).
    (26) Annual waste tar collected (metric tons) (Equation F-7).
    (27) Annual packing coke consumption (metric tons/metric ton baked 
anode) (Equation F-8 of Sec. 98.63).
    (28) Annual baked anode production (metric tons) (Equation F-8).
    (29) Sulfur content in packing coke (weight percent) (Equation F-8).
    (30) Ash content in packing coke (weight percent) (Equation F-8).

[74 FR 56374, Oct. 30, 2009, as amended at 79 FR 63784, Oct. 24, 2014]



Sec. 98.68  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.



     Sec. Table F-1 to Subpart F of Part 98--Slope and Overvoltage 
    Coefficients for the Calculation of PFC Emissions From Aluminum 
                               Production

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                      CF4 slope coefficient    CF4 overvoltage coefficient
                             Technology                              [(kg CF4/metric ton Al)/   [(kg CF4/metric ton Al)/      Weight fraction C2F6/CF4
                                                                       (AE-Mins/cell-day)]                (mV)]                  [(kg C2F6/kg CF4)]
--------------------------------------------------------------------------------------------------------------------------------------------------------
Center Worked Prebake (CWPB).......................................                    0.143                          1.16                         0.121
Side Worked Prebake (SWPB).........................................                    0.272                          3.65                         0.252
Vertical Stud S[oslash]derberg (VSS)...............................                    0.092                            NA                         0.053
Horizontal Stud S[oslash]derberg (HSS).............................                    0.099                            NA                         0.085
--------------------------------------------------------------------------------------------------------------------------------------------------------


[75 FR 79156, Dec. 17, 2010]



    Sec. Table F-2 to Subpart F of Part 98--Default Data Sources for 
              Parameters Used for CO2 Emissions

------------------------------------------------------------------------
            Parameter                           Data source
------------------------------------------------------------------------
            CO2 Emissions from Prebake Cells (CWPB and SWPB)
------------------------------------------------------------------------
MP: metal production (metric tons  Individual facility records.
 Al).
NAC: net annual prebaked anode     Individual facility records.
 consumption per metric ton Al
 (metric tons C/metric tons Al).
Sa: sulfur content in baked anode  2.0.
 (percent weight).
Asha: ash content in baked anode   0.4.
 (percent weight).
------------------------------------------------------------------------
      CO2 Emissions From Pitch Volatiles Combustion (CWPB and SWPB)
------------------------------------------------------------------------
MP: metal production (metric tons  Individual facility records.
 Al).
PC: annual paste consumption       Individual facility records.
 (metric ton/metric ton Al).
CSM: annual emissions of           HSS: 4.0.
 cyclohexane soluble matter (kg/   VSS: 0.5.
 metric ton Al).
BC: binder content of paste        Dry Paste: 24.
 (percent weight).                 Wet Paste: 27.
Sp: sulfur content of pitch        0.6.
 (percent weight).
Ashp: ash content of pitch         0.2.
 (percent weight).
Hp: hydrogen content of pitch      3.3.
 (percent weight).
Sc: sulfur content in calcined     1.9.
 coke (percent weight).
Ashc: ash content in calcined      0.2.
 coke (percent weight).
CD: carbon in skimmed dust from    0.01.
 S[oslash]derberg cells (metric
 ton C/metric ton Al).
------------------------------------------------------------------------
       CO2 Emissions from Pitch Volatiles Combustion (VSS and HSS)
------------------------------------------------------------------------
GA: initial weight of green        Individual facility records.
 anodes (metric tons).
Hw: annual hydrogen content in     0.005 x GA.
 green anodes (metric tons).
BA: annual baked anode production  Individual facility records.
 (metric tons).
WT: annual waste tar collected     (a) 0.005 x GA.
 (metric tons).
(a) Riedhammer furnaces..........  (b) insignificant.
(b) all other furnaces...........
------------------------------------------------------------------------
 

[[Page 653]]

 
    CO2 Emissions From Bake Furnace Packing Materials (CWPB and SWPB)
------------------------------------------------------------------------
PCC: annual packing coke           0.015.
 consumption (metric tons/metric
 ton baked anode).
BA: annual baked anode production  Individual facility records.
 (metric tons).
Spc: sulfur content in packing     2.
 coke (percent weight).
Ashpc: ash content in packing      2.5.
 coke (percent weight).
------------------------------------------------------------------------


[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79156, Dec. 17, 2010]



                     Subpart G_Ammonia Manufacturing



Sec. 98.70  Definition of source category.

    The ammonia manufacturing source category comprises the process 
units listed in paragraphs (a) and (b) of this section.
    (a) Ammonia manufacturing processes in which ammonia is manufactured 
from a fossil-based feedstock produced via steam reforming of a 
hydrocarbon.
    (b) Ammonia manufacturing processes in which ammonia is manufactured 
through the gasification of solid and liquid raw material.



Sec. 98.71  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains an ammonia manufacturing process and the facility meets the 
requirements of either Sec. 98.2(a)(1) or (2).



Sec. 98.72  GHGs to report.

    You must report:
    (a) CO2 process emissions from steam reforming of a 
hydrocarbon or the gasification of solid and liquid raw material, 
reported for each ammonia manufacturing process unit following the 
requirements of this subpart (CO2 process emissions reported 
under this subpart may include CO2 that is later consumed on 
site for urea production, and therefore is not released to the ambient 
air from the ammonia manufacturing process unit).
    (b) CO2, CH4, and N2O emissions 
from each stationary fuel combustion unit. You must report these 
emissions under subpart C of this part (General Stationary Fuel 
Combustion Sources), by following the requirements of subpart C, except 
that for ammonia manufacturing processes subpart C does not apply to any 
CO2 resulting from combustion of the waste recycle stream 
(commonly referred to as the purge gas stream).
    (c) CO2 emissions collected and transferred off site 
under subpart PP of this part (Suppliers of CO2), following 
the requirements of subpart PP.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79156, Dec. 17, 2010]



Sec. 98.73  Calculating GHG emissions.

    You must calculate and report the annual process CO2 
emissions from each ammonia manufacturing process unit using the 
procedures in either paragraph (a) or (b) of this section.
    (a) Calculate and report under this subpart the process 
CO2 emissions by operating and maintaining CEMS according to 
the Tier 4 Calculation Methodology specified in Sec. 98.33(a)(4) and 
all associated requirements for Tier 4 in subpart C of this part 
(General Stationary Fuel Combustion Sources).
    (b) Calculate and report under this subpart process CO2 
emissions using the procedures in paragraphs (b)(1) through (b)(5) of 
this section for gaseous feedstock, liquid feedstock, or solid 
feedstock, as applicable.
    (1) Gaseous feedstock. You must calculate, from each ammonia 
manufacturing unit, the CO2 process emissions from gaseous 
feedstock according to Equation G-1 of this section:

[[Page 654]]

[GRAPHIC] [TIFF OMITTED] TR30OC09.034

Where:

CO2,G,k = Annual CO2 emissions arising from 
          gaseous feedstock consumption (metric tons).
Fdstkn = Volume of the gaseous feedstock used in month n (scf 
          of feedstock).
CCn = Carbon content of the gaseous feedstock, for month n 
          (kg C per kg of feedstock), determined according to 98.74(c).
MW = Molecular weight of the gaseous feedstock (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf per kg-mole at standard 
          conditions).
44/12 = Ratio of molecular weights, CO2 to carbon.
0.001 = Conversion factor from kg to metric tons.
k = Processing unit.
n = Number of month.

    (2) Liquid feedstock. You must calculate, from each ammonia 
manufacturing unit, the CO2 process emissions from liquid 
feedstock according to Equation G-2 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.035

Where:

CO2,L,k = Annual CO2 emissions arising from liquid 
          feedstock consumption (metric tons).
Fdstkn = Volume of the liquid feedstock used in month n 
          (gallons of feedstock).
CCn = Carbon content of the liquid feedstock, for month n (kg 
          C per gallon of feedstock) determined according to 98.74(c).
44/12 = Ratio of molecular weights, CO2 to carbon.
0.001 = Conversion factor from kg to metric tons.
k = Processing unit.
n = Number of month.

    (3) Solid feedstock. You must calculate, from each ammonia 
manufacturing unit, the CO2 process emissions from solid 
feedstock according to Equation G-3 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.036

Where:

CO2,S,k = Annual CO2 emissions arising from solid 
          feedstock consumption (metric tons).
Fdstkn = Mass of the solid feedstock used in month n (kg of 
          feedstock).
CCn = Carbon content of the solid feedstock, for month n (kg 
          C per kg of feedstock), determined according to 98.74(c).
44/12 = Ratio of molecular weights, CO2 to carbon.
0.001 = Conversion factor from kg to metric tons.
k = Processing unit.
n = Number of month.

    (4) You must calculate the annual process CO2 emissions 
from each ammonia processing unit k at your facility according to 
Equation G-4 of this section:

[[Page 655]]

[GRAPHIC] [TIFF OMITTED] TR29NO13.027

Where:

ECO2k = Annual CO2 emissions from each ammonia 
          processing unit k (metric tons).
k = Processing unit.

    (5) You must determine the combined CO2 emissions from 
all ammonia processing units at your facility using Equation G-5 of this 
section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.038

Where:

CO2 = Annual combined CO2 emissions from all 
          ammonia processing units (metric tons) (CO2 process 
          emissions reported under this subpart may include 
          CO2 that is later consumed on site for urea 
          production, and therefore is not released to the ambient air 
          from the ammonia manufacturing process unit(s)).
ECO2k = Annual CO2 emissions from each ammonia 
          processing unit (metric tons).
k = Processing unit.
n = Total number of ammonia processing units.

    (c) If GHG emissions from an ammonia manufacturing unit are vented 
through the same stack as any combustion unit or process equipment that 
reports CO2 emissions using a CEMS that complies with the 
Tier 4 Calculation Methodology in subpart C of this part (General 
Stationary Fuel Combustion Sources), then the calculation methodology in 
paragraph (b) of this section shall not be used to calculate process 
emissions. The owner or operator shall report under this subpart the 
combined stack emissions according to the Tier 4 Calculation Methodology 
in Sec. 98.33(a)(4) and all associated requirements for Tier 4 in 
subpart C of this part.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79156, Dec. 17, 2010]



Sec. 98.74  Monitoring and QA/QC requirements.

    (a) You must continuously measure the quantity of gaseous or liquid 
feedstock consumed using a flow meter. The quantity of solid feedstock 
consumed can be obtained from company records and aggregated on a 
monthly basis.
    (b) You must document the procedures used to ensure the accuracy of 
the estimates of feedstock consumption.
    (c) You must determine monthly carbon contents and the average 
molecular weight of each feedstock consumed from reports from your 
supplier. As an alternative to using supplier information on carbon 
contents, you can also collect a sample of each feedstock on a monthly 
basis and analyze the carbon content and molecular weight of the fuel 
using any of the following methods listed in paragraphs (c)(1) through 
(c)(8) of this section, as applicable.
    (1) ASTM D1945-03 Standard Test Method for Analysis of Natural Gas 
by Gas Chromatography (incorporated by reference, see Sec. 98.7).
    (2) ASTM D1946-90 (Reapproved 2006) Standard Practice for Analysis 
of Reformed Gas by Gas Chromatography (incorporated by reference, see 
Sec. 98.7).
    (3) ASTM D2502-04 (Reapproved 2002) Standard Test Method for 
Estimation of Mean Relative Molecular Mass of Petroleum Oils from 
Viscosity Measurements (incorporated by reference, see Sec. 98.7).
    (4) ASTM D2503-92 (Reapproved 2007) Standard Test Method for 
Relative Molecular Mass (Molecular Weight) of Hydrocarbons by 
Thermoelectric Measurement of Vapor Pressure (incorporated by reference, 
see Sec. 98.7).
    (5) ASTM D3238-95 (Reapproved 2005) Standard Test Method for 
Calculation of Carbon Distribution and Structural Group Analysis of 
Petroleum Oils by the n-d-M Method (incorporated by reference, see Sec. 
98.7).
    (6) ASTM D5291-02 (Reapproved 2007) Standard Test Methods for 
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in 
Petroleum Products and Lubricants (incorporated by reference, see Sec. 
98.7).
    (7) ASTM D3176-89 (Reapproved 2002) Standard Practice for Ultimate 
Analysis of Coal and Coke (incorporated by reference, see Sec. 98.7).

[[Page 656]]

    (8) ASTM D5373-08 Standard Methods for Instrumental Determination of 
Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal 
(incorporated by reference, see Sec. 98.7).
    (d) Calibrate all oil and gas flow meters that are used to measure 
liquid and gaseous feedstock volumes and flow rates (except for gas 
billing meters) according to the monitoring and QA/QC requirements for 
the Tier 3 methodology in Sec. 98.34(b)(1). Perform oil tank drop 
measurements (if used to quantify feedstock volumes) according to Sec. 
98.34(b)(2).
    (e) For quality assurance and quality control of the supplier data, 
on an annual basis, you must measure the carbon contents of a 
representative sample of the feedstocks consumed using the appropriate 
ASTM Method as listed in paragraphs (c)(1) through (c)(8) of this 
section.
    (f) [Reserved]
    (g) If CO2 from ammonia production is used to produce 
urea at the same facility, you must determine the quantity of urea 
produced using methods or plant instruments used for accounting purposes 
(such as sales records). You must document the procedures used to ensure 
the accuracy of the estimates of urea produced.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79156, Dec. 17, 2010]



Sec. 98.75  Procedures for estimating missing data.

    A complete record of all measured parameters used in the GHG 
emissions calculations is required. Therefore, whenever the monitoring 
and quality assurance procedures in Sec. 98.74 cannot be followed 
(e.g., if a meter malfunctions during unit operation), a substitute data 
value for the missing parameter shall be used in the calculations 
following paragraphs (a) and (b) of this section. You must document and 
keep records of the procedures used for all such estimates.
    (a) For missing data on monthly carbon contents of feedstock, the 
substitute data value shall be the arithmetic average of the quality-
assured values of that carbon content in the month preceding and the 
month immediately following the missing data incident. If no quality-
assured data are available prior to the missing data incident, the 
substitute data value shall be the first quality-assured value for 
carbon content obtained in the month after the missing data period.
    (b) For missing feedstock supply rates used to determine monthly 
feedstock consumption, you must determine the best available estimate(s) 
of the parameter(s), based on all available process data.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79157, Dec. 17, 2010; 
78 FR 71953, Nov. 29, 2013]



Sec. 98.76  Data reporting requirements.

    In addition to the information required by Sec. 98.3(c), each 
annual report must contain the information specified in paragraphs (a) 
and (b) of this section, as applicable for each ammonia manufacturing 
process unit.
    (a) If a CEMS is used to measure CO2 emissions, then you 
must report the relevant information required under Sec. 98.36 for the 
Tier 4 Calculation Methodology and the information in paragraphs (a)(1) 
and (2) of this section:
    (1) Annual quantity of each type of feedstock consumed for ammonia 
manufacturing (scf of feedstock or gallons of feedstock or kg of 
feedstock).
    (2) Method used for determining quantity of feedstock used.
    (b) If a CEMS is not used to measure emissions, then you must report 
all of the following information in this paragraph (b):
    (1) Annual CO2 process emissions (metric tons) for each 
ammonia manufacturing process unit.
    (2) [Reserved]
    (3) Method used for determining quantity of monthly feedstock used.
    (4) Whether carbon content for each feedstock for month n is based 
on reports from the supplier or analysis of carbon content.
    (5) If carbon content of feedstock for month n is based on analysis, 
the test method used.
    (6) Sampling analysis results of carbon content of feedstock as 
determined for QA/QC of supplier data under Sec. 98.74(e).
    (7)-(11) [Reserved]
    (12) Annual urea production (metric tons) and method used to 
determine urea production.

[[Page 657]]

    (13) Annual CO2 emissions (metric tons) from the steam 
reforming of a hydrocarbon or the gasification of solid and liquid raw 
material at the ammonia manufacturing process unit used to produce urea 
and the method used to determine the CO2 consumed in urea 
production.
    (14) Annual ammonia production (metric tons, sum of all process 
units reported within subpart G).
    (15) Annual methanol production for each process unit (metric tons).

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79157, Dec. 17, 2010; 
78 FR 71953, Nov. 29, 2013; 79 FR 63785, Oct. 24, 2014]



Sec. 98.77  Records that must be retained.

    In addition to the records required by Sec. 98.3(g), you must 
retain the following records specified in paragraphs (a) through (c) of 
this section for each ammonia manufacturing unit.
    (a) If a CEMS is used to measure emissions, retain records of all 
feedstock purchases in addition to the requirements in Sec. 98.37 for 
the Tier 4 Calculation Methodology.
    (b) If a CEMS is not used to measure process CO2 
emissions, you must also retain the records specified in paragraphs 
(b)(1) through (b)(2) of this section:
    (1) Records of all analyses and calculations conducted for reported 
data as listed in Sec. 98.76(b).
    (2) Monthly records of carbon content of feedstock from supplier 
and/or all analyses conducted of carbon content.
    (c) Verification software records. You must keep a record of the 
file generated by the verification software specified in Sec. 98.5(b) 
for the applicable data specified in paragraphs (c)(1) through (7) of 
this section. Retention of this file satisfies the recordkeeping 
requirement for the data in paragraphs (c)(1) through (7) of this 
section.
    (1) Volume of each gaseous feedstock used in month (scf of 
feedstock) (in Equation G-1 of Sec. 98.73).
    (2) Carbon content of each gaseous feedstock, for month (kg C per kg 
of feedstock) (in Equation G-1).
    (3) Molecular weight of each gaseous feedstock per ammonia 
manufacturing unit with gaseous feedstock (kg/kg-mole) (Equation G-1).
    (4) Volume of each liquid feedstock used in month (gallons of 
feedstock) (Equation G-2 of Sec. 98.73).
    (5) Carbon content of each liquid feedstock, for month (kg C per 
gallon of feedstock) (Equation G-2).
    (6) Mass of each solid feedstock used in month (kg of feedstock) 
(Equation G-3 of Sec. 98.73).
    (7) Carbon content of each solid feedstock, for month (kg C per kg 
of feedstock) (Equation G-3).

[74 FR 56374, Oct. 30, 2009, as amended at 79 FR 63785, Oct. 24, 2014]



Sec. 98.78  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.



                       Subpart H_Cement Production



Sec. 98.80  Definition of the source category.

    The cement production source category consists of each kiln and each 
in-line kiln/raw mill at any portland cement manufacturing facility 
including alkali bypasses, and includes kilns and in-line kiln/raw mills 
that burn hazardous waste.



Sec. 98.81  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains a cement production process and the facility meets the 
requirements of either Sec. 98.2(a)(1) or (2).



Sec. 98.82  GHGs to report.

    You must report:
    (a) CO2 process emissions from calcination in each kiln.
    (b) CO2 combustion emissions from each kiln.
    (c) CH4 and N2O combustion emissions from each 
kiln. You must calculate and report these emissions under subpart C of 
this part (General Stationary Fuel Combustion Sources) by following the 
requirements of subpart C.
    (d) CO2, CH4, and N2O emissions 
from each stationary combustion unit other than kilns. You must report 
these emissions under subpart C of this part (General Stationary Fuel 
Combustion

[[Page 658]]

Sources) by following the requirements of subpart C.



Sec. 98.83  Calculating GHG emissions.

    You must calculate and report the annual process CO2 
emissions from each kiln using the procedure in paragraphs (a) and (b) 
of this section.
    (a) For each cement kiln that meets the conditions specified in 
Sec. 98.33(b)(4)(ii) or (b)(4)(iii), you must calculate and report 
under this subpart the combined process and combustion CO2 
emissions by operating and maintaining a CEMS to measure CO2 
emissions according to the Tier 4 Calculation Methodology specified in 
Sec. 98.33(a)(4) and all associated requirements for Tier 4 in subpart 
C of this part (General Stationary Fuel Combustion Sources).
    (b) For each kiln that is not subject to the requirements in 
paragraph (a) of this section, calculate and report the process and 
combustion CO2 emissions from the kiln by using the procedure 
in either paragraph (c) or (d) of this section.
    (c) Calculate and report under this subpart the combined process and 
combustion CO2 emissions by operating and maintaining a CEMS 
to measure CO2 emissions according to the Tier 4 Calculation 
Methodology specified in Sec. 98.33(a)(4) and all associated 
requirements for Tier 4 in subpart C of this part (General Stationary 
Fuel Combustion Sources).
    (d) Calculate and report process and combustion CO2 
emissions separately using the procedures specified in paragraphs (d)(1) 
through (d)(4) of this section.
    (1) Calculate CO2 process emissions from all kilns at the 
facility using Equation H-1 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.040

Where:

CO2 CMF = Annual process emissions of CO2 from 
          cement manufacturing, metric tons.
CO2 Cli,m = Total annual emissions of CO2 from 
          clinker production from kiln m, metric tons.
CO2 rm = Total annual emissions of CO2 from raw 
          materials, metric tons.
k = Total number of kilns at a cement manufacturing facility.

    (2) CO2 emissions from clinker production. Calculate 
CO2 emissions from each kiln using Equations H-2 through H-5 
of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.041

Where:

Cli,j = Quantity of clinker produced in month j from kiln m, 
          tons.
EFCli,j = Kiln specific clinker emission factor for month j 
          for kiln m, metric tons CO2/metric ton clinker 
          computed as specified in Equation H-3 of this section.
CKD,i = Cement kiln dust (CKD) not recycled to the kiln in 
          quarter i from kiln m, tons.
EFCKD,i = Kiln specific CKD emission factor for quarter i 
          from kiln m, metric tons CO2/metric ton CKD 
          computed as specified in Equation H-4 of this section.
p = Number of months for clinker calculation, 12.
r = Number of quarters for CKD calculation, 4.
2000/2205 = Conversion factor to convert tons to metric tons.

    (i) Kiln-Specific Clinker Emission Factor. (A) Calculate the kiln-
specific clinker emission factor using Equation H-3 of this section.

[[Page 659]]

[GRAPHIC] [TIFF OMITTED] TR30OC09.042

Where:

CliCaO = Monthly total CaO content of Clinker, wt-fraction.
ClincCaO = Monthly non-calcined CaO content of Clinker, wt-
          fraction.
MRCaO = Molecular-weight Ratio of CO2/CaO = 0.785.
CliMgO = Monthly total MgO content of Clinker, wt-fraction.
ClincMgO = Monthly non-calcined MgO content of Clinker, wt-
          fraction.
MRMgO = Molecular-weight Ratio of CO2/MgO = 1.092.

    (B) Non-calcined CaO is CaO that remains in the clinker in the form 
of CaCO3 and CaO in the clinker that entered the kiln as a 
non-carbonate species. Non-calcined MgO is MgO that remains in the 
clinker in the form of MgCO3 and MgO in the clinker that 
entered the kiln as a non-carbonate species.
    (ii) Kiln-Specific CKD Emission Factor. (A) Calculate the kiln-
specific CKD emission factor for CKD not recycled to the kiln using 
Equation H-4 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.043

Where:

CKDCaO = Quarterly total CaO content of CKD not recycled to 
          the kiln, wt-fraction.
CKDCaO = Quarterly non-calcined CaO content of CKD not 
          recycled to the kiln, wt-fraction.
MRCaO = Molecular-weight Ratio of CO2/CaO = 0.785.
CKDMgO = Quarterly total MgO content of CKD not recycled to 
          the kiln, wt-fraction.
CKDMgO = Quarterly non-calcined MgO content of CKD not 
          recycled to the kiln, wt-fraction.
MRMgO = Molecular-weight Ratio of CO2/MgO = 1.092.

    (B) Non-calcined CaO is CaO that remains in the CKD in the form of 
CaCO3 and CaO in the CKD that entered the kiln as a non-
carbonate species. Non-calcined MgO is MgO that remains in the CKD in 
the form of MgCO3 and MgO in the CKD that entered the kiln as 
a non-carbonate species.
    (3) CO2 emissions from raw materials. Calculate 
CO2 emissions from raw materials using Equation H-5 of this 
section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.044

Where:

rm = The amount of raw material i consumed annually, tons/yr (dry basis) 
          or the amount of raw kiln feed consumed annually, tons/yr (dry 
          basis).
CO2,rm = Annual CO2 emissions from raw materials.
TOCrm = Organic carbon content of raw material i or organic carbon 
          content of combined raw kiln feed (dry basis), as determined 
          in Sec. 98.84(c) or using a default factor of 0.2 percent of 
          total raw material weight.
M = Number of raw materials or 1 if calculating emissions based on 
          combined raw kiln feed.
44/12 = Ratio of molecular weights, CO2 to carbon.
2000/2205 = Conversion factor to convert tons to metric tons.

    (4) Calculate and report under subpart C of this part (General 
Stationary

[[Page 660]]

Fuel Combustion Sources) the combustion CO2 emissions from 
the kiln according to the applicable requirements in subpart C.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66461, Oct. 28, 2010]



Sec. 98.84  Monitoring and QA/QC requirements.

    (a) You must determine the weight fraction of total CaO and total 
MgO in CKD not recycled to the kiln from each kiln using ASTM C114-09, 
Standard Test Methods for Chemical Analysis of Hydraulic Cement 
(incoporated by reference, see Sec. 98.7). The monitoring must be 
conducted quarterly for each kiln from a CKD sample drawn either as CKD 
is exiting the kiln or from bulk CKD storage.
    (b) You must determine the weight fraction of total CaO and total 
MgO in clinker from each kiln using ASTM C114-09 Standard Test Methods 
for Chemical Analysis of Hydraulic Cement (incorporated by reference, 
see Sec. 98.7). The monitoring must be conducted monthly for each kiln 
from a monthly clinker sample drawn from bulk clinker storage if storage 
is dedicated to the specific kiln, or from a monthly arithmetic average 
of daily clinker samples drawn from the clinker conveying systems 
exiting each kiln.
    (c) The total organic carbon content (dry basis) of raw materials 
must be determined annually using ASTM C114-09 Standard Test Methods for 
Chemical Analysis of Hydraulic Cement (incorporated by reference, see 
Sec. 98.7) or a similar industry standard practice or method approved 
for total organic carbon determination in raw mineral materials. The 
analysis must be conducted either on sample material drawn from bulk raw 
kiln feed storage or on sample material drawn from bulk raw material 
storage for each category of raw material (i.e., limestone, sand, shale, 
iron oxide, and alumina). Facilities that opt to use the default total 
organic carbon factor provided in Sec. 98.83(d)(3), are not required to 
monitor for TOC.
    (d) The quantity of clinker produced monthly by each kiln must be 
determined by direct weight measurement of clinker using the same plant 
techniques used for accounting purposes, such as reconciling weigh 
hopper or belt weigh feeder measurements against inventory measurements. 
As an alternative, facilities may also determine clinker production by 
direct measurement of raw kiln feed and application of a kiln-specific 
feed-to-clinker factor. Facilities that opt to use a feed-to-clinker 
factor must verify the accuracy of this factor on a monthly basis.
    (e) The quantity of CKD not recycled to the kiln generated by each 
kiln must be determined quarterly using the same plant techniques used 
for accounting purposes, such as direct weight measurement using weigh 
hoppers, truck weigh scales, or belt weigh feeders.
    (f) The annual quantity of raw kiln feed or annual quantity of each 
category of raw materials consumed by the facility (e.g., limestone, 
sand, shale, iron oxide, and alumina) must be determined monthly by 
direct weight measurement using the same plant instruments used for 
accounting purposes, such as weigh hoppers, truck weigh scales, or belt 
weigh feeders.
    (g) The monthly non-calcined CaO and MgO that remains in the clinker 
in the form of CaCO3 or that enters the kiln as a non-
carbonate species may be assumed to be a default value of 0.0 or may be 
determined monthly by careful chemical analysis of feed material and 
clinker material from each kiln using well documented analytical and 
calculational methods or the appropriate industry standard practice.
    (h) The quarterly non-calcined CaO and MgO that remains in the CKD 
in the form of CaCO3 or that enters the kiln as a non-
carbonate species may be assumed to be a default value of 0.0 or may be 
determined quarterly by careful chemical analysis of feed material and 
CKD material from each kiln using well documented analytical and 
calculational methods or the appropriate industry standard practice.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66461, Oct. 28, 2010]



Sec. 98.85  Procedures for estimating missing data.

    A complete record of all measured parameters used in the GHG 
emissions calculations in Sec. 98.83 is required.

[[Page 661]]

Therefore, whenever a quality-assured value of a required parameter is 
unavailable, a substitute data value for the missing parameter shall be 
used in the calculations. The owner or operator must document and keep 
records of the procedures used for all such estimates.
    (a) If the CEMS approach is used to determine combined process and 
combustion CO2 emissions, the missing data procedures in 
Sec. 98.35 apply.
    (b) For CO2 process emissions from cement manufacturing 
facilities calculated according to Sec. 98.83(d), if data on the 
carbonate content (of clinker or CKD), noncalcined content (of clinker 
or CKD) or the annual organic carbon content of raw materials are 
missing, facilities must undertake a new analysis.
    (c) For each missing value of monthly clinker production the 
substitute data value must be the best available estimate of the monthly 
clinker production based on information used for accounting purposes, or 
use the maximum tons per day capacity of the system and the number of 
days per month.
    (d) For each missing value of monthly raw material consumption the 
substitute data value must be the best available estimate of the monthly 
raw material consumption based on information used for accounting 
purposes (such as purchase records), or use the maximum tons per day raw 
material throughput of the kiln and the number of days per month.



Sec. 98.86  Data reporting requirements.

    In addition to the information required by Sec. 98.3(c), each 
annual report must contain the information specified in paragraphs (a) 
and (b) of this section, as appropriate.
    (a) If a CEMS is used to measure CO2 emissions, then you 
must report under this subpart the relevant information required by 
Sec. 98.36(e)(2)(vi) and the information listed in this paragraph(a):
    (1) Monthly clinker production from each kiln at the facility.
    (2) Annual facility cement production.
    (3) Number of kilns and number of operating kilns.
    (b) If a CEMS is not used to measure CO2 emissions, then 
you must report the information listed in this paragraph (b) for each 
kiln:
    (1) Kiln identification number.
    (2) [Reserved]
    (3) Annual cement production at the facility.
    (4) Number of kilns and number of operating kilns.
    (5)-(6) [Reserved]
    (7) Method used to determine non-calcined CaO and non-calcined MgO 
in clinker.
    (8) [Reserved]
    (9) Method used to determine non-calcined CaO and non-calcined MgO 
in CKD.
    (10) [Reserved]
    (11) Quarterly kiln-specific CKD CO2 emission factors for 
each kiln (metric tons CO2/metric ton CKD produced).
    (12) [Reserved]
    (13) Name of raw kiln feed or raw material.
    (14) Number of times missing data procedures were used to determine 
the following information:
    (i) Clinker production (number of months).
    (ii) Carbonate contents of clinker (number of months).
    (iii) Non-calcined content of clinker (number of months).
    (iv) CKD not recycled to kiln (number of quarters).
    (v) Non-calcined content of CKD (number of quarters)
    (vi) Organic carbon contents of raw materials (number of times).
    (vii) Raw material consumption (number of months).
    (15) Method used to determine the monthly clinker production from 
each kiln.
    (16) Annual clinker production (metric tons).
    (17) Annual average clinker CO2 emission factor for the 
facility, averaged across all kilns (metric tons CO2/metric 
ton clinker produced).
    (18) Annual average CKD CO2 emission factor for the 
facility, averaged across all kilns (metric tons CO2/metric 
ton CKD produced).

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66461, Oct. 28, 2010; 
78 FR 71953, Nov. 29, 2013; 79 FR 63785, Oct. 24, 2014]

[[Page 662]]



Sec. 98.87  Records that must be retained.

    (a) If a CEMS is used to measure CO2 emissions, then in 
addition to the records required by Sec. 98.3(g), you must retain under 
this subpart the records required for the Tier 4 Calculation Methodology 
in Sec. 98.37.
    (b) If a CEMS is not used to measure CO2 emissions, then 
in addition to the records required by Sec. 98.3(g), you must retain 
the records specified in this paragraph (b) for each portland cement 
manufacturing facility.
    (1) Documentation of monthly calculated kiln-specific clinker 
CO2 emission factor.
    (2) Documentation of quarterly calculated kiln-specific CKD 
CO2 emission factor.
    (3) Measurements, records and calculations used to determine 
reported parameters.
    (c) Verification software records. You must keep a record of the 
file generated by the verification software specified in Sec. 98.5(b) 
for the applicable data specified in paragraphs (c)(1) through (17) of 
this section. Retention of this file satisfies the recordkeeping 
requirement for the data in paragraphs (c)(1) through (17) of this 
section.
    (1) Identify per kiln per month if clinker is measured directly, or 
is calculated from raw feed (Equation H-2 of Sec. 98.83 and the method 
in Sec. 98.84(d)).
    (2) Quantity of raw kiln feed in month from kiln (tons) (Equation H-
2 and the method in Sec. 98.84(d)).
    (3) Kiln-specific factor per kiln per month (ton clinker per ton raw 
feed) (Equation H-2 and the method in Sec. 98.84(d)).
    (4) Quantity of clinker produced in month from kiln (tons) (Equation 
H-2 and the method in Sec. 98.84(d)).
    (5) Cement kiln dust (CKD) not recycled to the kiln in quarter from 
kiln (tons) (Equation H-2 and the method in Sec. 98.84(d)).
    (6) Monthly total CaO content of clinker per kiln (weight fraction) 
(Equation H-3 of Sec. 98.83).
    (7) Monthly non-calcined CaO content of clinker per kiln (weight 
fraction) (Equation H-3).
    (8) Monthly total MgO content of clinker per kiln (weight fraction) 
(Equation H-3).
    (9) Monthly non-calcined MgO content of clinker per kiln (weight 
fraction) (Equation H-3).
    (10) Quarterly total CaO content of cement kiln dust not recycled to 
each kiln (weight fraction) (Equation H-4 of Sec. 98.83).
    (11) Quarterly non-calcined CaO content of cement kiln dust not 
recycled to each kiln (weight fraction) (Equation H-4).
    (12) Quarterly total MgO content of cement kiln dust not recycled to 
each kiln (weight fraction) (Equation H-4).
    (13) Quarterly non-calcined MgO content of cement kiln dust not 
recycled to each kiln (weight fraction) (Equation H-4).
    (14) The amount of each raw material consumed annually per kiln 
(tons/yr (dry basis)) (Equation H-5 of Sec. 98.83).
    (15) The amount of each raw kiln feed consumed annually per kiln 
(tons/yr (dry basis)) (Equation H-5).
    (16) Organic carbon content of each raw material per kiln, as 
determined in Sec. 98.84(c). Default value is 0.002 weight fraction 
(Equation H-5).
    (17) Organic carbon content of combined raw kiln feed per kiln, as 
determined in Sec. 98.84(c). Default value is 0.002 weight fraction 
(Equation H-5).

[75 FR 66461, Oct. 28, 2010, as amended at 79 FR 63785, Oct. 24, 2014]



Sec. 98.88  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.



                   Subpart I_Electronics Manufacturing

    Source: 75 FR 74818, Dec. 1, 2010, unless otherwise noted.



Sec. 98.90  Definition of the source category.

    (a) The electronics manufacturing source category consists of any of 
the production processes listed in paragraphs (a)(1) through (a)(5) of 
this section that use fluorinated GHGs or N2O. Facilities 
that may use these processes include, but are not limited to, facilities 
that manufacture micro-electro-mechanical systems (MEMS), liquid crystal 
displays (LCDs), photovoltaic

[[Page 663]]

cells (PV), and semiconductors (including light-emitting diodes (LEDs)).
    (1) Any electronics production process in which the etching process 
uses plasma-generated fluorine atoms and other reactive fluorine-
containing fragments, that chemically react with exposed thin-films 
(e.g., dielectric, metals) or substrate (e.g., silicon) to selectively 
remove portions of material.
    (2) Any electronics production process in which chambers used for 
depositing thin films are cleaned periodically using plasma-generated 
fluorine atoms and other reactive fluorine-containing fragments.
    (3) Any electronics production process in which wafers are cleaned 
using plasma generated fluorine atoms or other reactive fluorine-
containing fragments to remove residual material from wafer surfaces, 
including the wafer edge.
    (4) Any electronics production process in which the chemical vapor 
deposition (CVD) process or other manufacturing processes use 
N2O.
    (5) Any electronics manufacturing production process in which 
fluorinated heat transfer fluids are used to cool process equipment, to 
control temperature during device testing, to clean substrate surfaces 
and other parts, and for soldering (e.g., vapor phase reflow).

[75 FR 74818, Dec. 1, 2010, as amended at 77 FR 10380, Feb. 22, 2012]



Sec. 98.91  Reporting threshold.

    (a) You must report GHG emissions under this subpart if electronics 
manufacturing production processes, as defined in Sec. 98.90, are 
performed at your facility and your facility meets the requirements of 
either Sec. 98.2(a)(1) or (a)(2). To calculate total annual GHG 
emissions for comparison to the 25,000 metric ton CO2e per 
year emission threshold in Sec. 98.2(a)(2), follow the requirements of 
Sec. 98.2(b), with one exception. Rather than using the calculation 
methodologies in Sec. 98.93 to calculate emissions from electronics 
manufacturing production processes, calculate emissions of each 
fluorinated GHG from electronics manufacturing production processes by 
using paragraphs (a)(1), (a)(2), or (a)(3) of this section, as 
appropriate, and then sum the emissions of each fluorinated GHG by using 
paragraph (a)(4) of this section.
    (1) If you manufacture semiconductors or MEMS you must calculate 
annual production process emissions of each input gas i for threshold 
applicability purposes using the default emission factors shown in Table 
I-1 to this subpart and Equation I-1 of this subpart.
[GRAPHIC] [TIFF OMITTED] TR01DE10.002

where:

Ei = Annual production process emissions of input gas i for 
          threshold applicability purposes (metric tons 
          CO2e).
S = 100 percent of annual manufacturing capacity of a facility as 
          calculated using Equation I-5 of this subpart (m\2\).
EFi = Emission factor for input gas i (kg/m\2\).
GWPi = Gas-appropriate GWP as provided in Table A-1 to 
          subpart A of this part.
0.001 = Conversion factor from kg to metric tons.
i = Input gas.

    (2) If you manufacture LCDs, you must calculate annual production 
process emissions of each input gas i for threshold applicability 
purposes using the default emission factors shown in Table I-1 to this 
subpart and Equation I-2 of this subpart.
[GRAPHIC] [TIFF OMITTED] TR01DE10.003


[[Page 664]]


where:

Ei = Annual production process emissions of input gas i for 
          threshold applicability purposes (metric tons 
          Co2e).
S = 100 percent of annual manufacturing capacity of a facility as 
          calculated using Equation I-5 of this subpart (m\2\).
EFi = Emission factor for input gas i (g/m\2\).
GWPi = Gas-appropriate GWP as provided in Table A-1 to 
          subpart A of this part.
0.000001 = Conversion factor from g to metric tons.
i = Input gas.

    (3) If you manufacture PVs, you must calculate annual production 
process emissions of each input gas i for threshold applicability 
purposes using gas-appropriate GWP values shown in Table A-1 to subpart 
A of this part and Equation I-3 of this subpart.
[GRAPHIC] [TIFF OMITTED] TR01DE10.004

where:

Ei = Annual production process emissions of input gas i for 
          threshold applicability purposes (metric tons 
          Co2e).
Ci = Annual fluorinated GHG (input gas i) purchases or 
          consumption (kg). Only gases that are used in PV manufacturing 
          processes listed at Sec. 98.90(a)(1) through (a)(4) that have 
          listed GWP values in Table A-1 to subpart A of this part must 
          be considered for threshold applicability purposes.
GWPi = Gas-appropriate GWP as provided in Table A-1 to 
          subpart A of this part.
0.001 = Conversion factor from kg to metric tons.
i = Input gas.

    (4) You must calculate total annual production process emissions for 
threshold applicability purposes using Equation I-4 of this subpart.
[GRAPHIC] [TIFF OMITTED] TR01DE10.005

where:

ET = Annual production process emissions of all fluorinated 
          GHGs for threshold applicability purposes (metric tons 
          Co2e).
[delta] = Factor accounting for fluorinated heat transfer fluid 
          emissions, estimated as 10 percent of total annual production 
          process emissions at a semiconductor facility. Set equal to 
          1.1 when Equation I-4 of this subpart is used to calculate 
          total annual production process emissions from semiconductor 
          manufacturing. Set equal to 1 when Equation I-4 of this 
          subpart is used to calculate total annual production process 
          emissions from MEMS, LCD, or PV manufacturing.
Ei = Annual production process emissions of input gas i for 
          threshold applicability purposes (metric tons 
          Co2e), as calculated in Equations I-1, I-2 or I-3 
          of this subpart.
i = Input gas.

    (b) You must calculate annual manufacturing capacity of a facility 
using Equation I-5 of this subpart.
[GRAPHIC] [TIFF OMITTED] TR01DE10.006

where:

S = 100 percent of annual manufacturing capacity of a facility (m\2\).
WX = Maximum substrate starts of fab f in month x (m\2\ per 
          month).
x = Month.

[75 FR 74818, Dec. 1, 2010, as amended at 77 FR 10380, Feb. 22, 2012; 78 
FR 68202, Nov. 13, 2013]

[[Page 665]]



Sec. 98.92  GHGs to report.

    (a) You must report emissions of fluorinated GHGs (as defined in 
Sec. 98.6), N2O, and fluorinated heat transfer fluids (as 
defined in Sec. 98.98). The fluorinated GHGs and fluorinated heat 
transfer fluids that are emitted from electronics manufacturing 
production processes include, but are not limited to, those listed in 
Table I-2 to this subpart. You must individually report, as appropriate:
    (1) Fluorinated GHGs emitted.
    (2)-(3) [Reserved]
    (4) N2O emitted from chemical vapor deposition and other 
electronics manufacturing processes.
    (5) Emissions of fluorinated heat transfer fluids.
    (6) All fluorinated GHGs and N2O consumed.
    (b) CO2, CH4, and N2O combustion 
emissions from each stationary combustion unit. You must calculate and 
report these emissions under subpart C of this part (General Stationary 
Fuel Combustion Sources) by following the requirements of subpart C of 
this part.

[75 FR 74818, Dec. 1, 2010, as amended at 77 FR 10380, Feb. 22, 2012; 78 
FR 68202, Nov. 13, 2013]



Sec. 98.93  Calculating GHG emissions.

    (a) You must calculate total annual emissions of each fluorinated 
GHG emitted by electronics manufacturing production processes from each 
fab (as defined in Sec. 98.98) at your facility, including each input 
gas and each by-product gas. You must use either default gas utilization 
rates and by-product formations rates according to the procedures in 
paragraph (a)(1), (a)(2), or (a)(6) of this section, as appropriate, or 
the stack test method according to paragraph (i) of this section, to 
calculate emissions of each input gas and each by-product gas.
    (1) If you manufacture semiconductors, you must adhere to the 
procedures in paragraphs (a)(2)(i) through (iii) of this section. You 
must calculate annual emissions of each input gas and of each by-product 
gas using Equations I-6 and I-7, respectively. If your fab uses less 
than 50 kg of a fluorinated GHG in one reporting year, you may calculate 
emissions as equal to your fab's annual consumption for that specific 
gas as calculated in Equation I-11 of this subpart, plus any by-product 
emissions of that gas calculated under this paragraph (a).
[GRAPHIC] [TIFF OMITTED] TR13NO13.000

Where:

ProcesstypeEi = Annual emissions of input gas i from the 
          process type on a fab basis (metric tons).
Eij = Annual emissions of input gas i from process sub-type 
          or process type j as calculated in Equation I-8 of this 
          subpart (metric tons).
N = The total number of process sub-types j that depends on the 
          electronics manufacturing fab and emission calculation 
          methodology. If Eij is calculated for a process 
          type j in Equation I-8 of this subpart, N = 1.
i = Input gas.
j = Process sub-type or process type.
[GRAPHIC] [TIFF OMITTED] TR13NO13.001

Where:

ProcesstypeBEk = Annual emissions of by-product gas k from 
          the processes type on a fab basis (metric tons).
BEijk = Annual emissions of by-product gas k formed from 
          input gas i used for process sub-type or process type j as 
          calculated

[[Page 666]]

          in Equation I-9 of this subpart (metric tons).
N = The total number of process sub-types j that depends on the 
          electronics manufacturing fab and emission calculation 
          methodology. If BEijk is calculated for a process 
          type j in Equation I-9 of this subpart, N = 1.
i = Input gas.
j = Process sub-type, or process type.
k = By-product gas.

    (i) You must calculate annual fab-level emissions of each 
fluorinated GHG used for the plasma etching/wafer cleaning process type 
using default utilization and by-product formation rates as shown in 
Table I-3 or I-4 of this subpart, and by using Equations I-8 and I-9 of 
this subpart.
[GRAPHIC] [TIFF OMITTED] TR06MY14.001

Where:

Eij = Annual emissions of input gas i from process sub-type 
          or process type j, on a fab basis (metric tons).
Cij = Amount of input gas i consumed for process sub-type or 
          process type j, as calculated in Equation I-13 of this 
          subpart, on a fab basis (kg).
Uij = Process utilization rate for input gas i for process 
          sub-type or process type j (expressed as a decimal fraction).
aij = Fraction of input gas i used in process sub-type or 
          process type j with abatement systems, on a fab basis 
          (expressed as a decimal fraction).
dij = Fraction of input gas i destroyed or removed in 
          abatement systems connected to process tools where process 
          sub-type, or process type j is used, on a fab basis (expressed 
          as a decimal fraction). This is zero unless the facility 
          adheres to the requirements in Sec. 98.94(f).
UTij = The average uptime factor of all abatement systems 
          connected to process tools in the fab using input gas i in 
          process sub-type or process type j, as calculated in Equation 
          I-15 of this subpart, on a fab basis (expressed as a decimal 
          fraction).
0.001 = Conversion factor from kg to metric tons.
i = Input gas.
j = Process sub-type or process type.
[GRAPHIC] [TIFF OMITTED] TR13NO13.003

Where:

BEijk = Annual emissions of by-product gas k formed from 
          input gas i from process sub-type or process type j, on a fab 
          basis (metric tons).
Bijk = By-product formation rate of gas k created as a by-
          product per amount of input gas i (kg) consumed by process 
          sub-type or process type j (kg).
Cij = Amount of input gas i consumed for process sub-type, or 
          process type j, as calculated in Equation I-13 of this 
          subpart, on a fab basis (kg).
aij = Fraction of input gas i used for process sub-type, or 
          process type j with abatement systems, on a fab basis 
          (expressed as a decimal fraction).
djk = Fraction of by-product gas k destroyed or removed in 
          abatement systems connected to process tools where process 
          sub-type, or process type j is used, on a fab basis (expressed 
          as a decimal fraction). This is zero unless the facility 
          adheres to the requirements in Sec. 98.94(f).
UTijk = The average uptime factor of all abatement systems 
          connected to process tools in the fab emitting by-product gas 
          k, formed from input gas i in process sub-type or process type 
          j, on a fab basis (expressed as a decimal fraction). For this 
          equation, UTijk is assumed to be equal to 
          UTij as calculated in Equation I-15 of this 
          subpart.
0.001 = Conversion factor from kg to metric tons.
i = Input gas.
j = Process sub-type or process type.
k = By-product gas.

    (ii) You must calculate annual fab-level emissions of each 
fluorinated GHG used for each of the process sub-

[[Page 667]]

types associated with the chamber cleaning process type, including in-
situ plasma chamber clean, remote plasma chamber clean, and in-situ 
thermal chamber clean, using default utilization and by-product 
formation rates as shown in Table I-3 or I-4 of this subpart, and by 
using Equations I-8 and I-9 of this subpart.
    (iii) If default values are not available for a particular input gas 
and process type or sub-type combination in Tables I-3 or I-4, you must 
follow the procedures in paragraph (a)(6) of this section.
    (2) If you manufacture MEMS, LCDs, or PVs, you must calculate annual 
fab-level emissions of each fluorinated GHG used for the plasma etching 
and chamber cleaning process types using default utilization and by-
product formation rates as shown in Table I-5, I-6, or I-7 of this 
subpart, as appropriate, and by using Equations I-8 and I-9 of this 
subpart. If default values are not available for a particular input gas 
and process type or sub-type combination in Tables I-5, I-6, or I-7, you 
must follow the procedures in paragraph (a)(6) of this section. If your 
fab uses less than 50 kg of a fluorinated GHG in one reporting year, you 
may calculate emissions as equal to your fab's annual consumption for 
that specific gas as calculated in Equation I-11 of this subpart, plus 
any by-product emissions of that gas calculated under this paragraph 
(a).
    (3)-(5) [Reserved]
    (6) If you are required, or elect, to perform calculations using 
default emission factors for gas utilization and by-product formation 
rates according to the procedures in paragraphs (a)(1) or (a)(2) of this 
section, and default values are not available for a particular input gas 
and process type or sub-type combination in Tables I-3, I-4, I-5, I-6, 
or I-7, you must use the utilization and by-product formation rates of 
zero and use Equations I-8 and I-9 of this subpart.
    (b) You must calculate annual fab-level N2O emissions 
from all chemical vapor deposition processes and from the aggregate of 
all other electronics manufacturing production processes using Equation 
I-10 of this subpart and the methods in paragraphs (b)(1) and (2) of 
this section. If your fab uses less than 50 kg of N2O in one 
reporting year, you may calculate fab emissions as equal to your fab's 
annual consumption for N2O as calculated in Equation I-11 of 
this subpart.
[GRAPHIC] [TIFF OMITTED] TR13NO13.004

    Where:

E(N2O)j = Annual emissions of N2O for 
          N2O-using process j, on a fab basis (metric tons).
CN2O,j = Amount of N2O consumed for 
          N2O-using process j, as calculated in Equation I-13 
          of this subpart and apportioned to N2O process j, 
          on a fab basis (kg).
UN2O,j = Process utilization factor for N2O-using 
          process j (expressed as a decimal fraction) from Table I-8 of 
          this subpart.
aN2O,j = Fraction of N2O used in N2O-
          using process j with abatement systems, on a fab basis 
          (expressed as a decimal fraction).
dN2O,j = Fraction of N2O for N2O-using 
          process j destroyed or removed in abatement systems connected 
          to process tools where process j is used, on a fab basis 
          (expressed as a decimal fraction). This is zero unless the 
          facility adheres to the requirements in Sec. 98.94(f).
UTN2O = The average uptime factor of all the abatement 
          systems connected to process tools in the fab that use 
          N2O, as calculated in Equation I-15 of this 
          subpart, on a fab basis (expressed as a decimal fraction). For 
          purposes of calculating the abatement system uptime for 
          N2O using process tools, in Equation I-15 of this 
          subpart, the only input gas i is N2O, j is the 
          N2O using process, and p is the N2O 
          abatement system connected to the N2O using tool.
0.001 = Conversion factor from kg to metric tons.
j = Type of N2O-using process, either chemical vapor 
          deposition or all other N2O-using manufacturing 
          processes.


[[Page 668]]


    (1) You must use the factor for N2O utilization for 
chemical vapor deposition processes as shown in Table I-8 to this 
subpart.
    (2) You must use the factor for N2O utilization for all 
other manufacturing production processes other than chemical vapor 
deposition as shown in Table I-8 to this subpart.
    (c) You must calculate total annual input gas i consumption on a fab 
basis for each fluorinated GHG and N2O using Equation I-11 of 
this subpart. Where a gas supply system serves more than one fab, 
Equation I-11 is applied to that gas which has been apportioned to each 
fab served by that system using the apportioning factors determined in 
accordance with Sec. 98.94(c).
[GRAPHIC] [TIFF OMITTED] TR01DE10.012

where:

Ci = Annual consumption of input gas i, on a fab basis (kg 
          per year).
IBi = Inventory of input gas i stored in containers at the 
          beginning of the reporting year, including heels, on a fab 
          basis (kg). For containers in service at the beginning of a 
          reporting year, account for the quantity in these containers 
          as if they were full.
IEi = Inventory of input gas i stored in containers at the 
          end of the reporting year, including heels, on a fab basis 
          (kg). For containers in service at the end of a reporting 
          year, account for the quantity in these containers as if they 
          were full.
Ai = Acquisitions of input gas i during the year through 
          purchases or other transactions, including heels in containers 
          returned to the electronics manufacturing facility, on a fab 
          basis (kg).
Di = Disbursements of input gas i through sales or other 
          transactions during the year, including heels in containers 
          returned by the electronics manufacturing facility to the 
          chemical supplier, as calculated using Equation I-12 of this 
          subpart, on a fab basis (kg).
i = Input gas.

    (d) You must calculate disbursements of input gas i using fab-wide 
gas-specific heel factors, as determined in Sec. 98.94(b), and by using 
Equation I-12 of this subpart. Where a gas supply system serves more 
than one fab, Equation I-12 is applied to that gas which has been 
apportioned to each fab served by that system using the apportioning 
factors determined in accordance with Sec. 98.94(c).
[GRAPHIC] [TIFF OMITTED] TR01DE10.013

where:

Di = Disbursements of input gas i through sales or other 
          transactions during the reporting year on a fab basis, 
          including heels in containers returned by the electronics 
          manufacturing fab to the gas distributor (kg).
hil = Fab-wide gas-specific heel factor for input gas i and 
          container size and type l (expressed as a decimal fraction), 
          as determined in Sec. 98.94(b). If your fab uses less than 50 
          kg of a fluorinated GHG or N2O in one reporting 
          year, you may assume that any hil for that 
          fluorinated GHG or N2O is equal to zero.
Nil = Number of containers of size and type l returned to the 
          gas distributor containing the standard heel of input gas i.
Fil = Full capacity of containers of size and type l 
          containing input gas i, on a fab basis (kg).
Xi = Disbursements under exceptional circumstances of input 
          gas i through sales or other transactions during the year, on 
          a fab basis (kg). These include returns of containers whose 
          contents have been weighed due to an exceptional circumstance 
          as specified in Sec. 98.94(b)(4).
i = Input gas.
l = Size and type of gas container.
M = The total number of different sized container types on a fab basis. 
          If only one size and container type is used for an input gas 
          i, M = 1.

    (e) You must calculate the amount of input gas i consumed, on a fab 
basis, for each process sub-type or process

[[Page 669]]

type j, using Equation I-13 of this subpart. Where a gas supply system 
serves more than one fab, Equation I-13 is applied to that gas which has 
been apportioned to each fab served by that system using the 
apportioning factors determined in accordance with Sec. 98.94(c). If 
you elect to calculate emissions using the stack test method in 
paragraph (i) of this section, you must calculate the amount of input 
gas i consumed on the applicable basis by using an appropriate 
apportioning factor. For example, when calculating fab-level emissions 
of each fluorinated GHG consumed using Equation I-21 of this section, 
you must substitute the term fij with the appropriate apportioning 
factor to calculate the total consumption of each fluorinated GHG in 
tools that are vented to stack systems that are tested.
[GRAPHIC] [TIFF OMITTED] TR01DE10.014

where:

Ci,j = The annual amount of input gas i consumed, on a fab 
          basis, for process sub-type or process type j (kg).
fi,j = Process sub-type-specific or process type-specific j, 
          input gas i apportioning factor (expressed as a decimal 
          fraction), as determined in accordance with Sec. 98.94(c).
Ci = Annual consumption of input gas i, on a fab basis, as 
          calculated using Equation I-11 of this subpart (kg).
i = Input gas.
j = Process sub-type or process type.

    (f) [Reserved]
    (g) If you report controlled emissions pursuant to Sec. 98.94(f), 
you must calculate the uptime of all the abatement systems for each 
combination of input gas or by-product gas, and process sub-type or 
process type, by using Equation I-15 of this subpart.
[GRAPHIC] [TIFF OMITTED] TR06MY14.002

Where:

UTij = The average uptime factor of all abatement systems 
          connected to process tools in the fab using input gas i in 
          process sub-type or process type j (expressed as a decimal 
          fraction).
Tdijp = The total time, in minutes, that abatement system p, 
          connected to process tool(s) in the fab using input gas i in 
          process sub-type or process type j, is not in operational 
          mode, as defined in Sec. 98.98, when at least one of the 
          tools connected to abatement system p is in operation.
UTijp = Total time, in minutes per year, in which abatement 
          system p has at least one associated tool in operation. For 
          determining the amount of tool operating time, you may assume 
          that tools that were installed for the whole of the year were 
          operated for 525,600 minutes per year. For tools that were 
          installed or uninstalled during the year, you must prorate the 
          operating time to account for the days in which the tool was 
          not installed; treat any partial day that a tool was installed 
          as a full day (1,440 minutes) of tool operation. For an 
          abatement system that has more than one connected tool, the 
          tool operating time is 525,600 minutes per year if at least 
          one tool was installed at all times throughout the year. If 
          you have tools that are idle with no gas flow through the tool 
          for part of the year, you may calculate total tool time using 
          the actual time that gas is flowing through the tool.
i = Input gas.
j = Process sub-type or process type.
p = Abatement system.

    (h) If you use fluorinated heat transfer fluids, you must calculate 
the annual emissions of fluorinated heat transfer fluids on a fab basis 
using the mass balance approach described in Equation I-16 of this 
subpart.

[[Page 670]]

[GRAPHIC] [TIFF OMITTED] TR01DE10.017

where:

EHi = Emissions of fluorinated heat transfer fluid i, on a 
          fab basis (metric tons/year).
Densityi = Density of fluorinated heat transfer fluid i (kg/
          l).
IiB = Inventory of fluorinated heat transfer fluid i, on a 
          fab basis, in containers other than equipment at the beginning 
          of the reporting year (in stock or storage) (l). The inventory 
          at the beginning of the reporting year must be the same as the 
          inventory at the end of the previous reporting year.
Pi = Acquisitions of fluorinated heat transfer fluid i, on a 
          fab basis, during the reporting year (l), including amounts 
          purchased from chemical suppliers, amounts purchased from 
          equipment suppliers with or inside of equipment, and amounts 
          returned to the facility after off-site recycling.
Ni = Total nameplate capacity (full and proper charge) of 
          equipment that uses fluorinated heat transfer fluid i and that 
          is newly installed in the fab during the reporting year (l).
Ri = Total nameplate capacity (full and proper charge) of 
          equipment that uses fluorinated heat transfer fluid i and that 
          is removed from service in the fab during the reporting year 
          (l).
IiE = Inventory of fluorinated heat transfer fluid i, on a 
          fab basis, in containers other than equipment at the end of 
          the reporting year (in stock or storage) (l). The inventory at 
          the beginning of the reporting year must be the same as the 
          inventory at the end of the previous reporting year.
Di = Disbursements of fluorinated heat transfer fluid i, on a 
          fab basis, during the reporting year, including amounts 
          returned to chemical suppliers, sold with or inside of 
          equipment, and sent off-site for verifiable recycling or 
          destruction (l). Disbursements should include only amounts 
          that are properly stored and transported so as to prevent 
          emissions in transit.
0.001 = Conversion factor from kg to metric tons.
i = Fluorinated heat transfer fluid.

    (1) If you use a fluorinated chemical both as a fluorinated heat 
transfer fluid and in other applications, you may calculate and report 
either emissions from all applications or from only those specified in 
the definition of fluorinated heat transfer fluids in Sec. 98.98.
    (2) [Reserved]
    (i) Stack Test Method. As an alternative to the default emission 
factor method in paragraph (a) of this section, you may calculate fab-
level fluorinated GHG emissions using fab-specific emission factors 
developed from stack testing. To use the method in this paragraph, you 
must first make a preliminary estimate of the fluorinated GHG emissions 
from each stack system in the fab under paragraph (i)(1) of this 
section. You must then compare the preliminary estimate for each stack 
system to the criteria in paragraph (i)(2) of this section to determine 
whether the stack system meets the criteria for using the stack test 
method described in paragraph (i)(3) of this section or whether the 
stack system meets the criteria for using the method described in 
paragraph (i)(4) of this section to estimate emissions from the stack 
systems that are not tested.
    (1) Preliminary estimate of emissions by stack system in the fab. 
You must calculate a preliminary estimate of the total annual emissions, 
on a metric ton CO2e basis, of all fluorinated GHG from each 
stack system in the fab using default utilization and by-product 
formation rates as shown in Table I-11, I-12, I-13, I-14, or I-15 of 
this subpart, as applicable, and by using Equations I-8 and I-9 of this 
subpart. You must include any intermittent low-use fluorinated GHGs, as 
defined in Sec. 98.98 of this subpart, in any preliminary estimates. 
When using Equations I-8 and I-9 of this subpart for the purposes of 
this paragraph (i)(1), you must also adhere to the procedures in 
paragraphs (i)(1)(i) to (iv) of this section to calculate preliminary 
estimates.
    (i) When you are calculating preliminary estimates for the purpose 
of this paragraph (i)(1), you must consider the subscript ``j'' in 
Equations I-8 and I-9, and I-13 of this subpart to mean ``stack system'' 
instead of ``process sub-type or process type.'' For the value of 
aij, the fraction of input gas i that is used in tools with 
abatement systems, for use in Equations I-8 and I-9, you may use the 
ratio of the number of tools using input gas i that have abatement

[[Page 671]]

systems that are vented to the stack system for which you are 
calculating the preliminary estimate to the total number of tools using 
input gas i that are vented to that stack system, expressed as a decimal 
fraction. In calculating the preliminary estimates, you must account for 
the effect of any fluorinated GHG abatement system meeting the 
definition of abatement system in Sec. 98.98. You may use this approach 
to determining aij only for this preliminary estimate.
    (ii) You must use representative data from the previous reporting 
year to estimate the consumption of input gas i as calculated in 
Equation I-13 of this subpart and the fraction of input gas i destroyed 
in abatement systems for each stack system as calculated by Equation I-
24 of this subpart. If you were not required to submit an annual report 
under subpart I for the previous reporting year and data from the 
previous reporting year are not available, you may estimate the 
consumption of input gas i and the fraction of input gas i destroyed in 
abatement systems based on representative operating data from a period 
of at least 30 days in the current reporting year. When calculating the 
consumption of input gas i using Equation I-13 of this subpart, the term 
``fij'' is replaced with the ratio of the number of tools 
using input gas i that are vented to the stack system for which you are 
calculating the preliminary estimate to the total number of tools in the 
fab using input gas i, expressed as a decimal fraction. You may use this 
approach to determining fij only for this preliminary 
estimate.
    (iii) You must use representative data from the previous reporting 
year to estimate the total uptime of all abatement systems for the stack 
system as calculated by Equation I-23 of this subpart, instead of using 
Equation I-15 of this subpart to calculate the average uptime factor. If 
you were not required to submit an annual report under subpart I for the 
previous reporting year and data from the previous reporting year are 
not available, you may estimate the total uptime of all abatement 
systems for the stack system based on representative operating data from 
a period of at least 30 days in the current reporting year.
    (iv) If you anticipate an increase or decrease in annual consumption 
or emissions of any fluorinated GHG, or the number of tools connected to 
abatement systems greater than 10 percent for the current reporting year 
compared to the previous reporting year, you must account for the 
anticipated change in your preliminary estimate. You may account for 
such a change using a quantifiable metric (e.g., the ratio of the number 
tools that are expected to be vented to the stack system in the current 
year as compared to the previous reporting year, ratio of the expected 
number of wafer starts in the current reporting year as compared to the 
previous reporting year), engineering judgment, or other industry 
standard practice.
    (2) Method selection for stack systems in the fab. If the 
calculations under paragraph (i)(1) of this section, as well as any 
subsequent annual measurements and calculations under this subpart, 
indicate that the stack system meets the criteria in paragraph (i)(2)(i) 
through (iii) of this section, then you may comply with either paragraph 
(i)(3) of this section (stack test method) or paragraph (i)(4) of this 
section (method to estimate emissions from the stack systems that are 
not tested). If the stack system does not meet all three criteria in 
paragraph (i)(2)(i) through (iii) of this section, then you must comply 
with the stack test method specified in paragraph (i)(3) of this 
section.
    (i) The sum of annual emissions of fluorinated GHGs from all of the 
combined stack systems that are not tested in the fab must be less than 
10,000 metric ton CO2e per year.
    (ii) When all stack systems in the fab are ordered from lowest to 
highest emitting in metric ton CO2e of fluorinated GHG per 
year, each of the stack systems that is not tested must be within the 
set of the fab's lowest emitting fluorinated GHG stack systems that 
together emit 15 percent or less of total CO2e fluorinated 
GHG emissions from the fab.
    (iii) Fluorinated GHG emissions from each of the stack systems that 
is not tested can only be attributed to particular process tools during 
the test (that is, the stack system that is not tested cannot be used as 
an alternative

[[Page 672]]

emission point or bypass stack system from other process tools not 
attributed to the untested stack system).
    (3) Stack system stack test method. For each stack system in the fab 
for which testing is required, measure the emissions of each fluorinated 
GHG from the stack system by conducting an emission test. In addition, 
measure the fab-specific consumption of each fluorinated GHG by the 
tools that are vented to the stack systems tested. Measure emissions and 
consumption of each fluorinated GHG as specified in Sec. 98.94(j). 
Develop fab-specific emission factors and calculate fab-level 
fluorinated GHG emissions using the procedures specified in paragraph 
(i)(3)(i) through (viii) of this section. All emissions test data and 
procedures used in developing emission factors must be documented and 
recorded according to Sec. 98.97.
    (i) You must measure, and, if applicable, apportion the fab-specific 
fluorinated GHG consumption of the tools that are vented to the stack 
systems that are tested during the emission test as specified in Sec. 
98.94(j)(3). Calculate the consumption for each fluorinated GHG for the 
test period.
    (ii) You must calculate the emissions of each fluorinated GHG 
consumed as an input gas using Equation I-17 of this subpart and each 
fluorinated GHG formed as a by-product gas using Equation I-18 of this 
subpart and the procedures specified in paragraphs (i)(3)(ii)(A) through 
(E) of this section. If a stack system is comprised of multiple stacks, 
you must sum the emissions from each stack in the stack system when 
using Equation I-17 or Equation I-18 of this subpart.
[GRAPHIC] [TIFF OMITTED] TR13NO13.006

Where:

Eis = Total fluorinated GHG input gas i, emitted from stack 
          system s, during the sampling period (kg).
Xism = Average concentration of fluorinated GHG input gas i 
          in stack system s, during the time interval m (ppbv).
MWi = Molecular weight of fluorinated GHG input gas i (g/g-
          mole).
Qs = Flow rate of the stack system s, during the sampling 
          period (m\3\/min).
SV = Standard molar volume of gas (0.0240 m\3\/g-mole at 68  deg.F and 1 
          atm).
Ftm = Length of time interval m (minutes). Each time interval 
          in the FTIR sampling period must be less than or equal to 60 
          minutes (for example an 8 hour sampling period would consist 
          of at least 8 time intervals).
1/10\3\ = Conversion factor (1 kilogram/1,000 grams).
i = Fluorinated GHG input gas.
s = Stack system.
N = Total number of time intervals m in sampling period.
m = Time interval.
[GRAPHIC] [TIFF OMITTED] TR13NO13.007

Where:

Eks = Total fluorinated GHG by-product gas k, emitted from 
          stack system s, during the sampling period (kg).
Xks = Average concentration of fluorinated GHG by-product gas 
          k in stack system s, during the time interval m (ppbv).
MWk = Molecular weight of the fluorinated GHG by-product gas 
          k (g/g-mole).
Qs = Flow rate of the stack system s, during the sampling 
          period (m\3\/min).
SV = Standard molar volume of gas (0.0240 m\3\/g-mole at 68  deg.F and 1 
          atm).
Ftm = Length of time interval m (minutes). Each time interval 
          in the FTIR sampling period must be less than or equal to 60 
          minutes (for example an 8 hour sampling period would consist 
          of at least 8 time intervals).

[[Page 673]]

1/10\3\ = Conversion factor (1 kilogram/1,000 grams).
k = Fluorinated GHG by-product gas.
s = Stack system.
N = Total number of time intervals m in sampling period.
m = Time interval.

    (A) If a fluorinated GHG is consumed during the sampling period, but 
emissions are not detected, use one-half of the field detection limit 
you determined for that fluorinated GHG according to Sec. 98.94(j)(2) 
for the value of ``Xism'' in Equation I-17.
    (B) If a fluorinated GHG is consumed during the sampling period and 
detected intermittently during the sampling period, use the detected 
concentration for the value of ``Xism'' in Equation I-17 when 
available and use one-half of the field detection limit you determined 
for that fluorinated GHG according to Sec. 98.94(j)(2) for the value of 
``Xism'' when the fluorinated GHG is not detected.
    (C) If an expected or possible by-product, as listed in Table I-17 
of this subpart, is detected intermittently during the sampling period, 
use the measured concentration for ``Xksm'' in Equation I-18 
when available and use one-half of the field detection limit you 
determined for that fluorinated GHG according to Sec. 98.94(j)(2) for 
the value of ``Xksm'' when the fluorinated GHG is not 
detected.
    (D) If a fluorinated GHG is not consumed during the sampling period 
and is an expected by-product gas as listed in Table I-17 of this 
subpart and is not detected during the sampling period, use one-half of 
the field detection limit you determined for that fluorinated GHG 
according to Sec. 98.94(j)(2) for the value of ``Xksm'' in 
Equation I-18.
    (E) If a fluorinated GHG is not consumed during the sampling period 
and is a possible by-product gas as listed in Table I-17 of this 
subpart, and is not detected during the sampling period, then assume 
zero emissions for that fluorinated GHG for the tested stack system.
    (iii) You must calculate a fab-specific emission factor for each 
fluorinated GHG input gas consumed (in kg of fluorinated GHG emitted per 
kg of input gas i consumed) in the tools that vent to stack systems that 
are tested, as applicable, using Equation I-19 of this subpart. If the 
emissions of input gas i exceed the consumption of input gas i during 
the sampling period, then equate ``Eis'' to the consumption 
of input gas i and treat the difference between the emissions and 
consumption of input gas i as a by-product of the other input gases, 
using Equation I-20 of this subpart.
[GRAPHIC] [TIFF OMITTED] TR13NO13.008

Where:

EFif = Emission factor for fluorinated GHG input gas i, from 
          fab f, representing 100 percent abatement system uptime (kg 
          emitted/kg input gas consumed).
Eis = Mass emission of fluorinated GHG input gas i from stack 
          system s, during the sampling period (kg emitted).
Activityif = Consumption of fluorinated GHG input gas i, for 
          fab f, in the tools vented to the stack systems being tested, 
          during the sampling period, as determined following the 
          procedures specified in Sec. 98.94(j)(3) (kg consumed).
UTf = The total uptime of all abatement systems for fab f, 
          during the sampling period, as calculated in Equation I-23 of 
          this subpart (expressed as decimal fraction). If the stack 
          system does not have abatement systems on the tools vented to 
          the stack system, the value of this parameter is zero.
aif = Fraction of fluorinated GHG input gas i used in fab f 
          in tools with abatement systems (expressed as a decimal 
          fraction).
dif = Fraction of fluorinated GHG input gas i destroyed or 
          removed in abatement systems connected to process tools in fab 
          f,

[[Page 674]]

          as calculated in Equation I-24 of this subpart (expressed as 
          decimal fraction). If the stack system does not have abatement 
          systems on the tools vented to the stack system, the value of 
          this parameter is zero.
f = Fab.
i = Fluorinated GHG input gas.
s = Stack system.

    (iv) You must calculate a fab-specific emission factor for each 
fluorinated GHG formed as a by-product (in kg of fluorinated GHG per kg 
of total fluorinated GHG consumed) in the tools vented to stack systems 
that are tested, as applicable, using Equation I-20 of this subpart. 
When calculating the by-product emission factor for an input gas for 
which emissions exceeded its consumption, exclude the consumption of 
that input gas from the term ``M(Activityif).''
[GRAPHIC] [TIFF OMITTED] TR13NO13.009

Where:

EFkf = Emission factor for fluorinated GHG by-product gas k, 
          from fab f, representing 100 percent abatement system uptime 
          (kg emitted/kg of all input gases consumed in tools vented to 
          stack systems that are tested).
Eks = Mass emission of fluorinated GHG by-product gas k, 
          emitted from stack system s, during the sampling period (kg 
          emitted).
Activityif = Consumption of fluorinated GHG input gas i for 
          fab f in tools vented to stack systems that are tested, during 
          the sampling period as determined following the procedures 
          specified in Sec. 98.94(j)(3) (kg consumed).
UTf = The total uptime of all abatement systems for fab f, 
          during the sampling period, as calculated in Equation I-23 of 
          this subpart (expressed as decimal fraction).
af = Fraction of all fluorinated input gases used in fab f in 
          tools with abatement systems (expressed as a decimal 
          fraction).
dkf = Fraction of fluorinated GHG by-product gas k destroyed 
          or removed in abatement systems connected to process tools in 
          fab f, as calculated in Equation I-24 of this subpart 
          (expressed as decimal fraction).
f = Fab.
i = Fluorinated GHG input gas.
k = Fluorinated GHG by-product gas.
s = Stack system.

    (v) You must calculate annual fab-level emissions of each 
fluorinated GHG consumed using Equation I-21 of this section.
[GRAPHIC] [TIFF OMITTED] TR13NO13.010

Where:

Eif = Annual emissions of fluorinated GHG input gas i (kg/
          year) from the stack systems that are tested for fab f.
EFif = Emission factor for fluorinated GHG input gas i 
          emitted from fab f, as calculated in Equation I-19 of this 
          subpart (kg emitted/kg input gas consumed).
Cif = Total consumption of fluorinated GHG input gas i in 
          tools that are vented to stack systems that are tested, for 
          fab f, for the reporting year, as calculated using Equation I-
          13 of this subpart (kg/year).
UTf = The total uptime of all abatement systems for fab f, 
          during the reporting year, as calculated using Equation I-23 
          of this subpart (expressed as a decimal fraction).
aif = Fraction of fluorinated GHG input gas i used in fab f 
          in tools with abatement systems (expressed as a decimal 
          fraction).
dif = Fraction of fluorinated GHG input gas i destroyed or 
          removed in abatement systems connected to process tools in fab 
          f

[[Page 675]]

          that are included in the stack testing option, as calculated 
          in Equation I-24 of this subpart (expressed as decimal 
          fraction).
f = Fab.
i = Fluorinated GHG input gas.

    (vi) You must calculate annual fab-level emissions of each 
fluorinated GHG by-product formed using Equation I-22 of this section.
[GRAPHIC] [TIFF OMITTED] TR13NO13.011

Where:

Ekf = Annual emissions of fluorinated GHG by-product k (kg/
          year) from the stack systems that are tested for fab f.
EFkf = Emission factor for fluorinated GHG by-product k, 
          emitted from fab f, as calculated in Equation I-20 of this 
          subpart (kg emitted/kg of all fluorinated input gases 
          consumed).
Cif = Total consumption of fluorinated GHG input gas i in 
          tools that are vented to stack systems that are tested, for 
          fab f, for the reporting year, as calculated using Equation I-
          13 of this subpart.
UTf = The total uptime of all abatement systems for fab f, 
          during the reporting year as calculated using Equation I-23 of 
          this subpart (expressed as a decimal fraction).
af = Fraction of fluorinated input gases used in fab f in 
          tools with abatement systems (expressed as a decimal 
          fraction).
dkf = Fraction of fluorinated GHG by-product k destroyed or 
          removed in abatement systems connected to process tools in fab 
          f that are included in the stack testing option, as calculated 
          in Equation I-24 of this subpart (expressed as decimal 
          fraction).
f = Fab.
i = Fluorinated GHG input gas.
k = Fluorinated GHG by-product

    (vii) When using the stack testing method described in this 
paragraph (i), you must calculate abatement system uptime on a fab basis 
using Equation I-23 of this subpart. When calculating abatement system 
uptime for use in Equation I-19 and I-20 of this subpart, you must 
evaluate the variables ``Tdpf'' and ``UTpf'' for 
the sampling period instead of the reporting year.
[GRAPHIC] [TIFF OMITTED] TR06MY14.003

Where:

UTf = The average uptime factor for all abatement systems in 
          fab f (expressed as a decimal fraction).
Tdpf = The total time, in minutes, that abatement system p, 
          connected to process tool(s) in fab f, is not in operational 
          mode as defined in Sec. 98.98.
UTpf = Total time, in minutes per year, in which the tool(s) 
          connected at any point during the year to abatement system p, 
          in fab f could be in operation. For determining the amount of 
          tool operating time, you may assume that tools that were 
          installed for the whole of the year were operated for 525,600 
          minutes per year. For tools that were installed or uninstalled 
          during the year, you must prorate the operating time to 
          account for the days in which the tool was not installed; 
          treat any partial day that a tool was installed as a full day 
          (1,440 minutes) of tool operation. For an abatement system 
          that has more than one connected tool, the tool operating time 
          is 525,600 minutes per year if there was at least one tool 
          installed at all times throughout the year. If you have tools 
          that are idle with no gas flow through the tool, you may 
          calculate total tool time using the actual time that gas is 
          flowing through the tool.
f = Fab.
p = Abatement system.

    (viii) When using the stack testing option described in this 
paragraph (i), you must calculate the weighted-average fraction of 
fluorinated input gas i destroyed or removed in abatement systems for 
each fab f, as applicable, by using Equation I-24 of this subpart.

[[Page 676]]

[GRAPHIC] [TIFF OMITTED] TR13NO13.013

Where:

dif = The average weighted fraction of fluorinated GHG input 
          gas i destroyed or removed in abatement systems in fab f 
          (expressed as a decimal fraction).
Cijf = The amount of fluorinated GHG input gas i consumed for 
          process type j fed into abatement systems in fab f as 
          calculated using Equation I-13 of this subpart (kg).
DREij = Destruction or removal efficiency for fluorinated GHG 
          input gas i in abatement systems connected to process tools 
          where process type j is used (expressed as a decimal fraction) 
          determined according to Sec. 98.94(f).
f = fab.
i = Fluorinated GHG input gas.
j = Process type.

    (4) Method to calculate emissions from stack systems that are not 
tested. You must calculate annual fab-level emissions of each 
fluorinated GHG input gas and by-product gas for those fluorinated GHG 
listed in paragraphs (i)(4)(i) and (ii) of this section using default 
utilization and by-product formation rates as shown in Tables I-11, I-
12, I-13, I-14, or I-15 of this subpart, as applicable, and by using 
Equations I-8, I-9, and I-13 of this subpart. When using Equations I-8, 
I-9, and I-13 of this subpart to fulfill the requirements of this 
paragraph, you must use, in place of the term Cij in each 
equation, the total consumption of each fluorinated GHG meeting the 
criteria in paragraph (i)(4)(i) of this section or that is used in tools 
vented to the stack systems that meet the criteria in paragraph 
(i)(4)(ii) of this section. You must use, in place of the term 
aij, the fraction of fluorinated GHG meeting the criteria in 
paragraph (i)(4)(i) of this section used in tools with abatement systems 
or that is used in tools with abatement systems that are vented to the 
stack systems that meet the criteria in paragraph (i)(4)(ii) of this 
section. You also must use the results of Equation I-24 of this subpart 
in place of the terms dij in Equation I-8 of this subpart and 
djk in Equation I-9 of this subpart, and use the results of 
Equation I-23 of this subpart in place of the results of Equation I-15 
of this subpart for the term UTij.
    (i) Calculate emissions from consumption of each intermittent low-
use fluorinated GHG as defined in Sec. 98.98 of this subpart using the 
default utilization and by-product formation rates and equations 
specified in paragraph (i)(4) of this section. If a fluorinated GHG was 
not being used during the stack testing and does not meet the definition 
of intermittent low-use fluorinated GHG in Sec. 98.98, then you must 
test the stack systems associated with the use of that fluorinated GHG 
at a time when that gas is in use at a magnitude that would allow you to 
determine an emission factor for that gas according to the procedures 
specified in paragraph (i)(3) of this section.
    (ii) Calculate emissions from consumption of each fluorinated GHG 
used in tools vented to stack systems that meet the criteria specified 
in paragraphs (i)(2)(i) through (i)(2)(iii) of this section, and were 
not tested according to the procedures in paragraph (i)(3) of this 
section. Calculate emissions using the default utilization and by-
product formation rates and equations specified in paragraph (i)(4) of 
this section. If you are using a fluorinated GHG not listed in Tables I-
11, I-12, I-13, I-14, or I-15 of this subpart, then you must assume 
utilization and by-product formation rates of zero for that fluorinated 
GHG.
    (5) To determine the total emissions of each fluorinated GHG from 
each fab under this stack testing option, you must sum the emissions of 
each fluorinated GHG determined from the procedures in paragraph (i)(3) 
of this section with the emissions of the same fluorinated GHG 
determined from the procedures in paragraph (i)(4) of this section. Sum 
the total emissions of each fluorinated GHG from all fabs at your 
facility to determine the facility-

[[Page 677]]

level emissions of each fluorinated GHG.

[75 FR 74818, Dec. 1, 2010, as amended at 76 FR 59551, Sept. 27, 2011; 
77 FR 10380, Feb. 22, 2012; 78 FR 68202, Nov. 13, 2013; 79 FR 25682, May 
6, 2014; 79 FR 73783, Dec. 11, 2014; 79 FR 77391, Dec. 24, 2014]



Sec. 98.94  Monitoring and QA/QC requirements.

    (a) [Reserved]
    (b) For purposes of Equation I-12 of this subpart, you must estimate 
fab-wide gas-specific heel factors for each container type for each gas 
used, according to the procedures in paragraphs (b)(1) through (b)(5) of 
this section. This paragraph (b) does not apply to fluorinated GHGs or 
N2O that your fab uses in quantities of less than 50 kg in 
one reporting year and for which you calculate emissions as equal to 
consumption under Sec. 98.93(a)(1), (a)(2), or (b), or for any 
intermittent low-use fluorinated GHG for which you calculate emissions 
according to Sec. 98.93(i)(4)(i).
    (1) Base your fab-wide gas-specific heel factors on the trigger 
point for change out of a container for each container size and type for 
each gas used. Fab-wide gas-specific heel factors must be expressed as 
the ratio of the trigger point for change out, in terms of mass, to the 
initial mass in the container, as determined by paragraphs (b)(2) and 
(3) of this section.
    (2) The trigger points for change out you use to calculate fab-wide 
gas-specific heel factors in paragraph (b)(1) of this section must be 
determined by monitoring the mass or the pressure of your containers. If 
you monitor the pressure, convert the pressure to mass using the ideal 
gas law, as displayed in Equation I-25 of this subpart, with the 
appropriate Z value selected based upon the properties of the gas.
[GRAPHIC] [TIFF OMITTED] TR13NO13.014

Where:

p = Absolute pressure of the gas (Pa).
V = Volume of the gas container (m\3\).
Z = Compressibility factor.
n = Amount of substance of the gas (moles).
R = Gas constant (8.314 Joule/Kelvin mole).
T = Absolute temperature (K).

    (3) The initial mass you use to calculate a fab-wide gas-specific 
heel factor in paragraph (b)(1) of this section may be based on the 
weight of the gas provided to you in gas supplier documents; however, 
you remain responsible for the accuracy of these masses and weights 
under this subpart.
    (4) If a container is changed in an exceptional circumstance, as 
specified in paragraphs (b)(4)(i) and (ii) of this section, you must 
weigh that container or measure the pressure of that container with a 
pressure gauge, in place of using a heel factor to determine the 
residual weight of gas. When using mass-based trigger points for change 
out, you must determine if an exceptional circumstance has occurred 
based on the net weight of gas in the container, excluding the tare 
weight of the container.
    (i) For containers with a maximum storage capacity of less than 9.08 
kg (20 lbs) of gas, an exceptional circumstance is a change out point 
that differs by more than 50 percent from the trigger point for change 
out used to calculate your fab-wide gas-specific heel factor for that 
gas and container type.
    (ii) For all other containers, an exceptional circumstance is a 
change out point that differs by more than 20 percent from the trigger 
point for change out used to calculate your fab-wide gas-specific heel 
factor for that gas and container type.
    (5) You must re-calculate a fab-wide gas-specific heel factor if you 
execute a process change to modify the trigger point for change out for 
a gas and container type that differs by more than 5 percent from the 
previously used trigger point for change out for that gas and container 
type.
    (c) You must develop apportioning factors for fluorinated GHG and 
N2O consumption (including the fraction of gas consumed by 
process tools connected to abatement systems as in

[[Page 678]]

Equations I-8, I-9, I-10, I-19, I-20, I-21, and I-22 of this subpart), 
to use in the equations of this subpart for each input gas i, process 
sub-type, process type, stack system, and fab as appropriate, using a 
fab-specific engineering model that is documented in your site GHG 
Monitoring Plan as required under Sec. 98.3(g)(5). This model must be 
based on a quantifiable metric, such as wafer passes or wafer starts, or 
direct measurement of input gas consumption as specified in paragraph 
(c)(3) of this section. To verify your model, you must demonstrate its 
precision and accuracy by adhering to the requirements in paragraphs 
(c)(1) and (2) of this section.
    (1) You must demonstrate that the fluorinated GHG and N2O 
apportioning factors are developed using calculations that are 
repeatable, as defined in Sec. 98.98.
    (2) You must demonstrate the accuracy of your fab-specific model by 
comparing the actual amount of input gas i consumed and the modeled 
amount of input gas i consumed in the fab, as follows:
    (i) You must analyze actual and modeled gas consumption for a period 
when the fab is at a representative operating level (as defined in Sec. 
98.98) lasting at least 30 days but no more than the reporting year.
    (ii) You must compare the actual gas consumed to the modeled gas 
consumed for one fluorinated GHG reported under this subpart for the 
fab. You must certify that the fluorinated GHG selected for comparison 
corresponds to the largest quantity, on a mass basis, of fluorinated GHG 
consumed at the fab during the reporting year for which you are required 
to apportion following the procedures specified in Sec. 98.93(a), (b), 
or (i). You may compare the actual gas consumed to the modeled gas 
consumed for two fluorinated GHGs and demonstrate conformance according 
to paragraph (c)(2)(iii) of this section on an aggregate use basis for 
both fluorinated GHGs if one of the fluorinated GHGs selected for 
comparison corresponds to the largest quantity, on a mass basis, of 
fluorinated GHGs used at each fab that requires apportionment during the 
reporting year.
    (iii) You must demonstrate that the comparison performed for the 
largest quantity of gas(es), on a mass basis, consumed in the fab in 
paragraph (c)(2)(ii) of this section, does not result in a difference 
between the actual and modeled gas consumption that exceeds 20 percent 
relative to actual gas consumption, reported to two significant figures 
using standard rounding conventions.
    (iv) If you are required to apportion gas consumption and you use 
the procedures in Sec. 98.93(i) to calculate annual emissions from a 
fab, you must verify your apportioning factors using the procedures in 
paragraphs (c)(2)(ii) and (iii) of this section such that the time 
period specified in paragraph (c)(2)(i) of this section and the last day 
you perform the sampling events specified under Sec. 98.93(i)(3) occur 
in the same accounting month.
    (v) If your facility has multiple fabs with a single centralized 
fluorinated-GHG supply system, you must verify that your apportioning 
model can apportion fluorinated GHG consumption among the fabs by 
adhering to the procedures in paragraphs (c)(2)(ii) through (c)(2)(iv) 
of this section.
    (3) As an alternative to developing apportioning factors for 
fluorinated GHG and N2O consumption using a fab-specific 
engineering model, you may develop apportioning factors through the use 
of direct measurement using gas flow meters and weigh scales to measure 
process sub-type, process type, stack system, or fab-specific input gas 
consumption. You may use a combination of apportioning factors developed 
using a fab-specific engineering model and apportioning factors 
developed through the use of direct measurement, provided this is 
documented in your site GHG Monitoring Plan as required under 
98.3(g)(5).
    (d)-(e) [Reserved]
    (f) If your fab employs abatement systems and you elect to reflect 
emission reductions due to these systems, or if your fab employs 
abatement systems designed for fluorinated GHG abatement and you elect 
to calculate fluorinated GHG emissions using the stack test method under 
98.93(i), you must comply with the requirements of paragraphs (f)(1) 
through (f)(3) of this

[[Page 679]]

section. If you use an average of properly measured destruction or 
removal efficiencies for a gas and process sub-type or process type 
combination, as applicable, in your emission calculations under Sec. 
98.93(a), (b), and/or (i), you must also adhere to procedures in 
paragraph (f)(4) of this section.
    (1) You must certify and document that the abatement systems are 
properly installed, operated, and maintained according to the site 
maintenance plan for abatement systems that is developed and maintained 
in your records as specified in Sec. 98.97(d)(9).
    (2) You must calculate and document the uptime of abatement systems 
using Equation I-15 or I-23 of this subpart, as applicable.
    (3) If you use default destruction and removal efficiency values in 
your emissions calculations under Sec. 98.93(a), (b), and/or (i), you 
must certify and document that the abatement systems at your facility 
for which you use default destruction or removal efficiency values are 
specifically designed for fluorinated GHG or N2O abatement, 
as applicable. If you elect to calculate fluorinated GHG emissions using 
the stack test method under Sec. 98.93(i), you must also certify that 
you have included and accounted for all abatement systems designed for 
fluorinated GHG abatement and any respective downtime in your emissions 
calculations under Sec. 98.93(i)(3).
    (4) If you do not use the default destruction or removal efficiency 
values in Table I-16 of this subpart to calculate and report controlled 
emissions, including situations in which your fab employs abatement 
systems not specifically designed for fluorinated GHG or N2O 
abatement and you elect to reflect emission reduction due to these 
systems, you must use an average of properly measured destruction or 
removal efficiencies for each gas and process sub-type or process type 
combination, as applicable, determined in accordance with procedures in 
paragraphs (f)(4)(i) through (vi) of this section. You must not use a 
default value from Table I-16 of this subpart for any abatement system 
not specifically designed for fluorinated GHG and N2O 
abatement, or for any gas and process type combination for which you 
have measured the destruction or removal efficiency according to the 
requirements of paragraphs (f)(4)(i) through (vi) of this section.
    (i) A properly measured destruction or removal efficiency value must 
be determined in accordance with EPA 430-R-10-003 (incorporated by 
reference, see Sec. 98.7), or according to an alternative method 
approved by the Administrator (or authorized representative) as 
specified in paragraph (k) of this section. If you are measuring 
destruction or removal efficiency according to EPA 430-R-10-003 
(incorporated by reference, see Sec. 98.7), you may follow the 
alternative procedures specified in Appendix A to this subpart.
    (ii) You must select and properly measure the destruction or removal 
efficiency for a random sample of abatement systems to include in a 
random sampling abatement system testing program in accordance with 
procedures in paragraphs (f)(4)(ii)(A) and (B) of this section.
    (A) For the first 2 years for which your fab is required to report 
emissions of fluorinated GHG and N2O, for each abatement 
system gas and process sub-type or process type combination, as 
applicable, a random sample of a minimum of 10 percent of installed 
abatement systems must be tested annually for a total of a minimum of 20 
percent, or a minimum of 20 percent may be tested in the first year. For 
every 3-year period following the initial 2-year period, a random sample 
of at least 15 percent of installed abatement systems must be tested for 
each gas and process sub-type or process type combination; you may test 
15-percent in the first year of the 3-year period, but you must test at 
least 5 percent each year until 15 percent are tested. For each 3-year 
period, you must determine the number of abatement systems to be tested 
based on the average number of abatement systems in service over the 3-
year period. If the required percent of the total number of abatement 
systems to be tested for each gas and process sub-type or process type 
combination does not equate to a whole number, the number of systems to 
be tested must be determined by rounding up to the nearest integer. 
Except as provided in paragraph (f)(4)(v) of this section, you may

[[Page 680]]

not retest an abatement system for any gas and process sub-type or 
process type combination, as applicable, until all of the abatement 
systems for that gas and process sub-type or process type combination 
have been tested.
    (B) If testing of a randomly selected abatement system would be 
disruptive to production, you may replace that system with another 
randomly selected system for testing and return the system to the 
sampling pool for subsequent testing. Any one abatement system must not 
be replaced by another randomly selected system for more than three 
consecutive selections. When you have to replace a system in one year, 
you may select that specific system to be tested in one of the next two 
sampling years so that you may plan testing of that abatement system to 
avoid disrupting production.
    (iii) If you elect to take credit for abatement system destruction 
or removal efficiency before completing testing on 20 percent of the 
abatement systems for that gas and process sub-type or process type 
combination, as applicable, you must use default destruction or removal 
efficiencies for a gas and process type combination. You must not use a 
default value from Table I-16 of this subpart for any abatement system 
not specifically designed for fluorinated GHG and N2O 
abatement, and must not take credit for abatement system destruction or 
removal efficiency before completing testing on 20 percent of the 
abatement systems for that gas and process sub-type or process type 
combination, as applicable. Following testing on 20 percent of abatement 
systems for that gas and process sub-type or process type combination, 
you must calculate the average destruction or removal efficiency as the 
arithmetic mean of all test results for that gas and process sub-type or 
process type combination, until you have tested at least 30 percent of 
all abatement systems for each gas and process sub-type or process type 
combination. After testing at least 30 percent of all systems for a gas 
and process sub-type or process type combination, you must use the 
arithmetic mean of the most recent 30 percent of systems tested as the 
average destruction or removal efficiency. You may include results of 
testing conducted on or after January 1, 2011 for use in determining the 
site-specific destruction or removal efficiency for a given gas and 
process sub-type or process type combination if the testing was 
conducted in accordance with the requirements of paragraph (f)(4)(i) of 
this section.
    (iv) If a measured destruction or removal efficiency is below the 
manufacturer-claimed fluorinated GHG or N2O destruction or 
removal efficiency for any abatement system specifically designed for 
fluorinated GHG or N2O abatement and the abatement system is 
installed, operated, and maintained in accordance with the site 
maintenance plan for abatement systems that is developed and maintained 
in your records as specified in Sec. 98.97(d)(9), the measured 
destruction or removal efficiency must be included in the calculation of 
the destruction or removal efficiency value for that gas and process 
sub-type or process type.
    (v) If a measured destruction or removal efficiency is below the 
manufacturer-claimed fluorinated GHG or N2O destruction or 
removal efficiency for any abatement system specifically designed for 
fluorinated GHG or N2O abatement and the abatement system is 
not installed, operated, or maintained in accordance with the site 
maintenance plan for abatement systems that is developed and maintained 
in your records as specified in Sec. 98.97(d)(9), you must implement 
corrective action and perform a retest to replace the measured value 
within the reporting year. In lieu of retesting within the reporting 
year, you may use the measured value in calculating the average 
destruction or removal efficiency for the reporting year, implement 
corrective action, and then include the same system in the next 
abatement system testing period in addition to the testing of randomly 
selected systems for that next testing period. Regardless of whether you 
use the lower measured destruction or removal efficiency and when you 
perform the retest of the abatement system, you must count the time that 
the abatement system is not operated and maintained according to the 
site maintenance plan for abatement systems as

[[Page 681]]

not being in operational mode for purposes of calculating abatement 
system uptime.
    (vi) If your fab uses redundant abatement systems, you may account 
for the total abatement system uptime (that is, the time that at least 
one abatement system is in operational mode) calculated for a specific 
exhaust stream during the reporting year.
    (g) You must adhere to the QA/QC procedures of this paragraph when 
calculating fluorinated GHG and N2O emissions from 
electronics manufacturing production processes:
    (1)-(2) [Reserved]
    (3) Follow the QA/QC procedures in accordance with those in EPA 430-
R-10-003 (incorporated by reference, see Sec. 98.7), or the applicable 
QA/QC procedures specified in an alternative method approved by the 
Administrator (or authorized representative) according to paragraph (k) 
of this section, when calculating abatement systems destruction or 
removal efficiencies. If you are measuring destruction or removal 
efficiency according to EPA 430-R-10-003 (incorporated by reference, see 
Sec. 98.7), and you elect to follow the alternative procedures 
specified in Appendix A to this subpart according to paragraph (f)(4)(i) 
of this section, you must follow any additional QA/QC procedures 
specified in Appendix A to this subpart.
    (4) As part of normal operations for each fab, the inventory of gas 
stored in containers at the beginning of the reporting year must be the 
same as the inventory of gas stored in containers at the end of the 
previous reporting year. You must maintain records documenting the year 
end and year beginning inventories under Sec. 98.97(a).
    (h) You must adhere to the QA/QC procedures of this paragraph (h) 
when calculating annual gas consumption for each fluorinated GHG and 
N2O used at each fab and emissions from the use of each 
fluorinated heat transfer fluid on a fab basis.
    (1) Review all inputs to Equations I-11 and I-16 of this subpart to 
ensure that all inputs and outputs are accounted for.
    (2) Do not enter negative inputs into the mass balance Equations I-
11 and I-16 of this subpart and ensure that no negative emissions are 
calculated.
    (3) Ensure that the inventory at the beginning of one reporting year 
is identical to the inventory at the end of the previous reporting year. 
You must maintain records documenting the year end and year beginning 
inventories under Sec. 98.97(a) and (r).
    (4) Ensure that the total quantity of gas i in containers in service 
at the end of a reporting year is accounted for as if the in-service 
containers were full for Equation I-11 of this subpart. Ensure also that 
the same quantity is accounted for in the inventory of input gas i 
stored in containers at the beginning of the subsequent reporting year.
    (i) All flow meters, weigh scales, pressure gauges, and thermometers 
used to measure quantities that are monitored under this section or used 
in calculations under Sec. 98.93 must meet the calibration and accuracy 
requirements specified in Sec. 98.3(i).
    (j) Stack test methodology. For each fab for which you calculate 
annual emissions for any fluorinated GHG emitted from your facility 
using the stack test method according to the procedure specified in 
Sec. 98.93(i)(3), you must adhere to the requirements in paragraphs 
(j)(1) through (8) of this section. You may request approval to use an 
alternative stack test method and procedure according to paragraph (k) 
of this section.
    (1) Stack system testing. Conduct an emissions test for each 
applicable stack system according to the procedures in paragraphs 
(j)(1)(i) through (iv) of this section.
    (i) You must conduct an emission test during which the fab is 
operating at a representative operating level, as defined in Sec. 
98.98, and with the abatement systems connected to the stack system 
being tested operating with at least 90 percent uptime, averaged over 
all abatement systems, during the 8-hour (or longer) period for each 
stack system, or at no less than 90 percent of the abatement system 
uptime rate measured over the previous reporting year, averaged over all 
abatement systems.
    (ii) You must measure for the expected and possible by-products 
identified in Table I-17 of this subpart and those fluorinated GHGs used 
as input

[[Page 682]]

fluorinated GHG in process tools vented to the stack system, except for 
any intermittent low-use fluorinated GHG as defined in Sec. 98.98. You 
must calculate annual emissions of intermittent low-use fluorinated GHGs 
by adhering to the procedures in Sec. 98.93(i)(4)(i).
    (iii) If a fluorinated GHG being consumed in the reporting year was 
not being consumed during the stack testing and does not meet the 
definition of intermittent low-use fluorinated GHG in Sec. 98.98, then 
you must test the stack systems associated with the use of that 
fluorinated GHG at a time when that gas is in use at a magnitude that 
would allow you to determine an emission factor for that gas. If a 
fluorinated GHG consumed in the reporting year was not being consumed 
during the stack testing and is no longer in use by your fab (e.g., use 
of the gas has become obsolete or has been discontinued), then you must 
calculate annual emissions for that fluorinated GHG according to the 
procedure specified in Sec. 98.93(i)(4).
    (iv) Although all applicable stack systems are not required to be 
tested simultaneously, you must certify that no significant changes in 
stack flow configuration occur between tests conducted for any 
particular fab in a reporting year. You must certify that no more than 
10 percent of the total number of fluorinated GHG emitting process tools 
are connected or disconnected from a stack system during testing. You 
must also certify that no process tools that were in operation at the 
start of the test period have been moved to a different stack system 
during the test period (i.e., during or in between testing of individual 
stack systems) and that no point-of-use abatement systems have been 
permanently removed from service during the test period. You must 
document any changes in stack flow configuration in the emissions test 
data and report required to be kept as records under Sec. 98.97(i)(4).
    (2) Test methods and procedures. You must adhere to the applicable 
test methods and procedures specified in Table I-9 to this subpart, or 
adhere to an alternative method approved by the Administrator (or 
authorized representative) according to paragraph (k) of this section. 
If you select Method 320 of 40 CFR part 63, Appendix A to measure the 
concentration of each fluorinated GHG in the stack system, you must 
complete a method validation according to Section 13 of Method 320 of 40 
CFR part 63, Appendix A for each FTIR system (hardware and software) and 
each tester (testing company). Method 320 validation is necessary when 
any change occurs in instrumentation, tester (i.e., testing company), or 
stack condition (e.g., acid gas vs. base). Measurement of new compounds 
require validation for those compounds according to Section 13 of Method 
320 of 40 CFR part 63, Appendix A. The field detection limits achieved 
under your test methods and procedures must fall at or below the maximum 
field detection limits specified in Table I-10 to this subpart.
    (3) Fab-specific fluorinated GHG consumption measurements. You must 
determine the amount of each fluorinated GHG consumed by each fab during 
the sampling period for all process tools connected to the stack systems 
tested under Sec. 98.93(i)(3), according to the procedures in 
paragraphs (j)(3)(i) and (ii) of this section. This determination must 
include apportioning gas consumption between stack systems that are 
being tested and those that are not tested under Sec. 98.93(i)(2).
    (i) Measure fluorinated GHG consumption using gas flow meters, 
scales, or pressure measurements. Measure the mass or pressure, as 
applicable, at the beginning and end of the sampling period and when 
containers are changed out. If you elect to measure gas consumption 
using pressure (i.e., because the gas is stored in a location above its 
critical temperature) you must estimate consumption as specified in 
paragraphs (j)(3)(i)(A) and (B) of this section.
    (A) For each fluorinated GHG, you must either measure the 
temperature of the fluorinated GHG container(s) when the sampling 
periods begin and end and when containers are changed out, or measure 
the temperature of the fluorinated GHG container(s) every hour for the 
duration of the sampling period. Temperature measurements of the 
immediate vicinity of the containers (e.g., in the same room, near

[[Page 683]]

the containers) shall be considered temperature measurements of the 
containers.
    (B) Convert the sampling period-beginning, sampling period-ending, 
and container change-out pressures to masses using Equation I-25 of this 
subpart, with the appropriate Z value selected based upon the properties 
of the gas (e.g., the Z value yielded by the Redlich, Kwong, Soave 
equation of state with appropriate values for that gas). Apply the 
temperatures measured at or nearest to the beginning and end of the 
sampling period and to the time(s) when containers are changed out, as 
applicable. For each gas, the consumption during the sampling period is 
the difference between the masses of the containers of that gas at the 
beginning and at the end of the sampling period, summed across 
containers, including containers that are changed out.
    (ii) For each fluorinated GHG gas for which consumption is too low 
to be accurately measured during the sampling period using gas flow 
meters, scales, or pressure measurements as specified in paragraph 
(j)(3)(i) of this section, you must follow at least one of the 
procedures listed in paragraph (j)(3)(ii)(A) through (C) of this section 
to obtain a consumption measurement.
    (A) Draw the gas from a single gas container if it is normally 
supplied from multiple containers connected by a shared manifold.
    (B) Calculate consumption from pro-rated long-term consumption data 
(for example, calculate and use hourly consumption rates from monthly 
consumption data).
    (C) Increase the duration of the sampling period for consumption 
measurement beyond the minimum duration specified in Table I-9 of this 
subpart.
    (4) Emission test results. The results of an emission test must 
include the analysis of samples, number of test runs, the average 
emission factor for each fluorinated GHG measured, the analytical method 
used, calculation of emissions, the fluorinated GHGs consumed during the 
sampling period, an identification of the stack systems tested, and the 
fluorinated GHGs that were included in the test. The emissions test 
report must contain all information and data used to derive the fab-
specific emission factor.
    (5) Emissions testing frequency. You must conduct emissions testing 
to develop fab-specific emission factors on a frequency according to the 
procedures in paragraph (j)(5)(i) or (ii) of this section.
    (i) Annual testing. You must conduct an annual emissions test for 
each stack system for which emissions testing is required under Sec. 
98.93(i)(3), unless you meet the criteria in paragraph (j)(5)(ii) of 
this section to skip annual testing. Each set of emissions testing for a 
stack system must be separated by a period of at least 2 months.
    (ii) Criteria to test less frequently. After the first 3 years of 
annual testing, you may calculate the relative standard deviation of the 
emission factors for each fluorinated GHG included in the test and use 
that analysis to determine the frequency of any future testing. As an 
alternative, you may conduct all three tests in less than 3 calendar 
years for purposes of this paragraph (j)(5)(ii), but this does not 
relieve you of the obligation to conduct subsequent annual testing if 
you do not meet the criteria to test less frequently. If the criteria 
specified in paragraphs (j)(5)(ii)(A) and (B) of this section are met, 
you may use the arithmetic average of the three emission factors for 
each fluorinated GHG and fluorinated GHG by-product for the current year 
and the next 4 years with no further testing unless your fab operations 
are changed in way that triggers the re-test criteria in paragraph 
(j)(8) of this section. In the fifth year following the last stack test 
included in the previous average, you must test each of the stack 
systems for which testing is required and repeat the relative standard 
deviation analysis using the results of the most recent three tests 
(i.e., the new test and the two previous tests conducted prior to the 4 
year period). If the criteria specified in paragraphs (j)(5)(ii)(A) and 
(B) of this section are not met, you must use the emission factors 
developed from the most recent testing and continue annual testing. You 
may conduct more than one test in the same year, but each set of 
emissions testing for a stack system must be separated by a period of at 
least 2 months. You

[[Page 684]]

may repeat the relative standard deviation analysis using the most 
recent three tests, including those tests conducted prior to the 4 year 
period, to determine if you are exempt from testing for the next 4 
years.
    (A) The relative standard deviation of the total CO2e 
emission factors calculated from each of the three tests (expressed as 
the total CO2e fluorinated GHG emissions of the fab divided 
by the total CO2e fluorinated GHG use of the fab) is less 
than or equal to 15 percent.
    (B) The relative standard deviation for all single fluorinated GHGs 
that individually accounted for 5 percent or more of CO2e 
emissions were less than 20 percent.
    (6) Subsequent measurements. You must make an annual determination 
of each stack system's exemption status under Sec. 98.93(i)(2) by March 
31 each year. If a stack system that was previously not required to be 
tested per Sec. 98.93(i)(2), no longer meets the criteria in Sec. 
98.93(i)(2), you must conduct the emissions testing for the stack system 
during the current reporting and develop the fab-specific emission 
factor from the emissions testing.
    (7) Previous measurements. You may include the results of emissions 
testing conducted on or after January 1, 2011 for use in the relative 
standard deviation calculation in paragraph (j)(5)(ii) of this section 
if the previous results were determined using a method meeting the 
requirements in paragraph (j)(2) of this section. You may request 
approval to use results of emissions testing conducted between January 
1, 2011 and January 1, 2014 using a method that deviated from the 
requirements in paragraph (j)(2) of this section by adhering to the 
requirements in paragraphs (j)(7)(i) through (j)(7)(iv) of this section.
    (i) Notify the Administrator (or an authorized representative) of 
your intention to use the results of the previous emissions testing. You 
must include in the notification the data and results you intend to use 
for meeting either reporting or recordkeeping requirements, a 
description of the method, and any deviations from the requirements in 
paragraph (j)(2) of this section. Your description must include an 
explanation of how any deviations do not affect the quality of the data 
collected.
    (ii) The Administrator will review the information submitted under 
paragraph (j)(7)(i) and determine whether the results of the previous 
emissions testing are adequate and issue an approval or disapproval of 
the use of the results within 120 days of the date on which you submit 
the notification specified in paragraph (j)(7)(i) of this section.
    (iii) If the Administrator finds reasonable grounds to disapprove 
the results of the previous emissions testing, the Administrator may 
request that you provide additional information to support the use of 
the results of the previous emissions testing. Failure to respond to any 
request made by the Administrator does not affect the 120 day deadline 
specified in paragraph (j)(7)(ii) of this section.
    (iv) Neither the approval process nor the failure to obtain approval 
for the use of results from previous emissions testing shall abrogate 
your responsibility to comply with the requirements of this subpart.
    (8) Scenarios that require a stack system to be re-tested. By March 
31 of each reporting year, you must evaluate and determine whether any 
changes to your fab operations meet the criteria specified in paragraphs 
(j)(8)(i) through (vi) of this section. If any of the scenarios 
specified in paragraph (j)(8)(i) through (vi) of this section occur, you 
must perform a re-test of any applicable stack system, irrespective of 
whether you have met the criteria for less frequent testing in paragraph 
(j)(5)(ii) of this section, before the end of the year in which the 
evaluation was completed. You must adhere to the methods and procedures 
specified in Sec. 98.93(i)(3) for performing a stack system emissions 
test and calculating emissions. If you meet the criteria for less 
frequent testing in paragraph (j)(5)(ii), and you are required to 
perform a re-test as specified in paragraph (j)(8)(i) through (vi) of 
this section, the requirement to perform a re-test does not extend the 
date of the next scheduled test that was established prior to meeting 
the requirement to perform a

[[Page 685]]

re-test. If the criteria specified in paragraph (j)(5)(ii) of this 
section are not met using the results from the re-test and the two most 
recent stack tests, you must use the emission factors developed from the 
most recent testing to calculate emissions and resume annual testing. 
You may resume testing less frequently according to your original 
schedule if the criteria specified in paragraph (j)(5)(ii) of this 
section are met using the most recent three tests.
    (i) Annual consumption of a fluorinated GHG used during the most 
recent emissions test (expressed in CO2e) changes by more 
than 10 percent of the total annual fluorinated GHG consumption, 
relative to gas consumption in CO2e for that gas during the 
year of the most recent emissions test (for example, if the use of a 
single gas goes from 25 percent of CO2e to greater than 35 
percent of CO2e, this change would trigger a re-test).
    (ii) A change in the consumption of an intermittent low-use 
fluorinated GHG (as defined in Sec. 98.98) that was not used during the 
emissions test and not reflected in the fab-specific emission factor, 
such that it no longer meets the definition of an intermittent low-use 
fluorinated GHG.
    (iii) A decrease by more than 10 percent in the fraction of tools 
with abatement systems, compared to the number during the most recent 
emissions test.
    (iv) A change in the wafer size manufactured by the fab since the 
most recent emissions test.
    (v) A stack system that formerly met the criteria specified under 
Sec. 98.93(i)(2) for not being subject to testing no longer meets those 
criteria.
    (vi) If a fluorinated GHG being consumed in the reporting year was 
not being consumed during the stack test and does not meet the 
definition of intermittent, low-use fluorinated GHG in Sec. 98.98, then 
you must test the stack systems associated with the use of that 
fluorinated GHG at a time when that gas is in use as required in 
paragraph (j)(1)(iii) of this section.
    (k) You may request approval to use an alternative stack test method 
and procedure or to use an alternative method to determine abatement 
system destruction or removal efficiency by adhering to the requirements 
in paragraphs (k)(1) through (6) of this section. An alternative method 
is any method of sampling and analyzing for a fluorinated GHG or 
N2O, or the determination of parameters other than 
concentration, for example, flow measurements, that is not a method 
specified in this subpart and that has been demonstrated to the 
Administrator's satisfaction, using Method 301 in appendix A of part 63, 
to produce results adequate for the Administrator's determination that 
it may be used in place of a method specified elsewhere in this subpart.
    (1) You may use an alternative method from that specified in this 
subpart provided that you:
    (i) Notify the Administrator (or an authorized representative) of 
your intention to use an alternative method. You must include in the 
notification a site-specific test plan describing the alternative method 
and procedures (the alternative test plan), the range of test conditions 
over which the validation is intended to be applicable, and an 
alternative means of calculating the fab-level fluorinated GHG or 
N2O emissions or determining the abatement system destruction 
or removal efficiency if the Administrator denies the use of the results 
of the alternative method under paragraph (k)(2) or (3) of this section.
    (ii) Use Method 301 in appendix A of part 63 of this chapter to 
validate the alternative method. This may include the use of only 
portions of specific procedures of Method 301 if use of such procedures 
are sufficient to validate the alternative method; and
    (iii) Submit the results of the Method 301 validation process along 
with the notification of intention and the rationale for not using the 
specified method.
    (2) The Administrator will determine whether the validation of the 
proposed alternative method is adequate and issue an approval or 
disapproval of the alternative test plan within 120 days of the date on 
which you submit the notification and alternative test plan specified in 
paragraph (k)(1) of this section. If the Administrator approves the 
alternative test plan, you are authorized to use the alternative 
method(s) in

[[Page 686]]

place of the methods described in paragraph (f)(4)(i) of this section 
for measuring destruction or removal efficiency or paragraph (j) of this 
section for conducting the stack test, as applicable, taking into 
account the Administrator's comments on the alternative test plan. 
Notwithstanding the requirement in the preceding sentence, you may at 
any time prior to the Administrator's approval or disapproval proceed to 
conduct the stack test using the methods specified in paragraph (j) of 
this section or the destruction or removal efficiency determination 
specified in (f)(4)(i) of this section if you use a method specified in 
this subpart instead of the requested alternative. If an alternative 
test plan is not approved and you still want to use an alternative 
method, you must recommence the process to have an alternative test 
method approved starting with the notification of intent to use an 
alternative test method specified in paragraph (k)(1)(i) of this 
section.
    (3) You must report the results of stack testing or destruction or 
removal efficiency determination using the alternative method and 
procedure specified in the approved alternative test plan. You must 
include in your report for an alternative stack test method and for an 
alternative abatement system destruction or removal efficiency 
determination the information specified in paragraph (j)(4) of this 
section, including all methods, calculations and data used to determine 
the fluorinated GHG emission factor or the abatement system destruction 
or removal efficiency. The Administrator will review the results of the 
test using the alternative methods and procedure and then approve or 
deny the use of the results of the alternative test method and procedure 
no later than 120 days after they are submitted to EPA.
    (4) If the Administrator finds reasonable grounds to dispute the 
results obtained by an alternative method for the purposes of 
determining fluorinated GHG emissions or destruction or removal 
efficiency of an abatement system, the Administrator may require the use 
of another method specified in this subpart.
    (5) Once the Administrator has approved the use of the alternative 
method for the purposes of determining fluorinated GHG emissions for 
specific fluorinated GHGs and types of stack systems or abatement system 
destruction or removal efficiency, that method may be used at any other 
facility for the same fluorinated GHGs and types of stack systems, or 
fluorinated GHGs and abatement systems, if the approved conditions apply 
to that facility. In granting approval, the Administrator may limit the 
range of test conditions and emission characteristics for which that 
approval is granted and under which the alternative method may be used 
without seeking approval under paragraphs (k)(1) through (4) of this 
section. The Administrator will specify those limitations, if any, in 
the approval of the alternative method.
    (6) Neither the validation and approval process nor the failure to 
validate or obtain approval of an alternative method shall abrogate your 
responsibility to comply with the requirements of this subpart.

[75 FR 74818, Dec. 1, 2010, as amended at 76 FR 36342, June 22, 2011; 76 
FR 59551, Sept. 27, 2011; 77 FR 10380, Feb. 22, 2012; 77 FR 48089, Aug. 
13, 2012; 78 FR 68209, Nov. 13, 2013; 79 FR 73785, Dec. 11, 2014]



Sec. 98.95  Procedures for estimating missing data.

    (a) Except as provided in paragraph (b) of this section, a complete 
record of all measured parameters used in the fluorinated GHG and 
N2O emissions calculations in Sec. 98.93 and Sec. 98.94 is 
required.
    (b) If you use fluorinated heat transfer fluids at your facility and 
are missing data for one or more of the parameters in Equation I-16 of 
this subpart, you must estimate fluorinated heat transfer fluid 
emissions using the arithmetic average of the emission rates for the 
reporting year immediately preceding the period of missing data and the 
months immediately following the period of missing data. Alternatively, 
you may estimate missing information using records from the fluorinated 
heat transfer fluid supplier. You must document the method used and 
values used for all missing data values.

[75 FR 74818, Dec. 1, 2010, as amended at 77 FR 10381, Feb. 22, 2012]

[[Page 687]]



Sec. 98.96  Data reporting requirements.

    In addition to the information required by Sec. 98.3(c), you must 
include in each annual report the following information for each 
electronics manufacturing facility:
    (a) Annual manufacturing capacity of each fab at your facility used 
to determine the annual manufacturing capacity of your facility in 
Equation I-5 of this subpart.
    (b) For facilities that manufacture semiconductors, the diameter of 
wafers manufactured at each fab at your facility (mm).
    (c) Annual emissions, on a fab basis as described in paragraph 
(c)(1) through (5) of this section.
    (1) When you use the procedures specified in Sec. 98.93(a) of this 
subpart, each fluorinated GHG emitted from each process type for which 
your fab is required to calculate emissions as calculated in Equations 
I-6 and I-7 of this subpart.
    (2) Each fluorinated GHG emitted from each process type or process 
sub-type as calculated in Equations I-8 and I-9 of this subpart, as 
applicable.
    (3) N2O emitted from all chemical vapor deposition 
processes and N2O emitted from the aggregate of other 
N2O-using manufacturing processes as calculated in Equation 
I-10 of this subpart.
    (4) Each fluorinated heat transfer fluid emitted as calculated in 
Equation 1-16 of this subpart.
    (5) When you use the procedures specified in Sec. 98.93(i) of this 
subpart, annual emissions of each fluorinated GHG, on a fab basis.
    (d) The method of emissions calculation used in Sec. 98.93.
    (e) Annual production in terms of substrate surface area (e.g., 
silicon, PV-cell, glass).
    (f)-(l) [Reserved]
    (m) For the fab-specific apportioning model used to apportion 
fluorinated GHG and N2O consumption under Sec. 98.94(c), the 
following information to determine it is verified in accordance with 
procedures in Sec. 98.94(c)(1) and (2):
    (1) Identification of the quantifiable metric used in your fab-
specific engineering model to apportion gas consumption for each fab, 
and/or an indication if direct measurements were used in addition to, or 
instead of, a quantifiable metric.
    (2) The start and end dates selected under Sec. 98.94(c)(2)(i).
    (3) Certification that the gas(es) you selected under Sec. 
98.94(c)(2)(ii) for each fab corresponds to the largest quantity(ies) 
consumed, on a mass basis, of fluorinated GHG used at your fab during 
the reporting year for which you are required to apportion.
    (4) The result of the calculation comparing the actual and modeled 
gas consumption under Sec. 98.94(c)(2)(iii) and (iv), as applicable.
    (5) If you are required to apportion fluorinated GHG consumption 
between fabs as required by Sec. 98.94(c)(2)(v), certification that the 
gas(es) you selected under Sec. 98.94(c)(2)(ii) corresponds to the 
largest quantity(ies) consumed on a mass basis, of fluorinated GHG used 
at your facility during the reporting year for which you are required to 
apportion.
    (n)-(o) [Reserved]
    (p) Inventory and description of all abatement systems through which 
fluorinated GHGs or N2O flow at your facility and for which 
you are claiming destruction or removal efficiency, including:
    (1) The number of abatement systems controlling emissions for each 
process sub-type, or process type, as applicable, for each gas used in 
the process sub-type or process type.
    (2) The basis of the destruction or removal efficiency being used 
(default or site specific measurement according to Sec. 98.94(f)(4)(i)) 
for each process sub-type or process type and for each gas.
    (q) For all abatement systems through which fluorinated GHGs or 
N2O flow at your facility, for which you are reporting 
controlled emissions, the following:
    (1) Certification that all abatement systems at the facility have 
been installed, maintained, and operated in accordance with the site 
maintenance plan for abatement systems that is developed and maintained 
in your records as specified in Sec. 98.97(d)(9).
    (2) If you use default destruction or removal efficiency values in 
your emissions calculations under Sec. 98.93(a), (b), or (i), 
certification that the site maintenance plan for abatement systems for

[[Page 688]]

which emissions are being reported contains manufacturer's 
recommendations and specifications for installation, operation, and 
maintenance for each abatement system.
    (3) If you use default destruction or removal efficiency values in 
your emissions calculations under Sec. 98.93(a), (b), and/or (i), 
certification that the abatement systems for which emissions are being 
reported were specifically designed for fluorinated GHG or 
N2O abatement, as applicable. You must support this 
certification by providing abatement system supplier documentation 
stating that the system was designed for fluorinated GHG or 
N2O abatement, as applicable.
    (4) For all stack systems for which you calculate fluorinated GHG 
emissions according to the procedures specified in Sec. 98.93(i)(3), 
certification that you have included and accounted for all abatement 
systems and any respective downtime in your emissions calculations under 
Sec. 98.93(i)(3).
    (r) You must report an effective fab-wide destruction or removal 
efficiency value for each fab at your facility calculated using Equation 
I-26, I-27, and I-28 of this subpart, as appropriate.
[GRAPHIC] [TIFF OMITTED] TR13NO13.015

Where:

DREFAB = Fab-wide effective destruction or removal efficiency 
          value, expressed as a decimal fraction.
FGHGi = Total emissions of each fluorinated GHG i emitted 
          from electronics manufacturing processes in the fab, 
          calculated according to the procedures in Sec. 98.93.
N2Oj = Emissions of N2O from each 
          N2O-emitting electronics manufacturing process j in 
          the fab, expressed in metric ton CO2 equivalents, 
          calculated according to the procedures in Sec. 98.93.
UAFGHG = Total unabated emissions of fluorinated GHG emitted from 
          electronics manufacturing processes in the fab, expressed in 
          metric ton CO2 equivalents as calculated in 
          Equation I-27 of this subpart.
SFGHG = Total unabated emissions of fluorinated GHG emitted from 
          electronics manufacturing processes in the fab, expressed in 
          metric ton CO2 equivalents, as calculated in 
          Equation I-28 of this subpart.
CN2O,j = Consumption of N2O in each 
          N2O emitting process j, expressed in metric ton 
          CO2 equivalents.
1-UN2O,j = N2O emission factor for each 
          N2O emitting process j from Table I-8 of this 
          subpart.
GWPi = GWP of emitted fluorinated GHG i from Table A-1 of 
          this part.
GWPN2O = GWP of N2O from Table A-1 of 
          this part.
i = Fluorinated GHG.
j = Process Type.

    (1) Use Equation I-27 of this subpart to calculate total unabated 
emissions, in metric tons CO2e, of all fluorinated GHG 
emitted from electronics manufacturing processes whose emissions of 
fluorinated GHG you calculated according to the default utilization and 
by-product formation rate procedures in Sec. 98.93(a) or Sec. 
98.93(i)(4). For each fluorinated GHG i in process j, use the same 
consumption (Cij), emission factors (1-Uij), and 
by-product formation rates (Bijk) to calculate unabated 
emissions as you used to calculate emissions in Sec. 98.93(a) or Sec. 
98.93(i)(4).
[GRAPHIC] [TIFF OMITTED] TR13NO13.016


[[Page 689]]


Where:

UAFGHG = Total unabated emissions of fluorinated GHG emitted from 
          electronics manufacturing processes in the fab, expressed in 
          metric ton CO2e for which you calculated total 
          emission according to the procedures in Sec. 98.93(a) or 
          Sec. 98.93(i)(4).
Cij = Total consumption of fluorinated GHG i, apportioned to 
          process j, expressed in metric ton CO2e, which you 
          used to calculate total emissions according to the procedures 
          in Sec. 98.93(a) or Sec. 98.93(i)(4).
Uij = Process utilization rate for fluorinated GHG i, process 
          type j, which you used to calculate total emissions according 
          to the procedures in Sec. 98.93(a) or Sec. 98.93(i)(4).
GWPi = GWP of emitted fluorinated GHG i from Table A-1 of 
          this part.
GWPk = GWP of emitted fluorinated GHG by-product k from Table 
          A-1 of this part.
Bijk = By-product formation rate of fluorinated GHG k created 
          as a by-product per amount of fluorinated GHG input gas i (kg) 
          consumed by process type j (kg).
i = Fluorinated GHG.
j = Process Type.
k = Fluorinated GHG by-product.

    (2) Use Equation I-28 to calculate total unabated emissions, in 
metric ton CO2e, of all fluorinated GHG emitted from 
electronics manufacturing processes whose emissions of fluorinated GHG 
you calculated according to the stack testing procedures in Sec. 
98.93(i)(3). For each set of processes, use the same input gas 
consumption (Cif), input gas emission factors 
(EFif), by-product gas emission factors (EFkf), 
fractions of tools abated (aif and af), and 
destruction efficiencies (dif and dkf) to 
calculate unabated emissions as you used to calculate emissions.
[GRAPHIC] [TIFF OMITTED] TR13NO13.017

Where:

SFGHG = Total unabated emissions of fluorinated GHG emitted from 
          electronics manufacturing processes in the fab, expressed in 
          metric ton CO2e for which you calculated total 
          emission according to the procedures in Sec. 98.93(i)(3).
EFif = Emission factor for fluorinated GHG input gas i, 
          emitted from fab f, as calculated in Equation I-19 of this 
          subpart (kg emitted/kg input gas consumed).
aif = Fraction of fluorinated GHG input gas i used in fab f 
          in tools with abatement systems (expressed as a decimal 
          fraction).
dif = Fraction of fluorinated GHG i destroyed or removed in 
          abatement systems connected to process tools in fab f, which 
          you used to calculate total emissions according to the 
          procedures in Sec. 98.93(i)(3) (expressed as a decimal 
          fraction).
Cif = Total consumption of fluorinated GHG input gas i, of 
          tools vented to stack systems that are tested, for fab f, for 
          the reporting year, expressed in metric ton CO2e, 
          which you used to calculate total emissions according to the 
          procedures in Sec. 98.93(i)(3) (expressed as a decimal 
          fraction).
EFkf = Emission factor for fluorinated GHG by-product gas k, 
          emitted from fab f, as calculated in Equation I-20 of this 
          subpart (kg emitted/kg of all input gases consumed in tools 
          vented to stack systems that are tested).
af = Fraction of input gases used in fab f in tools with 
          abatement systems (expressed as a decimal fraction).
dkf = Fraction of fluorinated GHG by-product k destroyed or 
          removed in abatement systems connected to process tools in fab 
          f, which you used to calculate total emissions according to 
          the procedures in Sec. 98.93(i)(3) (expressed as a decimal 
          fraction).
GWPi = GWP of emitted fluorinated GHG i from Table A-1 of 
          this part.
GWPk = GWP of emitted fluorinated GHG by-product k from Table 
          A-1 of this part.
i = Fluorinated GHG.
k = Fluorinated GHG by-product.

    (s) Where missing data procedures were used to estimate inputs into 
the fluorinated heat transfer fluid mass balance equation under Sec. 
98.95(b), the number of times missing data procedures were followed in 
the reporting year and the method used to estimate the missing data.
    (t)-(v) [Reserved]
    (w) If you elect to calculate fab-level emissions of fluorinated GHG 
using the stack test methods specified in Sec. 98.93(i), you must 
report the following in paragraphs (w)(1) and (2) for each

[[Page 690]]

stack system, in addition to the relevant data in paragraphs (a) through 
(v) of this section:
    (1) The date of any stack testing conducted during the reporting 
year, and the identity of the stack system tested.
    (2) An inventory of all stack systems from which process fluorinated 
GHG are emitted. For each stack system, indicate whether the stack 
system is among those for which stack testing was performed as per Sec. 
98.93(i)(3) or not performed as per Sec. 98.93(i)(2).
    (x) If the emissions you report under paragraph (c) of this section 
include emissions from research and development activities, as defined 
in Sec. 98.6, report the approximate percentage of total GHG emissions, 
on a metric ton CO2e basis, that are attributable to research 
and development activities, using the following ranges: less than 5 
percent, 5 percent to less than 10 percent, 10 percent to less than 25 
percent, 25 percent to less than 50 percent, 50 percent and higher.
    (y) If your semiconductor manufacturing facility emits more than 
40,000 metric ton CO2e of GHG emissions, based on your most 
recently submitted annual report (beginning with the 2015 reporting 
year) as required in paragraph (c) of this section, from the electronics 
manufacturing processes subject to reporting under this subpart, you 
must prepare and submit a triennial (every 3 years) technology 
assessment report to the Administrator (or an authorized representative) 
that meets the requirements specified in paragraphs (y)(1) through (6) 
of this section. Any other semiconductor manufacturing facility may 
voluntarily submit this report to the Administrator.
    (1) The first report must be submitted with the annual GHG emissions 
report that is due no later than March 31, 2017, and subsequent reports 
must be delivered every 3 years no later than March 31 of the year in 
which it is due.
    (2) The report must include the information described in paragraphs 
(y)(2)(i) through (v) of this section.
    (i) It must describe how the gases and technologies used in 
semiconductor manufacturing using 200 mm and 300 mm wafers in the United 
States have changed in the past 3 years and whether any of the 
identified changes are likely to have affected the emissions 
characteristics of semiconductor manufacturing processes in such a way 
that the default utilization and by-product formation rates or default 
destruction or removal efficiency factors of this subpart may need to be 
updated.
    (ii) It must describe the effect on emissions of the implementation 
of new process technologies and/or finer line width processes in 200 mm 
and 300 mm technologies, the introduction of new tool platforms, and the 
introduction of new processes on previously tested platforms.
    (iii) It must describe the status of implementing 450 mm wafer 
technology and the potential need to create or update default emission 
factors compared to 300 mm technology.
    (iv) It must provide any utilization and by-product formation rates 
and/or destruction or removal efficiency data that have been collected 
in the previous 3 years that support the changes in semiconductor 
manufacturing processes described in the report.
    (v) It must describe the use of a new gas, use of an existing gas in 
a new process type or sub-type, or a fundamental change in process 
technology.
    (3) If, on the basis of the information reported in paragraph (y)(2) 
of this section, the report indicates that GHG emissions from 
semiconductor manufacturing may have changed from those represented by 
the default utilization and by-product formation rates in Tables I-3 or 
I-4, or the default destruction or removal efficiency values in Table I-
16 of this subpart, the report must lay out a data gathering and 
analysis plan focused on the areas of potential change. The plan must 
describe the elements in paragraphs (y)(3)(i) and (ii).
    (i) The testing of tools to determine the potential effect on 
current utilization and by-product formation rates and destruction or 
removal efficiency values under the new conditions.
    (ii) A planned analysis of the effect on overall facility emissions 
using a representative gas-use profile for a 200 mm, 300 mm, or 450 mm 
fab (depending on which technology is under consideration).

[[Page 691]]

    (4) Multiple semiconductor manufacturing facilities may submit a 
single consolidated 3-year report as long as the facility identifying 
information in Sec. 98.3(c)(1) and the certification statement in Sec. 
98.3(c)(9) is provided for each facility for which the consolidated 
report is submitted.
    (5) The Administrator will review the report received and determine 
whether it is necessary to update the default utilization rates and by-
product formation rates in Tables I-3, I-4, I-11, and I-12 of this 
subpart and default destruction or removal efficiency values in Table I-
16 of this subpart based on the following:
    (i) Whether the revised default utilization and by-product formation 
rates and destruction or removal efficiency values will result in a 
projected shift in emissions of 10 percent or greater.
    (ii) Whether new platforms, processes, or facilities that are not 
captured in current default utilization and by-product formation rates 
and destruction or removal efficiency values should be included in 
revised values.
    (iii) Whether new data are available that could expand the existing 
data set to include new gases, tools, or processes not included in the 
existing data set (i.e. gases, tools, or processes for which no data are 
currently available).
    (6) The Administrator will review the reports within 120 days and 
will notify you of a determination whether it is necessary to update any 
default utilization and by-product formation rates and/or destruction or 
removal efficiency values. If the Administrator determines it is 
necessary to update default utilization and by-product formation rates 
and/or destruction or removal efficiency values, you will then have 180 
days from the date you receive notice of the determination to execute 
the data collection and analysis plan described in the report and submit 
those data to the Administrator.

[75 FR 74818, Dec. 1, 2010, as amended at 77 FR 10381, Feb. 22, 2010; 78 
FR 68215, Nov. 13, 2013; 78 FR 71954, Nov. 29, 2013; 79 FR 73785, Dec. 
11, 2014]



Sec. 98.97  Records that must be retained.

    In addition to the information required by Sec. 98.3(g), you must 
retain the following records:
    (a) All data used and copies of calculations made as part of 
estimating gas consumption and emissions, including all spreadsheets.
    (b) [Reserved]
    (c) Documentation for the fab-specific engineering model used to 
apportion fluorinated GHG and N2O consumption. This 
documentation must be part of your site GHG Monitoring Plan as required 
under Sec. 98.3(g)(5). At a minimum, you must retain the following:
    (1) A clear, detailed description of the fab-specific model, 
including how it was developed; the quantifiable metric used in the 
model; all sources of information, equations, and formulas, each with 
clear definitions of terms and variables; all apportioning factors used 
to apportion fluorinated GHG and N2O; and a clear record of 
any changes made to the model while it was used to apportion fluorinated 
GHG and N2O consumption across process sub-types, process 
types, tools with and without abatement systems, stack systems, and/or 
fabs.
    (2) Sample calculations used for developing the gas apportioning 
factors (fij) for the two fluorinated GHGs used at your 
facility in the largest quantities, on a mass basis, during the 
reporting year.
    (3) If you develop apportioning factors through the use of direct 
measurement according to Sec. 98.94(c)(3), calculations and data used 
to develop each gas apportioning factor.
    (4) Calculations and data used to determine and document that the 
fab was operating at representative operating levels, as defined in 
Sec. 98.98, during the apportioning model verification specified in 
Sec. 98.94(c).
    (d) For all abatement systems through which fluorinated GHGs or 
N2O flow at your facility, and for which you are reporting 
controlled emissions, the following in paragraphs (d)(1) to (9) of this 
section:
    (1) Records of the information in paragraphs (d)(1)(i) though (iv) 
of this section:
    (i) Documentation to certify that each abatement system or group of 
abatement systems is installed, maintained, and operated in accordance 
with the site maintenance plan for

[[Page 692]]

abatement systems that is specified in paragraph (d)(9) of this section.
    (ii) Documentation from the abatement system supplier describing the 
abatement system's designed purpose and emission control capabilities 
for fluorinated GHG and N2O for which the systems or group of 
systems is certified to abate, where available.
    (iii) If you use default destruction or removal efficiency values in 
your emissions calculations under Sec. 98.93(a), (b), and/or (i), 
certification that the abatement systems for which emissions are being 
reported were specifically designed for fluorinated GHG and 
N2O abatement, as required under Sec. 98.94(f)(3), and 
certification that the site maintenance plan includes manufacturer's 
recommendations and specifications for installation, operation, and 
maintenance for all applicable abatement systems.
    (iv) Certification that you have included and accounted for all 
abatement systems and any respective downtime in your emissions 
calculations under Sec. 98.93(i)(3), as required under Sec. 
98.94(f)(3).
    (2) Abatement system calibration and maintenance records.
    (3) Where the default destruction or removal efficiency value is 
used, documentation from the abatement system supplier describing the 
equipment's designed purpose and emission control capabilities for 
fluorinated GHG and N2O.
    (4) Where properly measured site-specific destruction or removal 
efficiencies are used to report emissions, the information in paragraphs 
(d)(4)(i) though (vi) of this section:
    (i) Dated certification by the technician who made the measurement 
that the destruction or removal efficiency is calculated in accordance 
with methods in EPA 430-R-10-003 (incorporated by reference, see Sec. 
98.7) and, if applicable Appendix A of this subpart, or an alternative 
method approved by the Administrator as specified in Sec. 98.94(k), 
complete documentation of the results of any initial and subsequent 
tests, the final report as specified in EPA 430-R-10-003 (incorporated 
by reference, see Sec. 98.7) and, if applicable, the records and 
documentation specified in Appendix A of this subpart including the 
information required in paragraph (b)(7) of Appendix A of this subpart, 
or a final report as specified in an alternative method approved by the 
Administrator as specified in Sec. 98.94(k).
    (ii) The average destruction or removal efficiency of the abatement 
systems operating during the reporting year for each process type and 
gas combination.
    (iii) A description of the calculation used to determine the average 
destruction or removal efficiency for each process type and gas 
combination, including all inputs to the calculation.
    (iv) The records of destruction or removal efficiency measurements 
for abatement systems for all tests that have been used to determine the 
site-specific destruction or removal efficiencies currently being used.
    (v) A description of the method used for randomly selecting 
abatement systems for testing.
    (vi) The total number of systems for which destruction or removal 
efficiency was properly measured for each process type and gas 
combination for the reporting year.
    (5) In addition to the inventory specified in Sec. 98.96(p), the 
information in paragraphs (d)(5)(i) though (iii) of this section:
    (i) The number of abatement systems of each manufacturer, and model 
numbers, and the manufacturer's claimed fluorinated GHG and 
N2O destruction or removal efficiency, if any.
    (ii) Records of destruction or removal efficiency measurements over 
the in-use life of each abatement system.
    (iii) A description of the tool, with the process type or sub-type, 
for which the abatement system treats exhaust.
    (6) Records of all inputs and results of calculations made 
accounting for the uptime of abatement systems used during the reporting 
year, in accordance with Equations I-15 or I-23 of this subpart, as 
applicable. The inputs should include an indication of whether each 
value for destruction or removal efficiency is a default value or a 
measured site-specific value.
    (7) Records of all inputs and results of calculations made to 
determine the average weighted fraction of each gas destroyed or removed 
in the abatement systems for each stack system using

[[Page 693]]

Equation I-24 of this subpart, if applicable. The inputs should include 
an indication of whether each value for destruction or removal 
efficiency is a default value or a measured site-specific value.
    (8) Records of all inputs and the results of the calculation of the 
facility-wide emission destruction or removal efficiency factor 
calculated according to Equations I-26, I-27, and I-28 of this subpart.
    (9) A site maintenance plan for abatement systems, which must be 
maintained on-site at the facility as part of the facility's GHG 
Monitoring Plan as described in Sec. 98.3(g)(5), and be developed and 
implemented according to paragraphs (d)(9)(i) through (iii) of this 
section.
    (i) The site maintenance plan for abatement systems must be based on 
the abatement system manufacturer's recommendations and specifications 
for installation, operation, and maintenance if you use default 
destruction and removal efficiency values in your emissions calculations 
under Sec. 98.93(a), (b), and/or (i). If the manufacturer's 
recommendations and specifications for installation, operation, and 
maintenance are not available, you cannot use default destruction and 
removal efficiency values in your emissions calculations under Sec. 
98.93(a), (b), and/or (i). If you use an average of properly measured 
destruction or removal efficiencies determined in accordance with the 
procedures in Sec. 98.94(f)(4)(i) through (vi), the site maintenance 
plan for abatement systems must be based on the abatement system 
manufacturer's recommendations and specifications for installation, 
operation, and maintenance, where available. If you deviate from the 
manufacturer's recommendations and specifications, you must include 
documentation that demonstrates how the deviations do not negatively 
affect the performance or destruction or removal efficiency of the 
abatement systems.
    (ii) The site maintenance plan for abatement systems must include a 
defined preventative maintenance process and checklist.
    (iii) The site maintenance plan for abatement systems must include a 
corrective action process that you must follow whenever an abatement 
system is found to be not operating properly.
    (e) Purchase records for gas purchased.
    (f) Invoices for gas purchases and sales.
    (g) Documents and records used to monitor and calculate abatement 
system uptime.
    (h) GHG Monitoring Plans, as described in Sec. 98.3(g)(5), must be 
completed by April 1, 2011. You must update your GHG Monitoring Plan to 
comply with Sec. 98.94(c) consistent with the requirements in Sec. 
98.3(g)(5)(iii).
    (i) Retain the following records for each fab for which you elect to 
calculate fab-level emissions of fluorinated GHG using the procedures 
specified in Sec. 98.93(i)(3) or (4).
    (1) Document all stack systems with emissions of fluorinated GHG 
that are less than 10,000 metric tons of CO2e per year and 
all stack systems with emissions of 10,000 metric tons CO2e 
per year or more. Include the data and calculation used to develop the 
preliminary estimate of emissions for each stack system.
    (2) For each stack system, identify the method used to calculate 
annual emissions; either Sec. 98.93(i)(3) or (4).
    (3) The identity and total annual consumption of each gas identified 
as an intermittent low use fluorinated GHG as specified in Sec. 
98.93(i)(4)(i) and defined in Sec. 98.98.
    (4) The emissions test data and reports (see Sec. 98.94(j)(4)) and 
the calculations used to determine the fab-specific emission factor, 
including the actual fab-specific emission factor, the average hourly 
emission rate of each fluorinated GHG from the stack system during the 
test and the stack system activity rate during the test. The report must 
also contain any changes in the stack system configuration during or 
between tests in a reporting year.
    (5) The fab-specific emission factor and the calculations and data 
used to determine the fab-specific emission factor for each fluorinated 
GHG and by-product, as calculated using Equations I-19 and I-20 of Sec. 
98.93(i)(3).
    (6) Calculations and data used to determine annual emissions of each 
fluorinated GHG for each fab.

[[Page 694]]

    (7) Calculations and data used to determine and document that the 
fab was operating at representative operating levels, as defined in 
Sec. 98.98, during the stack testing period.
    (8) A copy of the certification that no significant changes in stack 
system flow configuration occurred between tests conducted for any 
particular fab in a reporting year, as required by Sec. 98.94(j)(1)(iv) 
and any calculations and data supporting the certification.
    (9) The number of tools vented to each stack system in the fab.
    (j) If you report the approximate percentage of total GHG emissions 
from research and development activities under Sec. 98.96(x), 
documentation for the determination of the percentage of total emissions 
of each fluorinated GHG and/or N2O attributable to research 
and development activities, as defined in Sec. 98.6.
    (k) Annual gas consumption for each fluorinated GHG and 
N2O as calculated in Equation I-11 of this subpart, including 
where your fab used less than 50 kg of a particular fluorinated GHG or 
N2O used at your facility for which you have not calculated 
emissions using Equations I-6, I-7, I-8, I-9, I-10, I-21, or I-22 of 
this subpart, the chemical name of the GHG used, the annual consumption 
of the gas, and a brief description of its use.
    (l) All inputs used to calculate gas consumption in Equation I-11 of 
this subpart, for each fluorinated GHG and N2O used.
    (m) Annual amount of each fluorinated GHG consumed for process sub-
type, process type, stack system, or fab, as appropriate, and the annual 
amount of N2O consumed for the aggregate of all chemical 
vapor deposition processes and for the aggregate of all other 
electronics manufacturing production processes, as calculated using 
Equation I-13 of this subpart.
    (n) Disbursements for each fluorinated GHG and N2O during 
the reporting year, as calculated using Equation I-12 of this subpart 
and all inputs used to calculate disbursements for each fluorinated GHG 
and N2O used in Equation I-12 of this subpart, including all 
fab-wide gas-specific heel factors used for each fluorinated GHG and 
N2O. If your fab used less than 50 kg of a particular 
fluorinated GHG during the reporting year, fab-wide gas-specific heel 
factors do not need to be reported for those gases.
    (o) Fraction of each fluorinated GHG or N2O fed into a 
process sub-type, process type, stack system, or fab that is fed into 
tools connected to abatement systems.
    (p) Fraction of each fluorinated GHG or N2O destroyed or 
removed in abatement systems connected to process tools where process 
sub-type, process type j is used, or to process tools vented to stack 
system j or fab f.
    (q) All inputs and results of calculations made accounting for the 
uptime of abatement systems used during the reporting year, or during an 
emissions sampling period, in accordance with Equations I-15 and/or I-23 
of this subpart, as applicable.
    (r) For fluorinated heat transfer fluid emissions, inputs to the 
fluorinated heat transfer fluid mass balance equation, Equation I-16 of 
this subpart, for each fluorinated heat transfer fluid used.
    (s) Where missing data procedures were used to estimate inputs into 
the fluorinated heat transfer fluid mass balance equation under Sec. 
98.95(b), the estimates of those data.

[75 FR 74818, Dec. 1, 2010, as amended at 78 FR 68218, Nov. 13, 2013]



Sec. 98.98  Definitions.

    Except as provided in this section, all of the terms used in this 
subpart have the same meaning given in the Clean Air Act and subpart A 
of this part. If a conflict exists between a definition provided in this 
subpart and a definition provided in subpart A, the definition in this 
subpart takes precedence for the reporting requirements in this subpart.
    Abatement system means a device or equipment that is designed to 
destroy or remove fluorinated GHGs or N2O in exhaust streams 
from one or more electronics manufacturing production processes, or for 
which the destruction or removal efficiency for a fluorinated GHG or 
N2O has been properly measured according to the procedures 
under

[[Page 695]]

Sec. 98.94(f)(4), even if that abatement system is not designed to 
destroy or remove fluorinated GHGs or N2O. The device or 
equipment is only an abatement system for the individual fluorinated 
GHGs or N2O that it is designed to destroy or remove or for 
the individual fluorinated GHGs or N2O for which destruction 
or removal efficiencies were properly measured according to the 
procedures under Sec. 98.94(f)(4).
    Actual gas consumption means the quantity of gas used during wafer/
substrate processing over some period based on a measured change in gas 
container weight or gas container pressure or on a measured volume of 
gas.
    By-product formation means the creation of fluorinated GHGs during 
electronics manufacturing production processes or the creation of 
fluorinated GHGs by an abatement system. Where the procedures in Sec. 
98.93(a) are used to calculate annual emissions, by-product formation is 
the ratio of the mass of the by-product formed to the mass flow of the 
input gas. Where the procedures in Sec. 98.93(i) are used to calculate 
annual emissions, by-product formation is the ratio of the mass of the 
by-product formed to the total mass flow of all fluorinated GHG input 
gases.
    Chamber cleaning is a process type that consists of the process sub-
types defined in paragraphs (1) through (3) of this definition.
    (1) In situ plasma process sub-type consists of the cleaning of 
thin-film production chambers, after processing substrates, with a 
fluorinated GHG cleaning reagent that is dissociated into its cleaning 
constituents by a plasma generated inside the chamber where the film is 
produced.
    (2) Remote plasma process sub-type consists of the cleaning of thin-
film production chambers, after processing substrates, with a 
fluorinated GHG cleaning reagent dissociated by a remotely located 
plasma source.
    (3) In situ thermal process sub-type consists of the cleaning of 
thin-film production chambers, after processing substrates, with a 
fluorinated GHG cleaning reagent that is thermally dissociated into its 
cleaning constituents inside the chamber where thin films are produced.
    Controlled emissions means the quantity of emissions that are 
released to the atmosphere after application of an emission control 
device (e.g., abatement system).
    Destruction or removal efficiency (DRE) means the efficiency of an 
abatement system to destroy or remove fluorinated GHGs, N2O, 
or both. The destruction or removal efficiency is equal to one minus the 
ratio of the mass of all relevant GHGs exiting the abatement system to 
the mass of GHG entering the abatement system. When GHGs are formed in 
an abatement system, destruction or removal efficiency is expressed as 
one minus the ratio of amounts of exiting GHGs to the amounts entering 
the system in units of CO2-equivalents (CO2e).
    Fab means the portion of an electronics manufacturing facility 
located in a separate physical structure that began manufacturing on a 
certain date.
    Fluorinated heat transfer fluids means fluorinated GHGs used for 
temperature control, device testing, cleaning substrate surfaces and 
other parts, and soldering in certain types of electronics manufacturing 
production processes. Fluorinated heat transfer fluids do not include 
fluorinated GHGs used as lubricants or surfactants. For fluorinated heat 
transfer fluids under this subpart I, the lower vapor pressure limit of 
1 mm Hg in absolute at 25  deg.C in the definition of Fluorinated 
greenhouse gas in Sec. 98.6 shall not apply. Fluorinated heat transfer 
fluids used in the electronics manufacturing sector include, but are not 
limited to, perfluoropolyethers, perfluoroalkanes, perfluoroethers, 
tertiary perfluoroamines, and perfluorocyclic ethers.
    Fully fluorinated GHGs means fluorinated GHGs that contain only 
single bonds and in which all available valence locations are filled by 
fluorine atoms. This includes, but is not limited to, saturated 
perfluorocarbons, SF6, NF3, 
SF5CF3, C4F8O, fully 
fluorinated linear, branched, and cyclic alkanes, fully fluorinated 
ethers, fully fluorinated tertiary amines, fully fluorinated 
aminoethers, and perfluoropolyethers.

[[Page 696]]

    Gas utilization means the fraction of input N2O or 
fluorinated GHG converted to other substances during the etching, 
deposition, and/or wafer and chamber cleaning processes. Gas utilization 
is expressed as a rate or factor for specific electronics manufacturing 
process sub-types or process types.
    Heel means the amount of gas that remains in a gas container after 
it is discharged or off-loaded; heel may vary by container type.
    Input gas means a fluorinated GHG or N2O used in one of 
the processes described in Sec. 98.90(a)(1) through (4)
    Intermittent low-use fluorinated GHG, for the purposes of 
determining fluorinated GHG emissions using the stack testing method, 
means a fluorinated GHG that meets all of the following:
    (1) The fluorinated GHG is used by the fab but is not used during 
the period of stack testing for the fab/stack system.
    (2) The emissions of the fluorinated GHG, estimated using the 
methods in Sec. 98.93(i)(4) do not constitute more than 5 percent of 
the total fluorinated GHG emissions from the fab on a CO2e 
basis.
    (3) The sum of the emissions of all fluorinated GHGs that are 
considered intermittent low use gases does not exceed 10,000 metric tons 
CO2e for the fab for that year, as calculated using the 
procedures specified in Sec. 98.93(i)(1) of this subpart.
    (4) The fluorinated GHG is not an expected or possible by-product 
identified in Table I-17 of this subpart.
    Maximum substrate starts means for the purposes of Equation I-5 of 
this subpart, the maximum quantity of substrates, expressed as surface 
area, that could be started each month during a reporting year based on 
the equipment installed in that facility and assuming that the installed 
equipment were fully utilized. Manufacturing equipment is considered 
installed when it is on the manufacturing floor and connected to 
required utilities.
    Modeled gas consumed means the quantity of gas used during wafer/
substrate processing over some period based on a verified facility-
specific engineering model used to apportion gas consumption.
    Nameplate capacity means the full and proper charge of chemical 
specified by the equipment manufacturer to achieve the equipment's 
specified performance. The nameplate capacity is typically indicated on 
the equipment's nameplate; it is not necessarily the actual charge, 
which may be influenced by leakage and other emissions.
    Operational mode means the time in which an abatement system is 
properly installed, maintained, and operated according to the site 
maintenance plan for abatement systems as required in Sec. 98.94(f)(1) 
and defined in Sec. 98.97(d)(9). This includes being properly operated 
within the range of parameters as specified in the site maintenance plan 
for abatement systems.
    Plasma etching is a process type that consists of any production 
process using fluorinated GHG reagents to selectively remove materials 
from a substrate during electronics manufacturing. The materials removed 
may include SiO2, SiOX-based or fully organic-
based thin-film material, SiN, SiON, Si3N4, SiC, 
SiCO, SiCN, etc. (represented by the general chemical formula, 
SiwOXNyXz where w, x, y and 
z are zero or integers and X may be some other element such as carbon), 
substrate, or metal films (such as aluminum or tungsten).
    Process sub-type is a set of similar manufacturing steps, more 
closely related within a broad process type. For example, the chamber 
cleaning process type includes in-situ plasma chamber cleaning, remote 
plasma chamber cleaning, and in-situ thermal chamber cleaning sub-types.
    Process types are broad groups of manufacturing steps used at a 
facility associated with substrate (e.g., wafer) processing during 
device manufacture for which fluorinated GHG emissions and fluorinated 
GHG consumption is calculated and reported. The process types are Plasma 
etching/Wafer Cleaning and Chamber cleaning.
    Properly measured destruction or removal efficiency means 
destruction or removal efficiencies measured in accordance with EPA 430-
R-10-003 (incorporated by reference, see Sec. 98.7), and, if 
applicable, Appendix A to this subpart, or by an alternative method 
approved

[[Page 697]]

by the Administrator as specified in Sec. 98.94(k).
    The Random Sampling Abatement System Testing Program (RSASTP) means 
the required frequency for measuring the destruction or removal 
efficiencies of abatement systems in order to apply properly measured 
destruction or removal efficiencies to report controlled emissions.
    Redundant abatement systems means a system that is specifically 
designed, installed and operated for the purpose of destroying 
fluorinated GHGs and N2O gases, or for which the destruction 
or removal efficiency for a fluorinated GHG or N2O has been 
properly measured according to the procedures under Sec. 98.94(f)(4), 
and that is used as a backup to the main fluorinated GHGs and 
N2O abatement system during those times when the main system 
is not functioning or operating in accordance with design and operating 
specifications.
    Repeatable means that the variables used in the formulas for the 
facility's engineering model for gas apportioning factors are based on 
observable and measurable quantities that govern gas consumption rather 
than engineering judgment about those quantities or gas consumption.
    Representative operating levels means (for purposes of verification 
of the apportionment model or for determining the appropriate conditions 
for stack testing) operating the fab, in terms of substrate starts for 
the period of testing or monitoring, at no less than 50 percent of 
installed production capacity or no less than 70 percent of the average 
production rate for the reporting year, where production rate for the 
reporting year is represented in average monthly substrate starts. For 
the purposes of stack testing, the period for determining the 
representative operating level must be the period ending on the same 
date on which testing is concluded.
    Stack system means one or more stacks that are connected by a common 
header or manifold, through which a fluorinated GHG-containing gas 
stream originating from one or more fab processes is, or has the 
potential to be, released to the atmosphere. For purposes of this 
subpart, stack systems do not include emergency vents or bypass stacks 
through which emissions are not usually vented under typical operating 
conditions.
    Trigger point for change out means the residual weight or pressure 
of a gas container type that a facility uses as an indicator that 
operators need to change out that gas container with a full container. 
The trigger point is not the actual residual weight or pressure of the 
gas remaining in the cylinder that has been replaced.
    Unabated emissions means a gas stream containing fluorinated GHG or 
N2O that has exited the process, but which has not yet been 
introduced into an abatement system to reduce the mass of fluorinated 
GHG or N2O in the stream. If the emissions from the process 
are not routed to an abatement system, or are routed to an abatement 
device that is not in an operational mode, unabated emissions are those 
fluorinated GHG or N2O released to the atmosphere.
    Uptime means the ratio of the total time during which the abatement 
system is in an operational mode, to the total time during which 
production process tool(s) connected to that abatement system are 
normally in operation.
    Wafer cleaning is a process type that consists of any production 
process using fluorinated GHG reagents to clean wafers at any step 
during production.
    Wafer passes is a count of the number of times a wafer substrate is 
processed in a specific process sub-type, or type. The total number of 
wafer passes over a reporting year is the number of wafer passes per 
tool multiplied by the number of operational process tools in use during 
the reporting year.
    Wafer starts means the number of fresh wafers that are introduced 
into the fabrication sequence each month. It includes test wafers, which 
means wafers that are exposed to all of the conditions of process 
characterization, including but not limited to actual etch conditions or 
actual film deposition conditions.

[75 FR 74818, Dec. 1, 2010, as amended at 77 FR 10381, Feb. 22, 2012; 78 
FR 68220, Nov. 13, 2013]

[[Page 698]]



  Sec. Table I-1 to Subpart I of Part 98--Default Emission Factors for 
                  Threshold Applicability Determination

----------------------------------------------------------------------------------------------------------------
                                                                Emission factors EFi
           Product type            -----------------------------------------------------------------------------
                                        CF4          C2F6         CHF3         C3F8         NF3          SF6
----------------------------------------------------------------------------------------------------------------
Semiconductors (kg/m\2\)..........         0.90         1.00         0.04         0.05         0.04         0.20
LCD (g/m\2\)......................         0.50           NA           NA           NA         0.90         4.00
MEMS (kg/m\2\)....................           NA           NA           NA           NA           NA         1.02
----------------------------------------------------------------------------------------------------------------
Notes: NA denotes not applicable based on currently available information.


[75 FR 74818, Dec. 1, 2010, as amended at 78 FR 68221, Nov. 13, 2013]



  Sec. Table I-2 to Subpart I of Part 98--Examples of Fluorinated GHGs 
                    Used by the Electronics Industry

------------------------------------------------------------------------
                                 Fluorinated GHGs and fluorinated heat
         Product type           transfer fluids used during manufacture
------------------------------------------------------------------------
Electronics..................  CF4, C2F6, C3F8, c-C4F8, c-C4F8O, C4F6,
                                C5F8, CHF3, CH2F2, NF3, SF6, and
                                fluorinated HTFs (CF3-(O-CF(CF3)-CF2)n-
                                (O-CF2)m-O-CF3, CnF2n + 2, CnF2n +
                                1(O)CmF2m + 1, CnF2.O, (CnF2n + 1)3N).
------------------------------------------------------------------------


[77 FR 10381, Feb. 22, 2012]

[[Page 699]]



  Sec. Table I-3 to Subpart I of Part 98--Default Emission Factors (1-
   Uij) for Gas Utilization Rates (Uij) and By-
      Product Formation Rates (Bijk) for Semiconductor 
             Manufacturing for 150 mm and 200 mm Wafer Sizes
[GRAPHIC] [TIFF OMITTED] TR13NO13.018


[78 FR 68221, Nov. 13, 2013]

[[Page 700]]



  Sec. Table I-4 to Subpart I of Part 98--Default Emission Factors (1-
   Uij) for Gas Utilization Rates (Uij) and By-
      Product Formation Rates (Bijk) for Semiconductor 
             Manufacturing for 300 mm and 450 mm Wafer Size
[GRAPHIC] [TIFF OMITTED] TR13NO13.019


[[Page 701]]


[GRAPHIC] [TIFF OMITTED] TR13NO13.020


[[Page 702]]





  Sec. Table I-5 to Subpart I of Part 98--Default Emission Factors (1-
   Uij) for Gas Utilization Rates (Uij) and By-
    Product Formation Rates (Bijk) for MEMS Manufacturing

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                             Process gas i
                                             -----------------------------------------------------------------------------------------------------------
            Process type factors                                                                      NF3
                                                CF4      C2F6     CHF3    CH2F2     C3F8   c- C4F8   Remote    NF3      SF6     C4F6a    C5F8a    C4F8Oa
--------------------------------------------------------------------------------------------------------------------------------------------------------
Etch 1-Ui...................................      0.7     10.4     10.4    10.06       NA     10.2       NA      0.2      0.2      0.1      0.2       NA
Etch BCF4...................................       NA     10.4    10.07    10.08       NA      0.2       NA       NA       NA     10.3      0.2       NA
Etch BC2F6..................................       NA       NA       NA       NA       NA      0.2       NA       NA       NA     10.2      0.2       NA
CVD Chamber Cleaning 1-Ui...................      0.9      0.6       NA       NA      0.4      0.1     0.02      0.2       NA       NA      0.1      0.1
CVD Chamber Cleaning BCF4...................       NA      0.1       NA       NA      0.1      0.1    20.02     20.1       NA       NA      0.1      0.1
CVD Chamber Cleaning BC3F8..................       NA       NA       NA       NA       NA       NA       NA       NA       NA       NA       NA      0.4
--------------------------------------------------------------------------------------------------------------------------------------------------------
Notes: NA = Not applicable; i.e., there are no applicable default emission factor measurements for this gas. This does not necessarily imply that a
  particular gas is not used in or emitted from a particular process sub-type or process type.
\1\ Estimate includes multi-gas etch processes.
\2\ Estimate reflects presence of low-k, carbide and multi-gas etch processes that may contain a C-containing fluorinated GHG additive.


[75 FR 74818, Dec. 1, 2010, as amended at 78 FR 68225, Nov. 13, 2013]



  Sec. Table I-6 to Subpart I of Part 98--Default Emission Factors (1-
   Uij) for Gas Utilization Rates (Uij) and By-
     Product Formation Rates (Bijk) for LCD Manufacturing

----------------------------------------------------------------------------------------------------------------
                                                                  Process gas i
                                --------------------------------------------------------------------------------
      Process type factors                                                               NF3
                                   CF4      C2F6     CHF3    CH2F2     C3F8   c- C4F8   Remote    NF3      SF6
----------------------------------------------------------------------------------------------------------------
Etch 1-Ui......................      0.6       NA      0.2       NA       NA      0.1       NA       NA      0.3
Etch BCF4......................       NA       NA     0.07       NA       NA    0.009       NA       NA       NA
Etch BCHF3.....................       NA       NA       NA       NA       NA     0.02       NA       NA       NA
Etch BC2F4.....................       NA       NA     0.05       NA       NA       NA       NA       NA       NA
CVD Chamber Cleaning 1-Ui......       NA       NA       NA       NA       NA       NA     0.03      0.3      0.9
----------------------------------------------------------------------------------------------------------------
Notes: NA = Not applicable; i.e., there are no applicable default emission factor measurements for this gas.
  This does not necessarily imply that a particular gas is not used in or emitted from a particular process sub-
  type or process type.


[75 FR 74818, Dec. 1, 2010, as amended at 78 FR 68225, Nov. 13, 2013]



  Sec. Table I-7 To Subpart I of Part 98--Default Emission Factors (1-
   Uij) for Gas Utilization Rates (Uij) and By-
     Product Formation Rates (Bijk) for PV Manufacturing

----------------------------------------------------------------------------------------------------------------
                                                                  Process gas i
                                --------------------------------------------------------------------------------
      Process type factors                                                               NF3
                                   CF4      C2F6     CHF3    CH2F2     C3F8   c- C4F8   Remote    NF3      SF6
----------------------------------------------------------------------------------------------------------------
Etch 1-Ui......................      0.7      0.4      0.4       NA       NA      0.2       NA       NA      0.4
Etch BCF4......................       NA      0.2       NA       NA       NA      0.1       NA       NA       NA

[[Page 703]]

 
Etch BC2F6.....................       NA       NA       NA       NA       NA      0.1       NA       NA       NA
CVD Chamber Cleaning 1-Ui......       NA      0.6       NA       NA      0.1      0.1       NA      0.3      0.4
CVD Chamber Cleaning BCF4......       NA      0.2       NA       NA      0.2      0.1       NA       NA       NA
----------------------------------------------------------------------------------------------------------------
Notes: NA = Not applicable; i.e., there are no applicable default emission factor measurements for this gas.
  This does not necessarily imply that a particular gas is not used in or emitted from a particular process sub-
  type or process type.


[75 FR 74818, Dec. 1, 2010, as amended at 78 FR 68225, Nov. 13, 2013]



  Sec. Table I-8 to Subpart I of Part 98-- Default Emission Factors (1-
  UN2O,j) for N2O Utilization (UN2O,j)

------------------------------------------------------------------------
                       Process type factors                         N2O
------------------------------------------------------------------------
CVD 1-Ui.........................................................    0.8
Other Manufacturing Process 1-Ui.................................    1.0
------------------------------------------------------------------------


[[Page 704]]



   Sec. Table I-9 to Subpart I of Part 98--Methods and Procedures for 
               Conducting Emissions Test for Stack Systems
[GRAPHIC] [TIFF OMITTED] TR13NO13.031


[[Page 705]]


[GRAPHIC] [TIFF OMITTED] TR13NO13.032


[78 FR 68227, Nov. 13, 2013]



Sec. Table I-10 to Subpart I of Part 98--Maximum Field Detection Limits 
   Applicable to Fluorinated GHG Concentration Measurements for Stack 
                                 Systems

------------------------------------------------------------------------
                                                          Maximum field
                Fluorinated GHG Analyte                  detection limit
                                                             (ppbv)
------------------------------------------------------------------------
CF4...................................................                20
C2F6..................................................                20
C3F8..................................................                20
C4F6..................................................                20
C5F8..................................................                20
c-C4F8................................................                20
CH2F2.................................................                40
CH3F..................................................                40
CHF3..................................................                20
NF3...................................................                20
SF6...................................................                 4
Other fully fluorinated GHGs..........................                20
Other fluorinated GHGs................................                40
------------------------------------------------------------------------
ppbv--Parts per billion by volume.


[78 FR 68228, Nov. 13, 2013]

[[Page 706]]



  Sec. Table I-11 to Subpart I of Part 98--Default Emission Factors (1-
   Uij) for Gas Utilization Rates (Uij) and By-
      Product Formation Rates (Bijk) for Semiconductor 
  Manufacturing for Use With the Stack Test Method (150 mm and 200 mm 
                                 Wafers)
[GRAPHIC] [TIFF OMITTED] TR13NO13.023


[78 FR 68229, Nov. 13, 2013]

[[Page 707]]



  Sec. Table I-12 to Subpart I of Part 98--Default Emission Factors (1-
   Uij) for Gas Utilization Rates (Uij) and By-
      Product Formation Rates (Bijk) for Semiconductor 
  Manufacturing for Use With the Stack Test Method (300 mm and 450 mm 
                                 Wafers)
[GRAPHIC] [TIFF OMITTED] TR13NO13.024


[78 FR 68230, Nov. 13, 2013]

[[Page 708]]



  Sec. Table I-13 to Subpart I of Part 98--Default Emission Factors (1-
   Uij) for Gas Utilization Rates (Uij) and By-
Product Formation Rates (Bijk) for LCD Manufacturing for Use 
                       With the Stack Test Method
[GRAPHIC] [TIFF OMITTED] TR13NO13.025


[78 FR 68231, Nov. 13, 2013]

[[Page 709]]



  Sec. Table I-14 to Subpart I of Part 98--Default Emission Factors (1-
   Uij) for Gas Utilization Rates (Uij) and By-
 Product Formation Rates (Bijk) for PV Manufacturing for Use 
                       With the Stack Test Method
[GRAPHIC] [TIFF OMITTED] TR13NO13.026


[78 FR 68232, Nov. 13, 2013]

[[Page 710]]



  Sec. Table I-15 to Subpart I of Part 98--Default Emission Factors (1-
   Uij) for Gas Utilization Rates (Uij) and By-
Product Formation Rates (Bijk) for MEMS Manufacturing for Use 
                       With the Stack Test Method
[GRAPHIC] [TIFF OMITTED] TR13NO13.027


[78 FR 68233, Nov. 13, 2013]

[[Page 711]]



Sec. Table I-16 to Subpart I of Part 98--Default Emission Destruction or 
     Removal Efficiency (DRE) Factors for Electronics Manufacturing

------------------------------------------------------------------------
                                                          Default DRE
         Manufacturing type/process type/gas               (percent)
------------------------------------------------------------------------
MEMS, LCDs, and PV Manufacturing....................                  60
Semiconductor Manufacturing:
    Plasma Etch/Wafer Clean Process Type:
        CF4.........................................                  75
        CH3F........................................                  97
        CHF3........................................                  97
        CH2F2.......................................                  97
        C2F6........................................                  97
        C3F8........................................                  97
        C4F6........................................                  97
        C4F8........................................                  97
        C5F8........................................                  97
        SF6.........................................                  97
        NF3.........................................                  96
All other carbon-based plasma etch/wafer clean                        60
 fluorinated GHG....................................
Chamber Clean Process Type:
    NF3.............................................                  88
    All other chamber clean fluorinated GHG.........                  60
N2O Processes:
    CVD and all other N2O-using processes...........                  60
------------------------------------------------------------------------


[78 FR 68234, Nov. 13, 2013]



   Sec. Table I-17 to Subpart I of Part 98--Expected and Possible By-
                Products for Electronics Manufacturinglg

----------------------------------------------------------------------------------------------------------------
  For each stack system for which you
   use the ``stack test method'' to          If emissions are detected        If emissions are not detected, use
 calculate annual emissions, you must    intermittently, use the following        the following procedures:
        measure the following:                      procedures:
----------------------------------------------------------------------------------------------------------------
Expected By-products:.................  Use the measured concentration for   Use one-half of the field detection
 CF4..................................   ``Xksm'' in Equation I-18 when       limit you determined for the
 C2F6.................................   available and use one-half of the    fluorinated GHG according to Sec.
 CHF3.................................   field detection limit you             98.94(j)(2) for the value of
 CH2F2................................   determined for the fluorinated GHG   ``Xksm'' in Equation I-18.
 CH3F.................................   according to Sec. 98.94(j)(2)
                                         for the value of ``Xksm'' when the
                                         fluorinated GHG is not detected.
Possible By-products:.................  Use the measured concentration for   Assume zero emissions for that
 C3F8.................................   ``Xksm'' in Equation I-18 when       fluorinated GHG for the tested
 C4F6.................................   available and use one-half of the    stack system.
 c-C4F8...............................   field detection limit you
 C5F8.................................   determined for the fluorinated GHG
                                         according to Sec. 98.94(j)(2)
                                         for the value of ``Xksm'' when the
                                         fluorinated GHG is not detected.
----------------------------------------------------------------------------------------------------------------


[78 FR 68234, Nov. 13, 2013]



  Sec. Appendix A to Subpart I of Part 98--Alternative Procedures for 
     Measuring Point-of-Use Abatement Device Destruction or Removal 
                               Efficiency

    If you are measuring destruction or removal efficiency of a point-
of-use abatement device according to EPA 430-R-10-003 (incorporated by 
reference, see Sec. 98.7) as specified in Sec. 98.94(f)(4), you may 
follow the alternative procedures specified in paragraphs (a) through 
(c) of this appendix.
    (a) In place of the Quadrupole Mass Spectrometry protocol 
requirements specified in section 2.2.4 of EPA 430-R-10-003 
(incorporated by reference, see Sec. 98.7), you must conduct mass 
spectrometry testing in accordance with the provisions in paragraph 
(a)(1) through (a)(15) of this appendix.
    (1) Detection limits. The mass spectrometer chosen for this 
application must have the necessary sensitivity to detect the selected 
effluent species at or below the maximum field detection limits 
specified in Table 3 of section 2.2.7 of EPA 430-R-10-003 (incorporated 
by reference, see Sec. 98.7).
    (2) Sampling location. The sample at the inlet of the point-of-use 
abatement device must be taken downstream of the process tool and pump 
package. The sample exhaust must be vented back into the corrosive house 
ventilation system at a point downstream of the sample inlet location.
    (3) Sampling conditions. For etch processes, destruction or removal 
efficiencies must be determined while etching a substrate (product, 
dummy, or test). For chemical vapor deposition processes, destruction or 
removal efficiencies must be determined during a chamber clean after 
deposition (destruction or removal efficiencies must not be determined 
in a clean chamber). All sampling must be performed non-intrusively 
during wafer processing. Samples must be drawn

[[Page 712]]

through the mass spectrometer source by an external sample pump. Because 
of the volatility, vapor pressure, stability and inertness of 
CF4, C2F6, C3F8, 
CHF3, NF3, and SF6, the sample lines do 
not need to be heated.
    (4) Mass spectrometer parameters. The specific mass spectrometer 
operating conditions such as electron energy, secondary electron 
multiplier voltage, emission current, and ion focusing voltage must be 
selected according to the specifications provided by the mass 
spectrometer manufacturer, the mass spectrometer system manual, basic 
mass spectrometer textbook, or other such sources. The mass spectrometer 
responses to each of the target analytes must all be calibrated under 
the same mass spectrometer operating conditions.
    (5) Flow rates. A sample flow rate of 0.5-1.5 standard liters per 
minute (slm) must be drawn from the process tool exhaust stream under 
study.
    (6) Sample frequency. The mass spectrometer sampling frequency for 
etch processes must be in the range of 0.5 to 1 cycles per second, and 
for chemical vapor deposition processes must be in the range of 0.25 to 
0.5 cycles per second. As an alternative you may use the sampling 
frequencies specified in section 2.2.4 of EPA 430-R-10-003 (incorporated 
by reference, see Sec. 98.7).
    (7) Dynamic dilution calibration parameters. The quadrupole mass 
spectrometer must be calibrated for both mass location and response to 
analytes. A dynamic dilution calibration system may be used to perform 
both types of mass spectrometer system calibrations using two mass flow 
controllers. Use one mass flow controller to regulate the flow rate of 
the standard component used to calibrate the system and the second mass 
flow controller to regulate the amount of diluent gas used to mix with 
the standard to generate the calibration curve for each compound of 
interest. The mass flow controller must be calibrated using the single 
component gas being used with them, for example, nitrogen 
(N2) for the diluent. A mass flow controller used with 
calibration mixtures must be calibrated with the calibration mixture 
balance gas (for example, N2 or He) if the analyte components 
are 2 percent or less of the volume of the sample. All calibration 
mixtures must be National Institute of Standards and Technology 
Traceable gases or equivalent. They must be calibrated over their range 
of use and must be operated in their experimentally determined dynamic 
linear range. If compressed gas standards cannot be brought into the 
fab, metered gas flows of target compounds into the process chamber, 
under no thermal or plasma conditions and with no wafer(s) present, and 
with no process emissions from other tools contributing to the sample 
location, must then be performed throughout the appropriate 
concentration ranges to derive calibration curves for the subsequent 
destruction or removal efficiency tests.
    (8) Mass location calibration. A mixture containing 1 percent He, 
Ar, Kr, and Xe in a balance gas of nitrogen must be used to assure the 
alignment of the quadrupole mass filter (see EPA Method 205 at 40 CFR 
part 51, appendix M as reference). The mass spectrometer must be chosen 
so that the mass range is sufficient to detect the predominant peaks of 
the components under study.
    (9) Quadrupole mass spectrometer response calibration. A calibration 
curve must be generated for each compound of interest.
    (10) Calibration frequency. The mass spectrometer must be calibrated 
at the start of testing a given process. The calibration must be checked 
at the end of testing.
    (11) Calibration range. The mass spectrometer must be calibrated 
over the expected concentration range of analytes using a minimum of 
five concentrations including a zero. The zero point is defined as 
diluent containing no added analyte.
    (12) Operating procedures. You must follow the operating procedures 
specified in paragraphs (a)(12)(i) through (v) of this appendix.
    (i) You must perform a qualitative mass calibration by running a 
standard (or by flowing chamber gases under non-process conditions) 
containing stable components such as Ar, Kr, and Xe that provide 
predominant signals at m/e values distributed throughout the mass range 
to be used. You must adjust the quadrupole mass filter as needed to 
align with the inert gas fragments.
    (ii) You must quantitatively calibrate the quadrupole mass 
spectrometer for each analyte of interest. The analyte concentrations 
during calibration must include the expected concentrations in the 
process effluent. The calibration must be performed under the same 
operating conditions, such as inlet pressure, as when sampling process 
exhaust. If the calibration inlet pressure differs from the sampling 
inlet pressure then the relationship between inlet pressure and 
quadrupole mass spectrometer signal response must be empirically 
determined and applied to correct for any differences between 
calibration and process emissions monitoring data.
    (iii) To determine the response time of the instrument to changes in 
a process, a process gas such as C2F6 must be 
turned on at the process tool for a fixed period of time (for example, 
20 seconds), after which the gas is shut off. The sample flow rate 
through the system must be adjusted so that the signal increases to a 
constant concentration within a few seconds and decreases to background 
levels also within a few seconds.
    (iv) You must sample the process effluent through the quadrupole 
mass spectrometer and acquire data for the required amount of time to 
track the process, as determined in paragraph (a)(12)(iii) of this 
appendix. You

[[Page 713]]

must set the sample frequency to monitor the changes in the process as 
specified in paragraph (a)(6) of this appendix. You must repeat this for 
at least five substrates on the same process and calculate the average 
and standard deviation of the analyte concentration.
    (v) You must repeat the quantitative calibration at the conclusion 
of sampling to identify any drifts in quadrupole mass spectrometer 
sensitivity. If drift is observed, you must use an internal standard to 
correct for changes in sensitivity.
    (13) Sample analysis. To determine the concentration of a specific 
component in the sample, you must divide the ion intensity of the sample 
response by the calibrated response factor for each component.
    (14) Deconvolution of interfering peaks. The effects of interfering 
peaks must be deconvoluted from the mass spectra for each target 
analyte.
    (15) Calculations. Plot ion intensity versus analyte concentration 
for a given compound obtained when calibrating the analytical system. 
Determine the slope and intercept for each calibrated species to obtain 
response factors with which to calculate concentrations in the sample. 
For an acceptable calibration, the R\2\ value of the calibration curve 
must be at least 0.98.
    (b) In place of the Fourier Transform Infrared Spectroscopy protocol 
requirements specified in section 2.2.4 of EPA 430-R-10-003 
(incorporated by reference, see Sec. 98.7), you may conduct Fourier 
Transform Infrared Spectroscopy testing in accordance with the 
provisions in paragraph (b)(1) through (17) of this appendix, including 
the laboratory study phase described in paragraphs (b)(1) through (7), 
and the field study phase described in paragraphs (b)(8) through (17) of 
this appendix.
    (1) Conformance with provisions associated with the Calibration 
Transfer Standard. This procedure calls for the use of a calibration 
transfer standard in a number of instances. The use of a calibration 
transfer standard is necessary to validate optical pathlength and 
detector response for spectrometers where cell temperature, cell 
pressure, and cell optical pathlength are potentially variable. For 
fixed pathlength spectrometers capable of controlling cell temperature 
and pressure to within  10 percent of a desired 
set point, the use of a calibration transfer standard, as described in 
paragraphs (b)(2) to (17) this appendix is not required.
    (2) Defining spectroscopic conditions. Define a set of spectroscopic 
conditions under which the field studies and subsequent field 
applications are to be carried out. These include the minimum 
instrumental line-width, spectrometer wave number range, sample gas 
temperature, sample gas pressure, absorption pathlength, maximum 
sampling system volume (including the absorption cell), minimum sample 
flow rate, and maximum allowable time between consecutive infrared 
analyses of the effluent.
    (3) Criteria for reference spectral libraries. On the basis of 
previous emissions test results and/or process knowledge (including the 
documentation of results of any initial and subsequent tests, and the 
final reports required in Sec. 98.97(d)(4)(i)), estimate the maximum 
concentrations of all of the analytes in the effluent and their minimum 
concentrations of interest (those concentrations below which the 
measurement of the compounds is of no importance to the analysis). 
Values between the maximum expected concentration and the minimum 
concentration of interest are referred to below as the ``expected 
concentration range.'' A minimum of three reference spectra is 
sufficient for a small expected concentration range (e.g., a difference 
of 30 percent of the range between the low and high ends of the range), 
but a minimum of four spectra are needed where the range is greater, 
especially for concentration ranges that may differ by orders of 
magnitude. If the measurement method is not linear then multiple linear 
ranges may be necessary. If this approach is adopted, then linear range 
must be demonstrated to pass the required quality control. When the set 
of spectra is ordered according to absorbance, the absorbance levels of 
adjacent reference spectra should not differ by more than a factor of 
six. Reference spectra for each analyte should be available at 
absorbance levels that bracket the analyte's expected concentration 
range; minimally, the spectrum whose absorbance exceeds each analyte's 
expected maximum concentration or is within 30 percent of it must be 
available. The reference spectra must be collected at or near the same 
temperature and pressure at which the sample is to be analyzed under. 
The gas sample pressure and temperature must be continuously monitored 
during field testing and you must correct for differences in temperature 
and pressure between the sample and reference spectra. Differences 
between the sample and reference spectra conditions must not exceed 50 
percent for pressure and 40  deg.C for temperature.
    (4) Spectra without reference libraries. If reference spectral 
libraries meeting the criteria in paragraph (b)(3) of this appendix do 
not exist for all the analytes and interferants or cannot be accurately 
generated from existing libraries exhibiting lower minimum instrumental 
line-width values than those proposed for the testing, prepare the 
required spectra according to the procedures specified in paragraphs 
(b)(4)(i) and (ii) of this appendix.
    (i) Reference spectra at the same absorbance level (to within 10 
percent) of independently prepared samples must be recorded. The 
reference samples must be prepared from neat forms of the analyte or 
from gas

[[Page 714]]

standards of the highest quality commonly available from commercial 
sources. Either barometric or volumetric methods may be used to dilute 
the reference samples to the required concentrations, and the equipment 
used must be independently calibrated to ensure suitable accuracy. 
Dynamic and static reference sample preparation methods are acceptable, 
but dynamic preparations must be used for reactive analytes. Any well 
characterized absorption pathlength may be employed in recording 
reference spectra, but the temperature and pressure of the reference 
samples should match as closely as possible those of the proposed 
spectroscopic conditions.
    (ii) If a mercury cadmium telluride or other potentially non-linear 
detector (i.e., a detector whose response vs. total infrared power is 
not a linear function over the range of responses employed) is used for 
recording the reference spectra, you must correct for the effects of 
this type of response on the resulting concentration values. As needed, 
spectra of a calibration transfer standard must be recorded with the 
laboratory spectrometer system to verify the absorption pathlength and 
other aspects of the system performance. All reference spectral data 
must be recorded in interferometric form and stored digitally.
    (5) Sampling system preparation. Construct a sampling system 
suitable for delivering the proposed sample flow rate from the effluent 
source to the infrared absorption cell. For the compounds of interest, 
the surfaces of the system exposed to the effluent stream may need to be 
stainless steel or Teflon; because of the potential for generation of 
inorganic automated gases, glass surfaces within the sampling system and 
absorption cell may need to be Teflon-coated. The sampling system should 
be able to deliver a volume of sample that results in a necessary 
response time.
    (6) Preliminary analytical routines. For the proposed absorption 
pathlength to be used in actual emissions testing, you must prepare an 
analysis method containing of all the effluent compounds at their 
expected maximum concentrations plus the field calibration transfer 
standard compound at 20 percent of its full concentration as needed.
    (7) Documentation. The laboratory techniques used to generate 
reference spectra and to convert sample spectral information to compound 
concentrations must be documented. The required level of detail for the 
documentation is that which allows an independent analyst to reproduce 
the results from the documentation and the stored interferometric data.
    (8) Spectroscopic system performance. The performance of the 
proposed spectroscopic system, sampling system, and analytical method 
must be rigorously examined during and after a field study. Several 
iterations of the analysis method may need to be applied depending on 
observed concentrations, absorbance intensities, and interferences. 
During the field study, all the sampling and analytical procedures 
envisioned for future field applications must be documented. Additional 
procedures not required during routine field applications, notably 
dynamic spiking studies of the analyte gases, may be performed during 
the field study. These additional procedures need to be performed only 
once if the results are acceptable and if the effluent sources in future 
field applications prove suitably similar to those chosen for the field 
study. If changes in the effluent sources in future applications are 
noted and require substantial changes to the analytical equipment and/or 
conditions, a separate field study must be performed for the new set of 
effluent source conditions. All data recorded during the study must be 
retained and documented, and all spectral information must be 
permanently stored in interferometric form.
    (9) System installation. The spectroscopic and sampling sub-systems 
must be assembled and installed according to the manufacturers' 
recommendations. For the field study, the length of the sample lines 
used must not be less than the maximum length envisioned for future 
field applications. The system must be given sufficient time to 
stabilize before testing begins.
    (10) Pre-Test calibration. Record a suitable background spectrum 
using pure nitrogen gas; alternatively, if the analytes of interest are 
in a sample matrix consistent with ambient air, it is beneficial to use 
an ambient air background to control interferences from water and carbon 
dioxide. For variable pathlength Fourier Transform Infrared 
Spectrometers, introduce a sample of the calibration transfer standard 
gas directly into the absorption cell at the expected sample pressure 
and record its absorbance spectrum (the ``initial field calibration 
transfer standard spectrum''). Compare it to the laboratory calibration 
transfer standard spectra to determine the effective absorption 
pathlength. If possible, record spectra of field calibration gas 
standards (single component standards of the analyte compounds) and 
determine their concentrations using the reference spectra and 
analytical routines developed in paragraphs (b)(2) through (7) of this 
appendix; these spectra may be used instead of the reference spectra in 
actual concentration and uncertainty calculations.
    (11) Deriving the calibration transfer standard gas from tool 
chamber gases. The calibration transfer standard gas may be derived by 
flowing appropriate semiconductor tool chamber gases under non-process 
conditions (no thermal or plasma conditions and with no wafer(s) 
present) if compressed gas standards cannot be brought on-site.

[[Page 715]]

    (12) Reactivity and response time checks. While sampling ambient air 
and continuously recording absorbance spectra, suddenly replace the 
ambient air flow with calibration transfer standard gas introduced as 
close as possible to the probe tip. Examine the subsequent spectra to 
determine whether the flow rate and sample volume allow the system to 
respond quickly enough to changes in the sampled gas. Should a corrosive 
or reactive gas be of interest in the sample matrix it would be 
beneficial to determine the reactivity in a similar fashion, if 
practical. Examine the subsequent spectra to ensure that the 
reactivities of the analytes with the exposed surfaces of the sampling 
system do not limit the time response of the analytical system. If a 
pressure correction routine is not automated, monitor the absorption 
cell temperature and pressure; verify that the (absolute) pressure 
remains within 2 percent of the pressure specified in the proposed 
system conditions.
    (13) Analyte spiking. Analyte spiking must be performed. While 
sampling actual source effluent, introduce a known flow rate of 
calibration transfer standard gas into the sample stream as close as 
possible to the probe tip or between the probe and extraction line. 
Measure and monitor the total sample flow rate, and adjust the spike 
flow rate until it represents 10 percent to 20 percent of the total flow 
rate. After waiting until at least four absorption cell volumes have 
been sampled, record four spectra of the spiked effluent, terminate the 
calibration transfer standard spike flow, pause until at least four cell 
volumes are sampled, and then record four (unspiked) spectra. Repeat 
this process until 12 spiked and 12 unspiked spectra have been obtained. 
If a pressure correction routine is not automated, monitor the 
absorption cell temperature and pressure; verify that the pressure 
remains within 2 percent of the pressure specified in the proposed 
system conditions. Calculate the expected calibration transfer standard 
compound concentrations in the spectra and compare them to the values 
observed in the spectrum. This procedure is best performed using a 
spectroscopic tracer to calculate dilution (as opposed to measured flow 
rates) of the injected calibration transfer standard (or analyte). The 
spectroscopic tracer should be a component not in the gas matrix that is 
easily detectable and maintains a linear absorbance over a large 
concentration range. Repeat this spiking process with all effluent 
compounds that are potentially reactive with either the sampling system 
components or with other effluent compounds. The gas spike is delivered 
by a mass flow controller, and the expected concentration of analyte of 
interest (AOITheoretical) is calculated as follows:
[GRAPHIC] [TIFF OMITTED] TR13NO13.028

Where:

AOITheoretical = Theoretical analyte of interest concentration (parts 
          per million (ppm)).
Tracersample = Tracer concentration (ppm) as seen by the Fourier 
          Transform Infrared Spectrometer during spiking.
Tracercylinder = The concentration (ppm) of tracer recorded during 
          direct injection of the cylinder to the Fourier Transform 
          Infrared Spectrometer cell.
AOIcylinder = The supplier-certified concentration (ppm) of the analyte 
          of interest gas standard.
AOInative = The native AOI concentration (ppm) of the effluent during 
          stable conditions.

    (14) Post-test calibration. At the end of a sampling run and at the 
end of the field study, record the spectrum of the calibration transfer 
standard gas. The resulting ``final field calibration transfer standard 
spectrum'' must be compared to the initial field calibration transfer 
standard spectrum to verify suitable stability of the spectroscopic 
system throughout the course of the field study.
    (15) Amendment of analytical routines. The presence of unanticipated 
interferant compounds and/or the observation of compounds at 
concentrations outside their expected concentration ranges may 
necessitate the repetition of portions of the procedures in paragraphs 
(b)(2) through (14) of this appendix. Such amendments are allowable 
before final analysis of the data, but must be represented in the 
documentation required in paragraph (b)(16) of this appendix.
    (16) Documentation. The sampling and spiking techniques used to 
generate the field study spectra and to convert sample spectral 
information to concentrations must be documented at a level of detail 
that allows an independent analyst to reproduce the results from the 
documentation and the stored interferometric data.

[[Page 716]]

    (17) Method application. When the required laboratory and field 
studies have been completed and if the results indicate a suitable 
degree of accuracy, the methods developed may be applied to practical 
field measurement tasks. During field applications, the procedures 
demonstrated in the field study specified in paragraphs (b)(8) through 
(16) of this appendix must be adhered to as closely as possible, with 
the following exceptions specified in paragraphs (b)(17)(i) through 
(iii) of this appendix:
    (i) The sampling lines employed should be as short as practically 
possible and not longer than those used in the field study.
    (ii) Analyte spiking and reactivity checks are required after the 
installation of or major repair to the sampling system or major change 
in sample matrix. In these cases, perform three spiked/unspiked samples 
with calibration transfer standard or a surrogate analyte on a daily 
basis if time permits and gas standards are easy to obtain and get on-
site.
    (iii) Sampling and other operational data must be recorded and 
documented as during the field study, but only the interferometric data 
needed to sufficiently reproduce actual test and spiking data must be 
stored permanently. The format of this data does not need to be 
interferograms but may be absorbance spectra or single beams.
    (c) When using the flow and dilution measurement protocol specified 
in section 2.2.6 of EPA 430-R-10-003 (incorporated by reference, see 
Sec. 98.7), you may determine point-of-use abatement device total 
volume flow with the modifications specified in paragraphs (c)(1) 
through (3) of this appendix.
    (1) You may introduce the non-reactive, non-native gas used for 
determining total volume flow and dilution across the point-of-use 
abatement device at a location in the exhaust of the point-of-use 
abatement device. For abatement systems operating in a mode where 
specific F-GHG are not readily abated, you may introduce the non-
reactive, non-native gas used for determining total volume flow and 
dilution across the point-of-use abatement device prior to the point-of-
use abatement system; in this case, the tracer must be more difficult to 
destroy than the target compounds being measured based on the thermal 
stability of the tracer and target.
    (2) You may select a location for downstream non-reactive, non-
native gas analysis that complies with the requirements in this 
paragraph (c)(2) of this appendix. The sampling location should be 
traversed with the sampling probe measuring the non-reactive, non-native 
gas concentrations to ensure homogeneity of the non-reactive gas and 
point-of-use abatement device effluent (i.e., stratification test). To 
test for stratification, measure the non-reactive, non-native gas 
concentrations at three points on a line passing through the centroidal 
area. Space the three points at 16.7, 50.0, and 83.3 percent of the 
measurement line. Sample for a minimum of twice the system response 
time, determined according to paragraph (c)(3) of this appendix, at each 
traverse point. Calculate the individual point and mean non-reactive, 
non-native gas concentrations. If the non-reactive, non-native gas 
concentration at each traverse point differs from the mean concentration 
for all traverse points by no more than 5.0 
percent of the mean concentration, the gas stream is considered 
unstratified and you may collect samples from a single point that most 
closely matches the mean. If the 5.0 percent criterion is not met, but 
the concentration at each traverse point differs from the mean 
concentration for all traverse points by no more than 10.0 percent of the mean, you may take samples from two 
points and use the average of the two measurements. Space the two points 
at 16.7, 50.0, or 83.3 percent of the measurement line. If the 
concentration at each traverse point differs from the mean concentration 
for all traverse points by more than 10.0 percent 
of the mean but less than 20.0 percent, take samples from three points 
at 16.7, 50.0, and 83.3 percent of the measurement line and use the 
average of the three measurements. If the gas stream is found to be 
stratified because the 20.0 percent criterion for a 3-point test is not 
met, locate and sample the non-reactive, non-native gas from traverse 
points for the test in accordance with Sections 11.2 and 11.3 of EPA 
Method 1 in 40 CFR part 60, Appendix A-1. A minimum of 40 non-reactive 
gas concentration measurements will be collected at three to five 
different injected non-reactive gas flow rates for determination of 
point-of-use abatement device effluent flow. The total volume flow of 
the point-of-use abatement device exhaust will be calculated consistent 
with the EPA 430-R-10-003 (incorporated by reference, see Sec. 98.7) 
Equations 1 through 7.
    (3) You must determine the measurement system response time 
according to paragraphs (c)(3)(i) through (iii) of this appendix.
    (i) Before sampling begins, introduce ambient air at the probe 
upstream of all sample condition components in system calibration mode. 
Record the time it takes for the measured concentration of a selected 
compound (for example, carbon dioxide) to reach steady state.
    (ii) Introduce nitrogen in the system calibration mode and record 
the time required for the concentration of the selected compound to 
reach steady state.
    (iii) Observe the time required to achieve 95 percent of a stable 
response for both nitrogen and ambient air. The longer interval is the 
measurement system response time.

[78 FR 68234, Nov. 13, 2013]

[[Page 717]]

Subpart J [Reserved]



                     Subpart K_Ferroalloy Production



Sec. 98.110  Definition of the source category.

    The ferroalloy production source category consists of any facility 
that uses pyrometallurgical techniques to produce any of the following 
metals: ferrochromium, ferromanganese, ferromolybdenum, ferronickel, 
ferrosilicon, ferrotitanium, ferrotungsten, ferrovanadium, 
silicomanganese, or silicon metal.



Sec. 98.111  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains a ferroalloy production process and the facility meets the 
requirements of either Sec. 98.2(a)(1) or (2).



Sec. 98.112  GHGs to report.

    You must report:
    (a) Process CO2 emissions from each electric arc furnace 
(EAF) used for the production of any ferroalloy listed in Sec. 98.110, 
and process CH4 emissions from each EAF that is used for the 
production of any ferroalloy listed in Table K-1 to subpart K.
    (b) CO2, CH4, and N2O emissions 
from each stationary combustion unit following the requirements of 
subpart C of this part. You must report these emissions under subpart C 
of this part (General Stationary Fuel Combustion Sources).

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66461, Oct. 28, 2010]



Sec. 98.113  Calculating GHG emissions.

    You must calculate and report the annual process CO2 
emissions from each EAF not subject to paragraph (c) of this section 
using the procedures in either paragraph (a) or (b) of this section. For 
each EAF also subject to annual process CH4 emissions 
reporting, you must also calculate and report the annual process 
CH4 emissions from the EAF using the procedures in paragraph 
(d) of this section.
    (a) Calculate and report under this subpart the process 
CO2 emissions by operating and maintaining CEMS according to 
the Tier 4 Calculation Methodology in Sec. 98.33(a)(4) and all 
associated requirements for Tier 4 in subpart C of this part (General 
Stationary Fuel Combustion Sources).
    (b) Calculate and report under this subpart the annual process 
CO2 emissions using the procedure in either paragraph (b)(1) 
or (b)(2) of this section.
    (1) Calculate and report under this subpart the annual process 
CO2 emissions from EAFs by operating and maintaining a CEMS 
according to the Tier 4 Calculation Methodology specified in Sec. 
98.33(a)(4) and the applicable requirements for Tier 4 in subpart C of 
this part (General Stationary Fuel Combustion Sources).
    (2) Calculate and report under this subpart the annual process 
CO2 emissions from the EAFs using the carbon mass balance 
procedure specified in paragraphs (b)(2)(i) and (b)(2)(ii) of this 
section.
    (i) For each EAF, determine the annual mass of carbon in each 
carbon-containing input and output material for the EAF and estimate 
annual process CO2 emissions from the EAF using Equation K-1 
of this section. Carbon-containing input materials include carbon 
electrodes and carbonaceous reducing agents. If you document that a 
specific input or output material contributes less than 1 percent of the 
total carbon into or out of the process, you do not have to include the 
material in your calculation using Equation K-1 of this section.

[[Page 718]]

[GRAPHIC] [TIFF OMITTED] TR30OC09.045

Where:

ECO2 = Annual process CO2 emissions from an 
          individual EAF (metric tons).
44/12 = Ratio of molecular weights, CO2 to carbon.
2000/2205 = Conversion factor to convert tons to metric tons.
Mreducing agenti = Annual mass of reducing agent i fed, 
          charged, or otherwise introduced into the EAF (tons).
Creducing agenti = Carbon content in reducing agent i 
          (percent by weight, expressed as a decimal fraction).
Melectrodem = Annual mass of carbon electrode m consumed in 
          the EAF (tons).
Celectrodem = Carbon content of the carbon electrode m 
          (percent by weight, expressed as a decimal fraction).
Moreh = Annual mass of ore h charged to the EAF (tons).
Coreh = Carbon content in ore h (percent by weight, expressed 
          as a decimal fraction).
Mfluxj = Annual mass of flux material j fed, charged, or 
          otherwise introduced into the EAF to facilitate slag formation 
          (tons).
Cfluxj = Carbon content in flux material j (percent by 
          weight, expressed as a decimal fraction).
Mproductk = Annual mass of alloy product k tapped from EAF 
          (tons).
Cproductk = Carbon content in alloy product k. (percent by 
          weight, expressed as a decimal fraction).
Mnon-product outgoingl = Annual mass of non-product outgoing 
          material l removed from EAF (tons).
Cnon-product outgoingl = Carbon content in non-product 
          outgoing material l (percent by weight, expressed as a decimal 
          fraction).

    (ii) Determine the combined annual process CO2 emissions 
from the EAFs at your facility using Equation K-2 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.046

Where:

CO2 = Annual process CO2 emissions from EAFs at 
          facility used for the production of any ferroalloy listed in 
          Sec. 98.110 (metric tons).
ECO2k = Annual process CO2 emissions calculated 
          from EAF k calculated using Equation K-1 of this section 
          (metric tons).
k = Total number of EAFs at facility used for the production of any 
          ferroalloy listed in Sec. 98.110.

    (c) If GHG emissions from an EAF are vented through the same stack 
as any combustion unit or process equipment that reports CO2 
emissions using a CEMS that complies with the Tier 4 Calculation 
Methodology in subpart C of this part (General Stationary Fuel 
Combustion Sources), then the calculation methodology in paragraph (b) 
of

[[Page 719]]

this section shall not be used to calculate process emissions. The owner 
or operator shall report under this subpart the combined stack emissions 
according to the Tier 4 Calculation Methodology in Sec. 98.33(a)(4) and 
all associated requirements for Tier 4 in subpart C of this part.
    (d) For the EAFs at your facility used for the production of any 
ferroalloy listed in Table K-1 of this subpart, you must calculate and 
report the annual CH4 emissions using the procedure specified 
in paragraphs (d)(1) and (2) of this section.
    (1) For each EAF, determine the annual CH4 emissions 
using Equation K-3 of this section.
[GRAPHIC] [TIFF OMITTED] TR29NO13.014

Where:

ECH4 = Annual process CH4 emissions from an 
          individual EAF (metric tons).
Mproducti = Annual mass of alloy product i produced in the 
          EAF (tons).
2/2205 = Conversion factor to convert kg CH4/ton of product 
          to metric tons CH4.
EFproducti = CH4 emission factor for alloy product 
          i from Table K-1 in this subpart (kg of CH4 
          emissions per metric ton of alloy product i).

    (2) Determine the combined process CH4 emissions from the 
EAFs at your facility using Equation K-4 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.048

Where:

CH4 = Annual process CH4 emissions from EAFs at 
          facility used for the production of ferroalloys listed in 
          Table K-1 of this subpart (metric tons).
ECH4j = Annual process CH4 emissions from EAF j 
          calculated using Equation K-3 of this section (metric tons).
j = Total number of EAFs at facility used for the production of 
          ferroalloys listed in Table K-1 of this subpart.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66461, Oct. 28, 2010; 
78 FR 71954, Nov. 29, 2013]



Sec. 98.114  Monitoring and QA/QC requirements.

    If you determine annual process CO2 emissions using the 
carbon mass balance procedure in Sec. 98.113(b)(2), you must meet the 
requirements specified in paragraphs (a) and (b) of this section.
    (a) Determine the annual mass for each material used for the 
calculations of annual process CO2 emissions using Equation 
K-1 of this subpart by summing the monthly mass for the material 
determined for each month of the calendar year. The monthly mass may be 
determined using plant instruments used for accounting purposes, 
including either direct measurement of the quantity of the material 
placed in the unit or by calculations using process operating 
information.
    (b) For each material identified in paragraph (a) of this section, 
you must determine the average carbon content of the material consumed, 
used, or produced in the calendar year using the methods specified in 
either paragraph (b)(1) or (b)(2) of this section. If you document that 
a specific process input or output contributes less than one percent of 
the total mass of carbon into or out of the process, you do not have to 
determine the monthly mass or annual carbon content of that input or 
output.
    (1) Information provided by your material supplier.
    (2) Collecting and analyzing at least three representative samples 
of the material inputs and outputs each year. The carbon content of the 
material must be analyzed at least annually using the standard methods 
(and their QA/QC procedures) specified in paragraphs (b)(2)(i) through 
(b)(2)(iii) of this section, as applicable.
    (i) ASTM E1941-04, Standard Test Method for Determination of Carbon 
in Refractory and Reactive Metals and

[[Page 720]]

Their Alloys (incorporated by reference, see Sec. 98.7) for analysis of 
metal ore and alloy product.
    (ii) ASTM D5373-08 Standard Test Methods for Instrumental 
Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of 
Coal (incorporated by reference, see Sec. 98.7), for analysis of 
carbonaceous reducing agents and carbon electrodes.
    (iii) ASTM C25-06, Standard Test Methods for Chemical Analysis of 
Limestone, Quicklime, and Hydrated Lime (incorporated by reference, see 
Sec. 98.7) for analysis of flux materials such as limestone or 
dolomite.



Sec. 98.115  Procedures for estimating missing data.

    A complete record of all measured parameters used in the GHG 
emissions calculations in Sec. 98.113 is required. Therefore, whenever 
a quality-assured value of a required parameter is unavailable, a 
substitute data value for the missing parameter shall be used in the 
calculations as specified in the paragraphs (a) and (b) of this section. 
You must document and keep records of the procedures used for all such 
estimates.
    (a) If you determine CO2 emissions for the EAFs at your 
facility using the carbon mass balance procedure in Sec. 98.113(b), 100 
percent data availability is required for the carbon content of the 
input and output materials. You must repeat the test for average carbon 
contents of inputs according to the procedures in Sec. 98.114(b) if 
data are missing.
    (b) For missing records of the monthly mass of carbon-containing 
inputs and outputs, the substitute data value must be based on the best 
available estimate of the mass of the inputs and outputs from on all 
available process data or data used for accounting purposes, such as 
purchase records.
    (c) If you are required to calculate CH4 emissions for an 
EAF at your facility as specified in Sec. 98.113(d), the estimate is 
based an annual quantity of certain alloy products, so 100 percent data 
availability is required.



Sec. 98.116  Data reporting requirements.

    In addition to the information required by Sec. 98.3(c), each 
annual report must contain the information specified in paragraphs (a) 
through (e) of this section, as applicable:
    (a) Annual facility ferroalloy product production capacity (tons).
    (b) If a CEMS is used to measure CO2 emissions, report 
the annual production for each ferroalloy product identified in Sec. 
98.110, from each EAF (tons).
    (c) Total number of EAFs at facility used for production of 
ferroalloy products.
    (d) If a CEMS is used to measure CO2 emissions, then you 
must report under this subpart the relevant information required by 
Sec. 98.36 for the Tier 4 Calculation Methodology and the following 
information specified in paragraphs (d)(1) through (d)(3) of this 
section.
    (1) Annual process CO2 emissions (in metric tons) from 
each EAF used for the production of any ferroalloy product identified in 
Sec. 98.110.
    (2) Annual process CH4 emissions (in metric tons) from 
each EAF used for the production of any ferroalloy listed in Table K-1 
of this subpart (metric tons).
    (3) Identification number of each EAF.
    (e) If a CEMS is not used to measure CO2 process 
emissions, and the carbon mass balance procedure is used to determine 
CO2 emissions according to the requirements in Sec. 
98.113(b), then you must report the following information specified in 
paragraphs (e)(1) through (e)(7) of this section.
    (1) Annual process CO2 emissions (in metric tons) from 
each EAF used for the production of any ferroalloy identified in Sec. 
98.110 (metric tons).
    (2) Annual process CH4 emissions (in metric tons) from 
each EAF used for the production of any ferroalloy listed in Table K-1 
of this subpart.
    (3) Identification number for each material.
    (4)-(5) [Reserved]
    (6) List the method used for the determination of carbon content for 
each material included for the calculation of annual process 
CO2 emissions for each EAF (e.g., supplier provided 
information, analyses of representative samples you collected).
    (7) If you use the missing data procedures in Sec. 98.115(b), you 
must report

[[Page 721]]

how monthly mass of carbon-containing inputs and outputs with missing 
data was determined and the number of months the missing data procedures 
were used.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66462, Oct. 28, 2010; 
78 FR 71954, Nov. 29, 2013; 79 FR 63785, Oct. 24, 2014]



Sec. 98.117  Records that must be retained.

    In addition to the records required by Sec. 98.3(g), you must 
retain the records specified in paragraphs (a) through (e) of this 
section for each EAF, as applicable.
    (a) If a CEMS is used to measure CO2 emissions according 
to the requirements in Sec. 98.113(a), then you must retain under this 
subpart the records required for the Tier 4 Calculation Methodology in 
Sec. 98.37 and the information specified in paragraphs (a)(1) through 
(a)(3) of this section.
    (1) Monthly EAF production quantity for each ferroalloy product 
(tons).
    (2) Number of EAF operating hours each month.
    (3) Number of EAF operating hours in a calendar year.
    (b) If the carbon mass balance procedure is used to determine 
CO2 emissions according to the requirements in Sec. 
98.113(b)(2), then you must retain records for the information specified 
in paragraphs (b)(1) through (b)(5) of this section.
    (1) Monthly EAF production quantity for each ferroalloy product 
(tons).
    (2) Number of EAF operating hours each month.
    (3) Number of EAF operating hours in a calendar year.
    (4) Monthly material quantity consumed, used, or produced for each 
material included for the calculations of annual process CO2 
emissions (tons).
    (5) Average carbon content determined and records of the supplier 
provided information or analyses used for the determination for each 
material included for the calculations of annual process CO2 
emissions.
    (c) You must keep records that include a detailed explanation of how 
company records of measurements are used to estimate the carbon input 
and output to each EAF, including documentation of specific input or 
output materials excluded from Equation K-1 of this subpart that 
contribute less than 1 percent of the total carbon into or out of the 
process. You also must document the procedures used to ensure the 
accuracy of the measurements of materials fed, charged, or placed in an 
EAF including, but not limited to, calibration of weighing equipment and 
other measurement devices. The estimated accuracy of measurements made 
with these devices must also be recorded, and the technical basis for 
these estimates must be provided.
    (d) If you are required to calculate CH4 emissions for 
the EAF as specified in Sec. 98.113(d), you must maintain records of 
the total amount of each alloy product produced for the specified 
reporting period, and the appropriate alloy-product specific emission 
factor used to calculate the CH4 emissions.
    (e) Verification software records. You must keep a record of the 
file generated by the verification software specified in Sec. 98.5(b) 
for the applicable data specified in paragraphs (e)(1) through (13) of 
this section. Retention of this file satisfies the recordkeeping 
requirement for the data in paragraphs (e)(1) through (13) of this 
section.
    (1) Carbon content in reducing agent (percent by weight, expressed 
as a decimal fraction) (Equation K-1 of Sec. 98.113).
    (2) Annual mass of reducing agent fed, charged, or otherwise 
introduced into the EAF (tons) (Equation K-1).
    (3) Carbon content of carbon electrode (percent by weight, expressed 
as a decimal fraction) (Equation K-1).
    (4) Annual mass of carbon electrode consumed in the EAF (tons) 
(Equation K-1).
    (5) Carbon content in ore (percent by weight, expressed as a decimal 
fraction) (Equation K-1).
    (6) Annual mass of ore charged to the EAF (tons) (Equation K-1).
    (7) Carbon content in flux material (percent by weight, expressed as 
a decimal fraction) (Equation K-1).
    (8) Annual mass of flux material fed, charged, or otherwise 
introduced into the EAF to facilitate slag formation (tons) (Equation K-
1).
    (9) Carbon content in alloy product (percent by weight, expressed as 
a decimal fraction) (Equation K-1).

[[Page 722]]

    (10) Annual mass of alloy product produced/tapped in the EAF (tons) 
(Equation K-1).
    (11) Carbon content in non-product outgoing material (percent by 
weight, expressed as a decimal fraction) (Equation K-1).
    (12) Annual mass of non-product outgoing material removed from EAF 
(tons) (Equation K-1).
    (13) CH4 emission factor selected from Table K-1 of this 
subpart for each product (kg of CH4 emissions/metric ton of 
alloy product) (Equation K-3 of Sec. 98.113).

[74 FR 56374, Oct. 30, 2009, as amended at 79 FR 63785, Oct. 24, 2014]



Sec. 98.118  Definitions.

    All terms used of this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.



   Sec. Table K-1 to Subpart K of Part 98--Electric Arc Furnace (EAF) 
                     CH4 Emission Factors

------------------------------------------------------------------------
                                 CH4 emission factor (kg CH4 per metric
                                              ton product)
                               -----------------------------------------
                                              EAF Operation
 Alloy product produced in EAF -----------------------------------------
                                                             Sprinkle-
                                   Batch-     Sprinkle-    charging and
                                  charging     charging   750
                                                 \a\         deg.C \b\
------------------------------------------------------------------------
Silicon metal.................          1.5          1.2            0.7
Ferrosilicon 90%..............          1.4          1.1            0.6
Ferrosilicon 75%..............          1.3          1.0            0.5
Ferrosilicon 65%..............          1.3          1.0            0.5
------------------------------------------------------------------------
\a\ Sprinkle-charging is charging intermittently every minute.
\b\ Temperature measured in off-gas channel downstream of the furnace
  hood.



                  Subpart L_Fluorinated Gas Production

    Source: 75 FR 74831, Dec. 1, 2010, unless otherwise noted.



Sec. 98.120  Definition of the source category.

    (a) The fluorinated gas production source category consists of 
processes that produce a fluorinated gas from any raw material or 
feedstock chemical, except for processes that generate HFC-23 during the 
production of HCFC-22.
    (b) To produce a fluorinated gas means to manufacture a fluorinated 
gas from any raw material or feedstock chemical. Producing a fluorinated 
gas includes producing a fluorinated GHG as defined at Sec. 98.410(b). 
Producing a fluorinated gas also includes the manufacture of a 
chlorofluorocarbon (CFC) or hydrochlorofluorocarbon (HCFC) from any raw 
material or feedstock chemical, including manufacture of a CFC or HCFC 
as an isolated intermediate for use in a process that will result in the 
transformation of the CFC or HCFC either at or outside of the production 
facility. Producing a fluorinated gas does not include the reuse or 
recycling of a fluorinated gas, the creation of HFC-23 during the 
production of HCFC-22, the creation of intermediates that are created 
and transformed in a single process with no storage of the 
intermediates, or the creation of fluorinated GHGs that are released or 
destroyed at the production facility before the production measurement 
in Sec. 98.414(a).



Sec. 98.121  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains a fluorinated gas production process that generates or emits 
fluorinated GHG and the facility meets the requirements of either Sec. 
98.2(a)(1) or (a)(2). To calculate GHG emissions for comparison to the 
25,000 metric ton CO2e per year emission threshold in Sec. 
98.2(a)(2), calculate process emissions from fluorinated gas production 
using uncontrolled GHG emissions.

[[Page 723]]



Sec. 98.122  GHGs to report.

    (a) You must report CO2, CH4, and 
N2O combustion emissions from each stationary combustion 
unit. You must calculate and report these emissions under subpart C of 
this part (General Stationary Fuel Combustion Sources) by following the 
requirements of subpart C.
    (b) You must report under subpart O of this part (HCFC-22 Production 
and HFC-23 Destruction) the emissions of HFC-23 from HCFC-22 production 
processes and HFC-23 destruction processes. Do not report the generation 
and emissions of HFC-23 from HCFC-22 production under this subpart.
    (c) Emissions from production and transformation processes, process 
level. You must report, for each fluorinated GHG group, the total GWP-
weighted mass of all fluorinated GHGs in that group (in metric tons 
CO2e) emitted from:
    (1) Each fluorinated gas production process.
    (2) Each fluorinated gas transformation process that is not part of 
a fluorinated gas production process and where no fluorinated GHG 
reactant is produced at another facility.
    (3) Each fluorinated gas transformation process that is not part of 
a fluorinated gas production process and where one or more fluorinated 
GHG reactants are produced at another facility.
    (d) Emissions from production and transformation processes, facility 
level, multiple products. If your facility produces more than one 
fluorinated gas product, you must report the emissions (in metric tons) 
from production and transformation processes, totaled across the 
facility as a whole, of each fluorinated GHG that is emitted in 
quantities of 1,000 metric tons of CO2e or more from 
production or transformation processes, totaled across the facility as a 
whole. Aggregate and report emissions of all other fluorinated GHGs from 
production and transformation processes by fluorinated GHG group for the 
facility as a whole, in metric tons of CO2e.
    (e) Emissions from production and transformation processes, facility 
level, one product only. If your facility produces only one fluorinated 
gas product, aggregate and report the GWP-weighted emissions from 
production and transformation processes of fluorinated GHGs by 
fluorinated GHG group for the facility as a whole, in metric tons 
CO2e, with the following exception: Where emissions consist 
of a major fluorinated GHG constituent of a fluorinated gas product, and 
the product is sold or transferred to another person, report the total 
mass of each fluorinated GHG that is emitted from production and 
transformation processes and that is a major fluorinated GHG constituent 
of the product (in metric tons).
    (f) Emissions from destruction processes and venting of containers. 
You must report the total mass of each fluorinated GHG emitted (in 
metric tons) from:
    (1) Each fluorinated gas destruction process that is not part of a 
fluorinated gas production process or a fluorinated gas transformation 
process and all such fluorinated gas destruction processes combined.
    (2) Venting of residual fluorinated GHGs from containers returned 
from the field.

[75 FR 74831, Dec. 1, 2010, as amended at 79 FR 73785, Dec. 11, 2014



Sec. 98.123  Calculating GHG emissions.

    For fluorinated gas production and transformation processes, you 
must calculate the fluorinated GHG emissions from each process using the 
emission factor or emission calculation factor method specified in 
paragraphs (c), (d), and (e) of this section, as appropriate. For 
destruction processes that destroy fluorinated GHGs that were previously 
``produced'' as defined at Sec. 98.410(b), you must calculate emissions 
using the procedures in paragraph (f) of this section. For venting of 
residual gas from containers (e.g., cylinder heels), you must calculate 
emissions using the procedures in paragraph (g) of this section.
    (a) [Reserved]
    (b) Mass balance method. The mass balance method was available for 
reporting years 2011, 2012, 2013, and 2014 only. See paragraph 1 of 
appendix A of this subpart for the former mass balance method.
    (c) Emission factor and emission calculation factor methods. To use 
the

[[Page 724]]

method in this paragraph for batch processes, you must comply with 
either paragraph (c)(3) of this section (Emission Factor approach) or 
paragraph (c)(4) of this section (Emission Calculation Factor approach). 
To use the method in this paragraph for continuous processes, you must 
first make a preliminary estimate of the emissions from each individual 
continuous process vent under paragraph (c)(1) of this section. If your 
continuous process operates under different conditions as part of normal 
operations, you must also define the different operating scenarios and 
make a preliminary estimate of the emissions from the vent for each 
operating scenario. Then, compare the preliminary estimate for each 
continuous process vent (summed across operating scenarios) to the 
criteria in paragraph (c)(2) of this section to determine whether the 
process vent meets the criteria for using the emission factor method 
described in paragraph (c)(3) of this section or whether the process 
vent meets the criteria for using the emission calculation factor method 
described in paragraph (c)(4) of this section. For continuous process 
vents that meet the criteria for using the emission factor method 
described in paragraph (c)(3) of this section and that have more than 
one operating scenario, compare the preliminary estimate for each 
operating scenario to the criteria in (c)(3)(ii) to determine whether an 
emission factor must be developed for that operating scenario.
    (1) Preliminary estimate of emissions by process vent. You must 
estimate the annual CO2e emissions of fluorinated GHGs for 
each process vent within each operating scenario of a continuous process 
using the approaches specified in paragraph (c)(1)(i) or (c)(1)(ii) of 
this section, accounting for any destruction as specified in paragraph 
(c)(1)(iii) of this section. You must determine emissions of fluorinated 
GHGs by process vent by using measurements, by using calculations based 
on chemical engineering principles and chemical property data, or by 
conducting an engineering assessment. You may use previous measurements, 
calculations, and assessments if they represent current process 
operating conditions or process operating conditions that would result 
in higher fluorinated GHG emissions than the current operating 
conditions and if they were performed in accordance with paragraphs 
(c)(1)(i), (c)(1)(ii), and (c)(1)(iii) of this section, as applicable. 
You must document all data, assumptions, and procedures used in the 
calculations or engineering assessment and keep a record of the 
emissions determination as required by Sec. 98.127(a).
    (i) Engineering calculations. For process vent emission 
calculations, you may use any of paragraphs (c)(1)(i)(A), (c)(1)(i)(B), 
or (c)(1)(i)(C) of this section.
    (A) U.S. Environmental Protection Agency, Emission Inventory 
Improvement Program, Volume II: Chapter 16, Methods for Estimating Air 
Emissions from Chemical Manufacturing Facilities, August 2007, Final 
(incorporated by reference, see Sec. 98.7).
    (B) You may determine the fluorinated GHG emissions from any process 
vent within the process using the procedures specified in Sec. 
63.1257(d)(2)(i) and (d)(3)(i)(B) of this chapter, except as specified 
in paragraphs (c)(1)(i)(B)(1) through (c)(1)(i)(B)(4) of this section. 
For the purposes of this subpart, use of the term ``HAP'' in Sec. 
63.1257(d)(2)(i) and (d)(3)(i)(B) of this chapter means ``fluorinated 
GHG''.
    (1) To calculate emissions caused by the heating of a vessel without 
a process condenser to a temperature lower than the boiling point, you 
must use the procedures in Sec. 63.1257(d)(2)(i)(C)(3) of this chapter.
    (2) To calculate emissions from depressurization of a vessel without 
a process condenser, you must use the procedures in Sec. 
63.1257(d)(2)(i)(D)(10) of this chapter.
    (3) To calculate emissions from vacuum systems, the terms used in 
Equation 33 to Sec. 63.1257(d)(2)(i)(E) of this chapter are defined as 
follows:
    (i) Psystem = Absolute pressure of the receiving vessel.
    (ii) Pi= Partial pressure of the fluorinated GHG 
determined at the exit temperature and exit pressure conditions of the 
condenser or at the conditions of the dedicated receiver.
    (iii) Pj= Partial pressure of condensables (including 
fluorinated

[[Page 725]]

GHG) determined at the exit temperature and exit pressure conditions of 
the condenser or at the conditions of the dedicated receiver.
    (iv) MWFluorinated GHG= Molecular weight of the 
fluorinated GHG determined at the exit temperature and exit pressure 
conditions of the condenser or at the conditions of the dedicated 
receiver.
    (4) To calculate emissions when a vessel is equipped with a process 
condenser or a control condenser, you must use the procedures in Sec. 
63.1257(d)(3)(i)(B) of this chapter, except as follows:
    (i) You must determine the flowrate of gas (or volume of gas), 
partial pressures of condensables, temperature (T), and fluorinated GHG 
molecular weight (MWFluorinated GHG) at the exit temperature 
and exit pressure conditions of the condenser or at the conditions of 
the dedicated receiver.
    (ii) You must assume that all of the components contained in the 
condenser exit vent stream are in equilibrium with the same components 
in the exit condensate stream (except for noncondensables).
    (iii) You must perform a material balance for each component, if the 
condensate receiver composition is not known.
    (iv) For the emissions from gas evolution, the term for time, t, 
must be used in Equation 12 to Sec. 63.1257(d)(2)(i)(B) of this 
chapter.
    (v) Emissions from empty vessel purging must be calculated using 
Equation 36 to Sec. 63.1257(d)(2)(i)(H) of this chapter and the exit 
temperature and exit pressure conditions of the condenser or the 
conditions of the dedicated receiver.
    (C) Commercial software products that follow chemical engineering 
principles (e.g., including the calculation methodologies in paragraphs 
(c)(1)(i)(A) and (c)(1)(i)(B) of this section).
    (ii) Engineering assessments. For process vent emissions 
determinations, you may conduct an engineering assessment to calculate 
uncontrolled emissions. An engineering assessment includes, but is not 
limited to, the following:
    (A) Previous test results, provided the tests are representative of 
current operating practices of the process.
    (B) Bench-scale or pilot-scale test data representative of the 
process operating conditions.
    (C) Maximum flow rate, fluorinated GHG emission rate, concentration, 
or other relevant parameters specified or implied within a permit limit 
applicable to the process vent.
    (D) Design analysis based on chemical engineering principles, 
measureable process parameters, or physical or chemical laws or 
properties.
    (iii) Impact of destruction for the preliminary estimate. If the 
process vent is vented to a destruction device, you may reflect the 
impact of the destruction device on emissions. In your emissions 
estimate, account for the following:
    (A) The destruction efficiencies of the device that have been 
demonstrated for the fluorinated GHGs in the vent stream for periods 
when the process vent is vented to the destruction device.
    (B) Any periods when the process vent is not vented to the 
destruction device.
    (iv) Use of typical recent values. In the calculations in paragraphs 
(c)(1)(i), (c)(1)(ii), and (c)(1)(iii) of this section, the values used 
for the expected process activity and for the expected fraction of that 
activity whose emissions will be vented to the properly functioning 
destruction device must be based on either typical recent values for the 
process or values that would overestimate emissions from the process, 
unless there is a compelling reason to adopt a different value (e.g., 
installation of a destruction device for a previously uncontrolled 
process). If there is such a reason, it must be documented in the GHG 
Monitoring Plan.
    (v) GWPs. To convert the fluorinated GHG emissions to 
CO2e, use Equation A-1 of Sec. 98.2.
    (vi) [Reserved]
    (2) Method selection for continuous process vents.
    (i) If the calculations under paragraph (c)(1) of this section, as 
well as any subsequent measurements and calculations under this subpart, 
indicate

[[Page 726]]

that the continuous process vent has fluorinated GHG emissions of less 
than 10,000 metric ton CO2e per year, summed across all 
operating scenarios, then you may comply with either paragraph (c)(3) of 
this section (Emission Factor approach) or paragraph (c)(4) of this 
section (Emission Calculation Factor approach).
    (ii) If the continuous process vent does not meet the criteria in 
paragraph (c)(2)(i) of this section, then you must comply with the 
emission factor method specified in paragraph (c)(3) (Emission Factor 
approach) of this section.
    (A) You must conduct emission testing for process-vent-specific 
emission factor development before the destruction device unless the 
calculations you performed under paragraph (c)(1)(iii) of this section 
indicate that the uncontrolled fluorinated GHG emissions that occur 
during periods when the process vent is not vented to the properly 
functioning destruction device are less than 10,000 metric tons 
CO2e per year. In this case, you may conduct emission testing 
after the destruction device to develop a process-vent-specific emission 
factor. If you do so, you must develop and apply an emission calculation 
factor under paragraph (c)(4) to estimate emissions during any periods 
when the process vent is not vented to the properly functioning 
destruction device.
    (B) Regardless of the level of uncontrolled emissions, the emission 
testing for process-vent-specific emission factor development may be 
conducted on the outlet side of a wet scrubber in place for acid gas 
reduction, if one is in place, as long as there is no appreciable 
reduction in the fluorinated GHG.
    (3) Process-vent-specific emission factor method. For each process 
vent, conduct an emission test and measure fluorinated GHG emissions 
from the process and measure the process activity, such as the feed 
rate, production rate, or other process activity rate, during the test 
as described in this paragraph (c)(3). Conduct the emission test 
according to the procedures in Sec. 98.124. All emissions test data and 
procedures used in developing emission factors must be documented 
according to Sec. 98.127. If more than one operating scenario applies 
to the process that contains the subject process vent, you must comply 
with either paragraph (3)(i) or paragraph (3)(ii) of this section.
    (i) Conduct a separate emissions test for operation under each 
operating scenario.
    (ii) Conduct an emissions test for the operating scenario that is 
expected to have the largest emissions in terms of CO2e 
(considering both activity levels and emission calculation factors) on 
an annual basis. Also conduct an emissions test for each additional 
operating scenario that is estimated to emit 10,000 metric tons 
CO2e or more annually from the vent and whose emission 
calculation factor differs by 15 percent or more from the emission 
calculation factor of the operating scenario that is expected to have 
the largest emissions (or of another operating scenario for which 
emission testing is performed), unless the difference between the 
operating scenarios is solely due to the application of a destruction 
device to emissions under one of the operating scenarios. For any other 
operating scenarios, adjust the process-vent specific emission factor 
developed for the operating scenario that is expected to have the 
largest emissions (or for another operating scenario for which emission 
testing is performed) using the approach in paragraph (c)(3)(viii) of 
this section.
    (iii) You must measure the process activity, such as the process 
feed rate, process production rate, or other process activity rate, as 
applicable, during the emission test and calculate the rate for the test 
period, in kg (or another appropriate metric) per hour.
    (iv) For continuous processes, you must calculate the hourly 
emission rate of each fluorinated GHG using Equation L-19 of this 
section and determine the hourly emission rate of each fluorinated GHG 
per process vent (and per operating scenario, as applicable) for the 
test run.

[[Page 727]]

[GRAPHIC] [TIFF OMITTED] TR01DE10.037

Where:

EContPV = Mass of fluorinated GHG f emitted from process vent 
          v from process i, operating scenario j, during the emission 
          test during test run r (kg/hr).
CPV = Concentration of fluorinated GHG f during test run r of 
          the emission test (ppmv).
MW = Molecular weight of fluorinated GHG f (g/g-mole).
QPV = Flow rate of the process vent stream during test run r 
          of the emission test (m\3\/min).
SV = Standard molar volume of gas (0.0240 m\3\/g-mole at 68  deg.F and 1 
          atm).
1/10\3\ = Conversion factor (1 kilogram/1,000 grams).
60/1 = Conversion factor (60 minutes/1 hour).

    (v) You must calculate a site-specific, process-vent-specific 
emission factor for each fluorinated GHG for each process vent and each 
operating scenario, in kg of fluorinated GHG per process activity rate 
(e.g., kg of feed or production), as applicable, using Equation L-20 of 
this section. For continuous processes, divide the hourly fluorinated 
GHG emission rate during the test by the hourly process activity rate 
during the test runs.
[GRAPHIC] [TIFF OMITTED] TR01DE10.038

Where:

EFPV = Emission factor for fluorinated GHG f emitted from 
          process vent v during process i, operating scenario j (e.g., 
          kg emitted/kg activity).
EPV = Mass of fluorinated GHG f emitted from process vent v 
          from process i, operating scenario j, during the emission test 
          during test run r, for either continuous or batch (kg emitted/
          hr for continuous, kg emitted/batch for batch).
ActivityEmissionTest = Process feed, process production, or 
          other process activity rate for process i, operating scenario 
          j, during the emission test during test run r (e.g., kg 
          product/hr).
r = Number of test runs performed during the emission test.

    (vi) If you conducted emissions testing after the destruction 
device, you must calculate the emissions of each fluorinated GHG for the 
process vent (and operating scenario, as applicable) using Equation L-21 
of this section. You must also develop a process-vent-specific emission 
calculation factor based on paragraph (c)(4) of this section for the 
periods when the process vent is not venting to the destruction device.
[GRAPHIC] [TIFF OMITTED] TR01DE10.039

Where:

EPV = Mass of fluorinated GHG f emitted from process vent v 
          from process i, operating scenario j, for the year (kg).
EFPV-C = Emission factor for fluorinated GHG f emitted from 
          process vent v during process i, operating scenario j, based 
          on testing after the destruction device (kg emitted/activity) 
          (e.g., kg emitted/kg product).
ActivityC = Total process feed, process production, or other 
          process activity for process i, operating scenario j, during 
          the year for which emissions are vented to the properly 
          functioning destruction device (i.e., controlled).

[[Page 728]]

ECFPV-U = Emission calculation factor for fluorinated GHG f 
          emitted from process vent v during process i, operating 
          scenario j during periods when the process vent is not vented 
          to the properly functioning destruction device (kg emitted/
          activity) (e.g., kg emitted/kg product).
ActivityU = Total process feed, process production, or other 
          process activity during the year for which the process vent is 
          not vented to the properly functioning destruction device 
          (e.g., kg product).

    (vii) If you conducted emissions testing before the destruction 
device, apply the destruction efficiencies of the device that have been 
demonstrated for the fluorinated GHGs in the vent stream to the 
fluorinated GHG emissions for the process vent (and operating scenario, 
as applicable), using Equation L-22 of this section. You may apply the 
destruction efficiency only to the portion of the process activity 
during which emissions are vented to the properly functioning 
destruction device (i.e., controlled).
[GRAPHIC] [TIFF OMITTED] TR01DE10.040

where:

EPV = Mass of fluorinated GHG f emitted from process vent v 
          from process i, operating scenario j, for the year, 
          considering destruction efficiency (kg).
EFPV-U = Emission factor (uncontrolled) for fluorinated GHG f 
          emitted from process vent v during process i, operating 
          scenario j (kg emitted/kg product).
ActivityU = Total process feed, process production, or other 
          process activity for process i, operating scenario j, during 
          the year for which the process vent is not vented to the 
          properly functioning destruction device (e.g., kg product).
ActivityC = Total process feed, process production, or other 
          process activity for process i, operating scenario j, during 
          the year for which the process vent is vented to the properly 
          functioning destruction device (e.g., kg product).
DE = Demonstrated destruction efficiency of the destruction device 
          (weight fraction).

    (viii) Adjusted process-vent-specific emission factors for other 
operating scenarios. For process vents from processes with multiple 
operating scenarios, use Equation L-23 of this section to develop an 
adjusted process-vent-specific emission factor for each operating 
scenario from which the vent is estimated to emit less than 10,000 
metric tons CO2e annually or whose emission calculation 
factor differs by less than 15 percent from the emission calculation 
factor of the operating scenario that is expected to have the largest 
emissions (or of another operating scenario for which emission testing 
is performed).
[GRAPHIC] [TIFF OMITTED] TR01DE10.041

where:

EFPVadj = Adjusted process-vent-specific emission factor for 
          an untested operating scenario.
ECFUT = Emission calculation factor for the untested 
          operating scenario developed under paragraph (c)(4) of this 
          section.
ECFT = Emission calculation for the tested operating scenario 
          developed under paragraph (c)(4) of this section.
EFPV = Process vent specific emission factor for the tested 
          operating scenario.

    (ix) Sum the emissions of each fluorinated GHG from all process 
vents in each operating scenario and all operating scenarios in the 
process for the year to estimate the total process vent emissions of 
each fluorinated GHG from the process, using Equation L-24 of this 
section.

[[Page 729]]

[GRAPHIC] [TIFF OMITTED] TR01DE10.042

where:

EPfi = Mass of fluorinated GHG f emitted from process vents 
          for process i for the year (kg).
EPV = Mass of fluorinated GHG f emitted from process vent v 
          from process i, operating scenario j, for the year, 
          considering destruction efficiency (kg).
v = Number of process vents in process i, operating scenario j.
o = Number of operating scenarios for process i.

    (4) Process-vent-specific emission calculation factor method. For 
each process vent within an operating scenario, determine fluorinated 
GHG emissions by calculations and determine the process activity rate, 
such as the feed rate, production rate, or other process activity rate, 
associated with the emission rate.
    (i) You must calculate uncontrolled emissions of fluorinated GHG by 
individual process vent, EPV, by using measurements, by using 
calculations based on chemical engineering principles and chemical 
property data, or by conducting an engineering assessment. Use the 
procedures in paragraphs (c)(1)(i) or (ii) of this section, except 
paragraph (c)(1)(ii)(C) of this section. The procedures in paragraphs 
(c)(1)(i) and (ii) of this section may be applied either to batch 
process vents or to continuous process vents. The uncontrolled emissions 
must be based on a typical batch or production rate under a defined 
operating scenario. The process activity rate associated with the 
uncontrolled emissions must be determined. The methods, data, and 
assumptions used to estimate emissions for each operating scenario must 
be selected to yield a best estimate (expected value) of emissions 
rather than an over- or underestimate of emissions for that operating 
scenario. All data, assumptions, and procedures used in the calculations 
or engineering assessment must be documented according to Sec. 98.127.
    (ii) You must calculate a site-specific, process-vent-specific 
emission calculation factor for each process vent, each operating 
scenario, and each fluorinated GHG, in kg of fluorinated GHG per 
activity rate (e.g., kg of feed or production) as applicable, using 
Equation L-25 of this section.
[GRAPHIC] [TIFF OMITTED] TR01DE10.043

where:

ECFPV = Emission calculation factor for fluorinated GHG f 
          emitted from process vent v during process i, operating 
          scenario j, (e.g., kg emitted/kg product).
EPV = Average mass of fluorinated GHG f emitted, based on 
          calculations, from process vent v from process i, operating 
          scenario j, during the period or batch for which emissions 
          were calculated, for either continuous or batch (kg emitted/hr 
          for continuous, kg emitted/batch for batch).
ActivityRepresentative = Process feed, process production, or 
          other process activity rate corresponding to average mass of 
          emissions based on calculations (e.g., kg product/hr for 
          continuous, kg product/batch for batch).

    (iii) You must calculate emissions of each fluorinated GHG for the 
process vent (and operating scenario, as applicable) for the year by 
multiplying the process-vent-specific emission calculation factor by the 
total process activity, as applicable, for the year, using Equation L-26 
of this section.

[[Page 730]]

[GRAPHIC] [TIFF OMITTED] TR01DE10.044

where:

EPV = Mass of fluorinated GHG f emitted from process vent v 
          from process i, operating scenario j, for the year (kg).
ECFPV = Emission calculation factor for fluorinated GHG f 
          emitted from process vent v during process i, operating 
          scenario j, (kg emitted/activity) (e.g., kg emitted/kg 
          product).
Activity = Process feed, process production, or other process activity 
          for process i, operating scenario j, during the year.

    (iv) If the process vent is vented to a destruction device, apply 
the demonstrated destruction efficiency of the device to the fluorinated 
GHG emissions for the process vent (and operating scenario, as 
applicable), using Equation L-27 of this section. Apply the destruction 
efficiency only to the portion of the process activity that is vented to 
the properly functioning destruction device (i.e., controlled).
[GRAPHIC] [TIFF OMITTED] TR01DE10.045

where:

EPV = Mass of fluorinated GHG f emitted from process vent v 
          from process i, operating scenario j, for the year considering 
          destruction efficiency (kg).
ECFPV = Emission calculation factor for fluorinated GHG f 
          emitted from process vent v during process i, operating 
          scenario j, (e.g., kg emitted/kg product).
ActivityU = Total process feed, process production, or other 
          process activity for process i, operating scenario j, during 
          the year for which the process vent is not vented to the 
          properly functioning destruction device (e.g., kg product).
ActivityC = Total process feed, process production, or other 
          process activity for process i, operating scenario j, during 
          the year for which the process vent is vented to the properly 
          functioning destruction device (e.g., kg product).
DE = Demonstrated destruction efficiency of the destruction device 
          (weight fraction).

    (v) Sum the emissions of each fluorinated GHG from all process vents 
in each operating scenario and all operating scenarios in the process 
for the year to estimate the total process vent emissions of each 
fluorinated GHG from the process, using Equation L-28 of this section.
[GRAPHIC] [TIFF OMITTED] TR01DE10.046

where:

EPfi = Mass of fluorinated GHG f emitted from process vents 
          for process i for the year (kg).
EPV = Mass of fluorinated GHG f emitted from process vent v 
          from process i, operating scenario j, for the year, 
          considering destruction efficiency (kg).
v = Number of process vents in process i, operating scenario j.
o = Number of operating scenarios in process i.

    (d) Calculate fluorinated GHG emissions for equipment leaks (EL). If 
you comply with paragraph (c) of this section, you must calculate the 
fluorinated GHG emissions from pieces of equipment associated with 
processes covered under this subpart and in fluorinated GHG service. If 
you conduct monitoring of equipment in fluorinated GHG service, 
monitoring must be conducted for those in light liquid and in gas and 
vapor service. If you conduct monitoring of equipment in fluorinated GHG 
service, you may exclude from monitoring each piece of equipment that is 
difficult-to-monitor, that is unsafe-to-monitor, that is insulated, or 
that is in heavy liquid service; you may exclude from monitoring each

[[Page 731]]

pump with dual mechanical seals, agitator with dual mechanical seals, 
pump with no external shaft, agitator with no external shaft; you may 
exclude from monitoring each pressure relief device in gas and vapor 
service with upstream rupture disk, each sampling connection system with 
closed-loop or closed-purge systems, and any pieces of equipment where 
leaks are routed through a closed vent system to a destruction device. 
You must estimate emissions using another approach for those pieces of 
equipment excluded from monitoring. Equipment that is in fluorinated GHG 
service for less than 300 hr/yr; equipment that is in vacuum service; 
pressure relief devices that are in light liquid service; and 
instrumentation systems are exempted from these requirements.
    (1) The emissions from equipment leaks must be calculated using any 
of the procedures in paragraphs (d)(1)(i), (d)(1)(ii), (d)(1)(iii), or 
(d)(1)(iv) of this section.
    (i) Use of Average Emission Factor Approach in EPA Protocol for 
Equipment Leak Emission Estimates. The emissions from equipment leaks 
may be calculated using the default Average Emission Factor Approach in 
EPA-453/R-95-017 (incorporated by reference, see Sec. 98.7).
    (ii) Use of Other Approaches in EPA Protocol for Equipment Leak 
Emission Estimates in conjunction with EPA Method 21 at 40 CFR part 60, 
appendix A-7. The emissions from equipment leaks may be calculated using 
one of the following methods in EPA-453/R-95-017 (incorporated by 
reference, see Sec. 98.7): The Screening Ranges Approach; the EPA 
Correlation Approach; or the Unit-Specific Correlation Approach. If you 
determine that EPA Method 21 at 40 CFR part 60, appendix A-7 is 
appropriate for monitoring a fluorinated GHG, and if you calibrate your 
instrument with a compound different from one or more of the fluorinated 
GHGs or surrogates to be measured, you must develop response factors for 
each fluorinated GHG or for each surrogate to be measured using EPA 
Method 21 at 40 CFR part 60, appendix A-7. For each fluorinated GHG or 
surrogate measured, the response factor must be less than 10. The 
response factor is the ratio of the known concentration of a fluorinated 
GHG or surrogate to the observed meter reading when measured using an 
instrument calibrated with the reference compound.
    (iii) Use of Other Approaches in EPA Protocol for Equipment Leak 
Emission Estimates in conjunction with site-specific leak monitoring 
methods. The emissions from equipment leaks may be calculated using one 
of the following methods in EPA-453/R-95-017 (incorporated by reference, 
see Sec. 98.7): The Screening Ranges Approach; the EPA Correlation 
Approach; or the Unit-Specific Correlation Approach. You may develop a 
site-specific leak monitoring method appropriate for monitoring 
fluorinated GHGs or surrogates to use along with these three approaches. 
The site-specific leak monitoring method must meet the requirements in 
Sec. 98.124(f)(1).
    (iv) Use of site-specific leak monitoring methods. The emissions 
from equipment leaks may be calculated using a site-specific leak 
monitoring method. The site-specific leak monitoring method must meet 
the requirements in Sec. 98.124(f)(1).
    (2) You must collect information on the number of each type of 
equipment; the service of each piece of equipment (gas, light liquid, 
heavy liquid); the concentration of each fluorinated GHG in the stream; 
and the time period each piece of equipment was in service. Depending on 
which approach you follow, you may be required to collect information 
for equipment on the associated screening data concentrations for 
greater than or equal to 10,000 ppmv and associated screening data 
concentrations for less than 10,000 ppmv; associated actual screening 
data concentrations; or associated screening data and leak rate data 
(i.e., bagging) used to develop a unit-specific correlation.
    (3) Calculate and sum the emissions of each fluorinated GHG in 
metric tons per year for equipment pieces for each process, 
EELf, annually. You must include and estimate emissions for 
types of equipment that are excluded from monitoring, including 
difficult-to-monitor, unsafe-to-monitor and insulated pieces of 
equipment, pieces of equipment in heavy liquid service, pumps

[[Page 732]]

with dual mechanical seals, agitators with dual mechanical seals, pumps 
with no external shaft, agitators with no external shaft, pressure 
relief devices in gas and vapor service with upstream rupture disk, 
sampling connection systems with closed-loop or closed purge systems, 
and pieces of equipment where leaks are routed through a closed vent 
system to a destruction device.
    (e) Calculate total fluorinated GHG emissions for each process and 
for production or transformation processes at the facility. (1) Estimate 
annually the total mass of each fluorinated GHG emitted from each 
process, including emissions from process vents in paragraphs (c)(3) and 
(c)(4) of this section, as appropriate, and from equipment leaks in 
paragraph (d), using Equation L-29 of this section.
[GRAPHIC] [TIFF OMITTED] TR01DE10.047

where:

Ei = Total mass of each fluorinated GHG f emitted from 
          process i, annual basis (kg/year).
EPfi = Mass of fluorinated GHG f emitted from all process 
          vents and all operating scenarios in process i, annually (kg/
          year, calculated in Equation L-24 or L-28 of this section, as 
          appropriate).
EELfi = Mass of fluorinated GHG f emitted from equipment 
          leaks for pieces of equipment for process i, annually (kg/
          year, calculated in paragraph (d)(3) of this section).

    (2) Estimate annually the total mass of each fluorinated GHG emitted 
from each type of production or transformation process at the facility 
using Equation L-30 of this section. Develop separate totals for 
fluorinated gas production processes, transformation processes that 
transform fluorinated gases produced at the facility, and transformation 
processes that transform fluorinated gases produced at another facility.
[GRAPHIC] [TIFF OMITTED] TR01DE10.048

where:

E = Total mass of each fluorinated GHG f emitted from all fluorinated 
          gas production processes, all transformation processes that 
          transform fluorinated gases produced at the facility, or all 
          transformation processes that transform fluorinated gases 
          produced at another facility, as appropriate (metric tons).
Ei = Total mass of each fluorinated GHG f emitted from each 
          production or transformation process, annual basis (kg/year, 
          calculated in Equation L-29 of this section).
0.001 = Conversion factor from kg to metric tons.
z = Total number of fluorinated gas production processes, fluorinated 
          gas transformation processes that transform fluorinated gases 
          produced at the facility, or transformation processes that 
          transform fluorinated gases produced at another facility, as 
          appropriate.

    (f) Calculate fluorinated GHG emissions from destruction of 
fluorinated GHGs that were previously ``produced''. Estimate annually 
the total mass of fluorinated GHGs emitted from destruction of 
fluorinated GHGs that were previously ``produced'' as defined at Sec. 
98.410(b) using Equation L-31 of this section:
[GRAPHIC] [TIFF OMITTED] TR01DE10.049


[[Page 733]]


where:

ED = The mass of fluorinated GHGs emitted annually from 
          destruction of fluorinated GHGs that were previously 
          ``produced'' as defined at Sec. 98.410(b) (metric tons).
RED = The mass of fluorinated GHGs that were previously 
          ``produced'' as defined at Sec. 98.410(b) and that are fed 
          annually into the destruction device (metric tons).
DE = Destruction efficiency of the destruction device (fraction).

    (g) Emissions from venting of residual fluorinated GHGs in 
containers. If you vent residual fluorinated GHGs from containers, you 
must either measure the residual fluorinated GHGs vented from each 
container or develop a heel factor for each combination of fluorinated 
GHG, container size, and container type that you vent. You do not need 
to estimate de minimis emissions associated with good-faith attempts to 
recycle or recover residual fluorinated GHGs in or from containers.
    (1) Measuring contents of each container. If you weigh or otherwise 
measure the contents of each container before venting the residual 
fluorinated GHGs, use Equation L-32 of this section to calculate annual 
emissions of each fluorinated GHG from venting of residual fluorinated 
GHG from containers. Convert pressures to masses as directed in 
paragraph (g)(2)(ii) of this section.
[GRAPHIC] [TIFF OMITTED] TR11DE14.001

Where:

ECf = Total mass of each fluorinated GHG f emitted from the 
          facility through venting of residual fluorinated GHG from 
          containers, annual basis (metric tons/year).
HBfj = Mass of residual fluorinated GHG f in container j when 
          received by facility (metric tons).
HEfj = Mass of residual fluorinated GHG f in container j 
          after evacuation by facility (metric tons). (Facility may 
          equate to zero.)
n = Number of vented containers for each fluorinated GHG f.

    (2) Developing and applying heel factors. If you use heel factors to 
estimate emissions of residual fluorinated GHGs vented from containers, 
you must annually develop these factors based on representative samples 
of the containers received by your facility from fluorinated GHG users.
    (i) Sample size. For each combination of fluorinated GHG, container 
size, and container type that you vent, select a representative sample 
of containers that reflects the full range of quantities of residual gas 
returned in that container size and type. This sample must reflect the 
full range of the industries and a broad range of the customers that use 
and return the fluorinated GHG, container size, and container type. The 
minimum sample size for each combination of fluorinated GHG, container 
size, and container type must be 30, unless this is greater than the 
number of containers returned within that combination annually, in which 
case the contents of every container returned must be measured.
    (ii) Measurement of residual gas. The residual weight or pressure 
you use for paragraph (g)(1) of this section must be determined by 
monitoring the mass or the pressure of your cylinders/containers 
according to Sec. 98.124(k). If you monitor the pressure, convert the 
pressure to mass using a form of the ideal gas law, as displayed in 
Equation L-33 of this section, with an appropriately selected Z value.
[GRAPHIC] [TIFF OMITTED] TR11DE14.002


[[Page 734]]


Where:

mR = Mass of residual gas in the container (metric ton).
p = Absolute pressure of the gas (Pa).
V = Volume of the gas (m\3\).
MW = Molecular weight of the fluorinated GHG f (g/gmole).
Z = Compressibility factor.
R = Gas constant (8.314 Pa m\3\/Kelvin mole).
T = Absolute temperature (K).
10\6\ = Conversion factor (10\6\ g/metric ton).

    (iii) Heel factor calculation. To determine the heel factor 
hfj for each combination of fluorinated GHG, container size, 
and container type, use paragraph (g)(1) of this section to calculate 
the total heel emissions for each sample selected under paragraph 
(g)(2)(i) of this section. Divide this total by the number of containers 
in the sample. Divide the result by the full capacity (the mass of the 
contents of a full container) of that combination of fluorinated GHG, 
container size, and container type. The heel factor is expressed as a 
fraction of the full capacity.
    (iv) Calculate annual emissions of each fluorinated GHG from venting 
of residual fluorinated GHG from containers using Equation L-34 of this 
section.
[GRAPHIC] [TIFF OMITTED] TR11DE14.003

Where:

ECf = Total mass of each fluorinated GHG f emitted from the 
          facility through venting of residual fluorinated GHG from 
          containers, annual basis (metric tons/year).
hfj = Facility-wide gas-specific heel factor for fluorinated 
          GHG f (fraction) and container size and type j, as determined 
          in paragraph (g)(2)(iii) of this section.
Nfj = Number of containers of size and type j returned to the 
          fluorinated gas production facility.
Ffj = Full capacity of containers of size and type j 
          containing fluorinated GHG f (metric tons).
n = Number of combinations of container sizes and types for fluorinated 
          GHG f.

    (h) Effective destruction efficiency for each process. If you used 
the emission factor or emission calculation factor method to calculate 
emissions from the process, use Equation L-35 to calculate the effective 
destruction efficiency for the process, including each process vent:
[GRAPHIC] [TIFF OMITTED] TR11DE14.004

Where:

DEEffective = Effective destruction efficiency for process i 
          (fraction).
EPVf = Mass of fluorinated GHG f emitted from process vent v 
          from process i, operating scenario j, for the year, calculated 
          in Equation L-21, L-22, L-26, or L-27 of this section (kg).
GWPf = Global warming potential for each greenhouse gas from 
          Table A-1 of subpart A of this part.
ECFPV-Uf = Emission calculation factor for fluorinated GHG f 
          emitted from process vent v during process i, operating 
          scenario j during periods when the process vent is not vented 
          to the properly functioning destruction device, as used in 
          Equation L-21; or emission calculation factor for fluorinated 
          GHG f emitted from process vent v during process i, operating 
          scenario j, as used in Equation L-26 or L-27 (kg emitted/
          activity) (e.g., kg emitted/kg product), denoted as 
          ``ECFPV'' in those equations.

[[Page 735]]

EFPV-Uf = Emission factor (uncontrolled) for fluorinated GHG 
          f emitted from process vent v during process i, operating 
          scenario j, as used in Equation L-22 (kg emitted/activity) 
          (e.g., kg emitted/kg product), denoted as 
          ``EFPV-U'' in that equation.
ActivityU = Total process feed, process production, or other 
          process activity for process i, operating scenario j during 
          the year, for which the process vent is not vented to the 
          properly functioning destruction device (i.e., uncontrolled).
ActivityC = Total process feed, process production, or other 
          process activity for process i, operating scenario j during 
          the year, for which emissions are vented to the properly 
          functioning destruction device (i.e., controlled).
o = Number of operating scenarios for process i.
v = Number of process vents in process i, operating scenario j.
w = Number of fluorinated GHGs emitted from the process.

[75 FR 74831, Dec. 1, 2010, as amended at 79 FR 73785, Dec. 11, 2014]



Sec. 98.124  Monitoring and QA/QC requirements.

    (a) Initial scoping speciation to identify fluorinated GHGs. You 
must conduct an initial scoping speciation to identify all fluorinated 
GHGs that may be generated from processes that are subject to this 
subpart and that have at least one process vent with uncontrolled 
emissions of 1.0 metric ton or more of fluorinated GHGs per year based 
on the preliminary estimate of emissions in Sec. 98.123(c)(1). You are 
not required to quantify emissions under this initial scoping 
speciation. Only fluorinated GHG products and by-products that occur in 
greater than trace concentrations in at least one stream must be 
identified under this paragraph.
    (1) Procedure. To conduct the scoping speciation, select the 
stream(s) (including process streams or destroyed streams) or process 
vent(s) that would be expected to individually or collectively contain 
all of the fluorinated GHG by-products of the process at their maximum 
concentrations and sample and analyze the contents of these selected 
streams or process vents. For example, if fluorinated GHG by-products 
are separated into one low-boiling-point and one high-boiling-point 
stream, sample and analyze both of these streams. Alternatively, you may 
sample and analyze streams where fluorinated GHG by-products occur at 
less than their maximum concentrations, but you must ensure that the 
sensitivity of the analysis is sufficient to compensate for the expected 
difference in concentration. For example, if you sample and analyze 
streams where fluorinated GHG by-products are expected to occur at one 
half their maximum concentrations elsewhere in the process, you must 
ensure that the sensitivity of the analysis is sufficient to detect 
fluorinated GHG by-products that occur at concentrations of 0.05 percent 
or higher. You do not have to sample and analyze every stream or process 
vent, i.e., you do not have to sample and analyze a stream or process 
vent that contains only fluorinated GHGs that are contained in other 
streams or process vents that are being sampled and analyzed. Sampling 
and analysis must be conducted according to the procedures in paragraph 
(e) of this section.
    (2) Previous measurements. If you have conducted testing of streams 
(including process streams or destroyed streams) or process vents less 
than 10 years before December 31, 2010, and the testing meets the 
requirements in paragraph (a)(1) of this section, you may use the 
previous testing to satisfy this requirement.
    (b) Mass balance monitoring. Mass balance monitoring was available 
for reporting years 2011, 2012, 2013, and 2014 only. See paragraph 2 of 
Appendix A of this subpart for the former mass balance method.
    (c) Emission factor testing. If you determine fluorinated GHG 
emissions using the site-specific process-vent-specific emission factor, 
you must meet the requirements in paragraphs (c)(1) through (c)(8) of 
this section.
    (1) Process vent testing. Conduct an emissions test that is based on 
representative performance of the process or operating scenario(s) of 
the process, as applicable. For process vents for which you performed an 
initial scoping speciation, include in the emission test any fluorinated 
GHG that was identified in the initial scoping speciation. For process 
vents for which you did not perform an initial scoping speciation, 
include in the emission test any

[[Page 736]]

fluorinated greenhouse gas that occurs in more than trace concentrations 
in the vent stream or, where a destruction device is used, in the inlet 
to the destruction device. You may include startup and shutdown events 
if the testing is sufficiently long or comprehensive to ensure that such 
events are not overrepresented in the emission factor. Malfunction 
events must not be included in the testing. If you do not detect a 
fluorinated GHG that was identified in the scoping speciation or that 
occurs in more than trace concentrations in the vent stream or in the 
inlet to the destruction device, assume that fluorinated GHG was emitted 
at one half of the detection limit.
    (2) Number of runs. For continuous processes, sample the process 
vent for a minimum of three runs of 1 hour each. If the relative 
standard deviation (RSD) of the emission factor calculated based on the 
first three runs is greater than or equal to 0.15 for the emission 
factor, continue to sample the process vent for an additional three runs 
of 1 hour each. If more than one fluorinated GHG is measured, the RSD 
must be expressed in terms of total CO2e.
    (3) Process activity measurements. Determine the mass rate of 
process feed, process production, or other process activity as 
applicable during the test using flow meters, weigh scales, or other 
measurement devices or instruments with an accuracy and precision of 
1 percent of full scale or better. These devices 
may be the same plant instruments or procedures that are used for 
accounting purposes (such as weigh hoppers, belt weigh feeders, 
combination of volume measurements and bulk density, etc.) if these 
devices or procedures meet the requirement. For monitoring ongoing 
process activity, use flow meters, weigh scales, or other measurement 
devices or instruments with an accuracy and precision of 1 percent of full scale or better.
    (4) Sample each process. If process vents from separate processes 
are manifolded together to a common vent or to a common destruction 
device, you must follow paragraph (c)(4)(i), (c)(4)(ii), or (c)(4)(iii) 
of this section.
    (i) You may sample emissions from each process in the ducts before 
the emissions are combined.
    (ii) You may sample in the common duct or at the outlet of the 
destruction device when only one process is operating.
    (iii) You may sample the combined emissions and use engineering 
calculations and assessments as specified in Sec. 98.123(c)(4) to 
allocate the emissions to each manifolded process vent, provided the sum 
of the calculated fluorinated GHG emissions across the individual 
process vents is within 20 percent of the total fluorinated GHG 
emissions measured during the manifolded testing.
    (5) Emission test results. The results of an emission test must 
include the analysis of samples, number of test runs, the results of the 
RSD analysis, the analytical method used, determination of emissions, 
the process activity, and raw data and must identify the process, the 
operating scenario, the process vents tested, and the fluorinated GHGs 
that were included in the test. The emissions test report must contain 
all information and data used to derive the process-vent-specific 
emission factor, as well as key process conditions during the test. Key 
process conditions include those that are normally monitored for process 
control purposes and may include but are not limited to yields, 
pressures, temperatures, etc. (e.g., of reactor vessels, distillation 
columns).
    (6) Emissions testing frequency. You must conduct emissions testing 
to develop the process-vent-specific emission factor under paragraph 
(c)(7)(i) or (c)(7)(ii) of this section, whichever occurs first:
    (i) 10-year revision. Conduct an emissions test every 10 years. In 
the calculations under Sec. 98.123, apply the revised process-vent-
specific emission factor to the process activity that occurs after the 
revision.
    (ii) Operating scenario change that affects the emission factor. For 
planned operating scenario changes, you must estimate and compare the 
emission calculation factors for the changed operating scenario and for 
the original operating scenario whose process vent specific emission 
factor was measured. Use the calculation methods in Sec. 98.123(c)(4). 
If the emission calculation

[[Page 737]]

factor for the changed operating scenario is 15 percent or more 
different from the emission calculation factor for the previous 
operating scenario (this includes the cumulative change in the emission 
calculation factor since the last emissions test), you must conduct an 
emissions test to update the process-vent-specific emission factor, 
unless the difference between the operating scenarios is solely due to 
the application of a destruction device to emissions under the changed 
operating scenario. Conduct the test before February 28 of the year that 
immediately follows the change. In the calculations under Sec. 98.123, 
apply the revised process-vent-specific emission factor to the process 
activity that occurs after the operating scenario change.
    (7) Subsequent measurements. If a continuous process vent with 
fluorinated GHG emissions less than 10,000 metric tons CO2e, 
per Sec. 98.123(c)(2), is later found to have fluorinated GHG emissions 
of 10,000 metric tons CO2e or greater, you must conduct the 
emissions testing for the process vent during the following year and 
develop the process-vent-specific emission factor from the emissions 
testing.
    (8) Previous measurements. If you have conducted an emissions test 
less than 10 years before December 31, 2010, and the emissions testing 
meets the requirements in paragraphs (c)(1) through (c)(8) of this 
section, you may use the previous emissions testing to develop process-
vent-specific emission factors. For purposes of paragraph (c)(7)(i) of 
this section, the date of the previous emissions test rather than 
December 31, 2010 shall constitute the beginning of the 10-year re-
measurement cycle.
    (d) Emission calculation factor monitoring. If you determine 
fluorinated GHG emissions using the site-specific process-vent-specific 
emission calculation factor, you must meet the requirements in 
paragraphs (d)(1) through (d)(4) of this section.
    (1) Operating scenario. Perform the emissions calculation for the 
process vent based on representative performance of the operating 
scenario of the process. If more than one operating scenario applies to 
the process that contains the subject process vent, you must conduct a 
separate emissions calculation for operation under each operating 
scenario. For each continuous process vent that contains more than trace 
concentrations of any fluorinated GHG and for each batch process vent 
that contains more than trace concentrations of any fluorinated GHG, 
develop the process-vent-specific emission calculation factor for each 
operating scenario. For continuous process vents, determine the 
emissions based on the process activity for the representative 
performance of the operating scenario. For batch process vents, 
determine emissions based on the process activity for each typical batch 
operating scenario.
    (2) Process activity measurements. Use flow meters, weigh scales, or 
other measurement devices or instruments with an accuracy and precision 
of 1 percent of full scale or better for 
monitoring ongoing process activity.
    (3) Emission calculation results. The emission calculation must be 
documented by identifying the process, the operating scenario, and the 
process vents. The documentation must contain the information and data 
used to calculate the process-vent-specific emission calculation factor.
    (4) Operating scenario change that affects the emission calculation 
factor. For planned operating scenario changes that are expected to 
change the process-vent-specific emission calculation factor, you must 
conduct an emissions calculation to update the process-vent-specific 
emission calculation factor. In the calculations under Sec. 98.123, 
apply the revised emission calculation factor to the process activity 
that occurs after the operating scenario change.
    (5) Previous calculations. If you have performed an emissions 
calculation for the process vent and operating scenario less than 10 
years before December 31, 2010, and the emissions calculation meets the 
requirements in paragraphs (d)(1) through (d)(4) of this section and in 
Sec. 98.123(c)(4)(i) and (c)(4)(ii), you may use the previous 
calculation to develop the site-specific process-vent-specific emission 
calculation factor.
    (e) Emission and stream testing, including analytical methods. 
Select and document testing and analytical methods as follows:

[[Page 738]]

    (1) Sampling and mass measurement for emission testing. For emission 
testing in process vents or at the stack, use methods for sampling, 
measuring volumetric flow rates, non-fluorinated-GHG gas analysis, and 
measuring stack gas moisture that have been validated using a 
scientifically sound validation protocol.
    (i) Sample and velocity traverses. Acceptable methods include but 
are not limited to EPA Method 1 or 1A in Appendix A-1 of 40 CFR part 60.
    (ii) Velocity and volumetric flow rates. Acceptable methods include 
but are not limited to EPA Method 2, 2A, 2B, 2C, 2D, 2F, or 2G in 
Appendix A-1 of 40 CFR part 60. Alternatives that may be used for 
determining flow rates include OTM-24 (incorporated by reference, see 
Sec. 98.7) and ALT-012 (incorporated by reference, see Sec. 98.7).
    (iii) Non-fluorinated-GHG gas analysis. Acceptable methods include 
but are not limited to EPA Method 3, 3A, or 3B in Appendix A-1 of 40 CFR 
part 60.
    (iv) Stack gas moisture. Acceptable methods include but are not 
limited to EPA Method 4 in Appendix A-1 of 40 CFR part 60.
    (2) Analytical methods. Use a quality-assured analytical measurement 
technology capable of detecting the analyte of interest at the 
concentration of interest and use a sampling and analytical procedure 
validated with the analyte of interest at the concentration of interest. 
Where calibration standards for the analyte are not available, a 
chemically similar surrogate may be used. Acceptable analytical 
measurement technologies include but are not limited to gas 
chromatography (GC) with an appropriate detector, infrared (IR), fourier 
transform infrared (FTIR), and nuclear magnetic resonance (NMR). 
Acceptable methods for determining fluorinated GHGs include EPA Method 
18 in appendix A-1 of 40 CFR part 60, EPA Method 320 in appendix A of 40 
CFR part 63, EPA 430-R-10-003 (incorporated by reference, see Sec. 
98.7), ASTM D6348-03 (incorporated by reference, see Sec. 98.7), or 
other analytical methods validated using EPA Method 301 at 40 CFR part 
63, appendix A or some other scientifically sound validation protocol. 
Acceptable methods for determining total fluorine concentrations for 
fluorine-containing compounds in streams under paragraph (b)(3) of this 
section include ASTM D7359-08 (incorporated by reference, see Sec. 
98.7), or other analytical methods validated using EPA Method 301 at 40 
CFR part 63, appendix A or some other scientifically sound validation 
protocol. The validation protocol may include analytical technology 
manufacturer specifications or recommendations.
    (3) Documentation in GHG Monitoring Plan. Describe the sampling, 
measurement, and analytical method(s) used under paragraphs (e)(1) and 
(e)(2) of this section in the GHG Monitoring Plan as required under 
Sec. 98.3(g)(5). Identify the methods used to obtain the samples and 
measurements listed under paragraphs (e)(1)(i) through (e)(1)(iv) of 
this section. At a minimum, include in the description of the analytical 
method a description of the analytical measurement equipment and 
procedures, quantitative estimates of the method's accuracy and 
precision for the analytes of interest at the concentrations of 
interest, as well as a description of how these accuracies and 
precisions were estimated, including the validation protocol used.
    (f) Emission monitoring for pieces of equipment. If you conduct a 
site-specific leak detection method or monitoring approach for pieces of 
equipment, follow paragraph (f)(1) or (f)(2) of this section and follow 
paragraph (f)(3) of this section.
    (1) Site-specific leak monitoring approach. You may develop a site-
specific leak monitoring approach. You must validate the leak monitoring 
method and describe the method and the validation in the GHG Monitoring 
Plan. To validate the site-specific method, you may, for example, 
release a known rate of the fluorinated GHGs or surrogates of interest, 
or you may compare the results of the site-specific method to those of a 
method that has been validated for the fluorinated GHGs or surrogates of 
interest. In the description of the leak detection method and its 
validation, include a detailed description of the method, including the 
procedures and equipment used and any sampling strategies. Also include 
the

[[Page 739]]

rationale behind the method, including why the method is expected to 
result in an unbiased estimate of emissions from equipment leaks. If the 
method is based on methods that are used to detect or quantify leaks or 
other emissions in other regulations, standards, or guidelines, identify 
and describe the regulations, standards, or guidelines and why their 
methods are applicable to emissions of fluorinated GHGs or surrogates 
from leaks. Account for possible sources of error in the method, e.g., 
instrument detection limits, measurement biases, and sampling biases. 
Describe validation efforts, including but not limited to any 
comparisons against standard leaks or concentrations, any comparisons 
against other methods, and their results. If you use the Screening 
Ranges Approach, the EPA Correlation Approach, or the Unit-Specific 
Correlation Approach with a monitoring instrument that does not meet all 
of the specifications in EPA Method 21 at 40 CFR part 60, appendix A-7, 
then explain how and why the monitoring instrument, as used at your 
facility, would nevertheless be expected to accurately detect and 
quantify emissions of fluorinated GHGs or surrogates from process 
equipment, and describe how you verified its accuracy. For all methods, 
provide a quantitative estimate of the accuracy and precision of the 
method.
    (2) EPA Method 21 monitoring. If you determine that EPA Method 21 at 
40 CFR part 60, appendix A-7 is appropriate for monitoring a fluorinated 
GHG, conduct the screening value concentration measurements using EPA 
Method 21 at 40 CFR part 60, appendix A-7 to determine the screening 
range data or the actual screening value data for the Screening Ranges 
Approach, EPA Correlation Approach, or the Unit-Specific Correlation 
Approach. For the one-time testing to develop the Unit-Specific 
Correlation equations in EPA-453/R-95-017 (incorporated by reference, 
see Sec. 98.7), conduct the screening value concentration measurements 
using EPA Method 21 at 40 CFR part 60, appendix A-7 and the bagging 
procedures to measure mass emissions. Concentration measurements of 
bagged samples must be conducted using gas chromatography following EPA 
Method 18 analytical procedures or other method according to Sec. 
98.124(e). Use methane or other appropriate compound as the calibration 
gas.
    (3) Frequency of measurement and sampling. If you estimate emissions 
based on monitoring of equipment, conduct monitoring at least annually. 
Sample at least one-third of equipment annually (except for equipment 
that is unsafe-to-monitor, difficult-to-monitor, insulated, or in heavy 
liquid service, pumps with dual mechanical seals, agitators with dual 
mechanical seals, pumps with no external shaft, agitators with no 
external shaft, pressure relief devices in gas and vapor service with an 
upstream rupture disk, sampling connection systems with closed-loop or 
closed purge systems, and pieces of equipment whose leaks are routed 
through a closed vent system to a destruction device), changing the 
sample each year such that at the end of three years, all equipment in 
the process has been monitored. If you estimate emissions based on a 
sample of the equipment in the process, ensure that the sample is 
representative of the equipment in the process. If you have multiple 
processes that have similar types of equipment in similar service, and 
that produce or transform similar fluorinated GHGs (in terms of chemical 
composition, molecular weight, and vapor pressure) at similar pressures 
and concentrations, then you may annually sample all of the equipment in 
one third of these processes rather than one third of the equipment in 
each process.
    (g) Destruction device performance testing. If you vent or otherwise 
feed fluorinated GHGs into a destruction device and apply the 
destruction efficiency of the device to one or more fluorinated GHGs in 
Sec. 98.123, you must conduct emissions testing to determine the 
destruction efficiency for each fluorinated GHG to which you apply the 
destruction efficiency. You must either determine the destruction 
efficiency for the most-difficult-to-destroy fluorinated GHG fed into 
the device (or a surrogate that is still more difficult to destroy) and 
apply that destruction efficiency to all the fluorinated GHGs

[[Page 740]]

fed into the device or alternatively determine different destruction 
efficiencies for different groups of fluorinated GHGs using the most-
difficult-to-destroy fluorinated GHG of each group (or a surrogate that 
is still more difficult to destroy).
    (1) Destruction efficiency testing. You must sample the inlet and 
outlet of the destruction device for a minimum of three runs of 1 hour 
each to determine the destruction efficiency. You must conduct the 
emissions testing using the methods in paragraph (e) of this section. To 
determine the destruction efficiency, emission testing must be conducted 
when operating at high loads reasonably expected to occur (i.e., 
representative of high total fluorinated GHG load that will be sent to 
the device) and when destroying the most-difficult-to-destroy 
fluorinated GHG (or a surrogate that is still more difficult to destroy) 
that is fed into the device from the processes subject to this subpart 
or that belongs to the group of fluorinated GHGs for which you wish to 
establish a DE. If the outlet concentration of a fluorinated GHG that is 
fed into the device is below the detection limit of the method, you may 
use a concentration of one-half the detection limit to estimate the 
destruction efficiency.
    (i) If perfluoromethane (CF4) is vented to the 
destruction device in any stream in more than trace concentrations, you 
must test and determine the destruction efficiency achieved specifically 
for CF4 to take credit for the CF4 emissions 
reduction.
    (ii) If sulfur hexafluoride (SF6) is vented to the 
destruction device in any stream in more than trace concentrations, you 
must test and determine the destruction efficiency achieved specifically 
for SF6, or alternatively for CF4 as a surrogate, 
to take credit for the SF6 emissions reduction.
    (iii) If saturated perfluorocarbons other than CF4 are 
vented to the destruction device in any stream in more than trace 
concentrations, you must test and determine the destruction efficiency 
achieved for the lowest molecular weight saturated perfluorocarbon 
vented to the destruction device, or alternatively for a lower molecular 
weight saturated PFC or SF6 as a surrogate, to take credit 
for the PFC emission reduction.
    (iv) For all other fluorinated GHGs that are vented to the 
destruction device in any stream in more than trace concentrations, you 
must test and determine the destruction efficiency achieved for the 
most-difficult-to-destroy fluorinated GHG or surrogate vented to the 
destruction device. Examples of acceptable surrogates include the Class 
1 compounds (ranked 1 through 34) in Appendix D, Table D-1 of ``Guidance 
on Setting Permit Conditions and Reporting Trial Burn Results; Volume II 
of the Hazardous Waste Incineration Guidance Series,'' January 1989, EPA 
Publication EPA 625/6-89/019. You can obtain a copy of this publication 
by contacting the Environmental Protection Agency, 1200 Pennsylvania 
Avenue, NW., Washington, DC 20460, (202) 272-0167, http://www.epa.gov.
    (2) Destruction efficiency testing frequency. You must conduct 
emissions testing to determine the destruction efficiency as provided in 
paragraphs (g)(2)(i) or (ii) of this section, whichever occurs first:
    (i) Conduct an emissions test every 10 years. In the calculations 
under Sec. 98.123, apply the updated destruction efficiency to the 
destruction that occurs after the test.
    (ii) Destruction device changes that affect the destruction 
efficiency. If you make a change to the destruction device that would be 
expected to affect the destruction efficiency, you must conduct an 
emissions test to update the destruction efficiency. Conduct the test 
before the February 28 of the year that immediately follows the change. 
In the calculations under Sec. 98.123, apply the updated destruction 
efficiency to the destruction that occurs after the change to the 
device.
    (3) Previous testing .If you have conducted an emissions test within 
the 10 years prior to December 31, 2010, and the emissions testing meets 
the requirements in paragraph (g)(1) of this section, you may use the 
destruction efficiency determined during this previous emissions 
testing. For purposes of paragraph (g)(2)(i) of this section, the date 
of the previous emissions test rather than December 31, 2010 shall

[[Page 741]]

constitute the beginning of the 10-year re-measurement cycle.
    (4) Hazardous Waste Combustor testing. If a destruction device used 
to destroy fluorinated GHG is subject to subpart EEE of part 63 of this 
chapter or any portion of parts 260-270 of this chapter, you may apply 
the destruction efficiency specifically determined for CF4, 
SF6, PFCs other than CF4, and all other 
fluorinated GHGs under that test if the testing meets the criteria in 
paragraph (g)(1)(i) through (g)(1)(iv) of this section. If the testing 
of the destruction efficiency under subpart EEE of part 63 of this 
chapter was conducted more than 10 years ago, you may use the most 
recent destruction efficiency test provided that the design, operation, 
or maintenance of the destruction device has not changed since the last 
destruction efficiency test in a manner that could affect the ability to 
achieve the destruction efficiency, and the hazardous waste is fed into 
the normal flame zone.
    (h) Mass of previously produced fluorinated GHGs fed into 
destruction device. You must measure the mass of each fluorinated GHG 
that is fed into the destruction device in more than trace 
concentrations and that was previously produced as defined at Sec. 
98.410(b). Such fluorinated GHGs include but are not limited to 
quantities that are shipped to the facility by another facility for 
destruction and quantities that are returned to the facility for 
reclamation but are found to be irretrievably contaminated and are 
therefore destroyed. You must use flowmeters, weigh scales, or a 
combination of volumetric and density measurements with an accuracy and 
precision of 1 percent of full scale or better. If 
the measured mass includes more than trace concentrations of materials 
other than the fluorinated GHG being destroyed, you must measure the 
concentration of the fluorinated GHG being destroyed. You must multiply 
this concentration (mass fraction) by the mass measurement to obtain the 
mass of the fluorinated GHG fed into the destruction device.
    (i) Emissions due to malfunctions of destruction device. In their 
estimates of the mass of fluorinated GHG destroyed, fluorinated gas 
production facilities that destroy fluorinated GHGs must account for any 
temporary reductions in the destruction efficiency that result from any 
malfunctions of the destruction device, including periods of operation 
outside of the operating conditions defined in operating permit 
requirements and/or destruction device manufacturer specifications.
    (j) Emissions due to process startup, shutdown, or malfunctions. 
Fluorinated GHG production facilities must account for fluorinated GHG 
emissions that occur as a result of startups, shutdowns, and 
malfunctions, either recording fluorinated GHG emissions during these 
events, or documenting that these events do not result in significant 
fluorinated GHG emissions. Facilities may use the calculation methods in 
Sec. 98.123(c)(1) to estimate emissions during startups, shutdowns, and 
malfunctions.
    (k) Monitoring for venting residual fluorinated GHG in containers. 
Measure the residual fluorinated GHG in containers received by the 
facility either using scales or using pressure and temperature 
measurements. You may use pressure and temperature measurements only in 
cases where no liquid fluorinated GHG is present in the container. 
Scales must have an accuracy and precision of 1 
percent or better of the filled weight (gas plus tare) of the containers 
of fluorinated GHGs that are typically weighed on the scale. For 
example, for scales that are generally used to weigh cylinders that 
contain 115 pounds of gas when full and that have a tare weight of 115 
pounds, this equates to 1 percent of 230 pounds, 
or 2.3 pounds. Pressure gauges and thermometers 
used to measure quantities that are monitored under this paragraph must 
have an accuracy and precision of 1 percent of 
full scale or better.
    (l) Initial scoping speciations, emissions testing, emission factor 
development, emission calculation factor development, emission 
characterization development, and destruction efficiency determinations 
must be completed by February 29, 2012 for processes and operating 
scenarios that operate between December 31, 2010 and December 31, 2011. 
For other processes and operating scenarios, initial scoping

[[Page 742]]

speciations, emissions testing, emission factor development, emission 
calculation factor development, emission characterization development, 
and destruction efficiency determinations must be complete by February 
28 of the year following the year in which the process or operating 
scenario commences or recommences.
    (m) Calibrate all flow meters, weigh scales, and combinations of 
volumetric and density measures using monitoring instruments traceable 
to the International System of Units (SI) through the National Institute 
of Standards and Technology (NIST) or other recognized national 
measurement institute. Recalibrate all flow meters, weigh scales, and 
combinations of volumetric and density measures at the minimum frequency 
specified by the manufacturer. Use any of the following applicable flow 
meter test methods or the calibration procedures specified by the flow 
meter, weigh-scale, or other volumetric or density measure manufacturer.
    (1) ASME MFC-3M-2004 Measurement of Fluid Flow in Pipes Using 
Orifice, Nozzle, and Venturi (incorporated by reference, see Sec. 
98.7).
    (2) ASME MFC-4M-1986 (Reaffirmed 1997) Measurement of Gas Flow by 
Turbine Meters (incorporated by reference, see Sec. 98.7).
    (3) ASME-MFC-5M-1985, (Reaffirmed 1994) Measurement of Liquid Flow 
in Closed Conduits Using Transit-Time Ultrasonic Flowmeters 
(incorporated by reference, see Sec. 98.7).
    (4) ASME MFC-6M-1998 Measurement of Fluid Flow in Pipes Using Vortex 
Flowmeters (incorporated by reference, see Sec. 98.7).
    (5) ASME MFC-7M-1987 (Reaffirmed 1992) Measurement of Gas Flow by 
Means of Critical Flow Venturi Nozzles (incorporated by reference, see 
Sec. 98.7).
    (6) ASME MFC-9M-1988 (Reaffirmed 2001) Measurement of Liquid Flow in 
Closed Conduits by Weighing Method (incorporated by reference, see Sec. 
98.7).
    (7) ASME MFC-11M-2006 Measurement of Fluid Flow by Means of Coriolis 
Mass Flowmeters (incorporated by reference, see Sec. 98.7).
    (8) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore 
Precision Orifice Meters (incorporated by reference, see Sec. 98.7).
    (n) All analytical equipment used to determine the concentration of 
fluorinated GHGs, including but not limited to gas chromatographs and 
associated detectors, infrared (IR), fourier transform infrared (FTIR), 
and nuclear magnetic resonance (NMR) devices, must be calibrated at a 
frequency needed to support the type of analysis specified in the GHG 
Monitoring Plan as required under Sec. 98.124(e)(3) and 93.3(g)(5). 
Quality assurance samples at the concentrations of concern must be used 
for the calibration. Such quality assurance samples must consist of or 
be prepared from certified standards of the analytes of concern where 
available; if not available, calibration must be performed by a method 
specified in the GHG Monitoring Plan.
    (o) Special provisions for estimating 2011 and subsequent year 
emissions.
    (1) Best available monitoring methods. To estimate emissions that 
occur from January 1, 2011 through June 30, 2011, owners or operators 
may use best available monitoring methods for any parameter that cannot 
reasonably be measured according to the monitoring and QA/QC 
requirements of this subpart. The owner or operator must use the 
calculation methodologies and equations in Sec. 98.123, but may use the 
best available monitoring method for any parameter for which it is not 
reasonably feasible to acquire, install, or operate a required piece of 
monitoring equipment, to procure measurement services from necessary 
providers, or to gain physical access to make required measurements in a 
facility by January 1, 2011. Starting no later than July 1, 2011, the 
owner or operator must discontinue using best available methods and 
begin following all applicable monitoring and QA/QC requirements of this 
part, except as provided in paragraphs (o)(2) through (o)(4) of this 
section. Best available monitoring methods means any of the following 
methods specified in this paragraph:
    (i) Monitoring methods currently used by the facility that do not 
meet the specifications of this subpart.
    (ii) Supplier data.

[[Page 743]]

    (iii) Engineering calculations or assessments.
    (iv) Other company records.
    (2) Requests for extension of the use of best available monitoring 
methods to estimate 2011 emissions: parameters other than scoping 
speciations, emission factors, and emission characterizations. The owner 
or operator may submit a request to the Administrator to use one or more 
best available monitoring methods for parameters other than scoping 
speciations, emission factors, or emission characterizations to estimate 
emissions that occur between July 1, 2011 and December 31, 2011.
    (i) Timing of request. The extension request must be submitted to 
EPA no later than February 28, 2011.
    (ii) Content of request. Requests must contain the following 
information:
    (A) A list of specific items of monitoring equipment and measurement 
services for which the request is being made and the locations (e.g., 
processes and vents) where each piece of monitoring equipment will be 
installed and where each measurement service will be provided.
    (B) Identification of the specific rule requirements for which the 
monitoring equipment or measurement service is needed.
    (C) A description of the reasons why the needed equipment could not 
be obtained, installed, or operated or why the needed measurement 
service could not be provided before July 1, 2011. The owner or operator 
must consider all of the data collection and emission calculation 
options outlined in the rule for a specific emissions source before 
claiming that a specific safety, technical, logistical, or legal barrier 
exists.
    (D) If the reason for the extension is that the equipment cannot be 
purchased, delivered, or installed before July 1, 2011, include 
supporting documentation such as the date the monitoring equipment was 
ordered, investigation of alternative suppliers, the dates by which 
alternative vendors promised delivery or installation, backorder notices 
or unexpected delays, descriptions of actions taken to expedite delivery 
or installation, and the current expected date of delivery or 
installation.
    (E) If the reason for the extension is that service providers were 
unable to provide necessary measurement services, include supporting 
documentation demonstrating that these services could not be acquired 
before July 1, 2011. This documentation must include written 
correspondence to and from at least two service providers stating that 
they will not be able to provide the necessary services before July 1, 
2011.
    (F) If the reason for the extension is that the process is operating 
continuously without process shutdown, include supporting documentation 
showing that it is not practicable to isolate the process equipment or 
unit and install the measurement device without a full shutdown or a hot 
tap, and that there is no opportunity before July 1, 2011 to install the 
device. Include the date of the three most recent shutdowns for each 
relevant process equipment or unit, the frequency of shutdowns for each 
relevant process equipment or unit, and the date of the next planned 
process equipment or unit shutdown.
    (G) If the reason for the extension is that access to process 
streams, emissions streams, or destroyed streams, as applicable, could 
not be gained before July 1, 2011 for reasons other than the continuous 
operation of the process without shutdown, include illustrative 
documentation such as photographs and engineering diagrams demonstrating 
that access could not be gained.
    (H) A description of the best available monitoring methods that will 
be used and how their results will be applied (i.e., which calculation 
method will be used) to develop the emission estimate. Where the 
proposed best available monitoring method is the use of current 
monitoring data in the mass-balance approach, include the estimated 
relative and absolute errors of the mass-balance approach using the 
current monitoring data.
    (I) A description of the specific actions the owner or operator will 
take to comply with monitoring requirements by January 1, 2012.
    (3) Requests for extension of the use of best available monitoring 
methods to estimate 2011 emissions: scoping speciations,

[[Page 744]]

emission factors, and emission characterizations. The owner or operator 
may submit a request to the Administrator to use one or more best 
available monitoring methods for scoping speciations, emission factors, 
and emission characterizations to estimate emissions that occur between 
July 1, 2011 and December 31, 2011.
    (i) Timing of request. The extension request must be submitted to 
EPA no later than June 30, 2011.
    (ii) Content of request. Requests must contain the information 
outlined in paragraph (o)(2)(ii) of this section, substituting March 1, 
2012 for July 1, 2011 and substituting March 1, 2013 for January 1, 
2012.
    (iii) Reporting of 2011 emissions using scoping speciations, 
emission factors, and emission characterizations developed after 
February 29, 2012. Facilities that are approved to use best available 
monitoring methods in 2011 for scoping speciations, emission factors, or 
emission characterizations for certain processes must submit, by March 
31, 2013, revised 2011 emission estimates that reflect the scoping 
speciations, emission factors, and emission characterizations that are 
measured for those processes after February 29, 2012. If the operating 
scenario for 2011 is different from all of the operating scenarios for 
which emission factors are developed after February 29, 2012, use 
Equation L-23 at Sec. 98.123(c)(3)(viii) to adjust the emission 
factor(s) or emission characterizations measured for the post-February 
29, 2012 operating scenario(s) to account for the differences.
    (4) Requests for extension of the use of best available monitoring 
methods to estimate emissions that occur after 2011. EPA does not 
anticipate approving the use of best available monitoring methods to 
estimate emissions that occur beyond December 31, 2011; however, EPA 
reserves the right to review requests for unique and extreme 
circumstances which include safety, technical infeasibility, or 
inconsistency with other local, State or Federal regulations.
    (i) Timing of request. The extension request must be submitted to 
EPA no later than June 30, 2011.
    (ii) Content of request. Requests must contain the following 
information:
    (A) The information outlined in paragraph (o)(2)(ii) of this 
section. For scoping speciations, emission factors, and emission 
characterizations, substitute March 1, 2013 for July 1, 2011 and 
substitute March 1, 2014 for January 1, 2012. For other parameters, 
substitute January 1, 2012 for July 1, 2011 and substitute January 1, 
2013 for January 1, 2012.
    (B) A detailed outline of the unique circumstances necessitating an 
extension, including specific data collection issues that do not meet 
safety regulations, technical infeasibility or specific laws or 
regulations that conflict with data collection. The owner or operator 
must consider all the data collection and emission calculation options 
outlined in the rule for a specific emissions source before claiming 
that a specific safety, technical or legal barrier exists.
    (C) A detailed explanation and supporting documentation of how and 
when the owner or operator will receive the required data and/or 
services to comply with the reporting requirements of this subpart in 
the future.
    (E) The Administrator reserves the right to require that the owner 
or operator provide additional documentation.
    (iii) Reporting of 2011 and subsequent year emissions using scoping 
speciations, emission factors, and emission characterizations developed 
after approval to use best available monitoring methods expires. 
Facilities that are approved to use best available monitoring methods in 
2011 and subsequent years for scoping speciations, emission factors, or 
emission characterizations for certain processes must submit, by March 
31 of the year that begins one year after their approval to use best 
available monitoring method(s) expires, revised emission estimates for 
2011 and subsequent years that reflect the scoping speciations, emission 
factors, and emission characterizations that are measured for those 
processes in 2013 or subsequent years. If the operating scenario for 
2011 or subsequent years is different from all of the operating 
scenarios for which emission factors or emission characterizations are 
developed in 2013 or subsequent years, use Equation L-23 of Sec. 
98.123(c)(3)(viii) to adjust the emission

[[Page 745]]

factor(s) or emission characterization(s) measured for the new operating 
scenario(s) to account for the differences.
    (5) Approval criteria. To obtain approval, the owner or operator 
must demonstrate to the Administrator's satisfaction that it is not 
reasonably feasible to acquire, install, or operate the required piece 
of monitoring equipment, to procure measurement services from necessary 
providers, or to gain physical access to make required measurements in a 
facility according to the requirements of this subpart by the dates 
specified in paragraphs (o)(2), (3), and (4) of this section for any of 
the reasons described in paragraph (o)(2)(ii) of this section, or, for 
requests under paragraph (o)(4) of this section, any of the reasons 
described in paragraph (o)(4)(ii)(B) of this section.

[75 FR 74831, Dec. 1, 2010, as amended at 79 FR 73787, Dec. 11, 2014



Sec. 98.125  Procedures for estimating missing data.

    (a) A complete record of all measured parameters used in the GHG 
emissions calculations in Sec. 98.123 is required. Therefore, whenever 
a quality-assured value of a required parameter is unavailable, a 
substitute data value for the missing parameter must be used in the 
calculations as specified in the paragraphs (b) and (c) of this section. 
You must document and keep records of the procedures used for all such 
estimates.
    (b) For each missing value of the fluorinated GHG concentration or 
fluorine-containing compound concentration, the substitute data value 
must be the arithmetic average of the quality-assured values of that 
parameter immediately preceding and immediately following the missing 
data incident.
    (c) For each missing value of the mass produced, fed into the 
production process, fed into the transformation process, or fed into 
destruction devices, the substitute value of that parameter must be a 
secondary mass measurement where such a measurement is available. For 
example, if the mass produced is usually measured with a flowmeter at 
the inlet to the day tank and that flowmeter fails to meet an accuracy 
or precision test, malfunctions, or is rendered inoperable, then the 
mass produced may be estimated by calculating the change in volume in 
the day tank and multiplying it by the density of the product. Where a 
secondary mass measurement is not available, the substitute value of the 
parameter must be an estimate based on a related parameter. For example, 
if a flowmeter measuring the mass fed into a destruction device is 
rendered inoperable, then the mass fed into the destruction device may 
be estimated using the production rate and the previously observed 
relationship between the production rate and the mass flow rate into the 
destruction device.



Sec. 98.126  Data reporting requirements.

    (a) All facilities. In addition to the information required by Sec. 
98.3(c), you must report the information in paragraphs (a)(2) through 
(6) of this section according to the schedule in paragraph (a)(1) of 
this section, except as otherwise provided in paragraph (j) of this 
section or in Sec. 98.3(c)(4)(vii) and Table A-7 of subpart A of this 
part.
    (1) Frequency of reporting under paragraph (a) of this section. The 
information in paragraphs (a)(2) through (6) of this section must be 
reported annually.
    (2) Generically-identified process. For each production and 
transformation process at the facility, you must:
    (i) Provide a number, letter, or other identifier for the process. 
This identifier must be consistent from year to year.
    (ii) Indicate whether the process is a fluorinated gas production 
process, a fluorinated gas transformation process where no fluorinated 
GHG reactant is produced at another facility, or a fluorinated gas 
transformation process where one or more fluorinated GHG reactants are 
produced at another facility.
    (iii) Indicate whether the process could be characterized as 
reaction, distillation, or packaging (include all that apply).
    (iv) For each generically-identified process and each fluorinated 
GHG group, report the method(s) used to determine the mass emissions of 
that fluorinated GHG group from that process from vents (i.e., mass 
balance (for reporting years 2011, 2012, 2013, and 2014

[[Page 746]]

only), process-vent-specific emission factor, or process-vent-specific 
emission calculation factor).
    (v) For each generically-identified process and each fluorinated GHG 
group, report the method(s) used to determine the mass emissions of that 
fluorinated GHG group from that process from equipment leaks, unless you 
used the mass balance method (for reporting years 2011, 2012, 2013, and 
2014 only) for that process.
    (3) Emissions from production and transformation processes, process 
level, multiple products. If your facility produces more than one 
fluorinated gas product, for each generically-identified process and 
each fluorinated GHG group, you must report the total GWP-weighted 
emissions of all fluorinated GHGs in that group from the process, in 
metric tons CO2e.
    (4) Emissions from production and transformation processes, facility 
level, multiple products. If your facility produces more than one 
fluorinated gas product, you must report the information in paragraphs 
(a)(4)(i) and (ii) of this section, as applicable, for emissions from 
production and transformation processes.
    (i) For each fluorinated GHG with emissions of 1,000 metric tons of 
CO2e or more from production and transformation processes, 
summed across the facility as a whole, you must report the total mass in 
metric tons of the fluorinated GHG emitted from production and 
transformation processes, summed across the facility as a whole. If the 
fluorinated GHG does not have a chemical-specific GWP in Table A-1 of 
subpart A, identify the fluorinated GHG group of which that fluorinated 
GHG is a member.
    (ii) For all other fluorinated GHGs emitted from production and 
transformation processes, you must report the total GWP-weighted 
emissions from production and transformation processes of those 
fluorinated GHGs by fluorinated GHG group, summed across the facility as 
a whole, in metric tons of CO2e.
    (5) Emissions from production and transformation processes, facility 
level, one product only. If your facility produces only one fluorinated 
gas product, aggregate and report the total GWP-weighted emissions from 
production and transformation processes of fluorinated GHGs by 
fluorinated GHG group for the facility as a whole, in metric tons of 
CO2e, with the following exception: Where emissions consist 
of a major fluorinated GHG constituent of a fluorinated gas product, and 
the product is sold or transferred to another person, report the total 
mass in metric tons of each fluorinated GHG that is emitted from 
production and transformation processes and that is a major fluorinated 
GHG constituent of the product. If the fluorinated GHG does not have a 
chemical-specific GWP in Table A-1 of subpart A, identify the 
fluorinated GHG group of which that fluorinated GHG is a member.
    (6) Effective destruction efficiency. For each generically-
identified process, use Table L-1 of this subpart to report the range 
that encompasses the effective destruction efficiency, 
DEeffective, calculated for that process using Equation L-35 
of this subpart. The effective destruction efficiency must be reported 
on a CO2e basis.
    (b) Reporting for mass balance method for reporting years 2011, 
2012, 2013, and 2014. If you used the mass balance method to calculate 
emissions for any of the reporting years 2011, 2012, 2013, or 2014, you 
must conduct mass balance reporting for that reporting year. For 
processes whose emissions were determined using the mass balance method 
under the former Sec. 98.123(b), as included in paragraph 1 of Appendix 
A of this subpart, you must report the information listed in paragraphs 
(b)(1) and (b)(2) of this section for each process on an annual basis.
    (1) If you calculated the relative and absolute errors under the 
former Sec. 98.123(b)(1), the overall absolute and relative errors 
calculated for the process under the former Sec. 98.123(b)(1), in 
metric tons CO2e and decimal fraction, respectively.
    (2) The method used to estimate the total mass of fluorine in 
destroyed or recaptured streams (specify the former Sec. 98.123(b)(4) 
or (15), as included in paragraph 1 of Appendix A of this subpart).
    (c) Reporting for emission factor and emission calculation factor 
approach. For

[[Page 747]]

processes whose emissions are determined using the emission factor 
approach under Sec. 98.123(c)(3) or the emission calculation factor 
under Sec. 98.123(c)(4), you must report the following for each 
generically-identified process.
    (1) [Reserved]
    (2) [Reserved]
    (3) For each fluorinated GHG group, the total GWP-weighted mass of 
all fluorinated GHGs in that group emitted from all process vents 
combined, in metric tons of CO2e.
    (4) For each fluorinated GHG group, the total GWP-weighted mass of 
all fluorinated GHGs in that group emitted from equipment leaks, in 
metric tons of CO2e.
    (d) Reporting for missing data. Where missing data have been 
estimated pursuant to Sec. 98.125, you must report:
    (1) The generically-identified process for which the data were 
missing.
    (2) The reason the data were missing, the length of time the data 
were missing, and the method used to estimate the missing data.
    (3) Estimates of the missing data for all missing data associated 
with data elements required to be reported in this section.
    (e) Reporting of destruction device excess emissions data. Each 
fluorinated gas production facility that destroys fluorinated GHGs must 
report the excess emissions that result from malfunctions of the 
destruction device, and these excess emissions must be reflected in the 
fluorinated GHG estimates in the former Sec. 98.123(b) as included in 
paragraph 1 of Appendix A of this subpart for the former mass balance 
method, and in Sec. 98.123(c). Such excess emissions would occur if the 
destruction efficiency was reduced due to the malfunction.
    (f) Reporting of destruction device testing. By March 31, 2012 or by 
March 31 of the year immediately following the year in which it begins 
fluorinated GHG destruction, each fluorinated gas production facility 
that destroys fluorinated GHGs must submit a report containing the 
information in paragraphs (f)(1) through (f)(4) of this section. This 
report is one-time unless you make a change to the destruction device 
that would be expected to affect its destruction efficiencies.
    (1) [Reserved]
    (2) Chemical identity of the fluorinated GHG(s) used in the 
performance test conducted to determine destruction efficiency, 
including surrogates, and information on why the surrogate is sufficient 
to demonstrate the destruction efficiency for each fluorinated GHG, 
consistent with requirements in Sec. 98.124(g)(1), vented to the 
destruction device.
    (3) Date of the most recent destruction device test.
    (4) Name of all applicable Federal or State regulations that may 
apply to the destruction process.
    (5) [Reserved]
    (g) Reporting for destruction of previously produced fluorinated 
GHGs. Each fluorinated gas production facility that destroys fluorinated 
GHGs must report, separately from the fluorinated GHG emissions reported 
under paragraphs (b) or (c) of this section, the following for each 
previously produced fluorinated GHG destroyed:
    (1) [Reserved]
    (2) The mass of the fluorinated GHG emitted from the destruction 
device (metric tons).
    (h) Reporting of emissions from venting of residual fluorinated GHGs 
from containers. Each fluorinated gas production facility that vents 
residual fluorinated GHGs from containers must report the following for 
each fluorinated GHG vented:
    (1) The mass of the residual fluorinated GHG vented from containers 
annually (metric tons).
    (2) [Reserved]
    (i) Reporting of fluorinated GHG products of incomplete combustion 
(PICs) of fluorinated gases. Each fluorinated gas production facility 
that destroys fluorinated gases must submit a one-time report by June 
30, 2011, that describes any measurements, research, or analysis that it 
has performed or obtained that relate to the formation of products of 
incomplete combustion that are fluorinated GHGs during the destruction 
of fluorinated gases. The report must include the methods and results of 
any measurement or modeling studies, including the products of 
incomplete combustion for which the

[[Page 748]]

exhaust stream was analyzed, as well as copies of relevant scientific 
papers, if available, or citations of the papers, if they are not. No 
new testing is required to fulfill this requirement.
    (j) Special provisions for reporting years 2011, 2012, and 2013 
only. For reporting years 2011, 2012, and 2013, the owner or operator of 
a facility must comply with paragraphs (j)(1), (j)(2), and (j)(3) of 
this section.
    (1) Timing. The owner or operator of a facility is not required to 
report the data elements at Sec. 98.3(c)(4)(iii) and paragraphs (a)(2), 
(a)(3), (a)(4), (a)(6), (b), (c), (d), (e), (f), (g), and (h) of this 
section until the later of March 31, 2015 or the date set forth for that 
data element at Sec. 98.3(c)(4)(vii) and Table A-7 of Subpart A of this 
part.
    (2) Excess emissions. Excess emissions of fluorinated GHGs resulting 
from destruction device malfunctions must be reflected in the reported 
facility-wide CO2e emissions but are not required to be 
reported separately.
    (3) Calculation and reporting of CO2e. You must report 
the total fluorinated GHG emissions covered by this subpart, expressed 
in metric tons of CO2e. This includes emissions from all 
fluorinated gas production processes, all fluorinated gas transformation 
processes that are not part of a fluorinated gas production process, all 
fluorinated gas destruction processes that are not part of a fluorinated 
gas production process or a fluorinated gas transformation process, and 
venting of residual fluorinated GHGs from containers returned from the 
field. To convert fluorinated GHG emissions to CO2e for 
reporting under this section, use Equation A-1 of Sec. 98.2. For 
fluorinated GHGs whose GWPs are not listed in Table A-1 of Subpart A of 
this part, use either the default GWP specified below or your best 
estimate of the GWP based on the information described in Sec. 
98.123(c)(1)(vi)(A)(3). Use of quantitative structure activity 
relationships (QSARs) is an acceptable method for determining GWPs in 
situations where pure standards of the ``target'' fluorinated GHG are 
not available, the ``target'' fluorinated GHG cannot be isolated from 
gas streams, and FTIR spectra for the impurities are not available.
    (i) If you choose to use a default GWP rather than your best 
estimate of the GWP for fluorinated GHGs whose GWPs are not listed in 
Table A-1 of Subpart A of this part, use a default GWP of 10,000 for 
fluorinated GHGs that are fully fluorinated GHGs and use a default GWP 
of 2000 for other fluorinated GHGs.
    (ii) Provide the total annual emissions across fluorinated GHGs for 
the entire facility, in metric tons of CO2e, that were 
calculated using the default GWP of 2000.
    (iii) Provide the total annual emissions across fluorinated GHGs for 
the entire facility, in metric tons of CO2e, that were 
calculated using the default GWP of 10,000.
    (iv) Provide the total annual emissions across fluorinated GHGs for 
the entire facility, in metric tons of CO2e, that were 
calculated using your best estimate of the GWP.
    (k) Submission of complete reporting year 2011, 2012, and 2013 GHG 
reports. By March 31, 2015, you must submit annual GHG reports for 
reporting years 2011, 2012, and 2013 that contain the information 
specified in paragraphs (a) through (i) of this section. The reports 
must calculate CO2e using the GWPs in Table A-1 of subpart A 
of this part (as in effect on January 1, 2015). Prior submission of 
partial reports for these reporting years under paragraph (j) of this 
section does not affect your obligation to submit complete reports under 
this paragraph.

[75 FR 74831, Dec. 1, 2010, as amended at 77 FR 51489, Aug. 24, 2012; 78 
FR 71954, Nov. 29, 2013; 79 FR 73787, Dec. 11, 2014]



Sec. 98.127  Records that must be retained.

    In addition to the records required by Sec. 98.3(g), you must 
retain the dated records specified in paragraphs (a) through (l) of this 
section, as applicable.
    (a) Process information records. (1) Identify all products and 
processes subject to this subpart. Include the unit identification as 
appropriate, the generic process identification reported for the process 
under Sec. 98.126(a)(2)(i) through (iii), and the product with which 
the process is associated.

[[Page 749]]

    (2) Monthly and annual records, as applicable, of all analyses and 
calculations conducted as required under Sec. 98.123, including the 
data monitored under Sec. 98.124, and all information reported as 
required under Sec. 98.126.
    (3) Identify all fluorinated GHGs with emissions of 1,000 metric 
tons CO2e or more from production and transformation 
processes, summed across the facility as a whole, and identify all 
fluorinated GHGs with total emissions less than 1,000 metric tons 
CO2e from production and transformation processes, summed 
across the facility as a whole.
    (4) Calculations used to determine the total GWP-weighted emissions 
of fluorinated GHGs by fluorinated GHG group for each process, in metric 
tons CO2e.
    (b) Scoping speciation. Retain records documenting the information 
collected under Sec. 98.124(a).
    (c) Mass balance method. Retain the following records for each 
process for which the mass balance method was used to estimate emissions 
in reporting years 2011, 2012, 2013, or 2014. If you used an element 
other than fluorine in the mass balance equation pursuant to the former 
Sec. 98.123(b)(3) as included in paragraph 1 of Appendix A of this 
subpart for the former mass balance method, substitute that element for 
fluorine in the recordkeeping requirements of this paragraph.
    (1) The data and calculations used to estimate the absolute and 
relative errors associated with use of the mass-balance approach.
    (2) The data and calculations used to estimate the mass of fluorine 
emitted from the process.
    (3) The data and calculations used to determine the fractions of the 
mass emitted consisting of each reactant (FERd), product 
(FEP), and by-product (FEBk), including the preliminary 
calculations in the former Sec. 98.123(b)(8)(i).
    (d) Emission factor and emission calculation factor method. Retain 
the following records for each process for which the emission factor or 
emission calculation factor method was used to estimate emissions.
    (1) Identify all continuous process vents with emissions of 
fluorinated GHGs that are less than 10,000 metric tons CO2e 
per year and all continuous process vents with emissions of 10,000 
metric tons CO2e per year or more. Include the data and 
calculation used to develop the preliminary estimate of emissions for 
each process vent.
    (2) Identify all batch process vents.
    (3) For each vent, identify the method used to develop the factor 
(i.e., emission factor by emissions test or emission calculation 
factor).
    (4) The emissions test data and reports (see Sec. 98.124(c)(5)) and 
the calculations used to determine the process-vent-specific emission 
factor, including the actual process-vent-specific emission factor, the 
average hourly emission rate of each fluorinated GHG from the process 
vent during the test and the process feed rate, process production rate, 
or other process activity rate during the test.
    (5) The process-vent-specific emission calculation factor and the 
calculations used to determine the process-vent-specific emission 
calculation factor.
    (6) The annual process production quantity or other process activity 
information in the appropriate units, along with the dates and time 
period during which the process was operating and dates and time periods 
the process vents are vented to the destruction device. As an 
alternative to date and time periods when process vents are vented to 
the destruction device, a facility may track dates and time periods that 
process vents by-pass the destruction device.
    (7) Calculations used to determine annual emissions of each 
fluorinated GHG for each process and the total fluorinated GHG emissions 
for all processes, i.e., total for facility.
    (e) Destruction efficiency testing. A fluorinated GHG production 
facility that destroys fluorinated GHGs and reflects this destruction in 
Sec. 98.123 must retain the emissions performance testing reports 
(including revised reports) for each destruction device. The emissions 
performance testing report must contain all information and data used to 
derive the destruction efficiency for each fluorinated GHG whose 
destruction the facility reflects in Sec. 98.123, as well as the key 
process and device conditions during the test. This information includes 
the following:

[[Page 750]]

    (1) Destruction efficiency (DE) determined for each fluorinated GHG 
whose destruction the facility reflects in Sec. 98.123, in accordance 
with Sec. 98.124(g)(1)(i) through (iv).
    (2) Chemical identity of the fluorinated GHG(s) used in the 
performance test conducted to determine destruction efficiency, 
including surrogates, and information on why the surrogate is sufficient 
to demonstrate destruction efficiency for each fluorinated GHG, 
consistent with requirements in Sec. 98.124(g)(1)(i) through (iv), 
vented to the destruction device.
    (3) Mass flow rate of the stream containing the fluorinated GHG(s) 
or surrogate into the device during the test.
    (4) Concentration (mass fraction) of each fluorinated GHG or 
surrogate in the stream flowing into the device during the test.
    (5) Concentration (mass fraction) of each fluorinated GHG or 
surrogate at the outlet of the destruction device during the test.
    (6) Mass flow rate at the outlet of the destruction device during 
the test.
    (7) Test methods and analytical methods used to determine the mass 
flow rates and fluorinated GHG (or surrogate) concentrations of the 
streams flowing into and out of the destruction device during the test.
    (8) Destruction device conditions that are normally monitored for 
device control, such as temperature, total mass flow rates into the 
device, and CO or O2 levels.
    (9) Name of all applicable Federal or State regulations that may 
apply to the destruction process.
    (f) Equipment leak records. If you are subject to Sec. 98.123(d) of 
this subpart, you must maintain information on the number of each type 
of equipment; the service of each piece of equipment (gas, light liquid, 
heavy liquid); the concentration of each fluorinated GHG in the stream; 
each piece of equipment excluded from monitoring requirement; the time 
period each piece of equipment was in service, and the emission 
calculations for each fluorinated GHG for all processes. Depending on 
which equipment leak monitoring approach you follow, you must maintain 
information for equipment on the associated screening data 
concentrations for greater than or equal to 10,000 ppmv and associated 
screening data concentrations for less than 10,000 ppmv; associated 
actual screening data concentrations; and associated screening data and 
leak rate data (i.e., bagging) used to develop a unit-specific 
correlation. If you developed and follow a site-specific leak detection 
approach, provide the records for monitoring events and the emissions 
estimation calculations, as appropriate, consistent with the approach 
for equipment leak emission estimation in your GHG Monitoring Plan.
    (g) Container heel records. If you vent residual fluorinated GHGs 
from containers, maintain the following records of the measurements and 
calculations used to estimate emissions of residual fluorinated GHGs 
from containers.
    (i) If you measure the contents of each container, maintain records 
of these measurements and the calculations used to estimate emissions of 
each fluorinated GHG from each container size and type.
    (ii) If you develop and apply container heel factors to estimate 
emissions, maintain records of the measurements and calculations used to 
develop the heel factor for each fluorinated GHG and each container size 
and type and of the number of containers of each fluorinated GHG and of 
each container size and type returned to your facility.
    (h) Missing data records. Where missing data have been estimated 
pursuant to Sec. 98.125, you must record the reason the data were 
missing, the length of time the data were missing, the method used to 
estimate the missing data, and the estimates of those data.
    (i) All facilities. Dated records documenting the initial and 
periodic calibration of all analytical equipment used to determine the 
concentration of fluorinated GHGs, including but not limited to gas 
chromatographs, gas chromatography-mass spectrometry (GC/MS), gas 
chromatograph-electron capture detector (GC/ECD), fourier transform 
infrared (FTIR), and nuclear magnetic resonance (NMR) devices, and all 
mass measurement equipment such as weigh scales, flowmeters, and 
volumetric and density measures used to measure the quantities reported

[[Page 751]]

under this subpart, including the industry standards or manufacturer 
directions used for calibration pursuant to Sec. 98.124(e), (f), (g), 
(m), and (n).
    (j) GHG Monitoring Plans, as described in Sec. 98.3(g)(5), must be 
completed by April 1, 2011.
    (k) For fluorinated GHGs whose GWPs are not listed in Table A-1 to 
subpart A of this part, maintain records of the GWPs used to calculate 
facility-wide CO2e emissions under Sec. 98.127(j). Where you 
used your best estimate of the GWP, maintain records of the data and 
analysis used to develop that GWP, including the data elements at Sec. 
98.123(c)(1)(vi)(A)(1)through (3). If you have used QSARs to estimate 
the GWP, include information documenting the level of accuracy of the 
QSAR-derived GWP, including information on how the structure of the 
``target'' fluorinated GHG is similar to the structures of the 
fluorinated GHGs used to model the radiative forcing and/or reaction 
rate of the ``target'' fluorinated GHG, the quality and quantity of the 
measurements of the radiative forcings and/or reaction rates of the 
fluorinated GHGs used to model these parameters for the ``target'' 
fluorinated GHG, any estimated uncertainties of the modeled forcings 
and/or reaction rates, and descriptions and results of any efforts to 
validate the QSAR model(s).
    (l) Verification software records. For reporting year 2015 and 
thereafter, you must enter into verification software specified in Sec. 
98.5(b) the data specified in paragraphs (l)(1) through (15) of this 
section. The data specified in paragraphs (l)(1) through (11) must be 
entered for each process and each process vent, as applicable. The data 
specified in paragraphs (l)(1) through (15) must be entered for each 
fluorinated GHG, as applicable. You must keep a record of the file 
generated by the verification software specified in Sec. 98.5(b) for 
the applicable data specified in paragraphs (l)(1) through (15) of this 
section. Retention of this file satisfies the recordkeeping requirement 
for the data in paragraphs (l)(1) through (15) of this section.
    (1) The identity of the process vent (e.g., name or number assigned 
by the facility).
    (2) The equation used to estimate emissions from the process vent 
(Equations L-21, L-22, L-26, or L-27).
    (3) The type of process activity used to estimate emissions from the 
process vent (e.g., product of process or reactant consumed by process) 
(Activity, ActivityC, or ActivityU) (Equations L-
21, L-22, L-26, L-27, L-35).
    (4) The quantities of the process activity used to estimate 
controlled and uncontrolled emissions, respectively, for the process 
vent, Activity, ActivityU, or ActivityC, (e.g. kg 
product) (Equations L-21, L-22, L-26, L-27, L-35).
    (5) The site-specific, process-vent-specific emission factor, 
EFPV-C, for the process vent, measured after the destruction 
device (kg fluorinated GHG emitted per kg activity) (Equation L-21).
    (6) The site-specific, process-vent-specific emission calculation 
factor, ECFPV-U, for the process vent, for periods not vented 
to destruction device (kg fluorinated GHG emitted per kg activity) 
(Equations L-21, L-35).
    (7) The site-specific, process-vent-specific emission factor(s), 
EFPV-U, for the process vent, measured before the destruction 
device (kg fluorinated GHG emitted per kg activity) (Equations L-22, L-
35).
    (8) The site-specific, process-vent-specific emission calculation 
factor for the process vent, ECFPV (kg fluorinated GHG 
emitted per kg of activity) (Equations L-26, L-27, L-35).
    (9) Destruction efficiency, DE, of each destruction device for each 
fluorinated GHG whose destruction the facility reflects in Sec. 98.123, 
in accordance with Sec. 98.124(g)(1)(i) through (iv) (weight fraction) 
(Equations L-22, L-27, L-31).
    (10) Emissions of each fluorinated GHG for equipment pieces for the 
process, EELf (metric ton/yr) (98.123(d)(3)).
    (11) The mass of the fluorinated GHG previously produced and fed 
into the destruction device, RED, (metric tons) (Equation L-
31).
    (12) If applicable, the heel factor, hfj, calculated for 
each container size and type (decimal fraction) (Equation L-34).
    (13) If applicable, the number of containers of size and type j 
returned to

[[Page 752]]

the fluorinated gas production facility, Nfj, (Equation L-
34).
    (14) If applicable, the full capacity of containers of size and type 
j containing fluorinated GHG f, Ffj, (metric tons) (Equation 
L-34).
    (15) For fluorinated GHGs that do not have a chemical-specific GWP 
on Table A-1 of subpart A of this part, the fluorinated GHG group of 
which the fluorinated GHG is a member, as applicable (to permit look-up 
of global warming potential, GWPf, or GWPi, for 
that fluorinated GHG in Table A-1 of subpart A of this part (Equation A-
1 of subpart A of this part, Equation L-35)).

[75 FR 74831, Dec. 1, 2010, as amended at 77 FR 51490, Aug. 24, 2012; 79 
FR 73788, Dec. 11, 2014]



Sec. 98.128  Definitions.

    Except as provided in this section, all of the terms used in this 
subpart have the same meaning given in the Clean Air Act and subpart A 
of this part. If a conflict exists between a definition provided in this 
subpart and a definition provided in subpart A, the definition in this 
subpart shall take precedence for the reporting requirements in this 
subpart.
    Batch process or batch operation means a noncontinuous operation 
involving intermittent or discontinuous feed into equipment, and, in 
general, involves the emptying of the equipment after the batch 
operation ceases and prior to beginning a new operation. Addition of raw 
material and withdrawal of product do not occur simultaneously in a 
batch operation.
    Batch emission episode means a discrete venting episode associated 
with a vessel in a process; a vessel may have more than one batch 
emission episode. For example, a displacement of vapor resulting from 
the charging of a vessel with a feed material will result in a discrete 
emission episode that will last through the duration of the charge and 
will have an average flow rate equal to the rate of the charge. If the 
vessel is then heated, there will also be another discrete emission 
episode resulting from the expulsion of expanded vapor. Other emission 
episodes also may occur from the same vessel and other vessels in the 
process, depending on process operations.
    By-product means a chemical that is produced coincidentally during 
the production of another chemical.
    Completely destroyed means destroyed with a destruction efficiency 
of 99.99 percent or greater.
    Completely recaptured means 99.99 percent or greater of each 
fluorinated GHG is removed from a stream.
    Continuous process or operation means a process where the inputs and 
outputs flow continuously throughout the duration of the process. 
Continuous processes are typically steady state.
    Destruction device means any device used to destroy fluorinated GHG.
    Destruction process means a process used to destroy fluorinated GHG 
in a destruction device such as a thermal incinerator or catalytic 
oxidizer.
    Difficult-to-monitor means the equipment piece may not be monitored 
without elevating the monitoring personnel more than 2 meters (7 feet) 
above a support surface or it is not accessible in a safe manner when it 
is in fluorinated GHG service.
    Dual mechanical seal pump and dual mechanical seal agitator means a 
pump or agitator equipped with a dual mechanical seal system that 
includes a barrier fluid system where the barrier fluid is not in light 
liquid service; each barrier fluid system is equipped with a sensor that 
will detect failure of the seal system, the barrier fluid system, or 
both; and meets the following requirements:
    (1) Each dual mechanical seal system is operated with the barrier 
fluid at a pressure that is at all times (except periods of startup, 
shutdown, or malfunction) greater than the pump or agitator stuffing box 
pressure; or
    (2) Equipped with a barrier fluid degassing reservoir that is routed 
to a process or fuel gas system or connected by a closed-vent system to 
a control device; or
    (3) Equipped with a closed-loop system that purges the barrier fluid 
into a process stream.
    Equipment (for the purposes of Sec. 98.123(d) and Sec. 98.124(f) 
only) means each pump, compressor, agitator, pressure relief device, 
sampling connection system, open-ended valve or line, valve, connector, 
and instrumentation system in fluorinated GHG service for

[[Page 753]]

a process subject to this subpart; and any destruction devices or 
closed-vent systems to which processes subject to this subpart are 
vented.
    Fluorinated gas means any fluorinated GHG, CFC, or HCFC.
    Fluorinated gas product means the product of the process, including 
isolated intermediates.
    Fully fluorinated GHGs means fluorinated GHGs that contain only 
single bonds and in which all available valence locations are filled by 
fluorine atoms. This includes but is not limited to saturated 
perfluorocarbons, SF6, NF3, 
SF5CF3, fully fluorinated linear, branched and 
cyclic alkanes, fully fluorinated ethers, fully fluorinated tertiary 
amines, fully fluorinated aminoethers, and perfluoropolyethers.
    Generically-identified process means a process that is:
    (1) Identified as a production process, a transformation process 
where no fluorinated GHG reactant is produced at another facility, or a 
transformation process where one or more fluorinated GHG reactants are 
produced at another facility;
    (2) Further identified as a reaction, distillation, or packaging 
process, or a combination thereof; and
    (3) Tagged with a discrete identifier, such as a letter or number, 
that remains constant from year to year.
    In fluorinated GHG service means that a piece of equipment either 
contains or contacts a feedstock, by-product, or product that is a 
liquid or gas and contains at least 5 percent by weight fluorinated GHG.
    In gas and vapor service means that a piece of equipment in 
regulated material service contains a gas or vapor at operating 
conditions.
    In heavy liquid service means that a piece of equipment in regulated 
material service is not in gas and vapor service or in light liquid 
service.
    In light liquid service means that a piece of equipment in regulated 
material service contains a liquid that meets the following conditions:
    (1) The vapor pressure of one or more of the compounds is greater 
than 0.3 kilopascals at 20  deg.C.
    (2) The total concentration of the pure compounds constituents 
having a vapor pressure greater than 0.3 kilopascals at 20  deg.C is 
equal to or greater than 20 percent by weight of the total process 
stream.
    (3) The fluid is a liquid at operating conditions.

    Note to definition of ``in light liquid service'': Vapor pressures 
may be determined by standard reference texts or ASTM D-2879, 
(incorporated by reference, see Sec. 98.7).

    In vacuum service means that equipment is operating at an internal 
pressure which is at least 5 kilopascals below ambient pressure.
    Isolated intermediate means a product of a process that is stored 
before subsequent processing. An isolated intermediate is usually a 
product of chemical synthesis. Storage of an isolated intermediate marks 
the end of a process. Storage occurs at any time the intermediate is 
placed in equipment used solely for storage.
    Major fluorinated GHG constituent means a fluorinated GHG 
constituent of a fluorinated gas product that occurs in concentrations 
greater than 1 percent by mass.
    No external shaft pump and No external shaft agitator means any pump 
or agitator that is designed with no externally actuated shaft 
penetrating the pump or agitator housing.
    Operating scenario means any specific operation of a process and 
includes the information specified in paragraphs (1) through (5) of this 
definition for each process. A change or series of changes to any of 
these elements, except for paragraph (4) of this definition, constitutes 
a different operating scenario.
    (1) A description of the process, the specific process equipment 
used, and the range of operating conditions for the process.
    (2) An identification of related process vents, their associated 
emissions episodes and durations, and calculations and engineering 
analyses to show the annual uncontrolled fluorinated GHG emissions from 
the process vent.
    (3) The control or destruction devices used, as applicable, 
including a description of operating and/or testing conditions for any 
associated destruction device.
    (4) The process vents (including those from other processes) that 
are simultaneously routed to the control or destruction device(s).

[[Page 754]]

    (5) The applicable monitoring requirements and any parametric level 
that assures destruction or removal for all emissions routed to the 
control or destruction device.
    Process means all equipment that collectively functions to produce a 
fluorinated gas product, including an isolated intermediate (which is 
also a fluorinated gas product), or to transform a fluorinated gas 
product. A process may consist of one or more unit operations. For the 
purposes of this subpart, process includes any, all, or a combination of 
reaction, recovery, separation, purification, or other activity, 
operation, manufacture, or treatment which are used to produce a 
fluorinated gas product. For a continuous process, cleaning operations 
conducted may be considered part of the process, at the discretion of 
the facility. For a batch process, cleaning operations are part of the 
process. Ancillary activities are not considered a process or part of 
any process under this subpart. Ancillary activities include boilers and 
incinerators, chillers and refrigeration systems, and other equipment 
and activities that are not directly involved (i.e., they operate within 
a closed system and materials are not combined with process fluids) in 
the processing of raw materials or the manufacturing of a fluorinated 
gas product.
    Process condenser means a condenser whose primary purpose is to 
recover material as an integral part of a process. All condensers 
recovering condensate from a process vent at or above the boiling point 
or all condensers in line prior to a vacuum source are considered 
process condensers. Typically, a primary condenser or condensers in 
series are considered to be integral to the process if they are capable 
of and normally used for the purpose of recovering chemicals for fuel 
value (i.e., net positive heating value), use, reuse or for sale for 
fuel value, use, or reuse.
    Process vent (for the purposes of this subpart only) means a vent 
from a process vessel or vents from multiple process vessels within a 
process that are manifolded together into a common header, through which 
a fluorinated GHG-containing gas stream is, or has the potential to be, 
released to the atmosphere (or the point of entry into a control device, 
if any). Examples of process vents include, but are not limited to, 
vents on condensers used for product recovery, bottoms receivers, surge 
control vessels, reactors, filters, centrifuges, and process tanks. 
Process vents do not include vents on storage tanks, wastewater emission 
sources, or pieces of equipment.
    Typical batch means a batch process operated within a range of 
operating conditions that are documented in an operating scenario. 
Emissions from a typical batch are based on the operating conditions 
that result in representative emissions. The typical batch defines the 
uncontrolled emissions for each emission episode defined under the 
operating scenario.
    Uncontrolled fluorinated GHG emissions means a gas stream containing 
fluorinated GHG which has exited the process (or process condenser or 
control condenser, where applicable), but which has not yet been 
introduced into a destruction device to reduce the mass of fluorinated 
GHG in the stream. If the emissions from the process are not routed to a 
destruction device, uncontrolled emissions are those fluorinated GHG 
emissions released to the atmosphere.
    Unsafe-to-monitor means that monitoring personnel would be exposed 
to an immediate danger as a consequence of monitoring the piece of 
equipment. Examples of unsafe-to-monitor equipment include, but are not 
limited to, equipment under extreme pressure or heat.

[75 FR 74831, Dec. 1, 2010, as amended at 77 FR 51490, Aug. 24, 2012; 79 
FR 73789, Dec. 11, 2014]



Sec. Table L-1 to Subpart L of Part 98--Ranges of Effective Destruction 
                               Efficiency

------------------------------------------------------------------------
                           Range of Reductions
-------------------------------------------------------------------------
=99%.
=95% to <99%.
=75% to <95%.
=0% to <75%.
------------------------------------------------------------------------


[79 FR 73789, Dec. 11, 2014]

[[Page 755]]



    Sec. Appendix A to Subpart L of Part 98--Mass Balance Method for 
                       Fluorinated Gas Production

    1. Mass Balance Method for Sec. 98.123(b). [Note: Numbering 
convention here matches original rule text, 75 FR 74774, December 1, 
2010.]
    (b) Mass balance method. Before using the mass balance approach to 
estimate your fluorinated GHG emissions from a process, you must ensure 
that the process and the equipment and methods used to measure it meet 
either the error limits described in this paragraph and calculated under 
paragraph (b)(1) of this section or the requirements specified in 
paragraph Sec. 98.124(b)(8). If you choose to calculate the error 
limits, you must estimate the absolute and relative errors associated 
with using the mass balance approach on that process using Equations L-1 
through L-4 of this section in conjunction with Equations L-5 through L-
10 of this section. You may use the mass-balance approach to estimate 
emissions from the process if this calculation results in an absolute 
error of less than or equal to 3,000 metric tons CO2e per 
year or a relative error of less than or equal to 30 percent of the 
estimated CO2e fluorinated GHG emissions. If you do not meet 
either of the error limits or the requirements of paragraph Sec. 
98.124(b)(8), you must use the emission factor approach detailed in 
paragraphs (c), (d), and (e) of this section to estimate emissions from 
the process.
    (1) Error calculation. To perform the calculation, you must first 
calculate the absolute and relative errors associated with the 
quantities calculated using either Equations L-7 through L-10 of this 
section or Equation L-17 of this section. Alternatively, you may 
estimate these errors based on the variability of previous process 
measurements (e.g., the variability of measurements of stream 
concentrations), provided these measurements are representative of the 
current process and current measurement devices and techniques. Once 
errors have been calculated for the quantities in these equations, those 
errors must be used to calculate the errors in Equations L-6 and L-5 of 
this section. You may ignore the errors associated with Equations L-11, 
L-12, and L-13 of this section.
    (i) Where the measured quantity is a mass, the error in the mass 
must be equated to the accuracy or precision (whichever is larger) of 
the flowmeter, scale, or combination of volumetric and density 
measurements at the flow rate or mass measured.
    (ii) Where the measured quantity is a concentration of a stream 
component, the error of the concentration must be equated to the 
accuracy or precision (whichever is larger) with which you estimate the 
mean concentration of that stream component, accounting for the 
variability of the process, the frequency of the measurements, and the 
accuracy or precision (whichever is larger) of the analytical technique 
used to measure the concentration at the concentration measured. If the 
variability of process measurements is used to estimate the error, this 
variability shall be assumed to account both for the variability of the 
process and the precision of the analytical technique. Use standard 
statistical techniques such as the student's t distribution to estimate 
the error of the mean of the concentration measurements as a function of 
process variability and frequency of measurement.
    (iii) Equation L-1 of this section provides the general formula for 
calculating the absolute errors of sums and differences where the sum, 
S, is the summation of variables measured, a, b, c, etc. (e.g., S = a + 
b + c):
[GRAPHIC] [TIFF OMITTED] TR11DE14.005

Where:

eSA = Absolute error of the sum, expressed as one half of a 
          95 percent confidence interval.
ea = Relative error of a, expressed as one half of a 95 
          percent confidence interval.
eb = Relative error of b, expressed as one half of a 95 
          percent confidence interval.
ec = Relative error of c, expressed as one half of a 95 
          percent confidence interval.

    (iv) Equation L-2 of this section provides the general formula for 
calculating the relative errors of sums and differences:
[GRAPHIC] [TIFF OMITTED] TR11DE14.006


[[Page 756]]


Where:

eSR = Relative error of the sum, expressed as one half of a 
          95 percent confidence interval.
eSA = Absolute error of the sum, expressed as one half of a 
          95 percent confidence interval.
a + b + c = Sum of the variables measured.

    (v) Equation L-3 of this section provides the general formula for 
calculating the absolute errors of products (e.g., flow rates of GHGs 
calculated as the product of the flow rate of the stream and the 
concentration of the GHG in the stream), where the product, P, is the 
result of multiplying the variables measured, a, b, c, etc. (e.g., P = 
a*b*c):
[GRAPHIC] [TIFF OMITTED] TR11DE14.007

Where:
ePA = Absolute error of the product, expressed as one half of 
          a 95 percent confidence interval.
ea = Relative error of a, expressed as one half of a 95 
          percent confidence interval.
eb = Relative error of b, expressed as one half of a 95 
          percent confidence interval.
ec = Relative error of c, expressed as one half of a 95 
          percent confidence interval.

    (vi) Equation L-4 of this section provides the general formula for 
calculating the relative errors of products:
[GRAPHIC] [TIFF OMITTED] TR11DE14.008

Where:
ePR = Relative error of the product, expressed as one half of 
          a 95 percent confidence interval.
ePA = Absolute error of the product, expressed as one half of 
          a 95 percent confidence interval.
a*b*c = Product of the variables measured.

    (vii) Calculate the absolute error of the emissions estimate in 
terms of CO2e by performing a preliminary estimate of the 
annual CO2e emissions of the process using the method in 
paragraph (b)(1)(viii) of this section. Multiply this result by the 
relative error calculated for the mass of fluorine emitted from the 
process in Equation L-6 of this section.
    (viii) To estimate the annual CO2e emissions of the 
process for use in the error estimate, apply the methods set forth in 
paragraphs (b)(2) through (7) and (b)(9) through (16) of this section to 
representative process measurements. If these process measurements 
represent less than one year of typical process activity, adjust the 
estimated emissions to account for one year of typical process activity. 
To estimate the terms FERd, FEP, and FEBk for use 
in the error estimate for Equations L-11, L-12, and L-13 of this 
section, you must either use emission testing, monitoring of emitted 
streams, and/or engineering calculations or assessments, or in the 
alternative assume that all fluorine is emitted in the form of the 
fluorinated GHG that has the highest GWP among the fluorinated GHGs that 
occur in more than trace concentrations in the process. To convert the 
fluorinated GHG emissions to CO2e, use Equation A-1 of Sec. 
98.2. For fluorinated GHGs whose GWPs are not listed in Table A-1 to 
subpart A of this part, use a default GWP of 2,000.
    (2) The total mass of each fluorinated GHG emitted annually from 
each fluorinated gas production and each fluorinated GHG transformation 
process must be estimated by using Equation L-5 of this section.
[GRAPHIC] [TIFF OMITTED] TR11DE14.009


[[Page 757]]


Where:

EFGHGf = Total mass of each fluorinated GHG f emitted 
          annually from production or transformation process i (metric 
          tons).
ERp-FGHGf = Total mass of fluorinated GHG reactant f emitted 
          from production process i over the period p (metric tons, 
          calculated in Equation L-11 of this section).
EPp-FGHGf = Total mass of the fluorinated GHG product f 
          emitted from production process i over the period p (metric 
          tons, calculated in Equation L-12 of this section).
EBp-FGHGf = Total mass of fluorinated GHG by-product f 
          emitted from production process i over the period p (metric 
          tons, calculated in Equation L-13 of this section).
n = Number of concentration and flow measurement periods for the year.

    (3) The total mass of fluorine emitted from process i over the 
period p must be estimated at least monthly by calculating the 
difference between the total mass of fluorine in the reactant(s) (or 
inputs, for processes that do not involve a chemical reaction) and the 
total mass of fluorine in the product (or outputs, for processes that do 
not involve a chemical reaction), accounting for the total mass of 
fluorine in any destroyed or recaptured streams that contain reactants, 
products, or by-products (or inputs or outputs). This calculation must 
be performed using Equation L-6 of this section. An element other than 
fluorine may be used in the mass-balance equation, provided the element 
occurs in all of the fluorinated GHGs fed into or generated by the 
process. In this case, the mass fractions of the element in the 
reactants, products, and by-products must be calculated as appropriate 
for that element.
[GRAPHIC] [TIFF OMITTED] TR11DE14.010

Where:

EF = Total mass of fluorine emitted from process i over the 
          period p (metric tons).
Rd = Total mass of the fluorine-containing reactant d that is 
          fed into process i over the period p (metric tons).
P = Total mass of the fluorine-containing product produced by process i 
          over the period p (metric tons).
MFFRd = Mass fraction of fluorine in reactant d, calculated 
          in Equation L-14 of this section.
MFFP = Mass fraction of fluorine in the product, calculated 
          in Equation L-15 of this section.
FD = Total mass of fluorine in destroyed or recaptured 
          streams from process i containing fluorine-containing 
          reactants, products, and by-products over the period p, 
          calculated in Equation L-7 of this section.
v = Number of fluorine-containing reactants fed into process i.

    (4) The mass of total fluorine in destroyed or recaptured streams 
containing fluorine-containing reactants, products, and by-products must 
be estimated at least monthly using Equation L-7 of this section unless 
you use the alternative approach provided in paragraph (b)(15) of this 
section.
[GRAPHIC] [TIFF OMITTED] TR11DE14.011

Where:

FD = Total mass of fluorine in destroyed or recaptured 
          streams from process i containing fluorine-containing 
          reactants, products, and by-products over the period p.
Pj = Mass of the fluorine-containing product removed from 
          process i in stream j and destroyed over the period p 
          (calculated in Equation L-8 or L-9 of this section).
Bkj = Mass of fluorine-containing by-product k removed from 
          process i in stream j and destroyed over the period p 
          (calculated in Equation L-8 or L-9 of this section).
Bkl = Mass of fluorine-containing by-product k removed from 
          process i in stream l and recaptured over the period p.
Rdj = Mass of fluorine-containing reactant d removed from 
          process i in stream j and destroyed over the period p 
          (calculated in Equation L-8 or L-9 of this section).
MFFRd = Mass fraction of fluorine in reactant d, calculated 
          in Equation L-14 of this section.

[[Page 758]]

MFFP = Mass fraction of fluorine in the product, calculated 
          in Equation L-15 of this section.
MFFBk = Mass fraction of fluorine in by-product k, calculated 
          in Equation L-16 of this section.
q = Number of streams destroyed in process i.
x = Number of streams recaptured in process i.
u = Number of fluorine-containing by-products generated in process i.
v = Number of fluorine-containing reactants fed into process i.

    (5) The mass of each fluorinated GHG removed from process i in 
stream j and destroyed over the period p (i.e., Pj, 
Bkj, or Rdj, as applicable) must be estimated by 
applying the destruction efficiency (DE) of the device that has been 
demonstrated for the fluorinated GHG f to fluorinated GHG f using 
Equation L-8 of this section:
[GRAPHIC] [TIFF OMITTED] TR11DE14.012

Where:

MFGHGfj = Mass of fluorinated GHG f removed from process i in 
          stream j and destroyed over the period p. (This may be 
          Pj, Bkj, or Rdj, as 
          applicable.)
DEFGHGf = Destruction efficiency of the device that has been 
          demonstrated for fluorinated GHG f in stream j (fraction).
CFGHGfj = Concentration (mass fraction) of fluorinated GHG f 
          in stream j removed from process i and fed into the 
          destruction device over the period p. If this concentration is 
          only a trace concentration, cF-GHGfj is equal to 
          zero.
Sj = Mass removed in stream j from process i and fed into the 
          destruction device over the period p (metric tons).

    (6) The mass of each fluorine-containing compound that is not a 
fluorinated GHG and that is removed from process i in stream j and 
destroyed over the period p (i.e., Pj, Bkj, or 
Rdj, as applicable) must be estimated using Equation L-9 of 
this section.
[GRAPHIC] [TIFF OMITTED] TR11DE14.013

Where:

MFCgj = Mass of non-GHG fluorine-containing compound g 
          removed from process i in stream j and destroyed over the 
          period p. (This may be Pj, Bkj, or 
          Rdj, as applicable).
cFCgj = Concentration (mass fraction) of non-GHG fluorine-
          containing compound g in stream j removed from process i and 
          fed into the destruction device over the period p. If this 
          concentration is only a trace concentration, cFCgj 
          is equal to zero.
Sj = Mass removed in stream j from process i and fed into the 
          destruction device over the period p (metric tons).

    (7) The mass of fluorine-containing by-product k removed from 
process i in stream l and recaptured over the period p must be estimated 
using Equation L-10 of this section:
[GRAPHIC] [TIFF OMITTED] TR11DE14.014

Where:
Bkl = Mass of fluorine-containing by-product k removed from 
          process i in stream l and recaptured over the period p (metric 
          tons).
cBkl = Concentration (mass fraction) of fluorine-containing 
          by-product k in stream l removed from process i and recaptured 
          over the period p. If this concentration is only a trace 
          concentration, cBkl is equal to zero.
Sl = Mass removed in stream l from process i and recaptured 
          over the period p (metric tons).

    (8) To estimate the terms FERd, FEP, and FEBk 
for Equations L-11, L-12, and L-13 of this section, you must assume that 
the total mass of fluorine emitted, EF, estimated in

[[Page 759]]

Equation L-6 of this section, occurs in the form of the fluorinated GHG 
that has the highest GWP among the fluorinated GHGs that occur in more 
than trace concentrations in the process unless you possess emission 
characterization measurements showing otherwise. These emission 
characterization measurements must meet the requirements in paragraph 
(8)(i), (ii), or (iii) of this section, as appropriate. The sum of the 
terms must equal 1. You must document the data and calculations that are 
used to speciate individual compounds and to estimate FERd, 
FEP, and FEBk. Exclude from your calculations the fluorine 
included in FD. For example, exclude fluorine-containing 
compounds that are not fluorinated GHGs and that result from the 
destruction of fluorinated GHGs by any destruction devices (e.g., the 
mass of HF created by combustion of an HFC). However, include emissions 
of fluorinated GHGs that survive the destruction process.
    (i) If the calculations under paragraph (b)(1)(viii) of this 
section, or any subsequent measurements and calculations under this 
subpart, indicate that the process emits 25,000 metric tons 
CO2e or more, estimate the emissions from each process vent, 
considering controls, using the methods in Sec. 98.123(c)(1). You must 
characterize the emissions of any process vent that emits 25,000 metric 
tons CO2e or more as specified in Sec. 98.124(b)(4).
    (ii) For other vents, including vents from processes that emit less 
than 25,000 metric tons CO2e, you must characterize emissions 
as specified in Sec. 98.124(b)(5).
    (iii) For fluorine emissions that are not accounted for by vent 
estimates, you must characterize emissions as specified in Sec. 
98.124(b)(6).
    (9) The total mass of fluorine-containing reactant d emitted must be 
estimated at least monthly based on the total fluorine emitted and the 
fraction that consists of fluorine-containing reactants using Equation 
L-11 of this section. If the fluorine-containing reactant d is a non-
GHG, you may assume that FERd is zero.
[GRAPHIC] [TIFF OMITTED] TR11DE14.015

Where:

ER-ip = Total mass of fluorine-containing reactant d that is 
          emitted from process i over the period p (metric tons).
FERd = The fraction of the mass emitted that consists of the 
          fluorine-containing reactant d.
EF = Total mass of fluorine emissions from process i over the 
          period p (metric tons), calculated in Equation L-6 of this 
          section.
FEP = The fraction of the mass emitted that consists of the fluorine-
          containing product.
FEBk = The fraction of the mass emitted that consists of 
          fluorine-containing by-product k.
MFFRd = Mass fraction of fluorine in reactant d, calculated 
          in Equation L-14 of this section.
MFFP = Mass fraction of fluorine in the product, calculated 
          in Equation L-15 of this section.
MFFBk = Mass fraction of fluorine in by-product k, 
          calculation in Equation L-16 of this section.
u = Number of fluorine-containing by-products generated in process i.
v = Number of fluorine-containing reactants fed into process i.

    (10) The total mass of fluorine-containing product emitted must be 
estimated at least monthly based on the total fluorine emitted and the 
fraction that consists of fluorine-containing products using Equation L-
12 of this section. If the fluorine-containing product is a non-GHG, you 
may assume that FEP is zero.
[GRAPHIC] [TIFF OMITTED] TR11DE14.016


[[Page 760]]


Where:

EP-ip = Total mass of fluorine-containing product emitted 
          from process i over the period p (metric tons).
FEP = The fraction of the mass emitted that consists of the fluorine-
          containing product.
EF = Total mass of fluorine emissions from process i over the 
          period p (metric tons), calculated in Equation L-6 of this 
          section.
FERd = The fraction of the mass emitted that consists of 
          fluorine-containing reactant d.
FEBk = The fraction of the mass emitted that consists of 
          fluorine-containing by-product k.
MFFRd = Mass fraction of fluorine in reactant d, calculated 
          in Equation L-14 of this section.
MFFP = Mass fraction of fluorine in the product, calculated 
          in Equation L-15 of this section.
MFFBk = Mass fraction of fluorine in by-product k, 
          calculation in Equation L-16 of this section.
u = Number of fluorine-containing by-products generated in process i.
v = Number of fluorine-containing reactants fed into process i.

    (11) The total mass of fluorine-containing by-product k emitted must 
be estimated at least monthly based on the total fluorine emitted and 
the fraction that consists of fluorine-containing by-products using 
Equation L-13 of this section. If fluorine-containing by-product k is a 
non-GHG, you may assume that FEBk is zero.
[GRAPHIC] [TIFF OMITTED] TR11DE14.017

Where:

EBk-ip = Total mass of fluorine-containing by-product k 
          emitted from process i over the period p (metric tons).
FEBk = The fraction of the mass emitted that consists of 
          fluorine-containing by-product k.
FERd = The fraction of the mass emitted that consists of 
          fluorine-containing reactant d.
FEP = The fraction of the mass emitted that consists of the fluorine-
          containing product.
EF = Total mass of fluorine emissions from process i over the 
          period p (metric tons), calculated in Equation L-6 of this 
          section.
MFFRd = Mass fraction of fluorine in reactant d, calculated 
          in Equation L-14 of this section.
MFFP = Mass fraction of fluorine in the product, calculated 
          in Equation L-15 of this section.
MFFBk = Mass fraction of fluorine in by-product k, 
          calculation in Equation L-16 of this section.
u = Number of fluorine-containing by-products generated in process i.
v = Number of fluorine-containing reactants fed into process i.

    (12) The mass fraction of fluorine in reactant d must be estimated 
using Equation L-14 of this section:
[GRAPHIC] [TIFF OMITTED] TR11DE14.018

Where:

MFFRd = Mass fraction of fluorine in reactant d (fraction).
MFRd = Moles fluorine per mole of reactant d.
AWF = Atomic weight of fluorine.
MWRd = Molecular weight of reactant d.

    (13) The mass fraction of fluorine in the product must be estimated 
using Equation L-15 of this section:

[[Page 761]]

[GRAPHIC] [TIFF OMITTED] TR11DE14.019

Where:
MFFP = Mass fraction of fluorine in the product (fraction).
MFP = Moles fluorine per mole of product.
AWF = Atomic weight of fluorine.
MWP = Molecular weight of the product produced.

    (14) The mass fraction of fluorine in by-product k must be estimated 
using Equation L-16 of this section:
[GRAPHIC] [TIFF OMITTED] TR11DE14.020

Where:

MFFBk = Mass fraction of fluorine in the product (fraction).
MFBk = Moles fluorine per mole of by-product k.
AWF = Atomic weight of fluorine.
MWBk = Molecular weight of by-product k.

    (15) Alternative for determining the mass of fluorine destroyed or 
recaptured. As an alternative to using Equation L-7 of this section as 
provided in paragraph (b)(4) of this section, you may estimate at least 
monthly the total mass of fluorine in destroyed or recaptured streams 
containing fluorine-containing compounds (including all fluorine-
containing reactants, products, and byproducts) using Equation L-17 of 
this section.
[GRAPHIC] [TIFF OMITTED] TR11DE14.021

Where:

FD = Total mass of fluorine in destroyed or recaptured 
          streams from process i containing fluorine-containing 
          reactants, products, and by-products over the period p.
DEavgj = Weighted average destruction efficiency of the 
          destruction device for the fluorine-containing compounds 
          identified in destroyed stream j under Sec. 98.124(b)(4)(ii) 
          and (5)(ii) (calculated in Equation L-18 of this 
          section)(fraction).
cTFj = Concentration (mass fraction) of total fluorine in 
          stream j removed from process i and fed into the destruction 
          device over the period p. If this concentration is only a 
          trace concentration, cTFj is equal to zero.
Sj = Mass removed in stream j from process i and fed into the 
          destruction device over the period p (metric tons).
cTFl = Concentration (mass fraction) of total fluorine in 
          stream l removed from process i and recaptured over the period 
          p. If this concentration is only a trace concentration, 
          cBkl is equal to zero.
Sl = Mass removed in stream l from process i and recaptured 
          over the period p.
q = Number of streams destroyed in process i.
x = Number of streams recaptured in process i.

    (16) Weighted average destruction efficiency. For purposes of 
Equation L-17 of this section, calculate the weighted average 
destruction efficiency applicable to a destroyed stream using Equation 
L-18 of this section.

[[Page 762]]

[GRAPHIC] [TIFF OMITTED] TR11DE14.022

Where:

DEavgj = Weighted average destruction efficiency of the 
          destruction device for the fluorine-containing compounds 
          identified in destroyed stream j under 98.124(b)(4)(ii) or 
          (b)(5)(ii), as appropriate.
DEFGHGf = Destruction efficiency of the device that has been 
          demonstrated for fluorinated GHG f in stream j (fraction).
cFGHGfj = Concentration (mass fraction) of fluorinated GHG f 
          in stream j removed from process i and fed into the 
          destruction device over the period p. If this concentration is 
          only a trace concentration, cF-GHGfj is equal to 
          zero.
cFCgj = Concentration (mass fraction) of non-GHG fluorine-
          containing compound g in stream j removed from process i and 
          fed into the destruction device over the period p. If this 
          concentration is only a trace concentration, cFCgj 
          is equal to zero.
Sj = Mass removed in stream j from process i and fed into the 
          destruction device over the period p (metric tons).
MFFFGHGf = Mass fraction of fluorine in fluorinated GHG f, 
          calculated in Equation L-14, L-15, or L-16 of this section, as 
          appropriate.
MFFFCg = Mass fraction of fluorine in non-GHG fluorine-
          containing compound g, calculated in Equation L-14, L-15, or 
          L-16 of this section, as appropriate.
w = Number of fluorinated GHGs in destroyed stream j.
y = Number of non-GHG fluorine-containing compounds in destroyed stream 
          j.

    2. Mass Balance Method for Sec. 98.124(b). [Note: Numbering 
convention here matches original rule text, 75 FR 74774, December 1, 
2010.]
    (b) Mass balance monitoring. If you determine fluorinated GHG 
emissions from any process using the mass balance method under Sec. 
98.123(b), you must estimate the total mass of each fluorinated GHG 
emitted from that process at least monthly. Only streams that contain 
greater than trace concentrations of fluorine-containing reactants, 
products, or by-products must be monitored under this paragraph. If you 
use an element other than fluorine in the mass-balance equation pursuant 
to Sec. 98.123(b)(3), substitute that element for fluorine in the 
monitoring requirements of this paragraph.
    (1) Mass measurements. Measure the following masses on a monthly or 
more frequent basis using flowmeters, weigh scales, or a combination of 
volumetric and density measurements with accuracies and precisions that 
allow the facility to meet the error criteria in Sec. 98.123(b)(1):
    (i) Total mass of each fluorine-containing product produced. Account 
for any used fluorine-containing product added into the production 
process upstream of the output measurement as directed at Sec. Sec. 
98.413(b) and 98.414(b). For each product, the mass produced used for 
the mass-balance calculation must be the same as the mass produced that 
is reported under subpart OO of this part, where applicable.
    (ii) Total mass of each fluorine-containing reactant fed into the 
process.
    (iii) The mass removed from the process in each stream fed into the 
destruction device.
    (iv) The mass removed from the process in each recaptured stream.
    (2) Concentration measurements for use with Sec. 98.123(b)(4). If 
you use Sec. 98.123(b)(4) to estimate the mass of fluorine in destroyed 
or recaptured streams, measure the following concentrations at least 
once each calendar month during which the process is operating, on a 
schedule to ensure that the measurements are representative of the full 
range of process conditions (e.g., catalyst age). Measure more 
frequently if this is necessary to meet the error criteria in Sec. 
98.123(b)(1). Use equipment and methods (e.g., gas chromatography) that 
comply with paragraph (e) of this section and that have an accuracy and 
precision that allow the facility to meet the error criteria in Sec. 
98.123(b)(1). Only fluorine-containing reactants, products, and by-
products that occur in a stream in greater than trace concentrations 
must be monitored under this paragraph.
    (i) The concentration (mass fraction) of the fluorine-containing 
product in each stream that is fed into the destruction device.
    (ii) The concentration (mass fraction) of each fluorine-containing 
by-product in each stream that is fed into the destruction device.
    (iii) The concentration (mass fraction) of each fluorine-containing 
reactant in each stream that is fed into the destruction device.
    (iv) The concentration (mass fraction) of each fluorine-containing 
by-product in each stream that is recaptured (cBkl).

[[Page 763]]

    (3) Concentration measurements for use with Sec. 98.123(b)(15). If 
you use Sec. 98.123(b)(15) to estimate the mass of fluorine in 
destroyed or recaptured streams, measure the concentrations listed in 
paragraphs (b)(3)(i) and (ii) of this section at least once each 
calendar month during which the process is operating, on a schedule to 
ensure that the measurements are representative of the full range of 
process conditions (e.g., catalyst age). Measure more frequently if this 
is necessary to meet the error criteria in Sec. 98.123(b)(1). Use 
equipment and methods (e.g., gas chromatography) that comply with 
paragraph (e) of this section and that have an accuracy and precision 
that allow the facility to meet the error criteria in Sec. 
98.123(b)(1). Only fluorine-containing reactants, products, and by-
products that occur in a stream in greater than trace concentrations 
must be monitored under this paragraph.
    (i) The concentration (mass fraction) of total fluorine in each 
stream that is fed into the destruction device.
    (ii) The concentration (mass fraction) of total fluorine in each 
stream that is recaptured.
    (4) Emissions characterization: process vents emitting 25,000 metric 
tons CO2e or more. To characterize emissions from any process vent 
emitting 25,000 metric tons CO2e or more, comply with 
paragraphs (b)(4)(i) through (b)(4)(v) of this section, as appropriate. 
Only fluorine-containing reactants, products, and by-products that occur 
in a stream in greater than trace concentrations must be monitored under 
this paragraph.
    (i) Uncontrolled emissions. If emissions from the process vent are 
not routed through a destruction device, sample and analyze emissions at 
the process vent or stack or sample and analyze emitted streams before 
the process vent. If the process has more than one operating scenario, 
you must either perform the emission characterization for each operating 
scenario or perform the emission characterization for the operating 
scenario that is expected to have the largest emissions and adjust the 
emission characterization for other scenarios using engineering 
calculations and assessments as specified in Sec. 98.123(c)(4). To 
perform the characterization, take three samples under conditions that 
are representative for the operating scenario. Measure the concentration 
of each fluorine-containing compound in each sample. Use equipment and 
methods that comply with paragraph (e) of this section. Calculate the 
average concentration of each fluorine-containing compound across all 
three samples.
    (ii) Controlled emissions using Sec. 98.123(b)(15). If you use 
Sec. 98.123(b)(15) to estimate the total mass of fluorine in destroyed 
or recaptured streams, and if the emissions from the process vent are 
routed through a destruction device, characterize emissions as specified 
in paragraph (b)(4)(i) of this section before the destruction device. 
Apply the destruction efficiency demonstrated for each fluorinated GHG 
in the destroyed stream to that fluorinated GHG. Exclude from the 
characterization fluorine-containing compounds that are not fluorinated 
GHGs.
    (iii) Controlled emissions using Sec. 98.123(b)(4). If you use 
Sec. 98.123(b)(4) to estimate the mass of fluorine in destroyed or 
recaptured streams, and if the emissions from the process vent are 
routed through a destruction device, characterize the process vent's 
emissions monthly (or more frequently) using the monthly (or more 
frequent) measurements under paragraphs (b)(1)(iii) and (b)(2)(i) 
through (iii) of this section. Apply the destruction efficiency 
demonstrated for each fluorinated GHG in the destroyed stream to that 
fluorinated GHG. Exclude from the characterization fluorine-containing 
compounds that are not fluorinated GHGs.
    (iv) Emissions characterization frequency. You must repeat emission 
characterizations performed under paragraph (b)(4)(i) and (ii) of this 
section under paragraph (b)(4)(iv)(A) or (B) of this section, whichever 
occurs first:
    (A) 10-year revision. Repeat the emission characterization every 10 
years. In the calculations under Sec. 98.123, apply the revised 
emission characterization to the process activity that occurs after the 
revision.
    (B) Operating scenario change that affects the emission 
characterization. For planned operating scenario changes, you must 
estimate and compare the emission calculation factors for the changed 
operating scenario and for the original operating scenario whose process 
vent specific emission factor was measured. Use the engineering 
calculations and assessments specified in Sec. 98.123(c)(4). If the 
share of total fluorine-containing compound emissions represented by any 
fluorinated GHG changes under the changed operating scenario by 15 
percent or more of the total, relative to the previous operating 
scenario (this includes the cumulative change in the emission 
calculation factor since the last emissions test), you must repeat the 
emission characterization. Perform the emission characterization before 
February 28 of the year that immediately follows the change. In the 
calculations under Sec. 98.123, apply the revised emission 
characterization to the process activity that occurs after the operating 
scenario change.
    (v) Subsequent measurements. If a process vent with fluorinated GHG 
emissions less than 25,000 metric tons CO2e, per Sec. 
98.123(c)(2), is later found to have fluorinated GHG emissions of 25,000 
metric tons CO2e or greater, you must perform an emission 
characterization under this paragraph during the following year.
    (5) Emissions characterization: Process vents emitting less than 
25,000 metric tons CO2e. To characterize emissions from any process vent

[[Page 764]]

emitting less than 25,000 metric tons CO2e, comply with 
paragraphs (b)(5)(i) through (iii) of this section, as appropriate. Only 
fluorine-containing reactants, products, and by-products that occur in a 
stream in greater than trace concentrations must be monitored under this 
paragraph.
    (i) Uncontrolled emissions. If emissions from the process vent are 
not routed through a destruction device, emission measurements must 
consist of sampling and analysis of emissions at the process vent or 
stack, sampling and analysis of emitted streams before the process vent, 
previous test results, provided the tests are representative of current 
operating conditions of the process, or bench-scale or pilot-scale test 
data representative of the process operating conditions.
    (ii) Controlled emissions using Sec. 98.123(b)(15). If you use 
Sec. 98.123(b)(15) to estimate the total mass of fluorine in destroyed 
or recaptured streams, and if the emissions from the process vent are 
routed through a destruction device, characterize emissions as specified 
in paragraph (b)(5)(i) of this section before the destruction device. 
Apply the destruction efficiency demonstrated for each fluorinated GHG 
in the destroyed stream to that fluorinated GHG. Exclude from the 
characterization fluorine-containing compounds that are not fluorinated 
GHGs.
    (iii) Controlled emissions using Sec. 98.123(b)(4). If you use 
Sec. 98.123(b)(4) to estimate the mass of fluorine in destroyed or 
recaptured streams, and if the emissions from the process vent are 
routed through a destruction device, characterize the process vent's 
emissions monthly (or more frequently) using the monthly (or more 
frequent) measurements under paragraphs (b)(1)(iii) and (b)(2)(i) 
through (iii) of this section. Apply the destruction efficiency 
demonstrated for each fluorinated GHG in the destroyed stream to that 
fluorinated GHG. Exclude from the characterization fluorine-containing 
compounds that are not fluorinated GHGs.
    (6) Emissions characterization: Emissions not accounted for by 
process vent estimates. Calculate the weighted average emission 
characterization across the process vents before any destruction 
devices. Apply the weighted average emission characterization for all 
the process vents to any fluorine emissions that are not accounted for 
by process vent estimates.
    (7) Impurities in reactants. If any fluorine-containing impurity is 
fed into a process along with a reactant (or other input) in greater 
than trace concentrations, this impurity shall be monitored under this 
section and included in the calculations under Sec. 98.123 in the same 
manner as reactants fed into the process, fed into the destruction 
device, recaptured, or emitted, except the concentration of the impurity 
in the mass fed into the process shall be measured, and the mass of the 
impurity fed into the process shall be calculated as the product of the 
concentration of the impurity and the mass fed into the process. The 
mass of the reactant fed into the process may be reduced to account for 
the mass of the impurity.
    (8) Alternative to error calculation. As an alternative to 
calculating the relative and absolute errors associated with the 
estimate of emissions under Sec. 98.123(b), you may comply with the 
precision, accuracy, measurement and calculation frequency, and 
fluorinated GHG throughput requirements of paragraph (b)(8)(i) through 
(iv) of this section.
    (i) Mass measurements. Measure the masses specified in paragraph 
(b)(1) of this section using flowmeters, weigh scales, or a combination 
of volumetric and density measurements with accuracies and precisions of 
0.2 percent of full scale or better.
    (ii) Concentration measurements. Measure the concentrations 
specified in paragraph (b)(2) or (3) of this section, as applicable, 
using analytical methods with accuracies and precisions of 10 percent or better.
    (iii) Measurement and calculation frequency. Perform the mass 
measurements specified in paragraph (b)(1) of this section and the 
concentration measurements specified in paragraph (b)(2) or (3) of this 
section, as applicable, at least weekly, and calculate emissions at 
least weekly.
    (iv) Fluorinated-GHG throughput limit. You may use the alternative 
to the error calculation specified in paragraph (b)(8) of this section 
only if the total annual CO2-equivalent fluorinated GHG 
throughput of the process is 500,000 mtCO2e or less. The 
total throughput is the sum of the masses of the fluorinated GHG 
reactants, products, and by-products fed into and generated by the 
process. To convert these masses to CO2e, use Equation A-1 of 
Sec. 98.2. For fluorinated GHGs whose GWPs are not listed in Table A-1 
to subpart A of this part, use a default GWP of 2,000.

[79 FR 73789, Dec. 11, 2014]

Subpart M [Reserved]



                       Subpart N_Glass Production



Sec. 98.140  Definition of the source category.

    (a) A glass manufacturing facility manufactures flat glass, 
container glass, pressed and blown glass, or wool fiberglass by melting 
a mixture of raw materials to produce molten glass and form the molten 
glass into sheets, containers, fibers, or other shapes. A glass 
manufacturing facility uses one or more continuous glass melting 
furnaces to produce glass.

[[Page 765]]

    (b) A glass melting furnace that is an experimental furnace or a 
research and development process unit is not subject to this subpart.



Sec. 98.141  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains a glass production process and the facility meets the 
requirements of either Sec. 98.2(a)(1) or (2).



Sec. 98.142  GHGs to report.

    You must report:
    (a) CO2 process emissions from each continuous glass 
melting furnace.
    (b) CO2 combustion emissions from each continuous glass 
melting furnace.
    (c) CH4 and N2O combustion emissions from each 
continuous glass melting furnace. You must calculate and report these 
emissions under subpart C of this part (General Stationary Fuel 
Combustion Sources) by following the requirements of subpart C.
    (d) CO2, CH4, and N2O emissions 
from each stationary fuel combustion unit other than continuous glass 
melting furnaces. You must report these emissions under subpart C of 
this part (General Stationary Fuel Combustion Sources) by following the 
requirements of subpart C.



Sec. 98.143  Calculating GHG emissions.

    You must calculate and report the annual process CO2 
emissions from each continuous glass melting furnace using the procedure 
in paragraphs (a) through (c) of this section.
    (a) For each continuous glass melting furnace that meets the 
conditions specified in Sec. 98.33(b)(4)(ii) or (iii), you must 
calculate and report under this subpart the combined process and 
combustion CO2 emissions by operating and maintaining a CEMS 
to measure CO2 emissions according to the Tier 4 Calculation 
Methodology specified in Sec. 98.33(a)(4) and all associated 
requirements for Tier 4 in subpart C of this part (General Stationary 
Fuel Combustion Sources).
    (b) For each continuous glass melting furnace that is not subject to 
the requirements in paragraph (a) of this section, calculate and report 
the process and combustion CO2 emissions from the glass 
melting furnace by using either the procedure in paragraph (b)(1) of 
this section or the procedure in paragraph (b)(2) of this section, 
except as specified in paragraph (c) of this section.
    (1) Calculate and report under this subpart the combined process and 
combustion CO2 emissions by operating and maintaining a CEMS 
to measure CO2 emissions according to the Tier 4 Calculation 
Methodology specified in Sec. 98.33(a)(4) and all associated 
requirements for Tier 4 in subpart C of this part (General Stationary 
Fuel Combustion Sources).
    (2) Calculate and report the process and combustion CO2 
emissions separately using the procedures specified in paragraphs 
(b)(2)(i) through (b)(2)(vi) of this section.
    (i) For each carbonate-based raw material charged to the furnace, 
obtain from the supplier of the raw material the carbonate-based mineral 
mass fraction.
    (ii) Determine the quantity of each carbonate-based raw material 
charged to the furnace.
    (iii) Apply the appropriate emission factor for each carbonate-based 
raw material charged to the furnace, as shown in Table N-1 to this 
subpart.
    (iv) Use Equation N-1 of this section to calculate process mass 
emissions of CO2 for each furnace:
[GRAPHIC] [TIFF OMITTED] TR30OC09.049

Where:

ECO2 = Process emissions of CO2 from the furnace 
          (metric tons).
n = Number of carbonate-based raw materials charged to furnace.

[[Page 766]]

MFi = Annual average decimal mass fraction of carbonate-based 
          mineral i in carbonate-based raw material i.
Mi = Annual amount of carbonate-based raw material i charged 
          to furnace (tons).
2000/2205 = Conversion factor to convert tons to metric tons.
EFi = Emission factor for carbonate-based raw material i 
          (metric ton CO2 per metric ton carbonate-based raw 
          material as shown in Table N-1 to this subpart).
Fi = Decimal fraction of calcination achieved for carbonate-
          based raw material i, assumed to be equal to 1.0.

    (v) You must calculate the total process CO2 emissions 
from continuous glass melting furnaces at the facility using Equation N-
2 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.050

Where:

CO2 = Annual process CO2 emissions from glass 
          manufacturing facility (metric tons).
ECO2i = Annual CO2 emissions from glass melting 
          furnace i (metric tons).
k = Number of continuous glass melting furnaces.

    (vi) Calculate and report under subpart C of this part (General 
Stationary Fuel Combustion Sources) the combustion CO2 
emissions in the glass furnace according to the applicable requirements 
in subpart C.
    (c) As an alternative to data provided by the raw material supplier, 
a value of 1.0 can be used for the mass fraction (MFi) of 
carbonate-based mineral i in Equation N-1 of this section.

[75 FR 74831, Dec. 1, 2010, as amended at 78 FR 71954, Nov. 29, 2013]



Sec. 98.144  Monitoring and QA/QC requirements.

    (a) You must measure annual amounts of carbonate-based raw materials 
charged to each continuous glass melting furnace from monthly 
measurements using plant instruments used for accounting purposes, such 
as calibrated scales or weigh hoppers. Total annual mass charged to 
glass melting furnaces at the facility shall be compared to records of 
raw material purchases for the year.
    (b) You must measure carbonate-based mineral mass fractions at least 
annually to verify the mass fraction data provided by the supplier of 
the raw material; such measurements shall be based on sampling and 
chemical analysis using consensus standards that specify X-ray 
fluorescence. For measurements made in years prior to the emissions 
reporting year 2014, you may also use ASTM D3682-01 (Reapproved 2006) 
Standard Test Method for Major and Minor Elements in Combustion Residues 
from Coal Utilization Processes (incorporated by reference, see Sec. 
98.7) or ASTM D6349-09 Standard Test Method for Determination of Major 
and Minor Elements in Coal, Coke, and Solid Residues from Combustion of 
Coal and Coke by Inductively Coupled Plasma--Atomic Emission 
Spectrometry (incorporated by reference, see Sec. 98.7).
    (c) You must determine the annual average mass fraction for the 
carbonate-based mineral in each carbonate-based raw material by 
calculating an arithmetic average of the monthly data obtained from raw 
material suppliers or sampling and chemical analysis.
    (d) You must determine on an annual basis the calcination fraction 
for each carbonate consumed based on sampling and chemical analysis 
using an industry consensus standard. This chemical analysis must be 
conducted using an x-ray fluorescence test or other enhanced testing 
method published by an industry consensus standards organization (e.g., 
ASTM, ASME, API, etc.).

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66462, Oct. 28, 2010; 
78 FR 71954, Nov. 29, 2013]



Sec. 98.145  Procedures for estimating missing data.

    A complete record of all measured parameters used in the GHG 
emissions calculations is required (e.g., carbonate raw materials 
consumed, etc.). If the monitoring and quality assurance procedures in 
Sec. 98.144 cannot be followed and data is missing, you must use the 
most appropriate of the missing data procedures in paragraphs (a) and 
(b) of this section. You must document and keep records of the 
procedures used for all such missing value estimates.
    (a) For missing data on the monthly amounts of carbonate-based raw 
materials charged to any continuous glass

[[Page 767]]

melting furnace use the best available estimate(s) of the parameter(s), 
based on all available process data or data used for accounting 
purposes, such as purchase records.
    (b) For missing data on the mass fractions of carbonate-based 
minerals in the carbonate-based raw materials assume that the mass 
fraction of each carbonate based mineral is 1.0.



Sec. 98.146  Data reporting requirements.

    In addition to the information required by Sec. 98.3(c), each 
annual report must contain the information specified in paragraphs (a) 
and (b) of this section, as applicable.
    (a) If a CEMS is used to measure CO2 emissions, then you 
must report under this subpart the relevant information required under 
Sec. 98.36 for the Tier 4 Calculation Methodology and the following 
information specified in paragraphs (a)(1) and (2) of this section:
    (1) Annual quantity of each carbonate-based raw material charged to 
each continuous glass melting furnace and for all furnaces combined 
(tons).
    (2) Annual quantity of glass produced by each glass melting furnace 
and by all furnaces combined (tons).
    (b) If a CEMS is not used to determine CO2 emissions from 
continuous glass melting furnaces, and process CO2 emissions 
are calculated according to the procedures specified in Sec. 98.143(b), 
then you must report the following information as specified in 
paragraphs (b)(1) through (b)(9) of this section:
    (1) Annual process emissions of CO2 (metric tons) for 
each continuous glass melting furnace and for all furnaces combined.
    (2) Annual quantity of each carbonate-based raw material charged 
(tons) to all furnaces combined.
    (3) Annual quantity of glass produced (tons) from each continuous 
glass melting furnace and from all furnaces combined.
    (4) [Reserved]
    (5) Results of all tests used to verify the carbonate-based mineral 
mass fraction for each carbonate-based raw material charged to a 
continuous glass melting furnace, as specified in paragraphs (b)(5)(i) 
through (b)(5)(iii) of this section.
    (i) Date of test.
    (ii) Method(s) and any variations used in the analyses.
    (iii) Mass fraction of each sample analyzed.
    (6) [Reserved]
    (7) Method used to determine decimal fraction of calcination.
    (8) Total number of continuous glass melting furnaces.
    (9) The number of times in the reporting year that missing data 
procedures were followed to measure monthly quantities of carbonate-
based raw materials or mass fraction of the carbonate-based minerals for 
any continuous glass melting furnace (months).

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66462, Oct. 28, 2010; 
78 FR 71954, Nov. 29, 2013; 79 FR 63786, Oct. 24, 2014]



Sec. 98.147  Records that must be retained.

    In addition to the information required by Sec. 98.3(g), you must 
retain the records listed in paragraphs (a) through (d) of this section.
    (a) If a CEMS is used to measure emissions, then you must retain the 
records required under Sec. 98.37 for the Tier 4 Calculation 
Methodology and the following information specified in paragraphs (a)(1) 
and (a)(2) of this section:
    (1) Monthly glass production rate for each continuous glass melting 
furnace (tons).
    (2) Monthly amount of each carbonate-based raw material charged to 
each continuous glass melting furnace (tons).
    (b) If process CO2 emissions are calculated according to 
the procedures specified in Sec. 98.143(b), you must retain the records 
in paragraphs (b)(1) through (b)(5) of this section.
    (1) Monthly glass production rate for each continuous glass melting 
furnace (metric tons).
    (2) Monthly amount of each carbonate-based raw material charged to 
each continuous glass melting furnace (metric tons).
    (3) Data on carbonate-based mineral mass fractions provided by the 
raw material supplier for all raw materials consumed annually and 
included in calculating process emissions in Equation N-1 of this 
subpart.

[[Page 768]]

    (4) Results of all tests used to verify the carbonate-based mineral 
mass fraction for each carbonate-based raw material charged to a 
continuous glass melting furnace, including the data specified in 
paragraphs (b)(4)(i) through (b)(4)(v) of this section.
    (i) Date of test.
    (ii) Method(s), and any variations of the methods, used in the 
analyses.
    (iii) Mass fraction of each sample analyzed.
    (iv) Relevant calibration data for the instrument(s) used in the 
analyses.
    (v) Name and address of laboratory that conducted the tests.
    (5) The decimal fraction of calcination achieved for each carbonate-
based raw material, if a value other than 1.0 is used to calculate 
process mass emissions of CO2.
    (c) All other documentation used to support the reported GHG 
emissions.
    (d) Verification software records. You must keep a record of the 
file generated by the verification software specified in Sec. 98.5(b) 
for the applicable data specified in paragraphs (d)(1) through (3) of 
this section. Retention of this file satisfies the recordkeeping 
requirement for the data in paragraphs (d)(1) through (3) of this 
section.
    (1) Annual average decimal mass fraction of carbonate-based mineral 
in each carbonate-based raw material for each continuous glass melting 
furnace (specify the default value, if used, or the value determined 
according to Sec. 98.144) (percentage, expressed as a decimal) 
(Equation N-1 of Sec. 98.143).
    (2) Annual amount of each carbonate-based raw material charged to 
each continuous glass melting furnace (tons) (Equation N-1).
    (3) Decimal fraction of each calcination achieved for carbonate-
based raw material for each continuous glass melting furnace (specify 
the default value, if used, or the value determined according to Sec. 
98.144) (percentage, expressed as a decimal) (Equation N-1).

[74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71954, Nov. 29, 2013; 
79 FR 63786, Oct. 24, 2014]



Sec. 98.148  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.



Sec. Table N-1 to Subpart N of Part 98--CO2 Emission Factors 
                    for Carbonate-Based Raw Materials

------------------------------------------------------------------------
                                                                 CO2
           Carbonate-based raw material--mineral               emission
                                                              factor \a\
------------------------------------------------------------------------
Limestone--CaCO3...........................................        0.440
Dolomite--CaMg(CO3)2.......................................        0.477
Sodium carbonate/soda ash--Na2CO3..........................        0.415
Barium carbonate--BaCO3....................................        0.223
Potassium carbonate--K2CO3.................................        0.318
Lithium carbonate (Li2CO3).................................        0.596
Strontium carbonate (SrCO3)................................        0.298
------------------------------------------------------------------------
\a\ Emission factors in units of metric tons of CO2 emitted per metric
  ton of carbonate-based raw material charged to the furnace.


[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66462 , Oct. 28, 2010]



           Subpart O_HCFC	22 Production and HFC	23 Destruction



Sec. 98.150  Definition of the source category.

    The HCFC-22 production and HFC-23 destruction source category 
consists of HCFC-22 production processes and HFC-23 destruction 
processes.
    (a) An HCFC-22 production process produces HCFC-22 
(chlorodifluoromethane, or CHClF2) from chloroform 
(CHCl3) and hydrogen fluoride (HF).
    (b) An HFC-23 destruction process is any process in which HFC-23 
undergoes destruction. An HFC-23 destruction process may or may not be 
co-located with an HCFC-22 production process at the same facility.



Sec. 98.151  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains an HCFC-22 production or HFC-23 destruction process and the 
facility meets the requirements of either Sec. 98.2(a)(1) or (a)(2).



Sec. 98.152  GHGs to report.

    (a) You must report under subpart C of this part (General Stationary 
Fuel Combustion Sources) the emissions of CO2, 
CH4, and N2O from each stationary combustion unit 
following the requirements of subpart C.
    (b) You must report HFC-23 emissions from HCFC-22 production 
processes and HFC-23 destruction processes.

[[Page 769]]



Sec. 98.153  Calculating GHG emissions.

    (a) The mass of HFC-23 generated from each HCFC-22 production 
process shall be estimated by using one of two methods, as applicable:
    (1) Where the mass flow of the combined stream of HFC-23 and another 
reaction product (e.g., HCl) is measured, multiply the weekly (or more 
frequent) HFC-23 concentration measurement (which may be the average of 
more frequent concentration measurements) by the weekly (or more 
frequent) mass flow of the combined stream of HFC-23 and the other 
product. To estimate annual HFC-23 production, sum the weekly (or more 
frequent) estimates of the quantities of HFC-23 produced over the year. 
This calculation is summarized in Equation O-1 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.051

Where:

G23 = Mass of HFC-23 generated annually (metric tons).
c23 = Fraction HFC-23 by weight in HFC-23/other product 
          stream.
Fp = Mass flow of HFC-23/other product stream during the 
          period p (kg).
p = Period over which mass flows and concentrations are measured.
n = Number of concentration and flow measurement periods for the year.
10-3 = Conversion factor from kilograms to metric tons.

    (2) Where the mass of only a reaction product other than HFC-23 
(either HCFC-22 or HCl) is measured, multiply the ratio of the weekly 
(or more frequent) measurement of the HFC-23 concentration and the 
weekly (or more frequent) measurement of the other product concentration 
by the weekly (or more frequent) mass produced of the other product. To 
estimate annual HFC-23 production, sum the weekly (or more frequent) 
estimates of the quantities of HFC-23 produced over the year. This 
calculation is summarized in Equation O-2 of this section, assuming that 
the other product is HCFC-22. If the other product is HCl, HCl may be 
substituted for HCFC-22 in Equations O-2 and O-3 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.052

Where:

G23 = Mass of HFC-23 generated annually (metric tons).
c23 = Fraction HFC-23 by weight in HCFC-22/HFC-23 stream.
c22 = Fraction HCFC-22 by weight in HCFC-22/HFC-23 stream.
P22 = Mass of HCFC-22 produced over the period p (kg), 
          calculated using Equation O-3 of this section.
p = Period over which masses and concentrations are measured.
n = Number of concentration and mass measurement periods for the year.
10-3 = Conversion factor from kilograms to metric tons.

    (b) The mass of HCFC-22 produced over the period p shall be 
estimated by using Equation O-3 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.053

Where:

P22 = Mass of HCFC-22 produced over the period p (kg).
O22 = mass of HCFC-22 that is measured coming out of the 
          Production process over the period p (kg).
U22 = Mass of used HCFC-22 that is added to the production 
          process upstream of the output measurement over the period p 
          (kg).
LF = Factor to account for the loss of HCFC-22 upstream of the 
          measurement. The value for LF shall be determined pursuant to 
          Sec. 98.154(e).

    (c) For HCFC-22 production facilities that do not use a destruction 
device or that have a destruction device that is not directly connected 
to the HCFC-22 production equipment, HFC-23 emissions shall be estimated 
using Equation O-4 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.054


[[Page 770]]


Where:

E23 = Mass of HFC-23 emitted annually (metric tons).
G23 = Mass of HFC-23 generated annually (metric tons).
S23 = Mass of HFC-23 sent off site for sale annually (metric 
          tons).
OD23 = Mass of HFC-23 sent off site for destruction (metric 
          tons).
D23 = Mass of HFC-23 destroyed on site (metric tons).
I23 = Increase in HFC-23 inventory = HFC-23 in storage at end 
          of year--HFC-23 in storage at beginning of year (metric tons).
    (d) For HCFC-22 production facilities that use a destruction device 
connected to the HCFC-22 production equipment, HFC-23 emissions shall be 
estimated using Equation O-5 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.055

Where:

E23 = Mass of HFC-23 emitted annually (metric tons).
EL = Mass of HFC-23 emitted annually from equipment leaks, 
          calculated using Equation O-6 of this section (metric tons).
EPV = Mass of HFC-23 emitted annually from process vents, 
          calculated using Equation O-7 of this section (metric tons).
ED = Mass of HFC-23 emitted annually from destruction device 
          (metric tons), calculated using Equation O-8 of this section.

    (1) The mass of HFC-23 emitted annually from equipment leaks (for 
use in Equation O-5 of this section) shall be estimated by using 
Equation O-6 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.056

Where:

EL = Mass of HFC-23 emitted annually from equipment leaks 
          (metric tons).
c23 = Fraction HFC-23 by weight in the stream(s) in the 
          equipment.
FGt = The applicable leak rate specified in Table O-1 of this 
          subpart for each source of equipment type and service t with a 
          screening value greater than or equal to 10,000 ppmv (kg/hr/
          source).
NGt = The number of sources of equipment type and service t 
          with screening values greater than or equal to 10,000 ppmv as 
          determined according to Sec. 98.154(i).
FLt = The applicable leak rate specified in Table O-1 of this 
          subpart for each source of equipment type and service t with a 
          screening value of less than 10,000 ppmv (kg/hr/source).
NLt = The number of sources of equipment type and service t 
          with screening values less than 10,000 ppmv as determined 
          according to Sec. 98.154(j).
p = One hour.
n = Number of hours during the year during which equipment contained 
          HFC-23.
t = Equipment type and service as specified in Table O-1 of this 
          subpart.
10-3 = Factor converting kg to metric tons.

    (2) The mass of HFC-23 emitted annually from process vents (for use 
in Equation O-5 of this section) shall be estimated by using Equation O-
7 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.057

Where:

EPV = Mass of HFC-23 emitted annually from process vents 
          (metric tons).
ERT = The HFC-23 emission rate from the process vents during 
          the period of the most recent test (kg/hr).
PRp = The HCFC-22 production rate during the period p (kg/
          hr).
PRT = The HCFC-22 production rate during the most recent test 
          period (kg/hr).
lp = The length of the period p (hours).
10-3 = Factor converting kg to metric tons.
n = The number of periods in a year.


[[Page 771]]


    (3) The total mass of HFC-23 emitted from destruction devices shall 
be estimated by using Equation O-8 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.058

Where:

ED = Mass of HFC-23 emitted annually from the destruction 
          device (metric tons).
FD = Mass of HFC-23 fed into the destruction device annually 
          (metric tons).
D23 = Mass of HFC-23 destroyed annually (metric tons).

    (4) For facilities that destroy HFC-23, the total mass of HFC-23 
destroyed shall be estimated by using Equation O-9 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.059

Where:

D23. = Mass of HFC-23 destroyed annually (metric tons).
FD = Mass of HFC-23 fed into the destruction device annually 
          (metric tons).
DE = Destruction Efficiency of the destruction device (fraction).

[74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71955, Nov. 29, 2013]



Sec. 98.154  Monitoring and QA/QC requirements.

    These requirements apply to measurements that are reported under 
this subpart or that are used to estimate reported quantities pursuant 
to Sec. 98.153.
    (a) The concentrations (fractions by weight) of HFC-23 and HCFC-22 
in the product stream shall be measured at least weekly using equipment 
and methods (e.g., gas chromatography) with an accuracy and precision of 
5 percent or better at the concentrations of the process samples.
    (b) The mass flow of the product stream containing the HFC-23 shall 
be measured at least weekly using weigh scales, flowmeters, or a 
combination of volumetric and density measurements with an accuracy and 
precision of 1.0 percent of full scale or better.
    (c) The mass of HCFC-22 or HCl coming out of the production process 
shall be measured at least weekly using weigh scales, flowmeters, or a 
combination of volumetric and density measurements with an accuracy and 
precision of 1.0 percent of full scale or better.
    (d) The mass of any used HCFC-22 added back into the production 
process upstream of the output measurement in paragraph (c) of this 
section shall be measured (when being added) using flowmeters, weigh 
scales, or a combination of volumetric and density measurements with an 
accuracy and precision of 1.0 percent of full scale or better. If the 
mass in paragraph (c) of this section is measured by weighing containers 
that include returned heels as well as newly produced fluorinated GHGs, 
the returned heels shall be considered used fluorinated HCFC-22 for 
purposes of this paragraph (d) of this section and Sec. 98.153(b).
    (e) The loss factor LF in Equation O-3 of this subpart for the mass 
of HCFC-22 produced shall have the value 1.015 or another value that can 
be demonstrated, to the satisfaction of the Administrator, to account 
for losses of HCFC-22 between the reactor and the point of measurement 
at the facility where production is being estimated.
    (f) The mass of HFC-23 sent off site for sale shall be measured at 
least weekly (when being packaged) using flowmeters, weigh scales, or a 
combination of volumetric and density measurements with an accuracy and 
precision of 1.0 percent of full scale or better.
    (g) The mass of HFC-23 sent off site for destruction shall be 
measured at least weekly (when being packaged) using flowmeters, weigh 
scales, or a combination of volumetric and density measurements with an 
accuracy and precision of 1.0 percent of full scale or better. If the 
measured mass includes more than trace concentrations of materials other 
than HFC-23, the concentration of the fluorinated GHG shall be measured 
at least weekly using equipment and methods (e.g., gas chromatography) 
with an accuracy and precision of 5 percent or better at the 
concentrations of the process samples. This concentration (mass 
fraction) shall be multiplied by the mass measurement to obtain the mass 
of the HFC-23 sent to another facility for destruction.
    (h) The masses of HFC-23 in storage at the beginning and end of the 
year shall be measured using flowmeters,

[[Page 772]]

weigh scales, or a combination of volumetric and density measurements 
with an accuracy and precision of 1.0 percent of full scale or better.
    (i) The number of sources of equipment type t with screening values 
greater than or equal to 10,000 ppmv shall be determined using EPA 
Method 21 at 40 CFR part 60, appendix A-7, and defining a leak as 
follows:
    (1) A leak source that could emit HFC-23, and
    (2) A leak source at whose surface a concentration of fluorocarbons 
equal to or greater than 10,000 ppm is measured.
    (j) The number of sources of equipment type t with screening values 
less than 10,000 ppmv shall be the difference between the number of leak 
sources of equipment type t that could emit HFC-23 and the number of 
sources of equipment type t with screening values greater than or equal 
to 10,000 ppmv as determined under paragraph (i) of this section.
    (k) The mass of HFC-23 emitted from process vents shall be estimated 
at least monthly by incorporating the results of the most recent 
emissions test into Equation O-7 of this subpart. HCFC-22 production 
facilities that use a destruction device connected to the HCFC-22 
production equipment shall conduct emissions tests at process vents at 
least once every five years or after significant changes to the process. 
Emissions tests shall be conducted in accordance with EPA Method 18 at 
40 CFR part 60, appendix A-6, under conditions that are typical for the 
production process at the facility. The sensitivity of the tests shall 
be sufficient to detect an emission rate that would result in annual 
emissions of 200 kg of HFC-23 if sustained over one year.
    (l) For purposes of Equation O-9 of this subpart, the destruction 
efficiency must be equated to the destruction efficiency determined 
during a new or previous performance test of the destruction device. 
HFC-23 destruction facilities shall conduct annual measurements of HFC-
23 concentrations at the outlet of the destruction device in accordance 
with EPA Method 18 at 40 CFR part 60, appendix A-6. Three samples shall 
be taken under conditions that are typical for the production process 
and destruction device at the facility, and the average concentration of 
HFC-23 shall be determined. The sensitivity of the concentration 
measurement shall be sufficient to detect an outlet concentration equal 
to or less than the outlet concentration determined in the destruction 
efficiency performance test. If the concentration measurement indicates 
that the HFC-23 concentration is less than or equal to that measured 
during the performance test that is the basis for the destruction 
efficiency, continue to use the previously determined destruction 
efficiency. If the concentration measurement indicates that the HFC-23 
concentration is greater than that measured during the performance test 
that is the basis for the destruction efficiency, facilities shall 
either:
    (1) Substitute the higher HFC-23 concentration for that measured 
during the destruction efficiency performance test and calculate a new 
destruction efficiency, or
    (2) Estimate the mass emissions of HFC-23 from the destruction 
device based on the measured HFC-23 concentration and volumetric flow 
rate determined by measurement of volumetric flow rate using EPA Method 
2, 2A, 2C,2D, or 2F at 40 CFR part 60, appendix A-1, or Method 26 at 40 
CFR part 60, appendix A-2. Determine the mass rate of HFC-23 into the 
destruction device by measuring the HFC-23 concentration and volumetric 
flow rate at the inlet or by a metering device for HFC-23 sent to the 
device. Determine a new destruction efficiency based on the mass flow 
rate of HFC-23 into and out of the destruction device.
    (m) HCFC-22 production facilities shall account for HFC-23 
generation and emissions that occur as a result of startups, shutdowns, 
and malfunctions, either recording HFC-23 generation and emissions 
during these events, or documenting that these events do not result in 
significant HFC-23 generation and/or emissions.
    (n) The mass of HFC-23 fed into the destruction device shall be 
measured at least weekly using flow meters, weigh scales, or a 
combination of volumetric and density measurements with an accuracy and 
precision of 1.0 percent of full scale or better. If the measured

[[Page 773]]

mass includes more than trace concentrations of materials other than 
HFC-23, the concentrations of the HFC-23 shall be measured at least 
weekly using equipment and methods (e.g., gas chromatography) with an 
accuracy and precision of 5 percent or better at the concentrations of 
the process samples. This concentration (mass fraction) shall be 
multiplied by the mass measurement to obtain the mass of the HFC-23 
destroyed.
    (o) In their estimates of the mass of HFC-23 destroyed, HFC-23 
destruction facilities shall account for any temporary reductions in the 
destruction efficiency that result from any startups, shutdowns, or 
malfunctions of the destruction device, including departures from the 
operating conditions defined in State or local permitting requirements 
and/or destruction device manufacturer specifications.
    (p) Calibrate all flow meters, weigh scales, and combinations of 
volumetric and density measures using NIST-traceable standards and 
suitable methods published by a consensus standards organization (e.g., 
ASTM, ASME, ISO, or others). Recalibrate all flow meters, weigh scales, 
and combinations of volumetric and density measures at the minimum 
frequency specified by the manufacturer.
    (q) All gas chromatographs used to determine the concentration of 
HFC-23 in process streams shall be calibrated at least monthly through 
analysis of certified standards (or of calibration gases prepared from a 
high-concentration certified standard using a gas dilution system that 
meets the requirements specified in Method 205 at 40 CFR part 51, 
appendix M) with known HFC-23 concentrations that are in the same range 
(fractions by mass) as the process samples.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66462, Oct. 28, 2010; 
78 FR 71955, Nov. 29, 2013]



Sec. 98.155  Procedures for estimating missing data.

    (a) A complete record of all measured parameters used in the GHG 
emissions calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable (e.g., if a meter 
malfunctions during unit operation or if a required process sample is 
not taken), a substitute data value for the missing parameter shall be 
used in the calculations, according to the following requirements:
    (1) For each missing value of the HFC-23 or HCFC-22 concentration, 
the substitute data value shall be the arithmetic average of the 
quality-assured values of that parameter immediately preceding and 
immediately following the missing data incident. If, for a particular 
parameter, no quality-assured data are available prior to the missing 
data incident, the substitute data value shall be the first quality-
assured value obtained after the missing data period.
    (2) For each missing value of the product stream mass flow or 
product mass, the substitute value of that parameter shall be a 
secondary product measurement where such a measurement is available. If 
that measurement is taken significantly downstream of the usual mass 
flow or mass measurement (e.g., at the shipping dock rather than near 
the reactor), the measurement shall be multiplied by 1.015 to compensate 
for losses. Where a secondary mass measurement is not available, the 
substitute value of the parameter shall be an estimate based on a 
related parameter. For example, if a flowmeter measuring the mass fed 
into a destruction device is rendered inoperable, then the mass fed into 
the destruction device may be estimated using the production rate and 
the previously observed relationship between the production rate and the 
mass flow rate into the destruction device.



Sec. 98.156  Data reporting requirements.

    (a) In addition to the information required by Sec. 98.3(c), the 
HCFC-22 production facility shall report the following information at 
the facility level:
    (1) Annual mass of HCFC-22 produced in metric tons.
    (2) [Reserved]
    (3) Annual mass of reactants fed into the process in metric tons of 
reactant.
    (4) The mass (in metric tons) of materials other than HCFC-22 and 
HFC-23 (i.e., unreacted reactants, HCl and other by-products) that occur 
in more than trace concentrations and that are permanently removed from 
the process.

[[Page 774]]

    (5) The method for tracking startups, shutdowns, and malfunctions 
and HFC-23 generation/emissions during these events.
    (6) The names and addresses of facilities to which any HFC-23 was 
sent for destruction, and the quantities of HFC-23 (metric tons) sent to 
each.
    (7)-(10) [Reserved]
    (11) Annual mass of HFC-23 emitted in metric tons.
    (12) Annual mass of HFC-23 emitted from equipment leaks in metric 
tons.
    (13) Annual mass of HFC-23 emitted from process vents in metric 
tons.
    (b) In addition to the information required by Sec. 98.3(c), 
facilities that destroy HFC-23 shall report the following for each HFC-
23 destruction process:
    (1)-(2) [Reserved]
    (3) Annual mass of HFC-23 emitted from the destruction device.
    (c) Each HFC-23 destruction facility shall report the concentration 
(mass fraction) of HFC-23 measured at the outlet of the destruction 
device during the facility's annual HFC-23 concentration measurements at 
the outlet of the device. If the concentration of HFC-23 is below the 
detection limit of the measuring device, report the detection limit and 
that the concentration is below the detection limit.
    (d) If the HFC-23 concentration measured pursuant to Sec. 98.154(l) 
is greater than that measured during the performance test that is the 
basis for the destruction efficiency (DE), the facility shall report the 
following:
    (1) [Reserved]
    (2) Concentration (mass fraction) of HFC-23 at the outlet of the 
destruction device.
    (3) Flow rate at the outlet of the destruction device in kg/hr.
    (4) Emission rate (in kg/hr) calculated from paragraphs (d)(2) and 
(d)(3) of this section.
    (5) [Reserved]
    (e) By March 31, 2011 or within 60 days of commencing HFC-23 
destruction, HFC-23 destruction facilities shall submit a one-time 
report including the following information for each destruction process:
    (1) [Reserved]
    (2) The methods used to determine destruction efficiency.
    (3) The methods used to record the mass of HFC-23 destroyed.
    (4) The name of other relevant federal or state regulations that may 
apply to the destruction process.
    (5) If any changes are made that affect HFC-23 destruction 
efficiency or the methods used to record volume destroyed, then these 
changes must be reflected in a revision to this report. The revised 
report must be submitted to EPA within 60 days of the change.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66463, Oct. 28, 2010; 
78 FR 71955, Nov. 29, 2013; 79 FR 63786, Oct. 24, 2014]



Sec. 98.157  Records that must be retained.

    (a) In addition to the data required by Sec. 98.3(g), HCFC-22 
production facilities shall retain the following records:
    (1) The data used to estimate HFC-23 emissions.
    (2) Records documenting the initial and periodic calibration of the 
gas chromatographs, weigh scales, volumetric and density measurements, 
and flowmeters used to measure the quantities reported under this rule, 
including the industry standards or manufacturer directions used for 
calibration pursuant to Sec. 98.154(p) and (q).
    (b) In addition to the data required by Sec. 98.3(g), the HFC-23 
destruction facilities shall retain the following records:
    (1) Records documenting their one-time and annual reports in Sec. 
98.156(b) through (e).
    (2) Records documenting the initial and periodic calibration of the 
gas chromatographs, weigh scales, volumetric and density measurements, 
and flowmeters used to measure the quantities reported under this 
subpart, including the industry standard practice or manufacturer 
directions used for calibration pursuant to Sec. 98.154(p) and (q).
    (c) Verification software records. You must keep a record of the 
file generated by the verification software specified in Sec. 98.5(b) 
for the applicable data specified in paragraphs (c)(1) through (16) of 
this section. Retention of this file satisfies the recordkeeping 
requirement for the data in paragraphs (c)(1) through (16) of this 
section.

[[Page 775]]

    (1) Factor to account for the loss of HCFC-22 upstream of the 
measurement over the period, determined pursuant to Sec. 98.154(e) 
(Equation O-3 of Sec. 98.153).
    (2) Mass of HCFC-22 that is measured coming out of the production 
process over the period. A period can be one year (kg) (Equation O-3).
    (3) Mass of used HCFC-22 that is added to the production process 
upstream of the output measurement over the period. A period can be one 
year (kg) (Equation O-3).
    (4) Mass of HFC-23 generated annually per HCFC-22 production process 
(metric tons) (Equation O-4 of Sec. 98.153).
    (5) Mass of HFC-23 sent off site for sale annually per HCFC-22 
production process (metric tons) (Equation O-4).
    (6) Mass of HFC-23 sent off site for destruction annually per HCFC-
22 production process (metric tons) (Equation O-4).
    (7) Mass of HFC-23 destroyed on site per HCFC-22 production process 
(metric tons) (Equation O-4).
    (8) HFC-23 in storage at end of year per HCFC-22 production process 
(metric tons) (Equation O-4).
    (9) HFC-23 in storage at beginning of year per HCFC-22 production 
process (metric tons) (Equation O-4).
    (10) Mass of HFC-23 fed into each destruction device annually per 
HCFC-22 production process (metric tons) (Equation O-9 of Sec. 98.153 
and the calculation method in either Sec. 98.154(l)(1) or (2)).
    (11) Identify if each destruction efficiency for each HCFC-22 
production process is entered directly, or is calculated using Sec. 
98.154(l)(1), or is calculated using Sec. 98.154(l)(2) (Equation O-9 
and the calculation method in either Sec. 98.154(l)(1) or (2)).
    (12) Destruction efficiency of each destruction device for each 
HCFC-22 production process (decimal fraction) (Equation O-9 and the 
calculation method in either Sec. 98.154(l)(1) or (2)).
    (13) Volumetric flow rate at the inlet of each destruction device 
for each HCFC-22 production process from previous test (kg/hr) (Equation 
O-9 and the calculation method in either Sec. 98.154(l)(1) or (2)).
    (14) Volumetric flow rate at the inlet of destruction device during 
test for each HCFC-22 production process (kg/hr) (Equation O-9 and the 
calculation method in either Sec. 98.154(l)(1) or (2)).
    (15) Concentration of HFC-23 at the inlet of destruction device for 
each HCFC-22 production process from previous test (weight fraction) 
(Equation O-9 and the calculation method in either Sec. 98.154(l)(1) or 
(2)).
    (16) Concentration of HFC-23 at the inlet of destruction device for 
each HCFC-22 production process during test (weight fraction) (Equation 
O-9 and the calculation method in either Sec. 98.154(l)(1) or (2)).

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66463, Oct. 28, 2010; 
79 FR 63786, Oct. 24, 2014]



Sec. 98.158  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.



 Sec. Table O-1 to Subpart O of Part 98--Emission Factors for Equipment 
                                  Leaks

----------------------------------------------------------------------------------------------------------------
                                                                                  Emission factor (kg/hr/source)
                                                                                --------------------------------
                Equipment type                              Service              =10,000    <10,000
                                                                                        ppmv             ppmv
----------------------------------------------------------------------------------------------------------------
Valves.......................................  Gas.............................           0.0782        0.000131
Valves.......................................  Light liquid....................           0.0892        0.000165
Pump seals...................................  Light liquid....................            0.243         0.00187
Compressor seals.............................  Gas.............................            1.608          0.0894
Pressure relief valves.......................  Gas.............................            1.691          0.0447
Connectors...................................  All.............................            0.113       0.0000810
Open-ended lines.............................  All.............................          0.01195         0.00150
----------------------------------------------------------------------------------------------------------------


[[Page 776]]



                      Subpart P_Hydrogen Production



Sec. 98.160  Definition of the source category.

    (a) A hydrogen production source category consists of facilities 
that produce hydrogen gas sold as a product to other entities.
    (b) This source category comprises process units that produce 
hydrogen by reforming, gasification, oxidation, reaction, or other 
transformations of feedstocks.
    (c) This source category includes merchant hydrogen production 
facilities located within another facility if they are not owned by, or 
under the direct control of, the other facility's owner and operator.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66463, Oct. 28, 2010]



Sec. 98.161  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains a hydrogen production process and the facility meets the 
requirements of either Sec. 98.2(a)(1) or (a)(2).



Sec. 98.162  GHGs to report.

    You must report:
    (a) CO2 emissions from each hydrogen production process 
unit.
    (b) [Reserved]
    (c) CO2, CH4, and N2O emissions 
from each stationary combustion unit other than hydrogen production 
process units. You must calculate and report these emissions under 
subpart C of this part (General Stationary Fuel Combustion Sources) by 
following the requirements of subpart C.
    (d) For CO2 collected and transferred off site, you must 
follow the requirements of subpart PP of this part.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66463, Oct. 28, 2010]



Sec. 98.163  Calculating GHG emissions.

    You must calculate and report the annual CO2 emissions 
from each hydrogen production process unit using the procedures 
specified in either paragraph (a) or (b) of this section.
    (a) Continuous Emissions Monitoring Systems (CEMS). Calculate and 
report under this subpart the CO2 emissions by operating and 
maintaining CEMS according to the Tier 4 Calculation Methodology 
specified in Sec. 98.33(a)(4) and all associated requirements for Tier 
4 in subpart C of this part (General Stationary Fuel Combustion 
Sources).
    (b) Fuel and feedstock material balance approach. Calculate and 
report CO2 emissions as the sum of the annual emissions 
associated with each fuel and feedstock used for hydrogen production by 
following paragraphs (b)(1) through (3) of this section. The carbon 
content and molecular weight shall be obtained from the analyses 
conducted in accordance with Sec. 98.164(b)(2), (b)(3), or (b)(4), as 
applicable, or from the missing data procedures in Sec. 98.165. If the 
analyses are performed annually, then the annual value shall be used as 
the monthly average. If the analyses are performed more frequently than 
monthly, use the arithmetic average of values obtained during the month 
as the monthly average.
    (1) Gaseous fuel and feedstock. You must calculate the annual 
CO2 emissions from each gaseous fuel and feedstock according 
to Equation P-1 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.060

Where:

CO2 = Annual CO2 process emissions arising from 
          fuel and feedstock consumption (metric tons/yr).
Fdstkn = Volume or mass of the gaseous fuel or feedstock used 
          in month n (scf (at

[[Page 777]]

          standard conditions of 68  deg.F and atmospheric pressure) or 
          kg of fuel or feedstock).
CCn = Average carbon content of the gaseous fuel or feedstock 
          for month n (kg carbon per kg of fuel or feedstock).
MWn = Average molecular weight of the gaseous fuel or 
          feedstock for month n (kg/kg-mole). If you measure mass, the 
          term ``MWn/MVC'' is replaced with ``1''.
MVC = Molar volume conversion factor (849.5 scf per kg-mole at standard 
          conditions).
k = Months in the year.
44/12 = Ratio of molecular weights, CO2 to carbon. 0.001 = 
          Conversion factor from kg to metric tons.

    (2) Liquid fuel and feedstock. You must calculate the annual 
CO2 emissions from each liquid fuel and feedstock according 
to Equation P-2 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.061

Where:

CO2 = Annual CO2 emissions arising from fuel and 
          feedstock consumption (metric tons/yr).
Fdstkn = Volume or mass of the liquid fuel or feedstock used 
          in month n (gallons or kg of fuel or feedstock).
CCn = Average carbon content of the liquid fuel or feedstock, 
          for month n (kg carbon per gallon or kg of fuel or feedstock).
k = Months in the year.
44/12 = Ratio of molecular weights, CO2 to carbon.
0.001 = Conversion factor from kg to metric tons.

    (3) Solid fuel and feedstock. You must calculate the annual 
CO2 emissions from each solid fuel and feedstock according to 
Equation P-3 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.062

Where:

CO2 = Annual CO2 emissions from fuel and feedstock 
          consumption in metric tons per month (metric tons/yr).
Fdstkn = Mass of solid fuel or feedstock used in month n (kg 
          of fuel or feedstock).
CCn = Average carbon content of the solid fuel or feedstock, 
          for month n (kg carbon per kg of fuel or feedstock).
k = Months in the year.
44/12 = Ratio of molecular weights, CO2 to carbon.
0.001 = Conversion factor from kg to metric tons.

    (c) If GHG emissions from a hydrogen production process unit are 
vented through the same stack as any combustion unit or process 
equipment that reports CO2 emissions using a CEMS that 
complies with the Tier 4 Calculation Methodology in subpart C of this 
part (General Stationary Fuel Combustion Sources), then the calculation 
methodology in paragraph (b) of this section shall not be used to 
calculate process emissions. The owner or operator shall report under 
this subpart the combined stack emissions according to the Tier 4 
Calculation Methodology in Sec. 98.33(a)(4) and all associated 
requirements for Tier 4 in subpart C of this part (General Stationary 
Fuel Combustion Sources).

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66463, Oct. 28, 2010; 
75 FR 79157, Dec. 17, 2010; 78 FR 71955, Nov. 29, 2013]



Sec. 98.164  Monitoring and QA/QC requirements.

    The GHG emissions data for hydrogen production process units must be 
quality-assured as specified in paragraphs (a) or (b) of this section, 
as appropriate for each process unit:
    (a) If a CEMS is used to measure GHG emissions, then the facility 
must

[[Page 778]]

comply with the monitoring and QA/QC procedures specified in Sec. 
98.34(c).
    (b) If a CEMS is not used to measure GHG emissions, then you must:
    (1) Calibrate all oil and gas flow meters that are used to measure 
liquid and gaseous feedstock volumes (except for gas billing meters) 
according to the monitoring and QA/QC requirements for the Tier 3 
methodology in Sec. 98.34(b)(1). Perform oil tank drop measurements (if 
used to quantify liquid fuel or feedstock consumption) according to 
Sec. 98.34(b)(2). Calibrate all solids weighing equipment according to 
the procedures in Sec. 98.3(i).
    (2) Determine the carbon content and the molecular weight annually 
of standard gaseous hydrocarbon fuels and feedstocks having consistent 
composition (e.g., natural gas). For other gaseous fuels and feedstocks 
(e.g., biogas, refinery gas, or process gas), sample and analyze no less 
frequently than weekly to determine the carbon content and molecular 
weight of the fuel and feedstock.
    (3) Determine the carbon content of fuel oil, naphtha, and other 
liquid fuels and feedstocks at least monthly, except annually for 
standard liquid hydrocarbon fuels and feedstocks having consistent 
composition, or upon delivery for liquid fuels and feedstocks delivered 
by bulk transport (e.g., by truck or rail).
    (4) Determine the carbon content of coal, coke, and other solid 
fuels and feedstocks at least monthly, except annually for standard 
solid hydrocarbon fuels and feedstocks having consistent composition, or 
upon delivery for solid fuels and feedstocks delivered by bulk transport 
(e.g., by truck or rail).
    (5) You must use the following applicable methods to determine the 
carbon content for all fuels and feedstocks, and molecular weight of 
gaseous fuels and feedstocks. Alternatively, you may use the results of 
chromatographic analysis of the fuel and feedstock, provided that the 
chromatograph is operated, maintained, and calibrated according to the 
manufacturer's instructions; and the methods used for operation, 
maintenance, and calibration of the chromatograph are documented in the 
written monitoring plan for the unit under Sec. 98.3(g)(5).
    (i) ASTM D1945-03 Standard Test Method for Analysis of Natural Gas 
by Gas Chromatography (incorporated by reference, see Sec. 98.7).
    (ii) ASTM D1946-90 (Reapproved 2006), Standard Practice for Analysis 
of Reformed Gas by Gas Chromatography (incorporated by reference, see 
Sec. 98.7).
    (iii) ASTM D2013-07 Standard Practice of Preparing Coal Samples for 
Analysis (incorporated by reference, see Sec. 98.7).
    (iv) ASTM D2234/D2234M-07 Standard Practice for Collection of a 
Gross Sample of Coal (incorporated by reference, see Sec. 98.7).
    (v) ASTM D2597-94 (Reapproved 2004) Standard Test Method for 
Analysis of Demethanized Hydrocarbon Liquid Mixtures Containing Nitrogen 
and Carbon Dioxide by Gas Chromatography (incorporated by reference, see 
Sec. 98.7).
    (vi) ASTM D3176-89 (Reapproved 2002), Standard Practice for Ultimate 
Analysis of Coal and Coke (incorporated by reference, see Sec. 98.7).
    (vii) ASTM D3238-95 (Reapproved 2005), Standard Test Method for 
Calculation of Carbon Distribution and Structural Group Analysis of 
Petroleum Oils by the n-d-M Method (incorporated by reference, see Sec. 
98.7).
    (viii) ASTM D4057-06 Standard Practice for Manual Sampling of 
Petroleum and Petroleum Products (incorporated by reference, see Sec. 
98.7).
    (ix) ASTM D4177-95 (Reapproved 2005) Standard Practice for Automatic 
Sampling of Petroleum and Petroleum Products (incorporated by reference, 
see Sec. 98.7).
    (x) ASTM D5291-02 (Reapproved 2007), Standard Test Methods for 
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in 
Petroleum Products and Lubricants (incorporated by reference, see Sec. 
98.7).
    (xi) ASTM D5373-08 Standard Test Methods for Instrumental 
Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of 
Coal (incorporated by reference, see Sec. 98.7).
    (xii) ASTM D6609-08 Standard Guide for Part-Stream Sampling of Coal 
(incorporated by reference, see Sec. 98.7).
    (xiii) ASTM D6883-04 Standard Practice for Manual Sampling of 
Stationary Coal from Railroad Cars,

[[Page 779]]

Barges, Trucks, or Stockpiles (incorporated by reference, see Sec. 
98.7).
    (xiv) ASTM D7430-08ae1 Standard Practice for Mechanical Sampling of 
Coal (incorporated by reference, see Sec. 98.7).
    (xv) ASTM UOP539-97 Refinery Gas Analysis by Gas Chromatography 
(incorporated by reference, see Sec. 98.7).
    (xvi) GPA 2261-00 Analysis for Natural Gas and Similar Gaseous 
Mixtures by Gas Chromatography (incorporated by reference, see Sec. 
98.7).
    (xvii) ISO 3170: Petroleum Liquids--Manual sampling--Third Edition 
(incorporated by reference, see Sec. 98.7).
    (xviii) ISO 3171: Petroleum Liquids--Automatic pipeline sampling--
Second Edition (incorporated by reference, see Sec. 98.7).

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79157, Dec. 17, 2010; 
78 FR 71955, Nov. 29, 2013]



Sec. 98.165  Procedures for estimating missing data.

    A complete record of all measured parameters used in the GHG 
emissions calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable (e.g., if a meter 
malfunctions during unit operation), a substitute data value for the 
missing parameter must be used in the calculations as specified in 
paragraphs (a), (b), and (c) of this section:
    (a) For each missing value of the monthly fuel and feedstock 
consumption, the substitute data value must be the best available 
estimate of the fuel and feedstock consumption, based on all available 
process data (e.g., hydrogen production, electrical load, and operating 
hours). You must document and keep records of the procedures used for 
all such estimates.
    (b) For each missing value of the carbon content or molecular weight 
of the fuel and feedstock, the substitute data value must be the 
arithmetic average of the quality-assured values of carbon contents or 
molecular weight of the fuel and feedstock immediately preceding and 
immediately following the missing data incident. If no quality-assured 
data on carbon contents or molecular weight of the fuel and feedstock 
are available prior to the missing data incident, the substitute data 
value must be the first quality-assured value for carbon contents or 
molecular weight of the fuel and feedstock obtained after the missing 
data period. You must document and keep records of the procedures used 
for all such estimates.
    (c) For missing CEMS data, you must use the missing data procedures 
in Sec. 98.35.



Sec. 98.166  Data reporting requirements.

    In addition to the information required by Sec. 98.3(c), each 
annual report must contain the information specified in paragraphs (a) 
or (b) of this section, as appropriate, and paragraphs (c) through (e) 
of this section:
    (a) If a CEMS is used to measure CO2 emissions, then you 
must report the relevant information required under Sec. 98.36 for the 
Tier 4 Calculation Methodology and the following information in this 
paragraph (a):
    (1) Unit identification number and annual CO2 emissions.
    (2) Annual quantity of hydrogen produced (metric tons) for each 
process unit.
    (3) Annual quantity of ammonia produced (metric tons), if 
applicable, for each process unit.
    (b) If a CEMS is not used to measure CO2 emissions, then 
you must report the following information for each hydrogen production 
process unit:
    (1) Unit identification number and annual CO2 emissions.
    (2) [Reserved]
    (3) Annual quantity of hydrogen produced (metric tons).
    (4) Annual quantity of ammonia produced, if applicable (metric 
tons).
    (5)-(6) [Reserved]
    (7) Name and annual quantity (metric tons) of each carbon-containing 
fuel and feedstock.
    (c) Quantity of CO2 collected and transferred off site in 
either gas, liquid, or solid forms, following the requirements of 
subpart PP of this part.
    (d) Annual quantity of carbon other than CO2 collected 
and transferred off site in either gas, liquid, or solid forms (kg 
carbon).

[[Page 780]]

    (e) Annual methanol production (metric tons) for each process unit.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66463, Oct. 28, 2010; 
78 FR 71955, Nov. 29, 2013; 79 FR 63787, Oct. 24, 2014]



Sec. 98.167  Records that must be retained.

    In addition to the information required by Sec. 98.3(g), you must 
retain the records specified in paragraphs (a) through (e) of this 
section for each hydrogen production facility.
    (a) If a CEMS is used to measure CO2 emissions, then you 
must retain under this subpart the records required for the Tier 4 
Calculation Methodology in Sec. 98.37.
    (b) If a CEMS is not used to measure CO2 emissions, then 
you must retain records of all analyses and calculations conducted as 
listed in Sec. Sec. 98.166(b), (c), and (d).
    (c) For units using the calculation methodologies described in Sec. 
98.163(b), the records required under Sec. 98.3(g) must include both 
the company records and a detailed explanation of how company records 
are used to estimate the following:
    (1) Fuel and feedstock consumption, when solid fuel and feedstock is 
combusted and a CEMS is not used to measure GHG emissions.
    (2) Fossil fuel consumption, when, pursuant to Sec. 98.33(e), the 
owner or operator of a unit that uses CEMS to quantify CO2 
emissions and that combusts both fossil and biogenic fuels separately 
reports the biogenic portion of the total annual CO2 
emissions.
    (3) Sorbent usage, if the methodology in Sec. 98.33(d) is used to 
calculate CO2 emissions from sorbent.
    (d) The owner or operator must document the procedures used to 
ensure the accuracy of the estimates of fuel and feedstock usage and 
sorbent usage (as applicable) in Sec. 98.163(b), including, but not 
limited to, calibration of weighing equipment, fuel and feedstock flow 
meters, and other measurement devices. The estimated accuracy of 
measurements made with these devices must also be recorded, and the 
technical basis for these estimates must be provided.
    (e) Verification software records. You must keep a record of the 
file generated by the verification software specified in Sec. 98.5(b) 
for the applicable data specified in paragraphs (e)(1) through (12) of 
this section. Retention of this file satisfies the recordkeeping 
requirement for the data in paragraphs (e)(1) through (12) of this 
section.
    (1) Indicate whether the monthly consumption of each gaseous fuel or 
feedstock is measured as mass or volume (Equation P-1 of Sec. 98.163).
    (2) Monthly volume of the gaseous fuel or feedstock (scf at standard 
conditions of 68  deg.F and atmospheric pressure) (Equation P-1).
    (3) Monthly mass of the gaseous fuel or feedstock (kg of fuel or 
feedstock) (Equation P-1).
    (4) Average monthly carbon content of the gaseous fuel or feedstock 
(kg C per kg of fuel or feedstock) (Equation P-1).
    (5) Average monthly molecular weight of the gaseous fuel or 
feedstock (kg/kg-mole) (Equation P-1).
    (6) Indicate whether the monthly consumption of each liquid fuel or 
feedstock is measured as mass or volume (Equation P-2 of Sec. 98.163).
    (7) Monthly volume of the liquid fuel or feedstock (gallons of fuel 
or feedstock) (Equation P-2).
    (8) Monthly mass of the liquid fuel or feedstock (kg of fuel or 
feedstock) (Equation P-2).
    (9) Average monthly carbon content of the liquid fuel or feedstock 
(kg C per gallon of fuel or feedstock) (Equation P-2).
    (10) Average monthly carbon content of the liquid fuel or feedstock 
(kg C per kg of fuel or feedstock) (Equation P-2).
    (11) Monthly mass of solid fuel or feedstock (kg of fuel and 
feedstock) (Equation P-3 of Sec. 98.163).
    (12) Average monthly carbon content of the solid fuel or feedstock 
(kg C per kg of fuel and feedstock) (Equation P-3).

[74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71956, Nov. 29, 2013; 
79 FR 63787, Oct. 24, 2014]



Sec. 98.168  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.

[[Page 781]]



                   Subpart Q_Iron and Steel Production



Sec. 98.170  Definition of the source category.

    The iron and steel production source category includes facilities 
with any of the following processes: taconite iron ore processing, 
integrated iron and steel manufacturing, cokemaking not collocated with 
an integrated iron and steel manufacturing process, direct reduction 
furnaces not collocated with an integrated iron and steel manufacturing 
process, and electric arc furnace (EAF) steelmaking not collocated with 
an integrated iron and steel manufacturing process. Integrated iron and 
steel manufacturing means the production of steel from iron ore or iron 
ore pellets. At a minimum, an integrated iron and steel manufacturing 
process has a basic oxygen furnace for refining molten iron into steel. 
Each cokemaking process and EAF process located at a facility with an 
integrated iron and steel manufacturing process is part of the 
integrated iron and steel manufacturing facility.

[74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71955, Nov. 29, 2013]



Sec. 98.171  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains an iron and steel production process and the facility meets the 
requirements of either Sec. 98.2(a)(1) or (2).



Sec. 98.172  GHGs to report.

    (a) You must report under subpart C of this part (General Stationary 
Fuel Combustion Sources) the emissions of CO2, 
CH4, and N2O from each stationary combustion unit 
following the requirements of subpart C except for flares. Stationary 
combustion units include, but are not limited to, by-product recovery 
coke oven battery combustion stacks, blast furnace stoves, boilers, 
process heaters, reheat furnaces, annealing furnaces, flame suppression, 
ladle reheaters, and other miscellaneous combustion sources.
    (b) You must report CO2 emissions from flares that burn 
blast furnace gas or coke oven gas according to the procedures in Sec. 
98.253(b)(1) of subpart Y (Petroleum Refineries) of this part. When 
using the alternatives set forth in Sec. 98.253(b)(1)(ii)(B) and Sec. 
98.253(b)(1)(iii)(C), you must use the default CO2 emission 
factors for coke oven gas and blast furnace gas from Table C-1 to 
subpart C in Equations Y-2 and Y-3 of subpart Y. You must report 
CH4 and N2O emissions from flares according to the 
requirements in Sec. 98.33(c)(2) using the emission factors for coke 
oven gas and blast furnace gas in Table C-2 to subpart C of this part.
    (c) You must report process CO2 emissions from each 
taconite indurating furnace; basic oxygen furnace; non-recovery coke 
oven battery combustion stack; coke pushing process; sinter process; 
EAF; decarburization vessel; and direct reduction furnace by following 
the procedures in this subpart.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66463, Oct. 28, 2010]



Sec. 98.173  Calculating GHG emissions.

    You must calculate and report the annual process CO2 
emissions from each taconite indurating furnace, basic oxygen furnace, 
non-recovery coke oven battery, sinter process, EAF, decarburization 
vessel, and direct reduction furnace using the procedures in either 
paragraph (a) or (b) of this section. Calculate and report the annual 
process CO2 emissions from the coke pushing process according 
to paragraph (c) of this section.
    (a) Calculate and report under this subpart the process 
CO2 emissions by operating and maintaining CEMS according to 
the Tier 4 Calculation Methodology in Sec. 98.33(a)(4) and all 
associated requirements for Tier 4 in subpart C of this part (General 
Stationary Fuel Combustion Sources).
    (b) Calculate and report under this subpart the process 
CO2 emissions using the procedure in paragraph (b)(1) or 
(b)(2) of this section.
    (1) Carbon mass balance method. Calculate the annual mass emissions 
of CO2 for the process as specified in paragraphs (b)(1)(i) 
through (b)(1)(vii) of this section. The calculations are based on the 
annual mass of inputs and outputs to the process and an annual analysis 
of the respective weight fraction of carbon as determined according to 
the

[[Page 782]]

procedures in Sec. 98.174(b). If you have a process input or output 
other than CO2 in the exhaust gas that contains carbon that 
is not included in Equations Q-1 through Q-7 of this section, you must 
account for the carbon and mass rate of that process input or output in 
your calculations according to the procedures in Sec. 98.174(b)(5).
    (i) For taconite indurating furnaces, estimate CO2 
emissions using Equation Q-1 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.063

Where:

CO2 = Annual CO2 mass emissions from the taconite 
          indurating furnace (metric tons).
44/12 = Ratio of molecular weights, CO2 to carbon.
(Fs) = Annual mass of the solid fuel used (metric tons).
(Csf) = Carbon content of the solid fuel, from the fuel 
          analysis (expressed as a decimal fraction).
(Fg) = Annual volume of the gaseous fuel used (scf).
(Cgf) = Average carbon content of the gaseous fuel, from the 
          fuel analysis results (kg C per kg of fuel).
MW = Molecular weight of the gaseous fuel (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf per kg-mole at standard 
          conditions).
0.001 = Conversion factor from kg to metric tons.
(Fl) = Annual volume of the liquid fuel used (gallons).
(Clf) = Carbon content of the liquid fuel, from the fuel 
          analysis results (kg C per gallon of fuel).
(O) = Annual mass of greenball (taconite) pellets fed to the furnace 
          (metric tons).
(C0) = Carbon content of the greenball (taconite) pellets, 
          from the carbon analysis results (expressed as a decimal 
          fraction).
(P) = Annual mass of fired pellets produced by the furnace (metric 
          tons).
(Cp) = Carbon content of the fired pellets, from the carbon 
          analysis results (expressed as a decimal fraction).
(R) = Annual mass of air pollution control residue collected (metric 
          tons).
(CR) = Carbon content of the air pollution control residue, 
          from the carbon analysis results (expressed as a decimal 
          fraction).

    (ii) For basic oxygen process furnaces, estimate CO2 
emissions using Equation Q-2 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.064

Where:

CO2 = Annual CO2 mass emissions from the basic 
          oxygen furnace (metric tons).
44/12 = Ratio of molecular weights, CO2 to carbon.
(Iron) = Annual mass of molten iron charged to the furnace (metric 
          tons).
(CIron) = Carbon content of the molten iron, from the carbon 
          analysis results (expressed as a decimal fraction).
(Scrap) = Annual mass of ferrous scrap charged to the furnace (metric 
          tons).
(CScrap) = Carbon content of the ferrous scrap, from the 
          carbon analysis results (expressed as a decimal fraction).
(Flux) = Annual mass of flux materials (e.g., limestone, dolomite) 
          charged to the furnace (metric tons).
(CFlux) = Carbon content of the flux materials, from the 
          carbon analysis results (expressed as a decimal fraction).
(Carbon) = Annual mass of carbonaceous materials (e.g., coal, coke) 
          charged to the furnace (metric tons).
(CCarbon) = Carbon content of the carbonaceous materials, 
          from the carbon analysis results (expressed as a decimal 
          fraction).
(Steel) = Annual mass of molten raw steel produced by the furnace 
          (metric tons).
(CSteel) = Carbon content of the steel, from the carbon 
          analysis results (expressed as a decimal fraction).
(Slag) = Annual mass of slag produced by the furnace (metric tons).

[[Page 783]]

(CSlag) = Carbon content of the slag, from the carbon 
          analysis (expressed as a decimal fraction).
(R) = Annual mass of air pollution control residue collected (metric 
          tons).
(CR) = Carbon content of the air pollution control residue, 
          from the carbon analysis results (expressed as a decimal 
          fraction).

    (iii) For non-recovery coke oven batteries, estimate CO2 
emissions using Equation Q-3 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.065

Where:

CO2 = Annual CO2 mass emissions from the non-
          recovery coke oven battery (metric tons).
44/12 = Ratio of molecular weights, CO2 to carbon.
(Coal) = Annual mass of coal charged to the battery (metric tons).
(CCoal) = Carbon content of the coal, from the carbon 
          analysis results (expressed as a decimal fraction).
(Coke) = Annual mass of coke produced by the battery (metric tons).
(CCoke) = Carbon content of the coke, from the carbon 
          analysis results (expressed as a decimal fraction).
(R) = Annual mass of air pollution control residue collected (metric 
          tons).
(CR) = Carbon content of the air pollution control residue, 
          from the carbon analysis results (expressed as a decimal 
          fraction).

    (iv) For sinter processes, estimate CO2 emissions using 
Equation Q-4 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.066

Where:

CO2 = Annual CO2 mass emissions from the sinter 
          process (metric tons).
44/12 = Ratio of molecular weights, CO2 to carbon.
(Fg) = Annual volume of the gaseous fuel used (scf).
(Cgf) = Carbon content of the gaseous fuel, from the fuel 
          analysis results (kg C per kg of fuel).
MW = Molecular weight of the gaseous fuel (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf per kg-mole at standard 
          conditions).
0.001 = Conversion factor from kg to metric tons.
(Feed) = Annual mass of sinter feed material (metric tons).
(CFeed) = Carbon content of the mixed sinter feed materials 
          that form the bed entering the sintering machine, from the 
          carbon analysis results (expressed as a decimal fraction).
(Sinter) = Annual mass of sinter produced (metric tons).
(CSinter) = Carbon content of the sinter pellets, from the 
          carbon analysis results (expressed as a decimal fraction).
(R) = Annual mass of air pollution control residue collected (metric 
          tons).
(CR) = Carbon content of the air pollution control residue, 
          from the carbon analysis results (expressed as a decimal 
          fraction).

    (v) For EAFs, estimate CO2 emissions using Equation Q-5 
of this section.
[GRAPHIC] [TIFF OMITTED] TR29NO13.015


[[Page 784]]


Where:

CO2 = Annual CO2 mass emissions from the EAF 
          (metric tons).
44/12 = Ratio of molecular weights, CO2 to carbon.
(Iron) = Annual mass of direct reduced iron (if any) charged to the 
          furnace (metric tons).
(CIron) = Carbon content of the direct reduced iron, from the 
          carbon analysis results (expressed as a decimal fraction).
(Scrap) = Annual mass of ferrous scrap charged to the furnace (metric 
          tons).
(CScrap) = Carbon content of the ferrous scrap, from the 
          carbon analysis results (expressed as a decimal fraction).
(Flux) = Annual mass of flux materials (e.g., limestone, dolomite) 
          charged to the furnace (metric tons).
(CFlux) = Carbon content of the flux materials, from the 
          carbon analysis results (expressed as a decimal fraction).
(Electrode) = Annual mass of carbon electrode consumed (metric tons).
(CElectrode) = Carbon content of the carbon electrode, from 
          the carbon analysis results (expressed as a decimal fraction).
(Carbon) = Annual mass of carbonaceous materials (e.g., coal, coke) 
          charged to the furnace (metric tons).
(CCarbon) = Carbon content of the carbonaceous materials, 
          from the carbon analysis results (expressed as a decimal 
          fraction).
(Steel) = Annual mass of molten raw steel produced by the furnace 
          (metric tons).
(CSteel) = Carbon content of the steel, from the carbon 
          analysis results (expressed as a decimal fraction).
(Fg) = Annual volume of the gaseous fuel used (scf at 60 
          degrees F and one atmosphere).
(Cgf) = Average carbon content of the gaseous fuel, from the 
          fuel analysis results (kg C per kg of fuel).
(MW) = Molecular weight of the gaseous fuel (kg/kg-mole).
(MVC) = Molar volume conversion factor (836.6 scf per kg-mole at 
          standard conditions of 60 degrees F and one atmosphere).
(0.001) = Conversion factor from kg to metric tons.
(Slag) = Annual mass of slag produced by the furnace (metric tons).
(CSlag) = Carbon content of the slag, from the carbon 
          analysis results (expressed as a decimal fraction).
(R) = Annual mass of air pollution control residue collected (metric 
          tons).
(CR) = Carbon content of the air pollution control residue, 
          from the carbon analysis results (expressed as a decimal 
          fraction).

    (vi) For decarburization vessels, estimate CO2 emissions 
using Equation Q-6 of this section.
[GRAPHIC] [TIFF OMITTED] TR29NO13.016

Where:

CO2 = Annual CO2 mass emissions from the 
          decarburization vessel (metric tons).
44/12 = Ratio of molecular weights, CO2 to carbon.
(Steel) = Annual mass of molten steel charged to the vessel (metric 
          tons).
(CSteelin) = Carbon content of the molten steel before 
          decarburization, from the carbon analysis results (expressed 
          as a decimal fraction).
(CSteelout) = Carbon content of the molten steel after 
          decarburization, from the carbon analysis results (expressed 
          as a decimal fraction).
(R) = Annual mass of air pollution control residue collected (metric 
          tons).
(CR) = Carbon content of the air pollution control residue, 
          from the carbon analysis results (expressed as a decimal 
          fraction).

    (vii) For direct reduction furnaces, estimate CO2 
emissions using Equation Q-7 of this section.

[[Page 785]]

[GRAPHIC] [TIFF OMITTED] TR30OC09.069

Where:

CO2 = Annual CO2 mass emissions from the direct 
          reduction furnace (metric tons).
44/12 = Ratio of molecular weights, CO2 to carbon.
(Fg) = Annual volume of the gaseous fuel used (scf).
(Cgf) = Carbon content of the gaseous fuel, from the fuel 
          analysis results (kg C per kg of fuel).
MW = Molecular weight of the gaseous fuel (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf per kg-mole at standard 
          conditions).
0.001 = Conversion factor from kg to metric tons.
(Ore) = Annual mass of iron ore or iron ore pellets fed to the furnace 
          (metric tons).
(COre) = Carbon content of the iron ore or iron ore pellets, 
          from the carbon analysis results (expressed as a decimal 
          fraction).
(Carbon) = Annual mass of carbonaceous materials (e.g., coal, coke) 
          charged to the furnace (metric tons).
(CCarbon) = Carbon content of the carbonaceous materials, 
          from the carbon analysis results (expressed as a decimal 
          fraction).
(Other) = Annual mass of other materials charged to the furnace (metric 
          tons).
(COther) = Average carbon content of the other materials 
          charged to the furnace, from the carbon analysis results 
          (expressed as a decimal fraction).
(Iron) = Annual mass of iron produced (metric tons).
(CIron) = Carbon content of the iron, from the carbon 
          analysis results (expressed as a decimal fraction).
(NM) = Annual mass of non-metallic materials produced by the furnace 
          (metric tons).
(CNM) = Carbon content of the non-metallic materials, from 
          the carbon analysis results (expressed as a decimal fraction).
(R) = Annual mass of air pollution control residue collected (metric 
          tons).
(CR) = Carbon content of the air pollution control residue, 
          from the carbon analysis results (expressed as a decimal 
          fraction).

    (2) Site-specific emission factor method. Conduct a performance test 
and measure CO2 emissions from all exhaust stacks for the 
process and measure either the feed rate of materials into the process 
or the production rate during the test as described in paragraphs 
(b)(2)(i) through (b)(2)(iv) of this section.
    (i) You must measure the process production rate or process feed 
rate, as applicable, during the performance test according to the 
procedures in Sec. 98.174(c)(5) and calculate the average rate for the 
test period in metric tons per hour.
    (ii) You must calculate the hourly CO2 emission rate 
using Equation Q-8 of this section and determine the average hourly 
CO2 emission rate for the test.
[GRAPHIC] [TIFF OMITTED] TR30OC09.070

Where:

CO2 = CO2 mass emission rate, corrected for 
          moisture (metric tons/hr).
5.18 x 10-7 = Conversion factor (metric tons/scf-% 
          CO2).
CCO2 = Hourly CO2 concentration, dry basis (% 
          CO2).
Q = Hourly stack gas volumetric flow rate (scfh).
%H2O = Hourly moisture percentage in the stack gas.


[[Page 786]]


    (iii) You must calculate a site-specific emission factor for the 
process in metric tons of CO2 per metric ton of feed or 
production, as applicable, by dividing the average hourly CO2 
emission rate during the test by the average hourly feed or production 
rate during the test.
    (iv) You must calculate CO2 emissions for the process by 
multiplying the emission factor by the total amount of feed or 
production, as applicable, for the reporting period.
    (c) You must determine emissions of CO2 from the coke 
pushing process in mtCO2e by multiplying the metric tons of 
coal charged to the by-product recovery and non-recovery coke ovens 
during the reporting period by 0.008.
    (d) If GHG emissions from a taconite indurating furnace, basic 
oxygen furnace, non-recovery coke oven battery, sinter process, EAF, 
decarburization vessel, or direct reduction furnace are vented through a 
stack equipped with a CEMS that complies with the Tier 4 methodology in 
subpart C of this part, or through the same stack as any combustion unit 
or process equipment that reports CO2 emissions using a CEMS 
that complies with the Tier 4 Calculation Methodology in subpart C of 
this part (General Stationary Fuel Combustion Sources), then the 
calculation methodology in paragraph (b) of this section shall not be 
used to calculate process emissions. The owner or operator shall report 
under this subpart the combined stack emissions according to the Tier 4 
Calculation Methodology in Sec. 98.33(a)(4) and comply with all 
associated requirements for Tier 4 in subpart C of this part (General 
Stationary Fuel Combustion Sources).

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66464, Oct. 28, 2010; 
78 FR 71956, Nov. 29, 2013]



Sec. 98.174  Monitoring and QA/QC requirements.

    (a) If you operate and maintain a CEMS that measures CO2 
emissions consistent with subpart C of this part, you must meet the 
monitoring and QA/QC requirements of Sec. 98.34(c).
    (b) If you determine CO2 emissions using the carbon mass 
balance procedure in Sec. 98.173(b)(1), you must:
    (1) Except as provided in paragraph (b)(4) of this section, 
determine the mass of each process input and output other than fuels 
using the same plant instruments or procedures that are used for 
accounting purposes (such as weigh hoppers, belt weigh feeders, weighed 
purchased quantities in shipments or containers, combination of bulk 
density and volume measurements, etc.), record the totals for each 
process input and output for each calendar month, and sum the monthly 
mass to determine the annual mass for each process input and output. 
Determine the mass rate of fuels using the procedures for combustion 
units in Sec. 98.34. No determination of the mass of steel output from 
decarburization vessels is required.
    (2) Except as provided in paragraph (b)(4) of this section, 
determine the carbon content of each process input and output annually 
for use in the applicable equations in Sec. 98.173(b)(1) based on 
analyses provided by the supplier or by the average carbon content 
determined by collecting and analyzing at least three samples each year 
using the standard methods specified in paragraphs (b)(2)(i) through 
(b)(2)(vi) of this section as applicable.
    (i) ASTM C25-06, Standard Test Methods for Chemical Analysis of 
Limestone, Quicklime, and Hydrated Lime (incorporated by reference, see 
Sec. 98.7) for limestone, dolomite, and slag.
    (ii) ASTM D5373-08 Standard Test Methods for Instrumental 
Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of 
Coal (incorporated by reference, see Sec. 98.7) for coal, coke, and 
other carbonaceous materials.
    (iii) ASTM E1915-07a, Standard Test Methods for Analysis of Metal 
Bearing Ores and Related Materials by Combustion Infrared-Absorption 
Spectrometry (incorporated by reference, see Sec. 98.7) for iron ore, 
taconite pellets, and other iron-bearing materials.
    (iv) ASTM E1019-08, Standard Test Methods for Determination of 
Carbon, Sulfur, Nitrogen, and Oxygen in Steel, Iron, Nickel, and Cobalt 
Alloys by Various Combustion and Fusion Techniques (incorporated by 
reference, see Sec. 98.7) for iron and ferrous scrap.

[[Page 787]]

    (v) ASM CS-104 UNS No. G10460--Alloy Digest April 1985 (Carbon Steel 
of Medium Carbon Content) (incorporated by reference, see Sec. 98.7); 
ISO/TR 15349-1:1998, Unalloyed steel--Determination of low carbon 
content, Part 1: Infrared absorption method after combustion in an 
electric resistance furnace (by peak separation) (1998-10-15) First 
Edition (incorporated by reference, see Sec. 98.7); or ISO/TR 15349-
3:1998, Unalloyed steel-Determination of low carbon content Part 3: 
Infrared absorption method after combustion in an electric resistance 
furnace (with preheating) (1998-10-15) First Edition (incorporated by 
reference, see Sec. 98.7) as applicable for steel.
    (vi) For each process input that is a fuel, determine the carbon 
content and molecular weight (if applicable) using the applicable 
methods listed in Sec. 98.34.
    (3) For solid ferrous materials charged to basic oxygen process 
furnaces or EAFs that differ in carbon content, you may determine a 
weighted average carbon content based on the carbon content of each type 
of ferrous material and the average weight percent of each type that is 
used. Examples of these different ferrous materials include carbon 
steel, low carbon steel, stainless steel, high alloy steel, pig iron, 
iron scrap, and direct reduced iron.
    (4) If you document that a specific process input or output 
contributes less than one percent of the total mass of carbon into or 
out of the process, you do not have to determine the monthly mass or 
annual carbon content of that input or output.
    (5) Except as provided in paragraph (b)(4) of this section, you must 
determine the annual carbon content and monthly mass rate of any input 
or output that contains carbon that is not listed in the equations in 
Sec. 98.173(b)(1) using the procedures in paragraphs (b)(1) and (b)(2) 
of this section.
    (c) If you determine CO2 emissions using the site-
specific emission factor procedure in Sec. 98.173(b)(2), you must:
    (1) Conduct an annual performance test that is based on 
representative performance (i.e., performance based on normal operating 
conditions) of the affected process.
    (2)(i) For the exhaust from basic oxygen furnaces, EAFs, 
decarburization vessels, and direct reduction furnaces, sample the 
furnace exhaust for at least three complete production cycles that start 
when the furnace is being charged and end after steel or iron and slag 
have been tapped. For EAFs that produce both carbon steel and stainless 
or specialty (low carbon) steel, develop an emission factor for the 
production of both types of steel.
    (ii) For the exhaust from continuously charged EAFs, sample the 
exhaust for a period spanning at least three hours. For EAFs that 
produce both carbon steel and stainless or specialty (low carbon) steel, 
develop an emission factor for the production of both types of steel.
    (3) For taconite indurating furnaces, non-recovery coke batteries, 
and sinter processes, sample for at least 3 hours.
    (4) Conduct the stack test using EPA Method 3A at 40 CFR part 60, 
appendix A-2 to measure the CO2 concentration, Method 2, 2A, 
2C, 2D, or 2F at 40 CFR part 60, appendix A-1 or Method 26 at 40 CFR 
part 60, appendix A-2 to determine the stack gas volumetric flow rate, 
and Method 4 at 40 CFR part 60, at appendix A-3 to determine the 
moisture content of the stack gas.
    (5) Determine the mass rate of process feed or process production 
(as applicable) during the test using the same plant instruments or 
procedures that are used for accounting purposes (such as weigh hoppers, 
belt weigh feeders, combination of bulk density and volume measurements, 
etc.)
    (6) If your process operates under different conditions as part of 
normal operations in such a manner that CO2 emissions change 
by more than 20 percent (e.g., routine changes in the carbon content of 
the sinter feed or change in grade of product), you must perform 
emission testing and develop separate emission factors for these 
different operating conditions and determine emissions based on the 
number of hours the process operates and the production or feed rate (as 
applicable) at each specific different condition.
    (7) If your EAF and decarburization vessel exhaust to a common 
emission control device and stack, you must sample each process in the 
ducts before the emissions are combined, sample each process when only 
one process is

[[Page 788]]

operating, or sample the combined emissions when both processes are 
operating and base the site-specific emission factor on the steel 
production rate of the EAF.
    (8) The results of a performance test must include the analysis of 
samples, determination of emissions, and raw data. The performance test 
report must contain all information and data used to derive the emission 
factor.
    (d) For a coke pushing process, determine the metric tons of coal 
charged to the coke ovens and record the totals for each pushing process 
for each calendar month. Coal charged to coke ovens can be measured 
using weigh belts or a combination of measuring volume and bulk density.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66464, Oct. 28, 2010; 
78 FR 71957, Nov. 29, 2013]



Sec. 98.175  Procedures for estimating missing data.

    A complete record of all measured parameters used in the GHG 
emissions calculations in Sec. 98.173 is required. Therefore, whenever 
a quality-assured value of a required parameter is unavailable, a 
substitute data value for the missing parameter shall be used in the 
calculations as specified in the paragraphs (a) and (b) of this section. 
You must follow the missing data procedures in Sec. 98.255(b) of 
subpart Y (Petroleum Refineries) of this part for flares burning coke 
oven gas or blast furnace gas. You must document and keep records of the 
procedures used for all such estimates.
    (a) Except as provided in Sec. 98.174(b)(4), 100 percent data 
availability is required for the carbon content of inputs and outputs 
for facilities that estimate emissions using the carbon mass balance 
procedure in Sec. 98.173(b)(1) or facilities that estimate emissions 
using the site-specific emission factor procedure in Sec. 98.173(b)(2).
    (b) For missing records of the monthly mass or volume of carbon-
containing inputs and outputs using the carbon mass balance procedure in 
Sec. 98.173(b)(1), the substitute data value must be based on the best 
available estimate of the mass of the input or output material from all 
available process data or data used for accounting purposes.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66464, Oct. 28, 2010; 
78 FR 71958, Nov. 29, 2013]



Sec. 98.176  Data reporting requirements.

    In addition to the information required by Sec. 98.3(c), each 
annual report must contain the information required in paragraphs (a) 
through (h) of this section for each coke pushing operation; taconite 
indurating furnace; basic oxygen furnace; non-recovery coke oven 
battery; sinter process; EAF; decarburization vessel; direct reduction 
furnace; and flare burning coke oven gas or blast furnace gas. For 
reporting year 2010, the information required in paragraphs (a) through 
(h) of this section is not required for decarburization vessels that are 
not argon-oxygen decarburization vessels. For reporting year 2011 and 
each subsequent reporting year, the information in paragraphs (a) 
through (h) of this section must be reported for all decarburization 
vessels.
    (a) Unit identification number and annual CO2 emissions 
(in metric tons).
    (b) If a CEMS is used to measure CO2 emissions, then you 
must report the annual production quantity for the production unit (in 
metric tons) for taconite pellets, coke, sinter, iron, and raw steel.
    (c) If a CEMS is used to measure CO2 emissions, then you 
must report the relevant information required under Sec. 98.36 for the 
Tier 4 Calculation Methodology.
    (d) If a CEMS is not used to measure CO2 emissions, then 
you must report for each process whether the emissions were determined 
using the carbon mass balance method in Sec. 98.173(b)(1) or the site-
specific emission factor method in Sec. 98.173(b)(2).
    (e) If you use the carbon mass balance method in Sec. 98.173(b)(1) 
to determine CO2 emissions, you must, except as provided in 
Sec. 98.174(b)(4), report the following information for each process:
    (1) [Reserved]
    (2) Whether the carbon content was determined from information from 
the supplier or by laboratory analysis, and if by laboratory analysis, 
the method used.

[[Page 789]]

    (3)-(4) [Reserved]
    (5) If you used the missing data procedures in Sec. 98.175(b), you 
must report how the monthly mass for each process input or output with 
missing data was determined and the number of months the missing data 
procedures were used.
    (6) The information specified in paragraphs (e)(6)(i) through (vi) 
of this section aggregated for all process units for which 
CO2 emissions were determined using the mass balance method 
in Sec. 98.173(b)(1), except as provided in Sec. 98.174(b)(4).
    (i) The annual mass (metric tons) of all gaseous, liquid, and solid 
fuels (combined) used in process units for which CO2 
emissions were determined using Equations Q-1 through Q-7 of Sec. 
98.173, calculated as specified in Equation Q-9 of this section.
[GRAPHIC] [TIFF OMITTED] TR24OC14.011


Where:

Fuel = Annual mass of all gaseous, liquid, and solid fuels used in 
          process units (metric tons).
n = Number of process units where fuel is used.
Fg,i = Annual volume of gaseous fuel combusted 
          (``(Fg)'' in Equations Q-1, Q-4 and Q-7 of Sec. 
          98.173) for each process (scf).
MWi = Molecular weight of gaseous fuel used in each process 
          (kg/kg-mole).
MVC = Molar volume conversion factor at standard conditions, as defined 
          in Sec. 98.6. Use 849.5 scf per kg mole if you select 68 
          deg.F as standard temperature and 836.6 scf per kg mole if you 
          select 60  deg.F as standard temperature.
Fl,i = Annual volume of the liquid fuel combusted 
          (``(Fl)'' included in Equation Q-1) for each 
          process unit (gallons).
Fs,i = Annual mass of the solid fuel combusted 
          (``(Fs)'' in Equation Q-1) for each process unit 
          (metric tons).
nl,i = Density of the liquid fuel (kg/gallon).
0.001 = Conversion factor from kg to metric tons.

    (ii) The annual mass (metric tons) of all non-fuel material inputs 
(combined) specified in Equations Q-1 through Q-7 of Sec. 98.173, 
calculated as specified in Equation Q-10 of this section.
[GRAPHIC] [TIFF OMITTED] TR24OC14.012


Where:

NFI = Annual mass of all non-fuel inputs (to all process unit types) 
          specified in Equations Q-1 through Q-7 of Sec. 98.173 (metric 
          tons).
n = Number of process units, all process types.
O = Annual mass of greenball (taconite) pellets fed to the taconite 
          furnace(s) (metric tons).
Iron = Annual mass of molten iron charged to the basic oxygen furnace(s) 
          plus annual mass of direct reduced iron charged to the EAF(s) 
          (metric tons).
Scrap = Annual mass of ferrous scrap charged to the basic oxygen 
          furnace(s) and EAF(s) (metric tons).
Flux = Annual mass of flux materials charged to the basic oxygen 
          furnace(s) and EAF(s) (metric tons).
Carbon = Annual mass of carbonaceous materials (e.g., coal, coke) 
          charged to the basic oxygen furnace(s), EAF(s), and direct 
          reduction furnace(s) (metric tons).
Coal = Annual mass of coal charged to the coke oven battery(s) (metric 
          tons).
Feed = Annual mass of sinter feed material charged to the sinter 
          process(es) (metric tons).
Electrode = Annual mass of carbon electrode consumed in the EAF(s) 
          (metric tons).
Steelin = Annual mass of molten steel charged to the 
          decarburization vessels (metric tons).
Ore = Annual mass of iron ore or iron ore pellets fed to the direct 
          reduction furnace(s) (metric tons).
Other = Annual mass of other materials charged to the direction 
          reduction furnace(s) (metric tons).


[[Page 790]]


    (iii) The annual mass (metric tons) of all solid and liquid products 
and byproducts (combined) specified in Equations Q-1 through Q-7 of 
Sec. 98.173, calculated as specified in Equation Q-11 of this section.
[GRAPHIC] [TIFF OMITTED] TR24OC14.013


Where:

Products = Annual mass of all solid and liquid products and by-products 
          (from all process units) specified in Equations Q-1 through Q-
          7 of Sec. 98.173 (metric tons).
n = Number of process units, all types.
P = Annual mass of fired pellets produced by the taconite furnace 
          (metric tons).
R = Annual mass of air pollution control residue from all process units 
          (metric tons).
Steelout = Annual mass of steel produced by the basic oxygen 
          furnace(s), EAF(s) and decarburization vessel(s) (metric 
          tons).
Slag = Annual mass of slag produced by the basic oxygen furnace(s) and 
          EAF(s) (metric tons).
Coke = Annual mass of coke produced by the non-recovery coke batteries 
          (metric tons).
Sinter = Annual mass of sinter produced from the sinter process(es) 
          (metric tons).
Iron = Annual mass of iron produced from the direct reduction furnace 
          (metric tons).
NM = Annual mass of non-metallic materials produced by the direct 
          reduction furnace (metric tons).

    (iv) The weighted average carbon content of all gaseous, liquid, and 
solid fuels (combined) included in Equation Q-9 of this section, 
calculated as specified in Equation Q-12 of this section.
[GRAPHIC] [TIFF OMITTED] TR24OC14.014


Where:

CFavg = Weighted average carbon content of all gaseous, 
          liquid, and solid fuels included in Equation Q-9 of this 
          section (weight fraction).
n = Number of gaseous, liquid, and solid fuel input to each process unit 
          as used in Equation Q-9.
Cgf,i = Average carbon content of the gaseous fuel used in 
          each process, from the fuel analysis results (kg C per kg of 
          fuel).
Clf,i = Carbon content of the liquid fuel used in each 
          process, from the fuel analysis results (kg C per gallon of 
          fuel.
Csf = Carbon content of the solid fuel used in each process, 
          from the fuel analysis (expressed as a decimal fraction, e.g., 
          95% = 0.95).
Fuel = Annual mass of all gaseous, liquid, and solid fuels used in 
          process units (metric tons), as calculated in Equation Q-9.

    (v) The weighted average carbon content of all non-fuel inputs to 
all process units (combined) included in Equation Q-10 of this section, 
calculated as specified in Equation Q-13 of this section.
[GRAPHIC] [TIFF OMITTED] TR24OC14.015


Where:

CIavg = Weighted average carbon content of all non-fuel 
          inputs to all process units included in Equation Q-10 of this 
          section (weight fraction).
n = Number of non-fuel inputs to all process units as used in Equation 
          Q-10.
NFIi = Annual mass of each non-fuel input used in Equation Q-
          10 (metric tons).
CNFIi = Average carbon content of each non-fuel input used in 
          Equation Q-10 (expressed as a decimal fraction).
NFI = Total of all non-fuel inputs to all process units (metric tons).

    (vi) The weighted average carbon content of all solid and liquid 
products and byproducts from all process units

[[Page 791]]

(combined) included in Equation Q-11 of this section, calculated as 
specified in Equation Q-14 of this section.
[GRAPHIC] [TIFF OMITTED] TR24OC14.016


Where:

CPavg = Weighted average carbon content of all solid and 
          liquid products and byproducts from all process units (weight 
          fraction).
n = Number of products and byproducts from each process unit as used in 
          Equation Q-11 of this section.
Producti = Annual mass of each product or byproduct used in 
          Equation Q-11 (metric tons).
Cp,i = Average carbon content of each product or byproduct 
          used in Equation Q-11 (expressed as a decimal fraction).
Products = Mass of all products and byproducts from all process units, 
          calculated in Equation Q-11 (metric tons).
    (f) If you used the site-specific emission factor method in Sec. 
98.173(b)(2) to determine CO2 emissions, you must report the 
following information for each process:
    (1) The measured average hourly CO2 emission rate during 
the test (in metric tons per hour).
    (2)-(4) [Reserved]
    (g) [Reserved]
    (h) For flares burning coke oven gas or blast furnace gas, the 
information specified in Sec. 98.256(e) of subpart Y (Petroleum 
Refineries) of this part.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66464, Oct. 28, 2010; 
78 FR 71958, Nov. 29, 2013; 79 FR 63787, Oct. 24, 2014]



Sec. 98.177  Records that must be retained.

    In addition to the records required by Sec. 98.3(g), you must 
retain the records specified in paragraphs (a) through (f) of this 
section, as applicable. Facilities that use CEMS to measure emissions 
must also retain records of the verification data required for the Tier 
4 Calculating Methodology in Sec. 98.36(e).
    (a) Records of all analyses and calculations conducted, including 
all information reported as required under Sec. 98.176.
    (b) When the carbon mass balance method is used to estimate 
emissions for a process, the monthly mass of each process input and 
output that are used to determine the annual mass, except that no 
determination of the mass of steel output from decarburization vessels 
is required.
    (c) Production capacity (in metric tons per year) for the production 
of taconite pellets, coke, sinter, iron, and raw steel.
    (d) Annual operating hours for each taconite indurating furnace, 
basic oxygen furnace, non-recovery coke oven battery, sinter process, 
electric arc furnace, decarburization vessel, and direct reduction 
furnace.
    (e) Facilities must keep records that include a detailed explanation 
of how company records or measurements are used to determine all sources 
of carbon input and output and the metric tons of coal charged to the 
coke ovens (e.g., weigh belts, a combination of measuring volume and 
bulk density). You also must document the procedures used to ensure the 
accuracy of the measurements of fuel usage including, but not limited 
to, calibration of weighing equipment, fuel flow meters, coal usage 
including, but not limited to, calibration of weighing equipment and 
other measurement devices. The estimated accuracy of measurements made 
with these devices must also be recorded, and the technical basis for 
these estimates must be provided.
    (f) Verification software records. You must keep a record of the 
file generated by the verification software specified in Sec. 98.5(b) 
for the applicable data specified in paragraphs (f)(1) through (9) of 
this section. Retention of this file satisfies the recordkeeping 
requirement for the data in paragraphs (f)(1) through (9) of this 
section.
    (1) The data in paragraphs (f)(1)(i) through (xxv) of this section 
for each applicable taconite indurating furnace

[[Page 792]]

for which the carbon mass balance method of reporting is used.
    (i) Annual mass of each solid fuel (metric tons) (Equation Q-1 of 
Sec. 98.173).
    (ii) Carbon content of each solid fuel, from the fuel analysis 
(expressed as a decimal fraction) (Equation Q-1).
    (iii) Annual volume of each gaseous fuel (scf) (Equation Q-1).
    (iv) Average carbon content of each gaseous fuel, from the fuel 
analysis results (kg C per kg of fuel) (Equation Q-1).
    (v) Molecular weight of each gaseous fuel (kg/kg-mole) (Equation Q-
1).
    (vi) Annual volume of each liquid fuel (gallons) (Equation Q-1).
    (vii) Carbon content of each liquid fuel, from the fuel analysis 
results (kg C per gallon of fuel) (Equation Q-1).
    (viii) Annual mass of the greenball (taconite) pellets fed to the 
furnace (metric tons) (Equation Q-1).
    (ix) Carbon content of the greenball (taconite) pellets, from the 
carbon analysis results (expressed as a decimal fraction) (Equation Q-
1).
    (x) Annual mass of fired pellets produced by the furnace (metric 
tons) (Equation Q-1).
    (xi) Carbon content of the fired pellets, from the carbon analysis 
results (expressed as a decimal fraction) (Equation Q-1).
    (xii) Annual mass of air pollution control residue collected (metric 
tons) (Equation Q-1).
    (xiii) Carbon content of the air pollution control residue, from the 
carbon analysis results (expressed as a decimal fraction) (Equation Q-
1).
    (xiv) Annual mass of each other solid input containing carbon fed to 
each furnace (metric tons) (Equation Q-1).
    (xv) Carbon content of each other solid input containing carbon fed 
to each furnace (expressed as a decimal fraction) (Equation Q-1).
    (xvi) Annual mass of each other solid output containing carbon 
produced by each furnace (metric tons) (Equation Q-1).
    (xvii) Carbon content of each other solid output containing carbon 
(expressed as a decimal fraction) (Equation Q-1).
    (xviii) Annual mass of each other gaseous input containing carbon 
fed to each furnace (metric tons) (Equation Q-1).
    (xix) Carbon content of each other gaseous input containing carbon 
fed to each furnace (expressed as a decimal fraction) (Equation Q-1).
    (xx) Annual mass of each other gaseous output containing carbon 
produced by each furnace (metric tons) (Equation Q-1).
    (xxi) Carbon content of each other gaseous output containing carbon 
produced by each furnace (expressed as a decimal fraction) (Equation Q-
1).
    (xxii) Annual mass of each other liquid input containing carbon fed 
to each furnace (metric tons) (Equation Q-1).
    (xxiii) Carbon content of each other liquid input containing carbon 
fed to each furnace (expressed as a decimal fraction) (Equation Q-1).
    (xxiv) Annual mass of each other liquid output containing carbon 
produced by each furnace (metric tons) (Equation Q-1).
    (xxv) Carbon content of each other liquid output containing carbon 
produced by each furnace (expressed as a decimal fraction) (Equation Q-
1).
    (2) The data in paragraphs (f)(2)(i) through (xxvi) of this section 
for each applicable basic oxygen process furnace for which the carbon 
mass balance method of reporting is used.
    (i) Annual mass of molten iron charged to the furnace (metric tons) 
(Equation Q-2 of Sec. 98.173).
    (ii) Carbon content of the molten iron charged to the furnace, from 
the carbon analysis results (expressed as a decimal fraction) (Equation 
Q-2).
    (iii) Annual mass of ferrous scrap charged to the furnace (metric 
tons) (Equation Q-2).
    (iv) Carbon content of the ferrous scrap charged to the furnace, 
from the carbon analysis results (expressed as a decimal fraction) 
(Equation Q-2).
    (v) Annual mass of the flux materials (e.g., limestone, dolomite) 
charged to the furnace (metric tons) (Equation Q-2).
    (vi) Carbon content of the flux materials charged to the furnace, 
from the carbon analysis results (expressed as a decimal fraction) 
(Equation Q-2).
    (vii) Annual mass of the carbonaceous materials (e.g., coal, coke)

[[Page 793]]

charged to the furnace (metric tons) (Equation Q-2).
    (viii) Carbon content of the carbonaceous materials charged to the 
furnace, from the carbon analysis results (expressed as a decimal 
fraction) (Equation Q-2).
    (ix) Annual mass of molten raw steel produced by the furnace (metric 
tons) (Equation Q-2).
    (x) Carbon content of the steel produced by the furnace, from the 
carbon analysis results (expressed as a decimal fraction) (Equation Q-
2).
    (xi) Annual mass of slag produced by the furnace (metric tons) 
(Equation Q-2).
    (xii) Carbon content of the slag produced by the furnace, from the 
carbon analysis (expressed as a decimal fraction) (Equation Q-2).
    (xiii) Annual mass of air pollution control residue collected for 
the furnace (metric tons) (Equation Q-2).
    (xiv) Carbon content of the air pollution control residue collected 
for the furnace, from the carbon analysis results (expressed as a 
decimal fraction) (Equation Q-2).
    (xv) Annual mass of each other solid input containing carbon fed to 
each furnace (metric tons) (Equation Q-2).
    (xvi) Carbon content of each other solid input containing carbon fed 
to each furnace (expressed as a decimal fraction) (Equation Q-2).
    (xvii) Annual mass of each other solid output containing carbon 
produced by each furnace (metric tons) (Equation Q-2).
    (xviii) Carbon content of each other solid output containing carbon 
(expressed as a decimal fraction) (Equation Q-2).
    (xix) Annual mass of each other gaseous input containing carbon fed 
to each furnace (metric tons) (Equation Q-2).
    (xx) Carbon content of each other gaseous input containing carbon 
fed to each furnace (expressed as a decimal fraction) (Equation Q-2).
    (xxi) Annual mass of each other gaseous output containing carbon 
produced by each furnace (metric tons) (Equation Q-2).
    (xxii) Carbon content of each other gaseous output containing carbon 
produced by each furnace (expressed as a decimal fraction) (Equation Q-
2).
    (xxiii) Annual mass of each other liquid input containing carbon fed 
to each furnace (metric tons) (Equation Q-2).
    (xxiv) Carbon content of each other liquid input containing carbon 
fed to each furnace (expressed as a decimal fraction) (Equation Q-2).
    (xxv) Annual mass of each other liquid output containing carbon 
produced by each furnace (metric tons) (Equation Q-2).
    (xxvi) Carbon content of each other liquid output containing carbon 
produced by each furnace (expressed as a decimal fraction) (Equation Q-
2).
    (3) The data in paragraphs (f)(3)(i) through (xviii) of this section 
for each applicable non-recovery coke oven battery for which the carbon 
mass balance method of reporting is used.
    (i) Annual mass of coal charged to the battery (metric tons) 
(Equation Q-3 of Sec. 98.173).
    (ii) Carbon content of the coal, from the carbon analysis results 
(expressed as a decimal fraction) (Equation Q-3).
    (iii) Annual mass of coke produced by the battery (metric tons) 
(Equation Q-3).
    (iv) Carbon content of the coke, from the carbon analysis results 
(expressed as a decimal fraction) (Equation Q-3).
    (v) Annual mass of air pollution control residue collected (metric 
tons) (Equation Q-3).
    (vi) Carbon content of the air pollution control residue, from the 
carbon analysis results (expressed as a decimal fraction) (Equation Q-
3).
    (vii) Annual mass of each other solid input containing carbon fed to 
each battery (metric tons) (Equation Q-3).
    (viii) Carbon content of each other solid input containing carbon 
fed to each battery (expressed as a decimal fraction) (Equation Q-3).
    (ix) Annual mass of each other solid output containing carbon 
produced by each battery (metric tons) (Equation Q-3).
    (x) Carbon content of each other solid output containing carbon 
(expressed as a decimal fraction) (Equation Q-3).
    (xi) Annual mass of each other gaseous input containing carbon fed 
to each battery (metric tons) (Equation Q-3).

[[Page 794]]

    (xii) Carbon content of each other gaseous input containing carbon 
fed to each battery (expressed as a decimal fraction) (Equation Q-3).
    (xiii) Annual mass of each other gaseous output containing carbon 
produced by each battery (metric tons) (Equation Q-3).
    (xiv) Carbon content of each other gaseous output containing carbon 
produced by each battery (expressed as a decimal fraction) (Equation Q-
3).
    (xv) Annual mass of each other liquid input containing carbon fed to 
each battery (metric tons) (Equation Q-3).
    (xvi) Carbon content of each other liquid input containing carbon 
fed to each battery (expressed as a decimal fraction) (Equation Q-3).
    (xvii) Annual mass of each other liquid output containing carbon 
produced by each battery (metric tons) (Equation Q-3).
    (xviii) Carbon content of each other liquid output containing carbon 
produced by each battery (expressed as a decimal fraction) (Equation Q-
3).
    (4) The data in paragraphs (f)(4)(i) through (xxi) of this section 
for each applicable sinter process for which the carbon mass balance 
method of reporting is used.
    (i) Annual volume of the gaseous fuel (scf) (Equation Q-4 of Sec. 
98.173).
    (ii) Carbon content of the gaseous fuel, from the fuel analysis 
results (kg C per kg of fuel) (Equation Q-4).
    (iii) Molecular weight of the gaseous fuel (kg/kg-mole) (Equation Q-
4).
    (iv) Annual mass of sinter feed material (metric tons) (Equation Q-
4).
    (v) Carbon content of the mixed sinter feed materials that form the 
bed entering the sintering machine, from the carbon analysis results 
(expressed as a decimal fraction) (Equation Q-4).
    (vi) Annual mass of sinter produced (metric tons) (Equation Q-4).
    (vii) Carbon content of the sinter pellets, from the carbon analysis 
results (expressed as a decimal fraction) (Equation Q-4).
    (viii) Annual mass of air pollution control residue collected 
(metric tons) (Equation Q-4).
    (ix) Carbon content of the air pollution control residue, from the 
carbon analysis results (expressed as a decimal fraction) (Equation Q-
4).
    (x) Annual mass of each other solid input containing carbon fed to 
each sinter process (metric tons) (Equation Q-4).
    (xi) Carbon content of each other solid input containing carbon fed 
to each sinter process (expressed as a decimal fraction) (Equation Q-4).
    (xii) Annual mass of each other solid output containing carbon 
produced by each sinter process (metric tons) (Equation Q-4).
    (xiii) Carbon content of each other solid output containing carbon 
(expressed as a decimal fraction) (Equation Q-4).
    (xiv) Annual mass of each other gaseous input containing carbon fed 
to each sinter process (metric tons) (Equation Q-4).
    (xv) Carbon content of each other gaseous input containing carbon 
fed to each sinter process (expressed as a decimal fraction) (Equation 
Q-4).
    (xvi) Annual mass of each other gaseous output containing carbon 
produced by each sinter process (metric tons) (Equation Q-4).
    (xvii) Carbon content of each other gaseous output containing carbon 
produced by each sinter process (expressed as a decimal fraction) 
(Equation Q-4).
    (xviii) Annual mass of each other liquid input containing carbon fed 
to each sinter process (metric tons) (Equation Q-4).
    (xix) Carbon content of each other liquid input containing carbon 
fed to each sinter process (expressed as a decimal fraction) (Equation 
Q-4).
    (xx) Annual mass of each other liquid output containing carbon 
produced by each sinter process (metric tons) (Equation Q-4).
    (xxi) Carbon content of each other liquid output containing carbon 
produced by each sinter process (expressed as a decimal fraction) 
(Equation Q-4).
    (5) The data in paragraphs (f)(5)(i) through (xxxi) of this section 
for each applicable electric arc furnace for which the carbon mass 
balance method of reporting is used.
    (i) Annual mass of direct reduced iron (if any) charged to the 
furnace (metric tons) (Equation Q-5 of Sec. 98.173).
    (ii) Carbon content of the direct reduced iron, from the carbon 
analysis

[[Page 795]]

results (expressed as a decimal fraction) (Equation Q-5)
    (iii) Annual mass of ferrous scrap charged to the furnace (metric 
tons) (Equation Q-5).
    (iv) Carbon content of the ferrous scrap, from the carbon analysis 
results (expressed as a decimal fraction) (Equation Q-5).
    (v) Annual mass of flux materials (e.g., limestone, dolomite) 
charged to the furnace (metric tons) (EquationQ-5).
    (vi) Carbon content of the flux materials, from the carbon analysis 
results (expressed as a decimal fraction) (Equation Q-5).
    (vii) Annual mass of carbon electrode consumed (metric tons) 
(Equation Q-5).
    (viii) Carbon content of the carbon electrode, from the carbon 
analysis results (expressed as a decimal fraction) (Equation Q-5).
    (ix) Annual mass of carbonaceous materials (e.g., coal, coke) 
charged to the furnace (metric tons) (Equation Q-5).
    (x) Carbon content of the carbonaceous materials, from the carbon 
analysis results (expressed as a decimal fraction) (Equation Q-5).
    (xi) Annual mass of molten raw steel produced by the furnace (metric 
tons) (Equation Q-5).
    (xii) Carbon content of the steel, from the carbon analysis results 
(expressed as a decimal fraction) (Equation Q-5).
    (xiii) Annual volume of the gaseous fuel (scf at 60F and 1 atm) 
(Equation Q-5).
    (xiv) Average carbon content of the gaseous fuel, from the fuel 
analysis results (kg C per kg of fuel) (Equation Q-5).
    (xv) Molecular weight of the gaseous fuel (kg/kg-mole) (Equation Q-
5).
    (xvi) Annual mass of slag produced by the furnace (metric tons) 
(Equation Q-5).
    (xvii) Carbon content of the slag, from the carbon analysis 
(expressed as a decimal fraction) (Equation Q-5).
    (xviii) Annual mass of air pollution control residue collected 
(metric tons) (Equation Q-5).
    (xix) Carbon content of the air pollution control residue, from the 
carbon analysis results (expressed as a decimal fraction) (Equation Q-
5).
    (xx) Annual mass of each other solid input containing carbon fed to 
each furnace (metric tons) (Equation Q-5).
    (xxi) Carbon content of each other solid input containing carbon fed 
to each furnace (expressed as a decimal fraction) (Equation Q-5).
    (xxii) Annual mass of each other solid output containing carbon 
produced by each furnace (metric tons) (Equation Q-5).
    (xxiii) Carbon content of each other solid output containing carbon 
(expressed as a decimal fraction) (Equation Q-5).
    (xxiv) Annual mass of each other gaseous input containing carbon fed 
to each furnace (metric tons) (Equation Q-5).
    (xxv) Carbon content of each other gaseous input containing carbon 
fed to each furnace (expressed as a decimal fraction) (Equation Q-5).
    (xxvi) Annual mass of each other gaseous output containing carbon 
produced by each furnace (metric tons) (Equation Q-5).
    (xxvii) Carbon content of each other gaseous output containing 
carbon produced by each furnace (expressed as a decimal fraction) 
(Equation Q-5).
    (xxviii) Annual mass of each other liquid input containing carbon 
fed to each furnace (metric tons) (Equation Q-5).
    (xxix) Carbon content of each other liquid input containing carbon 
fed to each furnace (expressed as a decimal fraction) (Equation Q-5).
    (xxx) Annual mass of each other liquid output containing carbon 
produced by each furnace (metric tons) (Equation Q-5).
    (xxxi) Carbon content of each other liquid output containing carbon 
produced by each furnace (expressed as a decimal fraction) (Equation Q-
5).
    (6) The data in paragraphs (f)(6)(i) through (xvii) of this section 
for each applicable decarburization vessel for which the carbon mass 
balance method of reporting is used.
    (i) Annual mass of molten steel charged to the vessel (metric tons) 
(Equation Q-6 of Sec. 98.173).
    (ii) Carbon content of the molten steel before decarburization, from 
the

[[Page 796]]

carbon analysis results (expressed as a decimal fraction) (Equation Q-
6).
    (iii) Carbon content of the molten steel after decarburization, from 
the carbon analysis results (expressed as a decimal fraction) (Equation 
Q-6).
    (iv) Annual mass of air pollution control residue collected (metric 
tons) (Equation Q-6).
    (v) Carbon content of the air pollution control residue, from the 
carbon analysis results (expressed as a decimal fraction) (Equation Q-
6).
    (vi) Annual mass of each other solid input containing carbon fed to 
each decarburization vessel (metric tons) (Equation Q-6).
    (vii) Carbon content of each other solid input containing carbon fed 
to each decarburization vessel (expressed as a decimal fraction) 
(Equation Q-6).
    (viii) Annual mass of each other solid output containing carbon 
produced by each decarburization vessel (metric tons) (Equation Q-6).
    (ix) Carbon content of each other solid output containing carbon 
(expressed as a decimal fraction) (Equation Q-6).
    (x) Annual mass of each other gaseous input containing carbon fed to 
each decarburization vessel (metric tons) (Equation Q-6).
    (xi) Carbon content of each other gaseous input containing carbon 
fed to each decarburization vessel (expressed as a decimal fraction) 
(Equation Q-6).
    (xii) Annual mass of each other gaseous output containing carbon 
produced by each decarburization vessel (metric tons) (Equation Q-6).
    (xiii) Carbon content of each other gaseous output containing carbon 
produced by each decarburization vessel (expressed as a decimal 
fraction) (Equation Q-6).
    (xiv) Annual mass of each other liquid input containing carbon fed 
to each decarburization vessel (metric tons) (Equation Q-6).
    (xv) Carbon content of each other liquid input containing carbon fed 
to each decarburization vessel (expressed as a decimal fraction) 
(Equation Q-6).
    (xvi) Annual mass of each other liquid output containing carbon 
produced by each decarburization vessel (metric tons) (Equation Q-6).
    (xvii) Carbon content of each other liquid output containing carbon 
produced by each decarburization vessel (expressed as a decimal 
fraction) (Equation Q-6).
    (7) The data in paragraphs (f)(7)(i) through (xxvii) of this section 
for each applicable direct reduction furnace for which the carbon mass 
balance method of reporting is used.
    (i) Annual volume of the gaseous fuel (scf at 68F and 1 atm) 
(Equation Q-7 of Sec. 98.173).
    (ii) Average carbon content of the gaseous fuel, from the fuel 
analysis results (kg C per kg of fuel) (Equation Q-7).
    (iii) Molecular weight of the gaseous fuel (kg/kg-mole) (Equation Q-
7).
    (iv) Annual mass of iron ore or iron pellets fed to the furnace 
(metric tons) (Equation Q-7).
    (v) Carbon content of the iron ore or iron pellets, from the carbon 
analysis (expressed as a decimal fraction) (Equation Q-7).
    (vi) Annual mass of carbonaceous materials (e.g., coal, coke) 
charged to the furnace (metric tons) (Equation Q-7).
    (vii) Carbon content of the carbonaceous materials, from the carbon 
analysis results (expressed as a decimal fraction) (Equation Q-7).
    (viii) Annual mass of each other material charged to the furnace 
(metric tons) (Equation Q-7).
    (ix) Average carbon content of each other material charged to the 
furnace, from the carbon analysis results (expressed as a decimal 
fraction) (Equation Q-7).
    (x) Annual mass of iron produced (metric tons) (Equation Q-7).
    (xi) Carbon content of the iron produced, from the carbon analysis 
results (expressed as a decimal fraction) (Equation Q-7).
    (xii) Annual mass of non-metallic materials produced by the furnace 
(metric tons) (Equation Q-7).
    (xiii) Carbon content of the non-metallic materials produced, from 
the carbon analysis results (expressed as a decimal fraction) (Equation 
Q-7).
    (xiv) Annual mass of air pollution control residue collected (metric 
tons) (Equation Q-7).

[[Page 797]]

    (xv) Carbon content of the air pollution control residue collected, 
from the carbon analysis results (expressed as a decimal fraction) 
(Equation Q-7).
    (xvi) Annual mass of each other solid input containing carbon fed to 
each furnace (metric tons) (Equation Q-7).
    (xvii) Carbon content of each other solid input containing carbon 
fed to each furnace (expressed as a decimal fraction) (Equation Q-7).
    (xviii) Annual mass of each other solid output containing carbon 
produced by each furnace (metric tons) (Equation Q-7).
    (xix) Carbon content of each other solid output containing carbon 
(expressed as a decimal fraction) (Equation Q-7).
    (xx) Annual mass of each other gaseous input containing carbon fed 
to each furnace (metric tons) (Equation Q-7).
    (xxi) Carbon content of each other gaseous input containing carbon 
fed to each furnace (expressed as a decimal fraction) (Equation Q-7).
    (xxii) Annual mass of each other gaseous output containing carbon 
produced by each furnace (metric tons) (Equation Q-7).
    (xxiii) Carbon content of each other gaseous output containing 
carbon produced by each furnace (expressed as a decimal fraction) 
(Equation Q-7).
    (xxiv) Annual mass of each other liquid input containing carbon fed 
to each furnace (metric tons) (Equation Q-7).
    (xxv) Carbon content of each other liquid input containing carbon 
fed to each furnace (expressed as a decimal fraction) (Equation Q-7).
    (xxvi) Annual mass of each other liquid output containing carbon 
produced by each furnace (metric tons) (Equation Q-7).
    (xxvii) Carbon content of each other liquid output containing carbon 
produced by each furnace (expressed as a decimal fraction) (Equation Q-
7).
    (8) The data in paragraphs (f)(8)(i) and (ii) of this section for 
each process unit for which the site-specific emission factor method was 
used.
    (i) Average hourly feed or production rate, as applicable, during 
the test (metric tons/hour) (as used in Sec. 98.173(b)(2)(iii)).
    (ii) Annual total feed or production, as applicable (metric tons) 
(as used in Sec. 98.173(b)(2)(iv)).
    (9) Total coal charged to the coke ovens for each process (metric 
tons/year)(as used in Sec. 98.173(c)).

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66464, Oct. 28, 2010; 
78 FR 71958, Nov. 29, 2013; 79 FR 63788, Oct. 24, 2014]



Sec. 98.178  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.



                        Subpart R_Lead Production



Sec. 98.180  Definition of the source category.

    The lead production source category consists of primary lead 
smelters and secondary lead smelters. A primary lead smelter is a 
facility engaged in the production of lead metal from lead sulfide ore 
concentrates through the use of pyrometallurgical techniques. A 
secondary lead smelter is a facility at which lead-bearing scrap 
materials (including but not limited to, lead-acid batteries) are 
recycled by smelting into elemental lead or lead alloys.



Sec. 98.181  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains a lead production process and the facility meets the 
requirements of either Sec. 98.2(a)(1) or (a)(2).



Sec. 98.182  GHGs to report.

    You must report:
    (a) Process CO2 emissions from each smelting furnace used 
for lead production.
    (b) CO2 combustion emissions from each smelting furnace 
used for lead production.
    (c) CH4 and N2O combustion emissions from each 
smelting furnace used for lead production. You must calculate and report 
these emissions under subpart C of this part (General Stationary Fuel 
Combustion Sources) by following the requirements of subpart C.
    (d) CO2, CH4, and N2O emissions 
from each stationary combustion unit other than smelting furnaces used 
for lead

[[Page 798]]

production. You must report these emissions under subpart C of this part 
(General Stationary Fuel Combustion Sources) by following the 
requirements of subpart C.



Sec. 98.183  Calculating GHG emissions.

    You must calculate and report the annual process CO2 
emissions from each smelting furnace using the procedure in paragraphs 
(a) and (b) of this section.
    (a) For each smelting furnace that meets the conditions specified in 
Sec. 98.33(b)(4)(ii) or (b)(4)(iii), you must calculate and report 
combined process and combustion CO2 emissions by operating 
and maintaining a CEMS to measure CO2 emissions according to 
the Tier 4 Calculation Methodology specified in Sec. 98.33(a)(4) and 
all associated requirements for Tier 4 in subpart C of this part 
(General Stationary Fuel Combustion Sources).
    (b) For each smelting furnace that is not subject to the 
requirements in paragraph (a) of this section, calculate and report the 
process and combustion CO2 emissions from the smelting 
furnace by using the procedure in either paragraph (b)(1) or (b)(2) of 
this section.
    (1) Calculate and report under this subpart the combined process and 
combustion CO2 emissions by operating and maintaining a CEMS 
to measure CO2 emissions according to the Tier 4 Calculation 
Methodology specified in Sec. 98.33(a)(4) and all associated 
requirements for Tier 4 in subpart C of this part (General Stationary 
Fuel Combustion Sources).
    (2) Calculate and report process and combustion CO2 
emissions separately using the procedures specified in paragraphs 
(b)(2)(i) through (b)(2)(iii) of this section.
    (i) For each smelting furnace, determine the annual mass of carbon 
in each carbon-containing material, other than fuel, that is fed, 
charged, or otherwise introduced into the smelting furnace and estimate 
annual process CO2 emissions using Equation R-1 of this 
section. Carbon-containing materials include carbonaceous reducing 
agents. If you document that a specific material contributes less than 1 
percent of the total carbon into the process, you do not have to include 
the material in your calculation using Equation R-1 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.071

Where:

ECO2 = Annual process CO2 emissions from an 
          individual smelting furnace (metric tons).
44/12 = Ratio of molecular weights, CO2 to carbon.
2000/2205 = Conversion factor to convert tons to metric tons.
Ore = Annual mass of lead ore charged to the smelting furnace (tons).
COre = Carbon content of the lead ore, from the carbon 
          analysis results (percent by weight, expressed as a decimal 
          fraction).
Scrap = Annual mass of lead scrap charged to the smelting furnace 
          (tons).
CScrap = Carbon content of the lead scrap, from the carbon 
          analysis (percent by weight, expressed as a decimal fraction).
Flux = Annual mass of flux materials (e.g., limestone, dolomite) charged 
          to the smelting furnace (tons).
CFlux = Carbon content of the flux materials, from the carbon 
          analysis (percent by weight, expressed as a decimal fraction).
Carbon = Annual mass of carbonaceous materials (e.g., coal, coke) 
          charged to the smelting furnace (tons).
CCarbon = Carbon content of the carbonaceous materials, from 
          the carbon analysis (percent by weight, expressed as a decimal 
          fraction).
Other = Annual mass of any other material containing carbon, other than 
          fuel, fed, charged, or otherwise introduced into the smelting 
          furnace (tons).
COther = Carbon content of the other material from the carbon 
          analysis results (percent by weight, expressed as a decimal 
          fraction).

    (ii) Determine the combined annual process CO2 emissions 
from the smelting furnaces at your facility using Equation R-2 of this 
section.

[[Page 799]]

[GRAPHIC] [TIFF OMITTED] TR30OC09.072

Where:

CO2 = Annual process CO2 emissions from smelting 
          furnaces at facility used for lead production (metric tons).
ECO2k = Annual process CO2 emissions from smelting 
          furnace k calculated using Equation R-1 of this section 
          (metric tons/year).
k = Total number of smelting furnaces at facility used for lead 
          production.

    (iii) Calculate and report under subpart C of this part (General 
Stationary Fuel Combustion Sources) the combustion CO2 
emissions from the smelting furnaces according to the applicable 
requirements in subpart C.



Sec. 98.184  Monitoring and QA/QC requirements.

    If you determine process CO2 emissions using the carbon 
mass balance procedure in Sec. 98.183(b)(2)(i) and (b)(2)(ii), you must 
meet the requirements specified in paragraphs (a) and (b) of this 
section.
    (a) Determine the annual mass for each material used for the 
calculations of annual process CO2 emissions using Equation 
R-1 of this subpart by summing the monthly mass for the material 
determined for each month of the calendar year. The monthly mass may be 
determined using plant instruments used for accounting purposes, 
including either direct measurement of the quantity of the material 
placed in the unit or by calculations using process operating 
information.
    (b) For each material identified in paragraph (a) of this section, 
you must determine the average carbon content of the material consumed 
or used in the calendar year using the methods specified in either 
paragraph (b)(1) or (b)(2) of this section. If you document that a 
specific process input or output contributes less than one percent of 
the total mass of carbon into or out of the process, you do not have to 
determine the monthly mass or annual carbon content of that input or 
output.
    (1) Information provided by your material supplier.
    (2) Collecting and analyzing at least three representative samples 
of the material each year. The carbon content of the material must be 
analyzed at least annually using the methods (and their QA/QC 
procedures) specified in paragraphs (b)(2)(i) through (b)(2)(iii) of 
this section, as applicable.
    (i) ASTM E1941-04, Standard Test Method for Determination of Carbon 
in Refractory and Reactive Metals and Their Alloys (incorporated by 
reference, see Sec. 98.7) for analysis of metal ore and alloy product.
    (ii) ASTM D5373-08 Standard Test Methods for Instrumental 
Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of 
Coal (incorporated by reference, see Sec. 98.7), for analysis of 
carbonaceous reducing agents and carbon electrodes.
    (iii) ASTM C25-06, Standard Test Methods for Chemical Analysis of 
Limestone, Quicklime, and Hydrated Lime (incorporated by reference, see 
Sec. 98.7) for analysis of flux materials such as limestone or 
dolomite.



Sec. 98.185  Procedures for estimating missing data.

    A complete record of all measured parameters used in the GHG 
emissions calculations in Sec. 98.183 is required. Therefore, whenever 
a quality-assured value of a required parameter is unavailable, a 
substitute data value for the missing parameter shall be used in the 
calculations as specified in the paragraphs (a) and (b) of this section. 
You must document and keep records of the procedures used for all such 
estimates.
    (a) For each missing data for the carbon content for the smelting 
furnaces at your facility that estimate annual process CO2 
emissions using the carbon mass balance procedure in Sec. 
98.183(b)(2)(i) and (ii), 100 percent data availability is required. You 
must repeat the test for average carbon contents of inputs according to 
the procedures in Sec. 98.184(b) if data are missing.
    (b) For missing records of the monthly mass of carbon-containing 
materials, the substitute data value must be based the best available 
estimate of the mass of the material from all available process data or 
data used for accounting purposes (such as purchase records).

[[Page 800]]



Sec. 98.186  Data reporting procedures.

    In addition to the information required by Sec. 98.3(c), each 
annual report must contain the information specified in paragraphs (a) 
or (b) of this section, as applicable.
    (a) If a CEMS is used to measure CO2 emissions according 
to the requirements in Sec. 98.183(a) or (b)(1), then you must report 
under this subpart the relevant information required by Sec. 98.36 and 
the information specified in paragraphs (a)(1) through (a)(4) of this 
section.
    (1) Identification number of each smelting furnace.
    (2) Annual lead product production capacity (tons).
    (3) Annual production for each lead product (tons).
    (4) Total number of smelting furnaces at facility used for lead 
production.
    (b) If a CEMS is not used to measure CO2 emissions, and 
you measure CO2 emissions according to the requirements in 
Sec. 98.183(b)(2)(i) and (b)(2)(ii), then you must report the 
information specified in paragraphs (b)(1) through (b)(9) of this 
section.
    (1) Identification number of each smelting furnace. (2) Annual 
process CO2 emissions (in metric tons) from each smelting 
furnace as determined by Equation R-1 of this subpart.
    (3) Annual lead product production capacity for the facility and 
each smelting furnace(tons).
    (4) Annual production for each lead product (tons).
    (5) Total number of smelting furnaces at facility used for 
production of lead products reported in paragraph (b)(4) of this 
section.
    (6)-(7) [Reserved]
    (8) List the method used for the determination of carbon content for 
each material used for the calculation of annual process CO2 
emissions using Equation R-1 of Sec. 98.183 for each smelting furnace 
(e.g., supplier provided information, analyses of representative samples 
you collected).
    (9) If you use the missing data procedures in Sec. 98.185(b), you 
must report how the monthly mass of carbon-containing materials with 
missing data was determined and the number of months the missing data 
procedures were used.

[74 FR 56374, Oct. 30, 2009, as amended at 79 FR 63792, Oct. 24, 2014]



Sec. 98.187  Records that must be retained.

    In addition to the records required by Sec. 98.3(g), you must 
retain the records of the information specified in paragraphs (a) 
through (d) of this section, as applicable to the smelting furnaces at 
your facility.
    (a) If a CEMS is used to measure combined process and combustion 
CO2 emissions according to the requirements in Sec. 
98.183(a) or (b)(1), then you must retain the records required for the 
Tier 4 Calculation Methodology in Sec. 98.37 and the information 
specified in paragraphs (a)(1) through (a)(3) of this section.
    (1) Monthly smelting furnace production quantity for each lead 
product (tons).
    (2) Number of smelting furnace operating hours each month.
    (3) Number of smelting furnace operating hours in calendar year.
    (b) If the carbon mass balance procedure is used to determine 
process CO2 emissions according to the requirements in Sec. 
98.183(b)(2)(i) and (b)(2)(ii), then you must retain under this subpart 
the records specified in paragraphs (b)(1) through (b)(5) of this 
section.
    (1) Monthly smelting furnace production quantity for each lead 
product (tons).
    (2) Number of smelting furnace operating hours each month.
    (3) Number of smelting furnace operating hours in calendar year.
    (4) Monthly material quantity consumed, used, or produced for each 
material included for the calculations of annual process CO2 
emissions using Equation R-1 of this subpart (tons).
    (5) Average carbon content determined and records of the supplier 
provided information or analyses used for the determination for each 
material included for the calculations of annual process CO2 
emissions using Equation R-1 of this subpart.
    (c) You must keep records that include a detailed explanation of how 
company records of measurements are used to estimate the carbon input to

[[Page 801]]

each smelting furnace, including documentation of any materials excluded 
from Equation R-1 of this subpart that contribute less than 1 percent of 
the total carbon into or out of the process. You also must document the 
procedures used to ensure the accuracy of the measurements of materials 
fed, charged, or placed in an smelting furnace including, but not 
limited to, calibration of weighing equipment and other measurement 
devices. The estimated accuracy of measurements made with these devices 
must also be recorded, and the technical basis for these estimates must 
be provided.
    (d) Verification software records. You must keep a record of the 
file generated by the verification software specified in Sec. 98.5(b) 
for the applicable data specified in paragraphs (d)(1) through (10) of 
this section. Retention of this file satisfies the recordkeeping 
requirement for the data in paragraphs (d)(1) through (10) of this 
section.
    (1) Annual mass of lead ore charged to each smelting furnace (tons) 
(Equation R-1 of Sec. 98.183).
    (2) Carbon content of the lead ore per furnace, from the carbon 
analysis results (percent by weight, expressed as a decimal fraction) 
(Equation R-1).
    (3) Annual mass of lead scrap charged to each smelting furnace 
(tons) (Equation R-1).
    (4) Carbon content of the lead scrap per furnace, from the carbon 
analysis (percent by weight, expressed as a decimal fraction) (Equation 
R-1).
    (5) Annual mass of flux materials (e.g., limestone, dolomite) 
charged to each smelting furnace (tons) (Equation R-1).
    (6) Carbon content of the flux materials per furnace, from the 
carbon analysis (percent by weight, expressed as a decimal fraction) 
(Equation R-1).
    (7) Annual mass of carbonaceous materials (e.g., coal, coke) charged 
to each smelting furnace (tons) (Equation R-1).
    (8) Carbon content of the carbonaceous materials per furnace, from 
the carbon analysis (percent by weight, expressed as a decimal fraction) 
(Equation R-1).
    (9) Annual mass of each other material containing carbon, other than 
fuel, fed, charged, or otherwise introduced into the smelting furnace 
(tons) (Equation R-1).
    (10) Carbon content of each other material, from the carbon analysis 
results per furnace (percent by weight, expressed as a decimal fraction) 
(Equation R-1).

[74 FR 56374, Oct. 30, 2009, as amended at 79 FR 63792, Oct. 24, 2014]



Sec. 98.188  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.



                      Subpart S_Lime Manufacturing



Sec. 98.190  Definition of the source category.

    (a) Lime manufacturing plants (LMPs) engage in the manufacture of a 
lime product by calcination of limestone, dolomite, shells or other 
calcareous substances as defined in 40 CFR 63.7081(a)(1).
    (b) This source category includes all LMPs unless the LMP is located 
at a kraft pulp mill, soda pulp mill, sulfite pulp mill, or only 
processes sludge containing calcium carbonate from water softening 
processes. The lime manufacturing source category consists of marketed 
and non-marketed lime manufacturing facilities.
    (c) Lime kilns at pulp and paper manufacturing facilities must 
report emissions under subpart AA of this part (Pulp and Paper 
Manufacturing).

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66464, Oct. 28, 2010; 
78 FR 71958, Nov. 29, 2013]



Sec. 98.191  Reporting threshold.

    You must report GHG emissions under this subpart if your facility is 
a lime manufacturing plant as defined in Sec. 98.190 and the facility 
meets the requirements of either Sec. 98.2(a)(1) or (a)(2).



Sec. 98.192  GHGs to report.

    You must report:
    (a) CO2 process emissions from lime kilns.
    (b) CO2 emissions from fuel combustion at lime kilns.
    (c) N2O and CH4 emissions from fuel combustion 
at each lime kiln. You

[[Page 802]]

must report these emissions under 40 CFR part 98, subpart C (General 
Stationary Fuel Combustion Sources).
    (d) CO2, N2O, and CH4 emissions 
from each stationary fuel combustion unit other than lime kilns. You 
must report these emissions under 40 CFR part 98, subpart C (General 
Stationary Fuel Combustion Sources).
    (e) CO2 collected and transferred off site under 40 CFR 
part 98, following the requirements of subpart PP of this part 
(Suppliers of Carbon Dioxide (CO2)).



Sec. 98.193  Calculating GHG emissions.

    You must calculate and report the annual process CO2 
emissions from all lime kilns combined using the procedure in paragraphs 
(a) and (b) of this section.
    (a) If all lime kilns meet the conditions specified in Sec. 
98.33(b)(4)(ii) or (iii), you must calculate and report under this 
subpart the combined process and combustion CO2 emissions 
from all lime kilns by operating and maintaining a CEMS to measure 
CO2 emissions according to the Tier 4 Calculation Methodology 
specified in Sec. 98.33(a)(4) and all associated requirements for Tier 
4 in subpart C of this part (General Stationary Fuel Combustion 
Sources).
    (b) If CEMS are not required to be used to determine CO2 
emissions from all lime kilns under paragraph (a) of this section, then 
you must calculate and report the process and combustion CO2 
emissions from the lime kilns by using the procedures in either 
paragraph (b)(1) or (b)(2) of this section.
    (1) Calculate and report under this subpart the combined process and 
combustion CO2 emissions from all lime kilns by operating and 
maintaining a CEMS to measure CO2 emissions from all lime 
kilns according to the Tier 4 Calculation Methodology specified in Sec. 
98.33(a)(4) and all associated requirements for Tier 4 in subpart C of 
this part (General Stationary Fuel Combustion Sources).
    (2) Calculate and report process and combustion CO2 
emissions from all lime kilns separately using the procedures specified 
in paragraphs (b)(2)(i) through (v) of this section.
    (i) You must calculate a monthly emission factor for each type of 
lime produced using Equation S-1 of this section. Calcium oxide and 
magnesium oxide content must be analyzed monthly for each lime product 
type that is produced:
[GRAPHIC] [TIFF OMITTED] TR30OC09.073

Where:

EFLIME,i,n = Emission factor for lime type i, for month n 
          (metric tons CO2/ton lime).
SRCaO = Stoichiometric ratio of CO2 and CaO for 
          calcium carbonate [see Table S-1 of this subpart] (metric tons 
          CO2/metric tons CaO).
SRMgO = Stoichiometric ratio of CO2 and MgO for 
          magnesium carbonate (See Table S-1 of this subpart) (metric 
          tons CO2/metric tons MgO).
CaOi,n = Calcium oxide content for lime type i, for month n, 
          determined according to Sec. 98.194(c) (metric tons CaO/
          metric ton lime).
MgOi,n = Magnesium oxide content for lime type i, for month 
          n, determined according to Sec. 98.194(c) (metric tons MgO/
          metric ton lime).
2000/2205 = Conversion factor for tons to metric tons.

    (ii) You must calculate a monthly emission factor for each type of 
calcined byproduct or waste sold (including lime kiln dust) using 
Equation S-2 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.074


[[Page 803]]


Where:

EFLKD,i,n = Emission factor for calcined lime byproduct/waste 
          type i sold, for month n (metric tons CO2/ton lime 
          byproduct).
SRCaO = Stoichiometric ratio of CO2 and CaO for 
          calcium carbonate (see Table S-1 of this subpart((metric tons 
          CO2/metric tons CaO).
SRMgO = Stoichiometric ratio of CO2 and MgO for 
          magnesium carbonate (See Table S-1 of this subpart) (metric 
          tons CO2/metric tons MgO).
CaOLKD,i,n = Calcium oxide content for calcined lime 
          byproduct/waste type i sold, for month n (metric tons CaO/
          metric ton lime).
MgOLKD,i,n = Magnesium oxide content for calcined lime 
          byproduct/waste type i sold, for month n (metric tons MgO/
          metric ton lime).
2000/2205 = Conversion factor for tons to metric tons.

    (iii) You must calculate the annual CO2 emissions from 
each type of calcined byproduct or waste that is not sold (including 
lime kiln dust and scrubber sludge) using Equation S-3 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.075

Where:

Ewaste,i = Annual CO2 emissions for calcined lime 
          byproduct or waste type i that is not sold (metric tons 
          CO2).
SRCaO = Stoichiometric ratio of CO2 and CaO for 
          calcium carbonate (see Table S-1 of this subpart) (metric tons 
          CO2/metric tons CaO).
SRMgO = Stoichiometric ratio of CO2 and MgO for 
          magnesium carbonate (See Table S-1 of this subpart) (metric 
          tons CO2/metric tons MgO).
CaOwaste,i = Calcium oxide content for calcined lime 
          byproduct or waste type i that is not sold (metric tons CaO/
          metric ton lime).
MgOwaste,i = Magnesium oxide content for calcined lime 
          byproduct or waste type i that is not sold (metric tons MgO/
          metric ton lime).
Mwaste,i = Annual weight or mass of calcined byproducts or 
          wastes for lime type i that is not sold (tons).
2000/2205 = Conversion factor for tons to metric tons.

    (iv) You must calculate annual CO2 process emissions for 
all lime kilns using Equation S-4 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.076

Where:

ECO2 = Annual CO2 process emissions from lime 
          production from all lime kilns (metric tons/year).
EFLIME,i,n = Emission factor for lime type i produced, in 
          calendar month n (metric tons CO2/ton lime) from 
          Equation S-1 of this section.
MLIME,i,n = Weight or mass of lime type i produced in 
          calendar month n (tons).
EFLKD,i,n = Emission factor of calcined byproducts or wastes 
          sold for lime type i in calendar month n, (metric tons 
          CO2/ton byproduct or waste) from Equation S-2 of 
          this section.
MLKD,i,n = Monthly weight or mass of calcined byproducts or 
          waste sold (such as lime kiln dust, LKD) for lime type i in 
          calendar month n (tons).
Ewaste,i = Annual CO2 emissions for calcined lime 
          byproduct or waste type i that is not sold (metric tons 
          CO2) from Equation S-3 of this section.
t = Number of lime types produced
b = Number of calcined byproducts or wastes that are sold.
z = Number of calcined byproducts or wastes that are not sold.

    (v) Calculate and report under subpart C of this part (General 
Stationary Fuel Combustion Sources) the combustion CO2 
emissions from each lime kiln according to the applicable requirements 
in subpart C.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66464, Oct. 28, 2010; 
78 FR 71958, Nov. 29, 2013]

[[Page 804]]



Sec. 98.194  Monitoring and QA/QC requirements.

    (a) You must determine the total quantity of each type of lime 
product that is produced and each calcined byproduct or waste (such as 
lime kiln dust) that is sold. The quantities of each should be directly 
measured monthly with the same plant instruments used for accounting 
purposes, including but not limited to, calibrated weigh feeders, rail 
or truck scales, and barge measurements. The direct measurements of each 
lime product shall be reconciled annually with the difference in the 
beginning of and end of year inventories for these products, when 
measurements represent lime sold.
    (b) You must determine the annual quantity of each calcined 
byproduct or waste generated that is not sold by either direct 
measurement using the same instruments identified in paragraph (a) of 
this section or by using a calcined byproduct or waste generation rate.
    (c) You must determine the chemical composition (percent total CaO 
and percent total MgO) of each type of lime product that is produced and 
each type of calcined byproduct or waste sold according to paragraph 
(c)(1) or (2) of this section. You must determine the chemical 
composition of each type of lime product that is produced and each type 
of calcined byproduct or waste sold on a monthly basis. You must 
determine the chemical composition for each type of calcined byproduct 
or waste that is not sold on an annual basis.
    (1) ASTM C25-06 Standard Test Methods for Chemical Analysis of 
Limestone, Quicklime, and Hydrated Lime (incorporated by reference--see 
Sec. 98.7).
    (2) The National Lime Association's CO2 Emissions 
Calculation Protocol for the Lime Industry English Units Version, 
February 5, 2008 Revision-National Lime Association (incorporated by 
reference--see Sec. 98.7).
    (d) You must use the analysis of calcium oxide and magnesium oxide 
content of each lime product that is produced and that is collected 
during the same month as the production data in monthly calculations.
    (e) You must follow the quality assurance/quality control procedures 
(including documentation) in National Lime Association's CO2 
Emissions Calculation Protocol for the Lime Industry English Units 
Version, February 5, 2008 Revision--National Lime Association 
(incorporated by reference--see Sec. 98.7).

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66465, Oct. 28, 2010; 
78 FR 71958, Nov. 29, 2013]



Sec. 98.195  Procedures for estimating missing data.

    For the procedure in Sec. 98.193(b)(1), a complete record of all 
measured parameters used in the GHG emissions calculations is required 
(e.g., oxide content, quantity of lime products, etc.). Therefore, 
whenever a quality-assured value of a required parameter is unavailable, 
a substitute data value for the missing parameter shall be used in the 
calculations as specified in paragraphs (a) or (b) of this section. You 
must document and keep records of the procedures used for all such 
estimates.
    (a) For each missing value of the quantity of lime produced (by lime 
type), and quantity of calcined byproduct or waste produced and sold, 
the substitute data value shall be the best available estimate based on 
all available process data or data used for accounting purposes.
    (b) For missing values related to the CaO and MgO content, you must 
conduct a new composition test according to the standard methods in 
Sec. 98.194 (c)(1) or (c)(2).

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66465, Oct. 28, 2010; 
78 FR 71959, Nov. 29, 2013]



Sec. 98.196  Data reporting requirements.

    In addition to the information required by Sec. 98.3(c), each 
annual report must contain the information specified in paragraphs (a) 
or (b) of this section, as applicable.
    (a) If a CEMS is used to measure CO2 emissions, then you 
must report under this subpart the relevant information required by 
Sec. 98.36 and the information listed in paragraphs (a)(1) through (8) 
of this section.
    (1) Method used to determine the quantity of lime that is produced 
and quantity of lime that is sold.

[[Page 805]]

    (2) Method used to determine the quantity of calcined lime byproduct 
or waste sold.
    (3) Beginning and end of year inventories for each lime product that 
is produced, by type.
    (4) Beginning and end of year inventories for calcined lime 
byproducts or wastes sold, by type.
    (5) Annual amount of calcined lime byproduct or waste sold, by type 
(tons).
    (6) Annual amount of lime product sold, by type (tons).
    (7) Annual amount of calcined lime byproduct or waste that is not 
sold, by type (tons).
    (8) Annual amount of lime product not sold, by type (tons).
    (b) If a CEMS is not used to measure CO2 emissions, then 
you must report the information listed in paragraphs (b)(1) through (18) 
of this section.
    (1) Annual CO2 process emissions from all lime kilns 
combined (metric tons).
    (2)-(3) [Reserved]
    (4) Standard method used (ASTM or NLA testing method) to determine 
chemical compositions of each lime type produced and each calcined lime 
byproduct or waste type.
    (5)-(6) [Reserved]
    (7) Method used to determine the quantity of lime produced and/or 
lime sold.
    (8) [Reserved]
    (9) Method used to determine the quantity of calcined lime byproduct 
or waste sold.
    (10)-(12) [Reserved]
    (13) Beginning and end of year inventories for each lime product 
that is produced.
    (14) Beginning and end of year inventories for calcined lime 
byproducts or wastes sold.
    (15) Annual lime production capacity (tons) per facility.
    (16) Number of times in the reporting year that missing data 
procedures were followed to measure lime production (months) or the 
chemical composition of lime products sold (months).
    (17) Indicate whether CO2 was used on-site (i.e. for use 
in a purification process). If CO2 was used on-site, provide 
the information in paragraphs (b)(17)(i) and (ii) of this section.
    (i) The annual amount of CO2 captured for use in the on-
site process.
    (ii) The method used to determine the amount of CO2 
captured.
    (18) Annual quantity (tons) of lime product sold, by type.

[75 FR 66465, Oct. 28, 2010, as amended at 78 FR 71959, Nov. 29, 2013; 
79 FR 63792, Oct. 24, 2014]



Sec. 98.197  Records that must be retained.

    In addition to the records required by Sec. 98.3(g), you must 
retain the records specified in paragraphs (a) through (c) of this 
section.
    (a) Annual operating hours in calendar year.
    (b) Records of all analyses (e.g. chemical composition of lime 
products, by type) and calculations conducted.
    (c) Verification software records. You must keep a record of the 
file generated by the verification software specified in Sec. 98.5(b) 
for the applicable data specified in paragraphs (c)(1) through (9) of 
this section. Retention of this file satisfies the recordkeeping 
requirement for the data in paragraphs (c)(1) through (9) of this 
section.
    (1) Monthly calcium oxide content for each lime type, determined 
according to Sec. 98.194(c) (metric tons CaO/metric ton lime) (Equation 
S-1 of Sec. 98.193).
    (2) Monthly magnesium oxide content for each lime type, determined 
according to Sec. 98.194(c) (metric tons MgO/metric ton lime) (Equation 
S-1).
    (3) Monthly calcium oxide content for each calcined lime byproduct 
or waste type sold (metric tons CaO/metric ton lime) (Equation S-2 of 
Sec. 98.193).
    (4) Monthly magnesium oxide content for each calcined lime byproduct 
or waste type sold (metric tons MgO/metric ton lime) (Equation S-2).
    (5) Calcium oxide content for each calcined lime byproduct or waste 
type that is not sold (metric tons CaO/metric ton lime) (Equation S-3 of 
Sec. 98.193).
    (6) Magnesium oxide content for each calcined lime byproduct or 
waste type that is not sold (metric tons MgO/metric ton lime) (Equation 
S-3).
    (7) Annual weight or mass of calcined byproducts or wastes for lime 
type that is not sold (tons) (Equation S-3).

[[Page 806]]

    (8) Monthly weight or mass of each lime type produced (tons) 
(Equation S-4 of Sec. 98.193).
    (9) Monthly weight or mass of each calcined byproducts or wastes 
sold (tons) (Equation S-4).

[74 FR 56374, Oct. 30, 2009, as amended at 79 FR 63792, Oct. 24, 2014]



Sec. 98.198  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.



    Sec. Table S-1 to Subpart S of Part 98--Basic Parameters for the 
           Calculation of Emission Factors for Lime Production

------------------------------------------------------------------------
                                                          Stoichiometric
                        Variable                               ratio
------------------------------------------------------------------------
SRCaO...................................................         0.7848
SRMgO...................................................         1.0918
------------------------------------------------------------------------



                     Subpart T_Magnesium Production

    Source: 75 FR 39761, July 12, 2010, unless otherwise noted.



Sec. 98.200  Definition of source category.

    The magnesium production and processing source category consists of 
the following processes:
    (a) Any process in which magnesium metal is produced through 
smelting (including electrolytic smelting), refining, or remelting 
operations.
    (b) Any process in which molten magnesium is used in alloying, 
casting, drawing, extruding, forming, or rolling operations.



Sec. 98.201  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains a magnesium production process and the facility meets the 
requirements of either Sec. 98.2(a)(1) or (2).



Sec. 98.202  GHGs to report.

    (a) You must report emissions of the following gases in metric tons 
per year resulting from their use as cover gases or carrier gases in 
magnesium production or processing:
    (1) Sulfur hexafluoride (SF6).
    (2) HFC-134a.
    (3) The fluorinated ketone, FK 5-1-12.
    (4) Carbon dioxide (CO2).
    (5) Any other GHGs (as defined in Sec. 98.6).
    (b) You must report under subpart C of this part (General Stationary 
Fuel Combustion Sources) the CO2, N2O, and 
CH4 emissions from each combustion unit by following the 
requirements of subpart C.



Sec. 98.203  Calculating GHG emissions.

    (a) Calculate the mass of each GHG emitted from magnesium production 
or processing over the calendar year using either Equation T-1 or 
Equation T-2 of this section, as appropriate. Both of these equations 
equate emissions of cover gases or carrier gases to consumption of cover 
gases or carrier gases.
    (1) To estimate emissions of cover gases or carrier gases by 
monitoring changes in container masses and inventories, emissions of 
each cover gas or carrier gas shall be estimated using Equation T-1 of 
this section:
[GRAPHIC] [TIFF OMITTED] TR12JY10.000

Where:

EX = Emissions of each cover gas or carrier gas, X, in metric 
          tons over the reporting year.
IB,x = Inventory of each cover gas or carrier gas stored in 
          cylinders or other containers at the beginning of the year, 
          including heels, in kg.
IE,x = Inventory of each cover gas or carrier gas stored in 
          cylinders or other containers at the end of the year, 
          including heels, in kg.
AX = Acquisitions of each cover gas or carrier gas during the 
          year through purchases or other transactions, including heels 
          in cylinders or other containers returned to the magnesium 
          production or processing facility, in kg.
DX = Disbursements of each cover gas or carrier gas to 
          sources and locations outside

[[Page 807]]

          the facility through sales or other transactions during the 
          year, including heels in cylinders or other containers 
          returned by the magnesium production or processing facility to 
          the gas supplier, in kg.
0.001 = Conversion factor from kg to metric tons
X = Each cover gas or carrier gas that is a GHG.

    (2) To estimate emissions of cover gases or carrier gases by 
monitoring changes in the masses of individual containers as their 
contents are used, emissions of each cover gas or carrier gas shall be 
estimated using Equation T-2 of this section:
[GRAPHIC] [TIFF OMITTED] TR12JY10.001

Where:

EGHG = Emissions of each cover gas or carrier gas, X, over 
          the reporting year (metric tons).
Qp = The mass of the cover or carrier gas consumed (kg) over 
          the container-use period p, from Equation T-3 of this section.
n = The number of container-use periods in the year.
0.001 = Conversion factor from kg to metric tons.
X = Each cover gas or carrier gas that is a GHG.

    (b) For purposes of Equation T-2 of this section, the mass of the 
cover gas used over the period p for an individual container shall be 
estimated by using Equation T-3 of this section:
[GRAPHIC] [TIFF OMITTED] TR12JY10.002

Where:

Qp = The mass of the cover or carrier gas consumed (kg) over 
          the container-use period p (e.g., one month).
MB = The mass of the container's contents (kg) at the 
          beginning of period p.
ME = The mass of the container's contents (kg) at the end of 
          period p.
    (c) If a facility has mass flow controllers (MFC) and the capacity 
to track and record MFC measurements to estimate total gas usage, the 
mass of each cover or carrier gas monitored may be used as the mass of 
cover or carrier gas consumed (Qp), in kg for period p in 
Equation T-2 of this section.



Sec. 98.204  Monitoring and QA/QC requirements.

    (a) For calendar year 2011 monitoring, the facility may submit a 
request to the Administrator to use one or more best available 
monitoring methods as listed in Sec. 98.3(d)(1)(i) through (iv). The 
request must be submitted no later than October 12, 2010 and must 
contain the information in Sec. 98.3(d)(2)(ii). To obtain approval, the 
request must demonstrate to the Administrator's satisfaction that it is 
not reasonably feasible to acquire, install, and operate a required 
piece of monitoring equipment by January 1, 2011. The use of best 
available monitoring methods will not be approved beyond December 31, 
2011.
    (b) Emissions (consumption) of cover gases and carrier gases may be 
estimated by monitoring the changes in container weights and inventories 
using Equation T-1 of this subpart, by monitoring the changes in 
individual container weights as the contents of each container are used 
using Equations T-2 and T-3 of this subpart, or by monitoring the mass 
flow of the pure cover gas or carrier gas into the gas distribution 
system. Emissions must be estimated at least annually.
    (c) When estimating emissions by monitoring the mass flow of the 
pure cover gas or carrier gas into the gas distribution system, you must 
use gas flow meters, or mass flow controllers, with an accuracy of 1 
percent of full scale or better.
    (d) When estimating emissions using Equation T-1 of this subpart, 
you must ensure that all the quantities required by Equation T-1 of this 
subpart have been measured using scales or load cells with an accuracy 
of 1 percent of full scale or better, accounting for the tare weights of 
the containers. You may accept gas masses or weights provided by the gas 
supplier e.g., for the contents of containers containing new gas or for 
the heels remaining in containers returned to the gas supplier) if the 
supplier provides documentation verifying that accuracy standards are 
met; however you remain responsible for the accuracy of these masses or 
weights under this subpart.
    (e) When estimating emissions using Equations T-2 and T-3 of this 
subpart,

[[Page 808]]

you must monitor and record container identities and masses as follows:
    (1) Track the identities and masses of containers leaving and 
entering storage with check-out and check-in sheets and procedures. The 
masses of cylinders returning to storage shall be measured immediately 
before the cylinders are put back into storage.
    (2) Ensure that all the quantities required by Equations T-2 and T-3 
of this subpart have been measured using scales or load cells with an 
accuracy of 1 percent of full scale or better, accounting for the tare 
weights of the containers. You may accept gas masses or weights provided 
by the gas supplier e.g., for the contents of cylinders containing new 
gas or for the heels remaining in cylinders returned to the gas 
supplier) if the supplier provides documentation verifying that accuracy 
standards are met; however, you remain responsible for the accuracy of 
these masses or weights under this subpart.
    (f) All flowmeters, scales, and load cells used to measure 
quantities that are to be reported under this subpart shall be 
calibrated using calibration procedures specified by the flowmeter, 
scale, or load cell manufacturer. Calibration shall be performed prior 
to the first reporting year. After the initial calibration, 
recalibration shall be performed at the minimum frequency specified by 
the manufacturer.



Sec. 98.205  Procedures for estimating missing data.

    (a) A complete record of all measured parameters used in the GHG 
emission calculations is required. Therefore, whenever a quality-assured 
value of a required parameter is unavailable, a substitute data value 
for the missing parameter will be used in the calculations as specified 
in paragraph (b) of this section.
    (b) Replace missing data on the emissions of cover or carrier gases 
by multiplying magnesium production during the missing data period by 
the average cover or carrier gas usage rate from the most recent period 
when operating conditions were similar to those for the period for which 
the data are missing. Calculate the usage rate for each cover or carrier 
gas using Equation T-4 of this section:
[GRAPHIC] [TIFF OMITTED] TR12JY10.003

Where:

RGHG = The usage rate for a particular cover or carrier gas 
          over the period of comparable operation (metric tons gas/
          metric ton Mg).
CGHG = The consumption of that cover or carrier gas over the 
          period of comparable operation (kg).
Mg = The magnesium produced or fed into the process over the period of 
          comparable operation (metric tons).
0.001 = Conversion factor from kg to metric tons.

    (c) If the precise before and after weights are not available, it 
should be assumed that the container was emptied in the process (i.e., 
quantity purchased should be used, less heel).



Sec. 98.206  Data reporting requirements.

    In addition to the information required by Sec. 98.3(c), each 
annual report must include the following information at the facility 
level:
    (a) Emissions of each cover or carrier gas in metric tons.
    (b) Types of production processes at the facility (e.g., primary, 
secondary, die casting).
    (c) Amount of magnesium produced or processed in metric tons for 
each process type. This includes the output of primary and secondary 
magnesium production processes and the input to magnesium casting 
processes.
    (d) Cover and carrier gas flow rate (e.g., standard cubic feet per 
minute) for each production unit and composition in percent by volume.
    (e) For any missing data, you must report the length of time the 
data were missing for each cover gas or carrier gas, the method used to 
estimate emissions in their absence, and the quantity of emissions 
thereby estimated.
    (f) The annual cover gas usage rate for the facility for each cover 
gas, excluding the carrier gas (kg gas/metric ton Mg).
    (g) If applicable, an explanation of any change greater than 30 
percent in the facility's cover gas usage rate (e.g., installation of 
new melt protection technology or leak discovered in the

[[Page 809]]

cover gas delivery system that resulted in increased emissions).
    (h) A description of any new melt protection technologies adopted to 
account for reduced or increased GHG emissions in any given year.



Sec. 98.207  Records that must be retained.

    In addition to the records specified in Sec. 98.3(g), you must 
retain the following information at the facility level:
    (a) Check-out and weigh-in sheets and procedures for gas cylinders.
    (b) Accuracy certifications and calibration records for scales 
including the method or manufacturer's specification used for 
calibration.
    (c) Residual gas amounts (heel) in cylinders sent back to suppliers.
    (d) Records, including invoices, for gas purchases, sales, and 
disbursements for all GHGs.



Sec. 98.208  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part. Additionally, some sector-
specific definitions are provided below:
    Carrier gas means the gas with which cover gas is mixed to transport 
and dilute the cover gas thus maximizing its efficient use. Carrier 
gases typically include CO2, N2, and/or dry air.
    Cover gas means SF6, HFC-134a, fluorinated ketone (FK 5-
1-12) or other gas used to protect the surface of molten magnesium from 
rapid oxidation and burning in the presence of air. The molten magnesium 
may be the surface of a casting or ingot production operation or the 
surface of a crucible of molten magnesium that feeds a casting 
operation.



                Subpart U_Miscellaneous Uses of Carbonate



Sec. 98.210  Definition of the source category.

    (a) This source category includes any equipment that uses carbonates 
listed in Table U-1 in manufacturing processes that emit carbon dioxide. 
Table U-1 includes the following carbonates: limestone, dolomite, 
ankerite, magnesite, siderite, rhodochrosite, or sodium carbonate. 
Facilities are considered to emit CO2 if they consume at 
least 2,000 tons per year of carbonates heated to a temperature 
sufficient to allow the calcination reaction to occur.
    (b) This source category does not include equipment that uses 
carbonates or carbonate containing minerals that are consumed in the 
production of cement, glass, ferroalloys, iron and steel, lead, lime, 
phosphoric acid, pulp and paper, soda ash, sodium bicarbonate, sodium 
hydroxide, or zinc.
    (c) This source category does not include carbonates used in sorbent 
technology used to control emissions from stationary fuel combustion 
equipment. Emissions from carbonates used in sorbent technology are 
reported under 40 CFR 98, subpart C (Stationary Fuel Combustion 
Sources).



Sec. 98.211  Reporting threshold.

    You must report GHG emissions from miscellaneous uses of carbonate 
if your facility uses carbonates as defined in Sec. 98.210 of this 
subpart and the facility meets the requirements of either Sec. 
98.2(a)(1) or (a)(2).



Sec. 98.212  GHGs to report.

    You must report CO2 process emissions from all 
miscellaneous carbonate use at your facility as specified in this 
subpart.



Sec. 98.213  Calculating GHG emissions.

    You must determine CO2 process emissions from carbonate 
use in accordance with the procedures specified in either paragraphs (a) 
or (b) of this section.
    (a) Calculate the process emissions of CO2 using 
calcination fractions with Equation U-1 of this section.

[[Page 810]]

[GRAPHIC] [TIFF OMITTED] TR30OC09.077

Where:

ECO2 = Annual CO2 mass emissions from consumption 
          of carbonates (metric tons).
Mi = Annual mass of carbonate type i consumed (tons).
EFi = Emission factor for the carbonate type i, as specified 
          in Table U-1 to this subpart, metric tons CO2/
          metric ton carbonate consumed.
Fi = Fraction calcination achieved for each particular 
          carbonate type i (decimal fraction). As an alternative to 
          measuring the calcination fraction, a value of 1.0 can be 
          used.
n = Number of carbonate types.
2000/2205 = Conversion factor to convert tons to metric tons.

(b) Calculate the process emissions of CO2 using actual mass 
of output carbonates with Equation U-2 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.078

Where:

ECO2 = Annual CO2 mass emissions from consumption 
          of carbonates (metric tons).
Mk = Annual mass of input carbonate type k (tons).
EFk = Emission factor for the carbonate type k, as specified 
          in Table U-1 of this subpart (metric tons CO2/
          metric ton carbonate input).
Mj = Annual mass of output carbonate type j (tons).
EFj = Emission factor for the output carbonate type j, as 
          specified in Table U-1 of this subpart (metric tons 
          CO2/metric ton carbonate input).
m = Number of input carbonate types.
n = Number of output carbonate types.



Sec. 98.214  Monitoring and QA/QC requirements.

    (a) The annual mass of carbonate consumed (for Equation U-1 of this 
subpart) or carbonate inputs (for Equation U-2 of this subpart) must be 
determined annually from monthly measurements using the same plant 
instruments used for accounting purposes including purchase records or 
direct measurement, such as weigh hoppers or weigh belt feeders.
    (b) The annual mass of carbonate outputs (for Equation U-2 of this 
subpart) must be determined annually from monthly measurements using the 
same plant instruments used for accounting purposes including purchase 
records or direct measurement, such as weigh hoppers or belt weigh 
feeders.
    (c) If you follow the procedures of Sec. 98.213(a), as an 
alternative to assuming a calcination fraction of 1.0, you can determine 
on an annual basis the calcination fraction for each carbonate consumed 
based on sampling and chemical analysis using a suitable method such as 
using an x-ray fluorescence standard method or other enhanced industry 
consensus standard method published by an industry consensus standard 
organization (e.g., ASTM, ASME, etc.).



Sec. 98.215  Procedures for estimating missing data.

    (a) A complete record of all measured parameters used in the GHG 
emissions calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable, a substitute data 
value for the missing parameter shall be used in the calculations as 
specified in paragraph (b) of this section. You must document and keep 
records of the procedures used for all such estimates.
    (b) For each missing value of monthly carbonate consumed, monthly 
carbonate output, or monthly carbonate input, the substitute data value 
must be the best available estimate based on

[[Page 811]]

the all available process data or data used for accounting purposes.



Sec. 98.216  Data reporting requirements.

    In addition to the information required by Sec. 98.3(c), each 
annual report must contain the information specified in paragraphs (a) 
through (g) of this section at the facility level, as applicable.
    (a) Annual CO2 emissions from miscellaneous carbonate use 
(metric tons).
    (b) [Reserved]
    (c) Measurement method used to determine the mass of carbonate.
    (d) Method used to calculate emissions.
    (e) If you followed the calculation method of Sec. 98.213(b)(1)(i), 
you must report the information in paragraphs (e)(1) through (e)(3) of 
this section.
    (1)-(2) [Reserved]
    (3) If you determined the calcination fraction, indicate which 
standard method was used.
    (f) [Reserved]
    (g) Number of times in the reporting year that missing data 
procedures were followed to measure carbonate consumption, carbonate 
input or carbonate output (months).

[74 FR 56374, Oct. 30, 2009, as amended at 79 FR 63792, Oct. 24, 2014]



Sec. 98.217  Records that must be retained.

    In addition to the records required by Sec. 98.3(g), you must 
retain the records specified in paragraphs (a) through (e) of this 
section:
    (a) Monthly carbonate consumption (by carbonate type in tons).
    (b) You must document the procedures used to ensure the accuracy of 
the monthly measurements of carbonate consumption, carbonate input or 
carbonate output including, but not limited to, calibration of weighing 
equipment and other measurement devices.
    (c) Records of all analyses conducted to meet the requirements of 
this rule.
    (d) Records of all calculations conducted.
    (e) Verification software records. You must keep a record of the 
file generated by the verification software specified in Sec. 98.5(b) 
for the applicable data specified in paragraphs (e)(1) through (4) of 
this section. Retention of this file satisfies the recordkeeping 
requirement for the data in paragraphs (e)(1) through (4) of this 
section.
    (1) Fraction calcination achieved for each particular carbonate 
type. As an alternative to measuring the calcination fraction, a value 
of 1.0 can be used (decimal fraction) (Equation U-1 of Sec. 98.213).
    (2) Annual mass of each carbonate type consumed (tons) (Equation U-
1).
    (3) Annual mass of each input carbonate type (tons) (Equation U-2 of 
Sec. 98.213).
    (4) Annual mass of each output carbonate type (tons) (Equation U-2).

[74 FR 56374, Oct. 30, 2009, as amended at 79 FR 63793, Oct. 24, 2014]



Sec. 98.218  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.



Sec. Table U-1 to Subpart U of Part 98--CO2 Emission Factors 
                          for Common Carbonates

------------------------------------------------------------------------
                                                                 CO2
                                                               emission
                                                                factor
                  Mineral name--carbonate                     (tons CO2/
                                                                 ton
                                                              carbonate)
------------------------------------------------------------------------
Limestone--CaCO3...........................................      0.43971
Magnesite--MgCO3...........................................      0.52197
Dolomite--CaMg(CO3)2.......................................      0.47732
Siderite--FeCO3............................................      0.37987
Ankerite--Ca(Fe, Mg, Mn)(CO3)2.............................      0.47572
Rhodochrosite--MnCO3.......................................      0.38286
Sodium Carbonate/Soda Ash--Na2CO3..........................      0.41492
------------------------------------------------------------------------



                    Subpart V_Nitric Acid Production



Sec. 98.220  Definition of source category.

    A nitric acid production facility uses one or more trains to produce 
weak nitric acid (30 to 70 percent in strength). A nitric acid train 
produces weak nitric acid through the catalytic oxidation of ammonia.



Sec. 98.221  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains a nitric acid train and the facility meets the requirements of 
either Sec. 98.2(a)(1) or (a)(2).

[[Page 812]]



Sec. 98.222  GHGs to report.

    (a) You must report N2O process emissions from each 
nitric acid train as required by this subpart.
    (b) You must report under subpart C of this part (General Stationary 
Fuel Combustion Sources) the emissions of CO2, 
CH4, and N2O from each stationary combustion unit 
by following the requirements of subpart C.

[74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71959, Nov. 29, 2013]



Sec. 98.223  Calculating GHG emissions.

    (a) You must determine annual N2O process emissions from 
each nitric acid train according to paragraphs (a)(1) or (a)(2) of this 
section.
    (1) Use a site-specific emission factor and production data 
according to paragraphs (b) through (i) of this section.
    (2) Request Administrator approval for an alternative method of 
determining N2O emissions according to paragraphs (a)(2)(i) 
and (a)(2)(ii) of this section.
    (i) You must submit the request within 45 days following 
promulgation of this subpart or within the first 30 days of each 
subsequent reporting year.
    (ii) If the Administrator does not approve your requested 
alternative method within 150 days of the end of the reporting year, you 
must determine the N2O emissions for the current reporting 
period using the procedures specified in paragraph (a)(1) of this 
section.
    (b) You must conduct an annual performance test for each nitric acid 
train according to paragraphs (b)(1) through (3) of this section.
    (1) You must conduct the performance test at the absorber tail gas 
vent, referred to as the test point, for each nitric acid train 
according to Sec. 98.224(b) through (f). If multiple nitric acid trains 
exhaust to a common abatement technology and/or emission point, you must 
sample each process in the ducts before the emissions are combined, 
sample each process when only one process is operating, or sample the 
combined emissions when multiple processes are operating and base the 
site-specific emission factor on the combined production rate of the 
multiple nitric acid trains.
    (2) You must conduct the performance test under normal process 
operating conditions.
    (3) You must measure the production rate during the performance test 
and calculate the production rate for the test period in tons (100 
percent acid basis) per hour.
    (c) Using the results of the performance test in paragraph (b) of 
this section, you must calculate an average site-specific emission 
factor for each nitric acid train ``t'' according to Equation V-1 of 
this section:
[GRAPHIC] [TIFF OMITTED] TR28OC10.025

where:

EFN2Ot = Average site-specific N2O 
          emissions factor for nitric acid train ``t'' (lb 
          N2O/ton nitric acid produced, 100 percent acid 
          basis).
CN2O = N2O concentration for each test run during 
          the performance test (ppm N2O).
1.14 x 10-7 = Conversion factor (lb/dscf-ppm N2O).
Q = Volumetric flow rate of effluent gas for each test run during the 
          performance test (dscf/hr).
P = Production rate for each test run during the performance test (tons 
          nitric acid produced per hour, 100 percent acid basis).
n = Number of test runs.

    (d) If nitric acid train ``t'' exhausts to any N2O 
abatement technology ``N'', you must determine the destruction 
efficiency for each N2O abatement technology ``N'' according 
to paragraphs (d)(1), (2), or (3) of this section.
    (1) Use the manufacturer's specified destruction efficiency.

[[Page 813]]

    (2) Estimate the destruction efficiency through process knowledge. 
Examples of information that could constitute process knowledge include 
calculations based on material balances, process stoichiometry, or 
previous test results provided the results are still relevant to the 
current vent stream conditions. You must document how process knowledge 
(if applicable) was used to determine the destruction efficiency.
    (3) Calculate the destruction efficiency by conducting an additional 
performance test on the emissions stream following the N2O 
abatement technology.
    (e) If nitric acid train ``t'' exhausts to any N2O 
abatement technology ``N'', you must determine the annual amount of 
nitric acid produced on nitric acid train ``t'' while N2O 
abatement technology ``N'' is operating according to Sec. 98.224(f). 
Then you must calculate the abatement utilization factor for each 
N2O abatement technology ``N'' for each nitric acid train 
``t'' according to Equation V-2 of this section.
[GRAPHIC] [TIFF OMITTED] TR28OC10.026

where:

AFt,N = Abatement utilization factor of N2O 
          abatement technology ``N'' at nitric acid train ``t'' 
          (fraction of annual production that abatement technology is 
          operating).
Pt = Total annual nitric acid production from nitric acid 
          train ``t'' (ton acid produced, 100 percent acid basis).
Pt,N = Annual nitric acid production from nitric acid train 
          ``t'' during which N2O abatement technology ``N'' 
          was operational (ton acid produced, 100 percent acid basis).

    (f) [Reserved]
    (g) You must calculate N2O emissions for each nitric acid 
train ``t'' according to paragraph (g)(1), (g)(2), (g)(3), or (g)(4) of 
this section.
    (1) If nitric acid train ``t'' exhausts to one N2O 
abatement technology ``N'' after the test point, you must use the 
emissions factor (determined in Equation V-1 of this section), the 
destruction efficiency (determined in paragraph (d) of this section), 
the annual nitric acid production (determined in paragraph (i) of this 
section), and the abatement utilization factor (determined in paragraph 
(e) of this section) according to Equation V-3a of this section:
[GRAPHIC] [TIFF OMITTED] TR28OC10.027

where:

EN2Ot = Annual N2O mass emissions from 
          nitric acid train ``t'' according to this Equation V-3a 
          (metric tons).
EFN2Ot = Average site-specific N2O 
          emissions factor for nitric acid train ''t'' (lb 
          N2O/ton acid produced, 100 percent acid basis).
Pt = Annual nitric acid production from nitric acid train 
          ``t'' (ton acid produced, 100 percent acid basis).
DF = Destruction efficiency of N2O abatement technology N 
          that is used on nitric acid train ``t'' (decimal fraction of 
          N2O removed from vent stream).
AF = Abatement utilization factor of N2O abatement technology 
          ``N'' for nitric acid train ``t'' (decimal fraction of annual 
          production during which abatement technology is operating).
2205 = Conversion factor (lb/metric ton).

    (2) If multiple N2O abatement technologies are located in 
series after your test point, you must use the emissions factor 
(determined in Equation V-1 of this section), the destruction efficiency 
(determined in paragraph (d) of this section), the annual nitric acid 
production (determined in paragraph (i) of this section), and the 
abatement utilization factor (determined in paragraph (e) of this 
section), according to Equation V-3b of this section:

[[Page 814]]

[GRAPHIC] [TIFF OMITTED] TR28OC10.028

where:

EN2Ot = Annual N2O mass emissions from 
          nitric acid train ``t'' according to this Equation V-3b 
          (metric tons).
EFN2O,t = N2O emissions factor for nitric acid 
          train ``t'' (lb N2O/ton nitric acid produced).
Pt = Annual nitric acid produced from nitric acid train ``t'' 
          (ton acid produced, 100 percent acid basis).
DF1 = Destruction efficiency of N2O abatement 
          technology 1 (decimal fraction of N2O removed from 
          vent stream).
AF1 = Abatement utilization factor of N2O 
          abatement technology 1 (decimal fraction of time that 
          abatement technology 1 is operating).
DF2 = Destruction efficiency of N2O abatement 
          technology 2 (decimal fraction of N2O removed from 
          vent stream).
AF2 = Abatement utilization factor of N2O 
          abatement technology 2 (decimal fraction of time that 
          abatement technology 2 is operating).
DFN = Destruction efficiency of N2O abatement 
          technology N (decimal fraction of N2O removed from 
          vent stream).
AFN = Abatement utilization factor of N2O 
          abatement technology N (decimal fraction of time that 
          abatement technology N is operating).
2205 = Conversion factor (lb/metric ton).
N = Number of different N2O abatement technologies.

    (3) If multiple N2O abatement technologies are located in 
parallel after your test point, you must use the emissions factor 
(determined in Equation V-1 of this section), the destruction efficiency 
(determined in paragraph (d) of this section), the annual nitric acid 
production (determined in paragraph (i) of this section), and the 
abatement utilization factor (determined in paragraph (e) of this 
section), according to Equation V-3c of this section:
[GRAPHIC] [TIFF OMITTED] TR28OC10.029

where:

EN2Ot = Annual N2O mass emissions from 
          nitric acid train ``t'' according to this Equation V-3c 
          (metric tons).
EFN2O,t = N2O emissions factor for nitric acid 
          train ``t'' (lb N2O/ton nitric acid produced).
Pt = Annual nitric acid produced from nitric acid train ``t'' 
          (ton acid produced, 100 percent acid basis).
DFN = Destruction efficiency of N2O abatement 
          technology ``N'' (decimal fraction of N2O removed 
          from vent stream).
AFN = Abatement utilization factor of N2O 
          abatement technology ``N'' (decimal fraction of time that 
          abatement technology ``N'' is operating).
FCN = Fraction control factor of N2O abatement 
          technology ``N'' (decimal fraction of total emissions from 
          nitric acid train ``t'' that are sent to abatement technology 
          ``N'').
2205 = Conversion factor (lb/metric ton).
N = Number of different N2O abatement technologies with a 
          fraction control factor.

    (4) If nitric acid train ``t'' does not exhaust to any 
N2O abatement technology after the test point, you must use 
the emissions factor (determined in Equation V-1 of this section), and 
the annual nitric acid production (determined in paragraph (i) of this 
section) according to Equation V-3b of this section:
[GRAPHIC] [TIFF OMITTED] TR28OC10.030

where:

EN2Ot = Annual N2O mass emissions from 
          nitric acid train ``t'' according to this Equation V-3d 
          (metric tons).
EFN2Ot = Average site-specific N2O 
          emissions factor for nitric acid train ''t'' (lb 
          N2O/ton acid produced, 100 percent acid basis).
Pt = Annual nitric acid production from nitric acid train 
          ``t'' (ton acid produced, 100 percent acid basis).
2205 = Conversion factor (lb/metric ton).



[[Page 815]]


    (h) You must determine the annual nitric acid production emissions 
combined from all nitric acid trains at your facility using Equation V-4 
of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.082

Where:

N2O = Annual process N2O emissions from nitric 
          acid production facility (metric tons).
EN2Ot = N2O mass emissions per year for 
          nitric acid train ``t'' (metric tons).
m = Number of nitric acid trains.
    (i) You must determine the total annual amount of nitric acid 
produced on each nitric acid train ``t'' (tons acid produced, 100 
percent acid basis), according to Sec. 98.224(f).

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66466, Oct. 28, 2010; 
78 FR 71959, Nov. 29, 2013]



Sec. 98.224  Monitoring and QA/QC requirements.

    (a) You must conduct a new performance test according to a test plan 
as specified in paragraphs (a)(1) through (3) of this section.
    (1) Conduct the performance test annually. The test should be 
conducted at a point during the campaign which is representative of the 
average emissions rate from the nitric acid campaigns. Facilities must 
document the methods used to determine the representative point of the 
campaign when the performance test is conducted.
    (2) Conduct the performance test when your nitric acid production 
process is changed, specifically when abatement equipment is installed.
    (3) If you requested Administrator approval for an alternative 
method of determining N2O emissions under Sec. 98.223(a)(2), 
you must conduct the performance test if your request has not been 
approved by the Administrator within 150 days of the end of the 
reporting year in which it was submitted.
    (b) You must measure the N2O concentration during the 
performance test using one of the methods in paragraphs (b)(1) through 
(b)(3) of this section.
    (1) EPA Method 320 at 40 CFR part 63, appendix A, Measurement of 
Vapor Phase Organic and Inorganic Emissions by Extractive Fourier 
Transform Infrared (FTIR) Spectroscopy.
    (2) ASTM D6348-03 Standard Test Method for Determination of Gaseous 
Compounds by Extractive Direct Interface Fourier Transform Infrared 
(FTIR) Spectroscopy (incorporated by reference in Sec. 98.7).
    (3) An equivalent method, with Administrator approval.
    (c) You must determine the production rate(s) (100 percent acid 
basis) from each nitric acid train during the performance test according 
to paragraphs (c)(1) or (2) of this section.
    (1) Direct measurement of production and concentration (such as 
using flow meters, weigh scales, for production and concentration 
measurements).
    (2) Existing plant procedures used for accounting purposes (i.e. 
dedicated tank-level and acid concentration measurements).
    (d) You must determine the volumetric flow rate during the 
performance test in conjunction with the applicable EPA methods in 40 
CFR part 60, appendices A-1 through A-4. Conduct three emissions test 
runs of 1 hour each. All QA/QC procedures specified in the reference 
test methods and any associated performance specifications apply. For 
each test, the facility must prepare an emission factor determination 
report that must include the items in paragraphs (d)(1) through (d)(3) 
of this section.
    (1) Analysis of samples, determination of emissions, and raw data.
    (2) All information and data used to derive the emissions factor(s).
    (3) The production rate during each test and how it was determined.

[[Page 816]]

    (e) You must determine the total monthly amount of nitric acid 
produced. You must also determine the monthly amount of nitric acid 
produced while N2O abatement technology is operating from 
each nitric acid train. These monthly amounts are determined according 
to the methods in paragraphs (c)(1) or (2) of this section.
    (f) You must determine the annual amount of nitric acid produced. 
You must also determine the annual amount of nitric acid produced while 
N2O abatement technology is operating for each nitric acid 
train. These annual amounts are determined by summing the respective 
monthly nitric acid quantities determined in paragraph (e) of this 
section.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66467, Oct. 28, 2010; 
78 FR 71960, Nov. 29, 2013]



Sec. 98.225  Procedures for estimating missing data.

    A complete record of all measured parameters used in the GHG 
emissions calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable, a substitute data 
value for the missing parameter shall be used in the calculations as 
specified in paragraphs (a) and (b) of this section.
    (a) For each missing value of nitric acid production, the substitute 
data shall be the best available estimate based on all available process 
data or data used for accounting purposes (such as sales records).
    (b) For missing values related to the performance test, including 
emission factors, production rate, and N2O concentration, you 
must conduct a new performance test according to the procedures in Sec. 
98.224 (a) through (d).



Sec. 98.226  Data reporting requirements.

    In addition to the information required by Sec. 98.3(c), each 
annual report must contain the information specified in paragraphs (a) 
through (q) of this section.
    (a) Nitric Acid train identification number.
    (b) Annual process N2O emissions from each nitric acid 
train (metric tons).
    (c) [Reserved]
    (d) [Reserved]
    (e) Annual nitric acid production from the nitric acid facility 
(tons, 100 percent acid basis).
    (f) Number of nitric acid trains.
    (g) Number of different N2O abatement technologies per 
nitric acid train ``t''.
    (h) Abatement technologies used (if applicable).
    (i) [Reserved]
    (j) [Reserved]
    (k) Type of nitric acid process used for each nitric acid train 
(low, medium, high, or dual pressure).
    (l) Number of times in the reporting year that missing data 
procedures were followed to measure nitric acid production (months).
    (m) If you conducted a performance test and calculated a site-
specific emissions factor according to Sec. 98.223(a)(1), each annual 
report must also contain the information specified in paragraphs (m)(1) 
through (7) of this section.
    (1) [Reserved]
    (2) Test method used for performance test.
    (3)-(6) [Reserved]
    (7) Number of times in the reporting year that a performance test 
had to be repeated (number).
    (n) If you requested Administrator approval for an alternative 
method of determining N2O emissions under Sec. 98.223(a)(2), 
each annual report must also contain the information specified in 
paragraphs (n)(1) through (4) of this section.
    (1) Name of alternative method.
    (2) Description of alternative method.
    (3) Request date.
    (4) Approval date.
    (o) [Reserved]
    (p) [Reserved]
    (q) Annual percent N2O emission reduction for all nitric 
acid trains combined.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66468, Oct. 28, 2010; 
75 FR 79157, Dec. 17, 2010; 78 FR 71960, Nov. 29, 2013; 79 FR 63793, 
Oct. 24, 2014]



Sec. 98.227  Records that must be retained.

    In addition to the information required by Sec. 98.3(g), you must 
retain the records specified in paragraphs (a)

[[Page 817]]

through (h) of this section for each nitric acid production facility:
    (a) Records of significant changes to process.
    (b) Documentation of how process knowledge was used to estimate 
abatement technology destruction efficiency (if applicable).
    (c) Performance test reports.
    (d) Number of operating hours in the calendar year for each nitric 
acid train (hours).
    (e) Annual nitric acid permitted production capacity (tons).
    (f) Measurements, records, and calculations used to determine 
reported parameters.
    (g) Documentation of the procedures used to ensure the accuracy of 
the measurements of all reported parameters, including but not limited 
to, calibration of weighing equipment, flow meters, and other 
measurement devices. The estimated accuracy of measurements made with 
these devices must also be recorded, and the technical basis for these 
estimates must be provided.
    (h) Verification software records. You must keep a record of the 
file generated by the verification software specified in Sec. 98.5(b) 
for the applicable data specified in paragraphs (h)(1) through (10) of 
this section. Retention of this file satisfies the recordkeeping 
requirement for the data in paragraphs (h)(1) through (10) of this 
section.
    (1) Annual nitric acid produced from each nitric acid train (tons 
nitric acid produced, 100% acid basis).
    (2) Indicate which equation was used to calculate emissions for each 
nitric acid train.
    (3) N2O concentration per test run during the performance 
test (ppm N2O) (Equation V-1 of Sec. 98.223).
    (4) Volumetric flow rate of effluent gas per test run during the 
performance test (dscf/hr) (Equation V-1).
    (5) Production rate per test run during the performance test (tons 
nitric acid produced per hour, 100 percent acid basis) (Equation V-1).
    (6) Annual nitric acid production from each nitric acid train during 
which each N2O abatement technology was operational (tons 
nitric acid produced, 100 percent acid basis) (Equation V-2 of Sec. 
98.223).
    (7) Destruction efficiency of N2O abatement technology 
that is used on each nitric acid train (decimal fraction of 
N2O removed from vent stream) (Equation V-3a of Sec. 
98.223).
    (8) Destruction efficiency of each N2O abatement 
technology that is used on each nitric acid train (decimal fraction of 
N2O removed from vent stream) (Equation V-3b of Sec. 
98.223).
    (9) Destruction efficiency of each N2O abatement 
technology that is used on each nitric acid train (decimal fraction of 
N2O removed from vent stream) (Equation V-3c of Sec. 
98.223).
    (10) Fraction control factor of each N2O abatement 
technology that is used on each nitric acid train (decimal fraction of 
total emissions from nitric acid train ``t'' that are sent to abatement 
technology ``n'') (Equation V-3c).

[74 FR 56374, Oct. 30, 2009, as amended at 79 FR 63793, Oct. 24, 2014]



Sec. 98.228  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.



               Subpart W_Petroleum and Natural Gas Systems

    Source: 75 FR 74488, Nov. 30, 2010, unless otherwise noted.



Sec. 98.230  Definition of the source category.

    (a) This source category consists of the following industry 
segments:
    (1) Offshore petroleum and natural gas production. Offshore 
petroleum and natural gas production is any platform structure, affixed 
temporarily or permanently to offshore submerged lands, that houses 
equipment to extract hydrocarbons from the ocean or lake floor and that 
processes and/or transfers such hydrocarbons to storage, transport 
vessels, or onshore. In addition, offshore production includes secondary 
platform structures connected to the platform structure via walkways, 
storage tanks associated with the platform structure and floating 
production and storage offloading equipment (FPSO). This source category 
does not include reporting of emissions from offshore

[[Page 818]]

drilling and exploration that is not conducted on production platforms.
    (2) Onshore petroleum and natural gas production. Onshore petroleum 
and natural gas production means all equipment on a single well-pad or 
associated with a single well-pad (including but not limited to 
compressors, generators, dehydrators, storage vessels, engines, boilers, 
heaters, flares, separation and processing equipment, and portable non-
self-propelled equipment, which includes well drilling and completion 
equipment, workover equipment, and leased, rented or contracted 
equipment) used in the production, extraction, recovery, lifting, 
stabilization, separation or treating of petroleum and/or natural gas 
(including condensate). This equipment also includes associated storage 
or measurement vessels, all petroleum and natural gas production 
equipment located on islands, artificial islands, or structures 
connected by a causeway to land, an island, or an artificial island. 
Onshore petroleum and natural gas production also means all equipment on 
or associated with a single enhanced oil recovery (EOR) well pad using 
CO2 or natural gas injection.
    (3) Onshore natural gas processing. Natural gas processing means the 
separation of natural gas liquids (NGLs) or non-methane gases from 
produced natural gas, or the separation of NGLs into one or more 
component mixtures. Separation includes one or more of the following: 
forced extraction of natural gas liquids, sulfur and carbon dioxide 
removal, fractionation of NGLs, or the capture of CO2 
separated from natural gas streams. This segment also includes all 
residue gas compression equipment owned or operated by the natural gas 
processing plant. This industry segment includes processing plants that 
fractionate gas liquids, and processing plants that do not fractionate 
gas liquids but have an annual average throughput of 25 MMscf per day or 
greater.
    (4) Onshore natural gas transmission compression. Onshore natural 
gas transmission compression means any stationary combination of 
compressors that move natural gas from production fields, natural gas 
processing plants, or other transmission compressors through 
transmission pipelines to natural gas distribution pipelines, LNG 
storage facilities, or into underground storage. In addition, a 
transmission compressor station includes equipment for liquids 
separation, and tanks for the storage of water and hydrocarbon liquids. 
Residue (sales) gas compression that is part of onshore natural gas 
processing plants are included in the onshore natural gas processing 
segment and are excluded from this segment.
    (5) Underground natural gas storage. Underground natural gas storage 
means subsurface storage, including depleted gas or oil reservoirs and 
salt dome caverns that store natural gas that has been transferred from 
its original location for the primary purpose of load balancing (the 
process of equalizing the receipt and delivery of natural gas); natural 
gas underground storage processes and operations (including compression, 
dehydration and flow measurement, and excluding transmission pipelines); 
and all the wellheads connected to the compression units located at the 
facility that inject and recover natural gas into and from the 
underground reservoirs.
    (6) Liquefied natural gas (LNG) storage. LNG storage means onshore 
LNG storage vessels located above ground, equipment for liquefying 
natural gas, compressors to capture and re-liquefy boil-off-gas, re-
condensers, and vaporization units for re-gasification of the liquefied 
natural gas.
    (7) LNG import and export equipment. LNG import equipment means all 
onshore or offshore equipment that receives imported LNG via ocean 
transport, stores LNG, re-gasifies LNG, and delivers re-gasified natural 
gas to a natural gas transmission or distribution system. LNG export 
equipment means all onshore or offshore equipment that receives natural 
gas, liquefies natural gas, stores LNG, and transfers the LNG via ocean 
transportation to any location, including locations in the United 
States.
    (8) Natural gas distribution. Natural gas distribution means the 
distribution pipelines and metering and regulating

[[Page 819]]

equipment at metering-regulating stations that are operated by a Local 
Distribution Company (LDC) within a single state that is regulated as a 
separate operating company by a public utility commission or that is 
operated as an independent municipally-owned distribution system. This 
segment also excludes customer meters and regulators, infrastructure, 
and pipelines (both interstate and intrastate) delivering natural gas 
directly to major industrial users and farm taps upstream of the local 
distribution company inlet.
    (9) Onshore petroleum and natural gas gathering and boosting. 
Onshore petroleum and natural gas gathering and boosting means gathering 
pipelines and other equipment used to collect petroleum and/or natural 
gas from onshore production gas or oil wells and used to compress, 
dehydrate, sweeten, or transport the petroleum and/or natural gas to a 
natural gas processing facility, a natural gas transmission pipeline or 
to a natural gas distribution pipeline. Gathering and boosting equipment 
includes, but is not limited to gathering pipelines, separators, 
compressors, acid gas removal units, dehydrators, pneumatic devices/
pumps, storage vessels, engines, boilers, heaters, and flares. Gathering 
and boosting equipment does not include equipment reported under any 
other industry segment defined in this section. Gathering pipelines 
operating on a vacuum and gathering pipelines with a GOR) less than 300 
standard cubic feet per stock tank barrel (scf/STB) are not included in 
this industry segment (oil here refers to hydrocarbon liquids of all API 
gravities).
    (10) Onshore natural gas transmission pipeline. Onshore natural gas 
transmission pipeline means all natural gas transmission pipelines as 
defined in Sec. 98.238.
    (b) [Reserved]

[75 FR 74488, Nov. 30, 2010, as amended at 76 FR 80574, Dec. 23, 2011; 
79 FR 70385, Nov. 25, 2014; 80 FR 64283, Oct. 22, 2015]



Sec. 98.231  Reporting threshold.

    (a) You must report GHG emissions under this subpart if your 
facility contains petroleum and natural gas systems and the facility 
meets the requirements of Sec. 98.2(a)(2), except for the industry 
segments in paragraphs (a)(1) through (4) of this section.
    (1) Facilities must report emissions from the onshore petroleum and 
natural gas production industry segment only if emission sources 
specified in Sec. 98.232(c) emit 25,000 metric tons of CO2 
equivalent or more per year.
    (2) Facilities must report emissions from the natural gas 
distribution industry segment only if emission sources specified in 
Sec. 98.232(i) emit 25,000 metric tons of CO2 equivalent or 
more per year.
    (3) Facilities must report emissions from the onshore petroleum and 
natural gas gathering and boosting industry segment only if emission 
sources specified in Sec. 98.232(j) emit 25,000 metric tons of 
CO2 equivalent or more per year.
    (4) Facilities must report emissions from the onshore natural gas 
transmission pipeline industry segment only if emission sources 
specified in Sec. 98.232(m) emit 25,000 metric tons of CO2 
equivalent or more per year.
    (b) For applying the threshold defined in Sec. 98.2(a)(2), natural 
gas processing facilities must also include owned or operated residue 
gas compression equipment.

[75 FR 74488, Nov. 30, 2010, as amended at 80 FR 64284, Oct. 22, 2015]



Sec. 98.232  GHGs to report.

    (a) You must report CO2, CH4, and 
N2O emissions from each industry segment specified in 
paragraphs (b) through (j) and (m) of this section, CO2, 
CH4, and N2O emissions from each flare as 
specified in paragraphs (b) through (j) of this section, and stationary 
and portable combustion emissions as applicable as specified in 
paragraph (k) of this section.
    (b) For offshore petroleum and natural gas production, report 
CO2, CH4, and N2O emissions from 
equipment leaks, vented emission, and flare emission source types as 
identified in the data collection and emissions estimation study 
conducted by BOEMRE in compliance with 30 CFR 250.302 through 304. 
Offshore platforms do not need to report portable emissions.
    (c) For an onshore petroleum and natural gas production facility, 
report CO2, CH4, and N2O emissions from 
only

[[Page 820]]

the following source types on a single well-pad or associated with a 
single well-pad:
    (1) Natural gas pneumatic device venting.
    (2) [Reserved]
    (3) Natural gas driven pneumatic pump venting.
    (4) Well venting for liquids unloading.
    (5) Gas well venting during well completions without hydraulic 
fracturing.
    (6) Well venting during well completions with hydraulic fracturing 
that have a GOR of 300 scf/STB or greater (oil here refers to 
hydrocarbon liquids produced of all API gravities).
    (7) Gas well venting during well workovers without hydraulic 
fracturing.
    (8) Well venting during well workovers with hydraulic fracturing 
that have a GOR of 300 scf/STB or greater (oil here refers to 
hydrocarbon liquids produced of all API gravities).
    (9) Flare stack emissions.
    (10) Storage tanks vented emissions from produced hydrocarbons.
    (11) Reciprocating compressor venting.
    (12) Well testing venting and flaring.
    (13) Associated gas venting and flaring from produced hydrocarbons.
    (14) Dehydrator vents.
    (15) [Reserved]
    (16) EOR injection pump blowdown.
    (17) Acid gas removal vents.
    (18) EOR hydrocarbon liquids dissolved CO2.
    (19) Centrifugal compressor venting.
    (20) [Reserved]
    (21) Equipment leaks from valves, connectors, open ended lines, 
pressure relief valves, pumps, flanges, and other equipment leak sources 
(such as instruments, loading arms, stuffing boxes, compressor seals, 
dump lever arms, and breather caps).
    (22) You must use the methods in Sec. 98.233(z) and report under 
this subpart the emissions of CO2, CH4, and 
N2O from stationary or portable fuel combustion equipment 
that cannot move on roadways under its own power and drive train, and 
that is located at an onshore petroleum and natural gas production 
facility as defined in Sec. 98.238. Stationary or portable equipment 
are the following equipment, which are integral to the extraction, 
processing, or movement of oil or natural gas: well drilling and 
completion equipment, workover equipment, natural gas dehydrators, 
natural gas compressors, electrical generators, steam boilers, and 
process heaters.
    (d) For onshore natural gas processing, report CO2, 
CH4, and N2O emissions from the following sources:
    (1) Reciprocating compressor venting.
    (2) Centrifugal compressor venting.
    (3) Blowdown vent stacks.
    (4) Dehydrator vents.
    (5) Acid gas removal vents.
    (6) Flare stack emissions.
    (7) Equipment leaks from valves, connectors, open ended lines, 
pressure relief valves, and meters.
    (e) For onshore natural gas transmission compression, report 
CO2, CH4, and N2O emissions from the 
following sources:
    (1) Reciprocating compressor venting.
    (2) Centrifugal compressor venting.
    (3) Transmission storage tanks.
    (4) Blowdown vent stacks.
    (5) Natural gas pneumatic device venting.
    (6) Flare stack emissions.
    (7) Equipment leaks from valves, connectors, open ended lines, 
pressure relief valves, and meters.
    (f) For underground natural gas storage, report CO2, 
CH4, and N2O emissions from the following sources:
    (1) Reciprocating compressor venting.
    (2) Centrifugal compressor venting.
    (3) Natural gas pneumatic device venting.
    (4) Flare stack emissions.
    (5) Equipment leaks from valves, connectors, open ended lines, 
pressure relief valves, and meters.
    (g) For LNG storage, report CO2, CH4, and 
N2O emissions from the following sources:
    (1) Reciprocating compressor venting.
    (2) Centrifugal compressor venting.
    (3) Equipment leaks from valves; pump seals; connectors; vapor 
recovery compressors, and other equipment leak sources.
    (4) Flare stack emissions.

[[Page 821]]

    (h) LNG import and export equipment, report CO2, 
CH4, and N2O emissions from the following sources:
    (1) Reciprocating compressor venting.
    (2) Centrifugal compressor venting.
    (3) Blowdown vent stacks.
    (4) Equipment leaks from valves, pump seals, connectors, vapor 
recovery compressors, and other equipment leak sources.
    (5) Flare stack emissions.
    (i) For natural gas distribution, report CO2, 
CH4, and N2O emissions from the following sources:
    (1) Equipment leaks from connectors, block valves, control valves, 
pressure relief valves, orifice meters, regulators, and open-ended lines 
at above grade transmission-distribution transfer stations.
    (2) Equipment leaks at below grade transmission-distribution 
transfer stations.
    (3) Equipment leaks at above grade metering-regulating stations that 
are not above grade transmission-distribution transfer stations.
    (4) Equipment leaks at below grade metering-regulating stations.
    (5) Distribution main equipment leaks.
    (6) Distribution services equipment leaks.
    (7) Report under subpart W of this part the emissions of 
CO2, CH4, and N2O emissions from 
stationary fuel combustion sources following the methods in Sec. 
98.233(z).
    (j) For an onshore petroleum and natural gas gathering and boosting 
facility, report CO2, CH4, and N2O 
emissions from the following source types:
    (1) Natural gas pneumatic device venting.
    (2) Natural gas driven pneumatic pump venting.
    (3) Acid gas removal vents.
    (4) Dehydrator vents.
    (5) Blowdown vent stacks.
    (6) Storage tank vented emissions.
    (7) Flare stack emissions.
    (8) Centrifugal compressor venting.
    (9) Reciprocating compressor venting.
    (10) Equipment leaks from valves, connectors, open ended lines, 
pressure relief valves, pumps, flanges, and other equipment leak sources 
(such as instruments, loading arms, stuffing boxes, compressor seals, 
dump lever arms, and breather caps).
    (11) Gathering pipeline equipment leaks.
    (12) You must use the methods in Sec. 98.233(z) and report under 
this subpart the emissions of CO2, CH4, and 
N2O from stationary or portable fuel combustion equipment 
that cannot move on roadways under its own power and drive train, and 
that is located at an onshore petroleum and natural gas gathering and 
boosting facility as defined in Sec. 98.238. Stationary or portable 
equipment includes the following equipment, which are integral to the 
movement of natural gas: Natural gas dehydrators, natural gas 
compressors, electrical generators, steam boilers, and process heaters.
    (k) Report under subpart C of this part (General Stationary Fuel 
Combustion Sources) the emissions of CO2, CH4, and 
N2O from each stationary fuel combustion unit by following 
the requirements of subpart C except for facilities under onshore 
petroleum and natural gas production, onshore petroleum and natural gas 
gathering and boosting, and natural gas distribution. Onshore petroleum 
and natural gas production facilities must report stationary and 
portable combustion emissions as specified in paragraph (c) of this 
section. Natural gas distribution facilities must report stationary 
combustion emissions as specified in paragraph (i) of this section. 
Onshore petroleum and natural gas gathering and boosting facilities must 
report stationary and portable combustion emissions as specified in 
paragraph (j) of this section.
    (l) You must report under subpart PP of this part (Suppliers of 
Carbon Dioxide), CO2 emissions captured and transferred off 
site by following the requirements of subpart PP.
    (m) For onshore natural gas transmission pipeline, report pipeline 
blowdown CO2 and CH4 emissions from blowdown vent 
stacks.

[75 FR 74488, Nov. 30, 2010, as amended at 76 FR 80574, Dec. 23, 2011; 
79 FR 70385, Nov. 25, 2014; 80 FR 64284, Oct. 22, 2015]

[[Page 822]]



Sec. 98.233  Calculating GHG emissions.

    You must calculate and report the annual GHG emissions as prescribed 
in this section. For calculations that specify measurements in actual 
conditions, reporters may use a flow or volume measurement system that 
corrects to standard conditions and determine the flow or volume at 
standard conditions; otherwise, reporters must use average atmospheric 
conditions or typical operating conditions as applicable to the 
respective monitoring methods in this section.
    (a) Natural gas pneumatic device venting. Calculate CH4 
and CO2 volumetric emissions from continuous high bleed, 
continuous low bleed, and intermittent bleed natural gas pneumatic 
devices using Equation W-1 of this section.
[GRAPHIC] [TIFF OMITTED] TR25NO14.026

Where:

Es,i = Annual total volumetric GHG emissions at standard 
          conditions in standard cubic feet per year from natural gas 
          pneumatic device vents, of types ``t'' (continuous high bleed, 
          continuous low bleed, intermittent bleed), for 
          GHGi.
Countt = Total number of natural gas pneumatic devices of 
          type ``t'' (continuous high bleed, continuous low bleed, 
          intermittent bleed) as determined in paragraph (a)(1) or 
          (a)(2) of this section.
EFt = Population emission factors for natural gas pneumatic 
          device vents (in standard cubic feet per hour per device) of 
          each type ``t'' listed in Tables W-1A, W-3, and W-4 of this 
          subpart for onshore petroleum and natural gas production, 
          onshore natural gas transmission compression, and underground 
          natural gas storage facilities, respectively. Onshore 
          petroleum and natural gas gathering and boosting facilities 
          must use the population emission factors listed in Table W-1A 
          of this subpart.
GHGi = For onshore petroleum and natural gas production 
          facilities, onshore petroleum and natural gas gathering and 
          boosting facilities, onshore natural gas transmission 
          compression facilities, and underground natural gas storage 
          facilities, concentration of GHGi, CH4 
          or CO2, in produced natural gas or processed 
          natural gas for each facility as specified in paragraphs 
          (u)(2)(i), (iii), and (iv) of this section.
Tt = Average estimated number of hours in the operating year 
          the devices, of each type ``t'', were operational using 
          engineering estimates based on best available data. Default is 
          8,760 hours.


    (1) For all industry segments, determine ``Countt'' for 
Equation W-1 of this subpart for each type of natural gas pneumatic 
device (continuous high bleed, continuous low bleed, and intermittent 
bleed) by counting the devices, except as specified in paragraph (a)(2) 
of this section. The reported number of devices must represent the total 
number of devices for the reporting year.
    (2) For the onshore petroleum and natural gas production industry 
segment, you have the option in the first two consecutive calendar years 
to determine ``Countt'' for Equation W-1 of this section for 
each type of natural gas pneumatic device (continuous high bleed, 
continuous low bleed, and intermittent bleed) using engineering 
estimates based on best available data. For the onshore petroleum and 
natural gas gathering and boosting industry segment, you have the option 
in the first two consecutive calendar years to determine 
``Countt'' for Equation W-1 for each type of natural gas 
pneumatic device (continuous high bleed, continuous low bleed, and 
intermittent bleed) using engineering estimates based on best available 
data.
    (3) For all industry segments, determine the type of pneumatic 
device using engineering estimates based on best available information.
    (4) Calculate both CH4 and CO2 mass emissions 
from volumetric emissions using calculations in paragraph (v) of this 
section.
    (b) [Reserved]
    (c) Natural gas driven pneumatic pump venting. (1) Calculate 
CH4 and CO2 volumetric emissions from natural gas 
driven pneumatic pump venting using Equation W-2 of this section. 
Natural

[[Page 823]]

gas driven pneumatic pumps covered in paragraph (e) of this section do 
not have to report emissions under this paragraph (c).
[GRAPHIC] [TIFF OMITTED] TR25NO14.059

Where:

Es,i = Annual total volumetric GHG emissions at standard 
          conditions in standard cubic feet per year from all natural 
          gas driven pneumatic pump venting, for GHGi.
Count = Total number of natural gas driven pneumatic pumps.
EF = Population emissions factors for natural gas driven pneumatic pumps 
          (in standard cubic feet per hour per pump) listed in Table W-
          1A of this subpart for onshore petroleum and natural gas 
          production and onshore petroleum and natural gas gathering and 
          boosting facilities.
GHGi = Concentration of GHGi, CH4, or 
          CO2, in produced natural gas as defined in 
          paragraph (u)(2)(i) of this section.
T = Average estimated number of hours in the operating year the pumps 
          were operational using engineering estimates based on best 
          available data. Default is 8,760 hours.

    (2) Calculate both CH4 and CO2 mass emissions 
from volumetric emissions using calculations in paragraph (v) of this 
section.
    (d) Acid gas removal (AGR) vents. For AGR vents (including processes 
such as amine, membrane, molecular sieve or other absorbents and 
adsorbents), calculate emissions for CO2 only (not 
CH4) vented directly to the atmosphere or emitted through a 
flare, engine (e.g., permeate from a membrane or de-adsorbed gas from a 
pressure swing adsorber used as fuel supplement), or sulfur recovery 
plant, using any of the calculation methods described in this paragraph 
(d), as applicable.
    (1) Calculation Method 1. If you operate and maintain a continuous 
emissions monitoring system (CEMS) that has both a CO2 
concentration monitor and volumetric flow rate monitor, you must 
calculate CO2 emissions under this subpart by following the 
Tier 4 Calculation Method and all associated calculation, quality 
assurance, reporting, and recordkeeping requirements for Tier 4 in 
subpart C of this part (General Stationary Fuel Combustion Sources). 
Alternatively, you may follow the manufacturer's instructions or 
industry standard practice. If a CO2 concentration monitor 
and volumetric flow rate monitor are not available, you may elect to 
install a CO2 concentration monitor and a volumetric flow 
rate monitor that comply with all of the requirements specified for the 
Tier 4 Calculation Method in subpart C of this part (General Stationary 
Fuel Combustion Sources). The calculation and reporting of 
CH4 and N2O emissions is not required as part of 
the Tier 4 requirements for AGR units.
    (2) Calculation Method 2. If a CEMS is not available but a vent 
meter is installed, use the CO2 composition and annual volume 
of vent gas to calculate emissions using Equation W-3 of this section.
[GRAPHIC] [TIFF OMITTED] TR25NO14.060

Where:

Ea,CO2 = Annual volumetric CO2 emissions at actual 
          conditions, in cubic feet per year.
VS = Total annual volume of vent gas flowing out of the AGR 
          unit in cubic feet per year at actual conditions as determined 
          by flow meter using methods set forth in Sec. 98.234(b). 
          Alternatively, you may follow the manufacturer's instructions 
          or industry standard practice for calibration of the vent 
          meter.
VolCO2 = Annual average volumetric fraction of CO2 
          content in vent gas flowing out of the AGR unit as determined 
          in paragraph (d)(6) of this section.

    (3) Calculation Method 3. If a CEMS or a vent meter is not 
installed, you may use the inlet or outlet gas flow rate of

[[Page 824]]

the acid gas removal unit to calculate emissions for CO2 
using Equations W-4A or W-4B of this section. If inlet gas flow rate is 
known, use Equation W-4A. If outlet gas flow rate is known, use Equation 
W-4B.
[GRAPHIC] [TIFF OMITTED] TR25NO14.027

Where:

Ea, CO2 = Annual volumetric CO2 emissions at 
          actual conditions, in cubic feet per year.
Vin = Total annual volume of natural gas flow into the AGR 
          unit in cubic feet per year at actual conditions as determined 
          using methods specified in paragraph (d)(5) of this section.
Vout = Total annual volume of natural gas flow out of the AGR 
          unit in cubic feet per year at actual conditions as determined 
          using methods specified in paragraph (d)(5) of this section.
VolI = Annual average volumetric fraction of CO2 
          content in natural gas flowing into the AGR unit as determined 
          in paragraph (d)(7) of this section.
Volo = Annual average volumetric fraction of CO2 
          content in natural gas flowing out of the AGR unit as 
          determined in paragraph (d)(8) of this section.

    (4) Calculation Method 4. If CEMS or a vent meter is not installed, 
you may calculate emissions using any standard simulation software 
package, such as AspenTech HYSYS[supreg], or API 4679 AMINECalc, that 
uses the Peng-Robinson equation of state and speciates CO2 
emissions. A minimum of the following, determined for typical operating 
conditions over the calendar year by engineering estimate and process 
knowledge based on best available data, must be used to characterize 
emissions:
    (i) Natural gas feed temperature, pressure, and flow rate.
    (ii) Acid gas content of feed natural gas.
    (iii) Acid gas content of outlet natural gas.
    (iv) Unit operating hours, excluding downtime for maintenance or 
standby.
    (v) Exit temperature of natural gas.
    (vi) Solvent pressure, temperature, circulation rate, and weight.
    (5) For Calculation Method 3, determine the gas flow rate of the 
inlet when using Equation W-4A of this section or the gas flow rate of 
the outlet when using Equation W-4B of this section for the natural gas 
stream of an AGR unit using a meter according to methods set forth in 
Sec. 98.234(b). If you do not have a continuous flow meter, either 
install a continuous flow meter or use an engineering calculation to 
determine the flow rate.
    (6) For Calculation Method 2, if a continuous gas analyzer is not 
available on the vent stack, either install a continuous gas analyzer or 
take quarterly gas samples from the vent gas stream for each quarter 
that the AGR unit is operating to determine VolCO2 in 
Equation W-3 of this section, according to the methods set forth in 
Sec. 98.234(b).
    (7) For Calculation Method 3, if a continuous gas analyzer is 
installed on the inlet gas stream, then the continuous gas analyzer 
results must be used. If a continuous gas analyzer is not available, 
either install a continuous gas analyzer or take quarterly gas samples 
from the inlet gas stream for each quarter that the AGR unit is 
operating to determine VolI in Equation W-4A or W-4B of this 
section, according to the methods set forth in Sec. 98.234(b).
    (8) For Calculation Method 3, determine annual average volumetric 
fraction of CO2 content in natural gas flowing out of the AGR 
unit using one of the methods specified in paragraphs (d)(8)(i) through 
(d)(8)(iii) of this section.

[[Page 825]]

    (i) If a continuous gas analyzer is installed on the outlet gas 
stream, then the continuous gas analyzer results must be used. If a 
continuous gas analyzer is not available, you may install a continuous 
gas analyzer.
    (ii) If a continuous gas analyzer is not available or installed, 
quarterly gas samples may be taken from the outlet gas stream for each 
quarter that the AGR unit is operating to determine VolO in 
Equation W-4A or W-4B of this section, according to the methods set 
forth in Sec. 98.234(b).
    (iii) If a continuous gas analyzer is not available or installed, 
you may use the outlet pipeline quality specification for CO2 
in natural gas.
    (9) Calculate annual volumetric CO2 emissions at standard 
conditions using calculations in paragraph (t) of this section.
    (10) Calculate annual mass CO2 emissions using 
calculations in paragraph (v) of this section.
    (11) Determine if CO2 emissions from the AGR unit are 
recovered and transferred outside the facility. Adjust the 
CO2 emissions estimated in paragraphs (d)(1) through (d)(10) 
of this section downward by the magnitude of CO2 emissions 
recovered and transferred outside the facility.
    (e) Dehydrator vents. For dehydrator vents, calculate annual 
CH4 and CO2 emissions using the applicable 
calculation methods described in paragraphs (e)(1) through (e)(4) of 
this section. If emissions from dehydrator vents are routed to a vapor 
recovery system, you must adjust the emissions downward according to 
paragraph (e)(5) of this section. If emissions from dehydrator vents are 
routed to a flare or regenerator fire-box/fire tubes, you must calculate 
CH4, CO2, and N2O annual emissions as 
specified in paragraph (e)(6) of this section.
    (1) Calculation Method 1. Calculate annual mass emissions from 
glycol dehydrators that have an annual average of daily natural gas 
throughput that is greater than or equal to 0.4 million standard cubic 
feet per day by using a software program, such as AspenTech 
HYSYS[supreg] or GRI-GLYCalc \TM\, that uses the Peng-Robinson equation 
of state to calculate the equilibrium coefficient, speciates 
CH4 and CO2 emissions from dehydrators, and has 
provisions to include regenerator control devices, a separator flash 
tank, stripping gas and a gas injection pump or gas assist pump. The 
following parameters must be determined by engineering estimate based on 
best available data and must be used at a minimum to characterize 
emissions from dehydrators:
    (i) Feed natural gas flow rate.
    (ii) Feed natural gas water content.
    (iii) Outlet natural gas water content.
    (iv) Absorbent circulation pump type (e.g., natural gas pneumatic/
air pneumatic/electric).
    (v) Absorbent circulation rate.
    (vi) Absorbent type (e.g., triethylene glycol (TEG), diethylene 
glycol (DEG) or ethylene glycol (EG)).
    (vii) Use of stripping gas.
    (viii) Use of flash tank separator (and disposition of recovered 
gas).
    (ix) Hours operated.
    (x) Wet natural gas temperature and pressure.
    (xi) Wet natural gas composition. Determine this parameter using one 
of the methods described in paragraphs (e)(1)(xi)(A) through (D) of this 
section.
    (A) Use the GHG mole fraction as defined in paragraph (u)(2)(i) or 
(ii) of this section.
    (B) If the GHG mole fraction cannot be determined using paragraph 
(u)(2)(i) or (ii) of this section, select a representative analysis.
    (C) You may use an appropriate standard method published by a 
consensus-based standards organization if such a method exists or you 
may use an industry standard practice as specified in Sec. 98.234(b) to 
sample and analyze wet natural gas composition.
    (D) If only composition data for dry natural gas is available, 
assume the wet natural gas is saturated.
    (2) Calculation Method 2. Calculate annual volumetric emissions from 
glycol dehydrators that have an annual average of daily natural gas 
throughput that is less than 0.4 million standard cubic feet per day 
using Equation W-5 of this section:

[[Page 826]]

[GRAPHIC] [TIFF OMITTED] TR25NO14.061

Where:

Es,i = Annual total volumetric GHG emissions (either 
          CO2 or CH4) at standard conditions in 
          cubic feet.
EFi = Population emission factors for glycol dehydrators in 
          thousand standard cubic feet per dehydrator per year. Use 73.4 
          for CH4 and 3.21 for CO2 at 60  deg.F 
          and 14.7 psia.
Count = Total number of glycol dehydrators that have an annual average 
          of daily natural gas throughput that is less than 0.4 million 
          standard cubic feet per day.
1000 = Conversion of EFi in thousand standard cubic feet to 
          standard cubic feet.

    (3) Calculation Method 3. For dehydrators of any size that use 
desiccant, you must calculate emissions from the amount of gas vented 
from the vessel when it is depressurized for the desiccant refilling 
process using Equation W-6 of this section. Desiccant dehydrator 
emissions covered in this paragraph do not have to be calculated 
separately using the method specified in paragraph (i) of this section 
for blowdown vent stacks.
[GRAPHIC] [TIFF OMITTED] TR25NO14.028

Where:

Es,n = Annual natural gas emissions at standard conditions in 
          cubic feet.
H = Height of the dehydrator vessel (ft).
D = Inside diameter of the vessel (ft).
P1 = Atmospheric pressure (psia).
P2 = Pressure of the gas (psia).
[pi] = pi (3.14).
%G = Percent of packed vessel volume that is gas.
N = Number of dehydrator openings in the calendar year.
100 = Conversion of %G to fraction.

    (4) For glycol dehydrators that use the calculation method in 
paragraph (e)(2) of this section, calculate both CH4 and 
CO2 mass emissions from volumetric GHGi emissions 
using calculations in paragraph (v) of this section. For desiccant 
dehydrators that use the calculation method in paragraph (e)(3) of this 
section, calculate both CH4 and CO2 volumetric and 
mass emissions from volumetric natural gas emissions using calculations 
in paragraphs (u) and (v) of this section.
    (5) Determine if the dehydrator unit has vapor recovery. Adjust the 
emissions estimated in paragraphs (e)(1), (2), and (3) of this section 
downward by the magnitude of emissions recovered using a vapor recovery 
system as determined by engineering estimate based on best available 
data.
    (6) Calculate annual emissions from dehydrator vents to flares or 
regenerator fire-box/fire tubes as follows:
    (i) Use the dehydrator vent volume and gas composition as determined 
in paragraphs (e)(1) through (5) of this section, as applicable.
    (ii) Use the calculation method of flare stacks in paragraph (n) of 
this section to determine dehydrator vent emissions from the flare or 
regenerator combustion gas vent.
    (f) Well venting for liquids unloadings. Calculate annual volumetric 
natural gas emissions from well venting for liquids unloading using one 
of the calculation methods described in paragraphs (f)(1), (2), or (3) 
of this section. Calculate annual CH4 and CO2 
volumetric and mass emissions using the method described in paragraph 
(f)(4) of this section.
    (1) Calculation Method 1. Calculate emissions from wells with 
plunger lifts and wells without plunger lifts separately. For at least 
one well of each unique well tubing diameter group and pressure group 
combination in each sub-basin category (see Sec. 98.238 for the 
definitions of tubing diameter group, pressure group, and sub-basin 
category), where gas wells are vented to

[[Page 827]]

the atmosphere to expel liquids accumulated in the tubing, install a 
recording flow meter on the vent line used to vent gas from the well 
(e.g., on the vent line off the wellhead separator or atmospheric 
storage tank) according to methods set forth in Sec. 98.234(b). 
Calculate the total emissions from well venting to the atmosphere for 
liquids unloading using Equation W-7A of this section. For any tubing 
diameter group and pressure group combination in a sub-basin where 
liquids unloading occurs both with and without plunger lifts, Equation 
W-7A will be used twice, once for wells with plunger lifts and once for 
wells without plunger lifts.
[GRAPHIC] [TIFF OMITTED] TR25NO14.029


Where:

Ea = Annual natural gas emissions for all wells of the same 
          tubing diameter group and pressure group combination in a sub-
          basin at actual conditions, a, in cubic feet. Calculate 
          emission from wells with plunger lifts and wells without 
          plunger lifts separately.
h = Total number of wells of the same tubing diameter group and pressure 
          group combination in a sub-basin either with or without 
          plunger lifts.
p = Wells 1 through h of the same tubing diameter group and pressure 
          group combination in a sub-basin.
Tp = Cumulative amount of time in hours of venting for each 
          well, p, of the same tubing diameter group and pressure group 
          combination in a sub-basin during the year. If the available 
          venting data do not contain a record of the date of the 
          venting events and data are not available to provide the 
          venting hours for the specific time period of January 1 to 
          December 31, you may calculate an annualized vent time, 
          Tp, using Equation W-7B of this section.
FR = Average flow rate in cubic feet per hour for all measured wells of 
          the same tubing diameter group and pressure group combination 
          in a sub-basin, over the duration of the liquids unloading, 
          under actual conditions as determined in paragraph (f)(1)(i) 
          of this section.
          [GRAPHIC] [TIFF OMITTED] TR25NO14.030
          

 Where:

HRp = Cumulative amount of time in hours of venting for each 
          well, p, during the monitoring period.
MPp = Time period, in days, of the monitoring period for each 
          well, p. A minimum of 300 days in a calendar year are 
          required. The next period of data collection must start 
          immediately following the end of data collection for the 
          previous reporting year.
Dp = Time period, in days during which the well, p, was in 
          production (365 if the well was in production for the entire 
          year).

    (i) Determine the well vent average flow rate (``FR'' in Equation W-
7A of this section) as specified in paragraphs (f)(1)(i)(A) through (C) 
of this section for at least one well in a unique well tubing diameter 
group and pressure group combination in each sub-basin category. 
Calculate emissions from wells with plunger lifts and wells without 
plunger lifts separately.
    (A) Calculate the average flow rate per hour of venting for each 
unique tubing diameter group and pressure group combination in each sub-
basin category by dividing the recorded total annual flow by the 
recorded time (in hours) for all measured liquid unloading events with 
venting to the atmosphere.
    (B) Apply the average hourly flow rate calculated under paragraph 
(f)(1)(i)(A) of this section to all wells in the same pressure group 
that have the

[[Page 828]]

same tubing diameter group, for the number of hours of venting these 
wells.
    (C) Calculate a new average flow rate every other calendar year 
starting with the first calendar year of data collection. For a new 
producing sub-basin category, calculate an average flow rate beginning 
in the first year of production.
    (ii) Calculate natural gas volumetric emissions at standard 
conditions using calculations in paragraph (t) of this section.
    (2) Calculation Method 2. Calculate the total emissions for each 
sub-basin from well venting to the atmosphere for liquids unloading 
without plunger lift assist using Equation W-8 of this section.
[GRAPHIC] [TIFF OMITTED] TR25NO14.031


Where:

Es = Annual natural gas emissions for each sub-basin at 
          standard conditions, s, in cubic feet per year.
W = Total number of wells with well venting for liquids unloading for 
          each sub-basin.
p = Wells 1 through W with well venting for liquids unloading for each 
          sub-basin.
Vp = Total number of unloading events in the monitoring 
          period per well, p.
0.37 x 10-3 = {{3.14 (pi)/4}/{14.7*144} (psia converted to 
          pounds per square feet).
CDp = Casing internal diameter for each well, p, in inches.
WDp = Well depth from either the top of the well or the 
          lowest packer to the bottom of the well, for each well, p, in 
          feet.
SPp = For each well, p, shut-in pressure or surface pressure 
          for wells with tubing production, or casing pressure for each 
          well with no packers, in pounds per square inch absolute 
          (psia). If casing pressure is not available for each well, you 
          may determine the casing pressure by multiplying the tubing 
          pressure of each well with a ratio of casing pressure to 
          tubing pressure from a well in the same sub-basin for which 
          the casing pressure is known. The tubing pressure must be 
          measured during gas flow to a flow-line. The shut-in pressure, 
          surface pressure, or casing pressure must be determined just 
          prior to liquids unloading when the well production is impeded 
          by liquids loading or closed to the flow-line by surface 
          valves.
SFRp = Average flow-line rate of gas for well, p, at standard 
          conditions in cubic feet per hour. Use Equation W-33 of this 
          section to calculate the average flow-line rate at standard 
          conditions.
HRp,q = Hours that each well, p, was left open to the 
          atmosphere during each unloading event, q.
1.0 = Hours for average well to blowdown casing volume at shut-in 
          pressure.
q = Unloading event.
Zp,q = If HRp,q is less than 1.0 then 
          Zp,q is equal to 0. If HRp,q is greater 
          than or equal to 1.0 then Zp,q is equal to 1.

    (3) Calculation Method 3. Calculate the total emissions for each 
sub-basin from well venting to the atmosphere for liquids unloading with 
plunger lift assist using Equation W-9 of this section.
[GRAPHIC] [TIFF OMITTED] TR25NO14.032


Where:

Es = Annual natural gas emissions for each sub-basin at 
          standard conditions, s, in cubic feet per year.
W = Total number of wells with plunger lift assist and well venting for 
          liquids unloading for each sub-basin.
p = Wells 1 through W with well venting for liquids unloading for each 
          sub-basin.
Vp = Total number of unloading events in the monitoring 
          period for each well, p.
0.37 x 10-3 = {3.14 (pi)/4}/{14.7*144} (psia converted to 
          pounds per square feet).
TDp = Tubing internal diameter for each well, p, in inches.
WDp = Tubing depth to plunger bumper for each well, p, in 
          feet.
SPp = Flow-line pressure for each well, p, in pounds per 
          square inch absolute (psia),

[[Page 829]]

          using engineering estimate based on best available data.
SFRp = Average flow-line rate of gas for well, p, at standard 
          conditions in cubic feet per hour. Use Equation W-33 of this 
          section to calculate the average flow-line rate at standard 
          conditions.
HRp,q = Hours that each well, p, was left open to the 
          atmosphere during each unloading event, q.
0.5 = Hours for average well to blowdown tubing volume at flow-line 
          pressure.
q = Unloading event.
Zp,q = If HRp,q is less than 0.5 then 
          Zp,q is equal to 0. If HRp,q is greater 
          than or equal to 0.5 then Zp,q is equal to 1.

    (4) Calculate CH4 and CO2 volumetric and mass 
emissions from volumetric natural gas emissions using calculations in 
paragraphs (u) and (v) of this section.
    (g) Well venting during completions and workovers with hydraulic 
fracturing. Calculate annual volumetric natural gas emissions from gas 
well and oil well venting during completions and workovers involving 
hydraulic fracturing using Equation W-10A or Equation W-10B of this 
section. Equation W-10A applies to well venting when the gas flowback 
rate is measured from a specified number of example completions or 
workovers and Equation W-10B applies when the gas flowback vent or flare 
volume is measured for each completion or workover. Completion and 
workover activities are separated into two periods, an initial period 
when flowback is routed to open pits or tanks and a subsequent period 
when gas content is sufficient to route the flowback to a separator or 
when the gas content is sufficient to allow measurement by the devices 
specified in paragraph (g)(1) of this section, regardless of whether a 
separator is actually utilized. If you elect to use Equation W-10A, you 
must follow the procedures specified in paragraph (g)(1). If you elect 
to use Equation W-10B, you must use a recording flow meter installed on 
the vent line, downstream of a separator and ahead of a flare or vent, 
to measure the gas flowback. For either equation, emissions must be 
calculated separately for completions and workovers, for each sub-basin, 
and for each well type combination identified in paragraph (g)(2) of 
this section. You must calculate CH4 and CO2 
volumetric and mass emissions as specified in paragraph (g)(3) of this 
section. If emissions from well venting during completions and workovers 
with hydraulic fracturing are routed to a flare, you must calculate 
CH4, CO2, and N2O annual emissions as 
specified in paragraph (g)(4) of this section.
[GRAPHIC] [TIFF OMITTED] TR22OC15.007

Where:

Es,n = Annual volumetric natural gas emissions in standard 
          cubic feet from gas venting during well completions or 
          workovers following hydraulic fracturing for each sub-basin 
          and well type combination.
W = Total number of wells completed or worked over using hydraulic 
          fracturing in a sub-basin and well type combination.
Tp,s = Cumulative amount of time of flowback, after 
          sufficient quantities of gas are present to enable separation, 
          where gas vented or flared for the completion or workover, in 
          hours, for each well, p, in a sub-basin and well type 
          combination during the reporting year. This may include non-
          contiguous periods of venting or flaring.
Tp,i = Cumulative amount of time of flowback to open tanks/
          pits, from when gas is first detected until sufficient 
          quantities of gas are present to enable separation, for the 
          completion or workover, in hours, for each well, p, in a sub-
          basin and well type combination during the reporting year. 
          This may include non-contiguous periods of routing to open 
          tanks/pits but does not include periods when the oil well 
          ceases to produce fluids to the surface.

[[Page 830]]

FRMs = Ratio of average gas flowback, during the period when 
          sufficient quantities of gas are present to enable separation, 
          of well completions and workovers from hydraulic fracturing to 
          30-day production rate for the sub-basin and well type 
          combination, calculated using procedures specified in 
          paragraph (g)(1)(iii) of this section.
FRMi = Ratio of initial gas flowback rate during well 
          completions and workovers from hydraulic fracturing to 30-day 
          gas production rate for the sub-basin and well type 
          combination, calculated using procedures specified in 
          paragraph (g)(1)(iv) of this section, for the period of flow 
          to open tanks/pits.
PRs,p = Average gas production flow rate during the first 30 
          days of production after completions of newly drilled wells or 
          well workovers using hydraulic fracturing in standard cubic 
          feet per hour of each well p, that was measured in the sub-
          basin and well type combination. If applicable, 
          PRs,p may be calculated for oil wells using 
          procedures specified in paragraph (g)(1)(vii) of this section.
EnFs,p = Volume of N2 injected gas in cubic feet 
          at standard conditions that was injected into the reservoir 
          during an energized fracture job or during flowback for each 
          well, p, as determined by using an appropriate meter according 
          to methods described in Sec. 98.234(b), or by using receipts 
          of gas purchases that are used for the energized fracture job 
          or injection during flowback. Convert to standard conditions 
          using paragraph (t) of this section. If the fracture process 
          did not inject gas into the reservoir or if the injected gas 
          is CO2 then EnFs,p is 0.
FVs,p = Flow volume of vented or flared gas for each well, p, 
          in standard cubic feet measured using a recording flow meter 
          (digital or analog) on the vent line to measure gas flowback 
          during the separation period of the completion or workover 
          according to methods set forth in Sec. 98.234(b).
FRp,i = Flow rate vented or flared of each well, p, in 
          standard cubic feet per hour measured using a recording flow 
          meter (digital or analog) on the vent line to measure the 
          flowback, at the beginning of the period of time when 
          sufficient quantities of gas are present to enable separation, 
          of the completion or workover according to methods set forth 
          in Sec. 98.234(b).

    (1) If you elect to use Equation W-10A of this section on gas wells, 
you must use Calculation Method 1 as specified in paragraph (g)(1)(i) of 
this section, or Calculation Method 2 as specified in paragraph 
(g)(1)(ii) of this section, to determine the value of FRMs 
and FRMi. If you elect to use Equation W-10A of this section 
on oil wells, you must use Calculation Method 1 as specified in 
paragraph (g)(1)(i) to determine the value of FRMs and 
FRMi. These values must be based on the flow rate for 
flowback gases, once sufficient gas is present to enable separation. The 
number of measurements or calculations required to estimate 
FRMs and FRMi must be determined individually for 
completions and workovers per sub-basin and well type combination as 
follows: Complete measurements or calculations for at least one 
completion or workover for less than or equal to 25 completions or 
workovers for each well type combination within a sub-basin; complete 
measurements or calculations for at least two completions or workovers 
for 26 to 50 completions or workovers for each sub-basin and well type 
combination; complete measurements or calculations for at least three 
completions or workovers for 51 to 100 completions or workovers for each 
sub-basin and well type combination; complete measurements or 
calculations for at least four completions or workovers for 101 to 250 
completions or workovers for each sub-basin and well type combination; 
and complete measurements or calculations for at least five completions 
or workovers for greater than 250 completions or workovers for each sub-
basin and well type combination.
    (i) Calculation Method 1. You must use Equation W-12A of this 
section as specified in paragraph (g)(1)(iii) of this section to 
determine the value of FRMs. You must use Equation W-12B of 
this section as specified in paragraph (g)(1)(iv) of this section to 
determine the value of FRMi. The procedures specified in 
paragraphs (g)(1)(v) and (vi) of this section also apply. When making 
gas flowback measurements for use in Equations W-12A and W-12B of this 
section, you must use a recording flow meter (digital or analog) 
installed on the vent line, downstream of a separator and ahead of a 
flare or vent, to measure the gas flowback rates in units of standard 
cubic feet per hour according to methods set forth in Sec. 98.234(b).
    (ii) Calculation Method 2 (for gas wells). You must use Equation W-
12A as

[[Page 831]]

specified in paragraph (g)(1)(iii) of this section to determine the 
value of FRMs. You must use Equation W-12B as specified in 
paragraph (g)(1)(iv) of this section to determine the value of 
FRMi. The procedures specified in paragraphs (g)(1)(v) and 
(vi) also apply. When calculating the flowback rates for use in 
Equations W-12A and W-12B of this section based on well parameters, you 
must record the well flowing pressure immediately upstream (and 
immediately downstream in subsonic flow) of a well choke according to 
methods set forth in Sec. 98.234(b) to calculate the well flowback. The 
upstream pressure must be surface pressure and reservoir pressure cannot 
be assumed. The downstream pressure must be measured after the choke and 
atmospheric pressure cannot be assumed. Calculate flowback rate using 
Equation W-11A of this section for subsonic flow or Equation W-11B of 
this section for sonic flow. You must use best engineering estimates 
based on best available data along with Equation W-11C of this section 
to determine whether the predominant flow is sonic or subsonic. If the 
value of R in Equation W-11C of this section is greater than or equal to 
2, then flow is sonic; otherwise, flow is subsonic. Convert calculated 
FRa values from actual conditions upstream of the restriction 
orifice to standard conditions (FRs,p and FRi,p) 
for use in Equations W-12A and W-12B of this section using Equation W-33 
in paragraph (t) of this section.
[GRAPHIC] [TIFF OMITTED] TR25NO14.034

Where:

FRa = Flowback rate in actual cubic feet per hour, under 
          actual subsonic flow conditions.
A = Cross sectional open area of the restriction orifice (m\2\).
P1 = Pressure immediately upstream of the choke (psia).
Tu = Temperature immediately upstream of the choke (degrees 
          Kelvin).
P2 = Pressure immediately downstream of the choke (psia).
3430 = Constant with units of m\2\/(sec \2\ * K).
1.27*10\5\ = Conversion from m\3\/second to ft\3\/hour.
[GRAPHIC] [TIFF OMITTED] TR25NO14.035

Where:

FRa = Flowback rate in actual cubic feet per hour, under 
          actual sonic flow conditions.
A = Cross sectional open area of the restriction orifice (m\2\).
Tu = Temperature immediately upstream of the choke (degrees 
          Kelvin).
187.08 = Constant with units of m\2\/(sec\2\ * K).
1.27*10 \5\ = Conversion from m \3\/second to ft\3\/hour.

[GRAPHIC] [TIFF OMITTED] TR25NO14.036

Where:

R = Pressure ratio.
P1 = Pressure immediately upstream of the choke (psia).
P2 = Pressure immediately downstream of the choke (psia).

    (iii) For Equation W-10A of this section, calculate FRMs 
using Equation W-12A of this section.

[[Page 832]]

[GRAPHIC] [TIFF OMITTED] TR25NO14.037

Where:

FRMs = Ratio of average gas flowback rate, during the period 
          of time when sufficient quantities of gas are present to 
          enable separation, of well completions and workovers from 
          hydraulic fracturing to 30-day gas production rate for each 
          sub-basin and well type combination.
FRs,p = Measured average gas flowback rate from Calculation 
          Method 1 described in paragraph (g)(1)(i) of this section or 
          calculated average flowback rate from Calculation Method 2 
          described in paragraph (g)(1)(ii) of this section, during the 
          separation period in standard cubic feet per hour for well(s) 
          p for each sub-basin and well type combination. Convert 
          measured and calculated FRa values from actual 
          conditions upstream of the restriction orifice 
          (FRa) to standard conditions (FRs,p) for 
          each well p using Equation W-33 in paragraph (t) of this 
          section. You may not use flow volume as used in Equation W-10B 
          of this section converted to a flow rate for this parameter.
PRs,p = Average gas production flow rate during the first 30 
          days of production after completions of newly drilled wells or 
          well workovers using hydraulic fracturing, in standard cubic 
          feet per hour for each well, p, that was measured in the sub-
          basin and well type combination. For oil wells for which 
          production is not measured continuously during the first 30 
          days of production, the average flow rate may be based on 
          individual well production tests conducted within the first 30 
          days of production. Alternatively, if applicable, 
          PRs,p may be calculated for oil wells using 
          procedures specified in paragraph (g)(1)(vii) of this section.
N = Number of measured or calculated well completions or workovers using 
          hydraulic fracturing in a sub-basin and well type combination.

    (iv) For Equation W-10A of this section, calculate FRMi 
using Equation W-12B of this section.

[GRAPHIC] [TIFF OMITTED] TR25NO14.038

Where:

FRMi = Ratio of initial gas flowback rate during well 
          completions and workovers from hydraulic fracturing to 30-day 
          gas production rate for the sub-basin and well type 
          combination, for the period of flow to open tanks/pits.
FRi,p = Initial measured gas flowback rate from Calculation 
          Method 1 described in paragraph (g)(1)(i) of this section or 
          initial calculated flow rate from Calculation Method 2 
          described in paragraph (g)(1)(ii) of this section in standard 
          cubic feet per hour for well(s), p, for each sub-basin and 
          well type combination. Measured and calculated 
          FRi,p values must be based on flow conditions at 
          the beginning of the separation period and must be expressed 
          at standard conditions.
PRs,p = Average gas production flow rate during the first 30-
          days of production after completions of newly drilled wells or 
          well workovers using hydraulic fracturing, in standard cubic 
          feet per hour of each well, p, that was measured in the sub-
          basin and well type combination. For oil wells for which 
          production is not measured continuously during the first 30 
          days of production, the average flow rate may be based on 
          individual well production tests conducted within the first 30 
          days of production. Alternatively, if applicable, 
          PRs,p may be calculated for

[[Page 833]]

          oil wells using procedures specified in paragraph (g)(1)(vii) 
          of this section.
N = Number of measured or calculated well completions or workovers using 
          hydraulic fracturing in a sub-basin and well type combination.

    (v) For Equation W-10A of this section, the ratio of gas flowback 
rate during well completions and workovers from hydraulic fracturing to 
30-day gas production rate are applied to all well completions and well 
workovers, respectively, in the sub-basin and well type combination for 
the total number of hours of flowback and for the first 30 day average 
gas production rate for each of these wells.
    (vi) For Equations W-12A and W-12B of this section, calculate new 
flowback rates for well completions and well workovers in each sub-basin 
and well type combination once every two years starting in the first 
calendar year of data collection.
    (vii) For oil wells where the gas production rate is not metered and 
you elect to use Equation W-10A of this section, calculate the average 
gas production rate (PRs,p) using Equation W-12C of this 
section. If GOR cannot be determined from your available data, then you 
must use one of the procedures specified in paragraph (g)(1)(vii)(A) or 
(B) of this section to determine GOR. If GOR from each well is not 
available, use the GOR from a cluster of wells in the same sub-basin 
category.
[GRAPHIC] [TIFF OMITTED] TR22OC15.008

Where:

PRs,p = Average gas production flow rate during the first 30 
          days of production after completions of newly drilled wells or 
          well workovers using hydraulic fracturing in standard cubic 
          feet per hour of well p, in the sub-basin and well type 
          combination.
GORp = Average gas to oil ratio during the first 30 days of 
          production after completions of newly drilled wells or 
          workovers using hydraulic fracturing in standard cubic feet of 
          gas per barrel of oil for each well p, that was measured in 
          the sub-basin and well type combination; oil here refers to 
          hydrocarbon liquids produced of all API gravities.
Vp = Volume of oil produced during the first 30 days of 
          production after completions of newly drilled wells or well 
          workovers using hydraulic fracturing in barrels of each well 
          p, that was measured in the sub-basin and well type 
          combination.
720 = Conversion from 30 days of production to hourly production rate.

    (A) You may use an appropriate standard method published by a 
consensus-based standards organization if such a method exists.
    (B) You may use an industry standard practice as described in Sec. 
98.234(b).
    (2) For paragraphs (g) introductory text and (g)(1) of this section, 
measurements and calculations are completed separately for workovers and 
completions per sub-basin and well type combination. A well type 
combination is a unique combination of the parameters listed in 
paragraphs (g)(2)(i) through (iv) of this section.
    (i) Vertical or horizontal (directional drilling).
    (ii) With flaring or without flaring.
    (iii) Reduced emission completion/workover or not reduced emission 
completion/workover.
    (iv) Oil well or gas well.
    (3) Calculate both CH4 and CO2 volumetric and 
mass emissions from total natural gas volumetric emissions using 
calculations in paragraphs (u) and (v) of this section.
    (4) Calculate annual emissions from well venting during well 
completions and workovers from hydraulic fracturing where all or a 
portion of the gas is flared as specified in paragraphs (g)(4)(i) and 
(ii) of this section.
    (i) Use the volumetric total natural gas emissions vented to the 
atmosphere during well completions and workovers as determined in 
paragraph (g) of this section to calculate volumetric and mass emissions 
using paragraphs (u) and (v) of this section.
    (ii) Use the calculation method of flare stacks in paragraph (n) of 
this

[[Page 834]]

section to adjust emissions for the portion of gas flared during well 
completions and workovers using hydraulic fracturing. This adjustment to 
emissions from completions using flaring, versus completions without 
flaring, accounts for the conversion of CH4 to CO2 
in the flare and for the formation on N2O during flaring.
    (h) Gas well venting during completions and workovers without 
hydraulic fracturing. Calculate annual volumetric natural gas emissions 
from each gas well venting during workovers without hydraulic fracturing 
using Equation W-13A of this section. Calculate annual volumetric 
natural gas emissions from each gas well venting during completions 
without hydraulic fracturing using Equation W-13B of this section. You 
must convert annual volumetric natural gas emissions to CH4 
and CO2 volumetric and mass emissions as specified in 
paragraph (h)(1) of this section. If emissions from gas well venting 
during completions and workovers without hydraulic fracturing are routed 
to a flare, you must calculate CH4, CO2, and 
N2O annual emissions as specified in paragraph (h)(2) of this 
section.
[GRAPHIC] [TIFF OMITTED] TR25NO14.039

Where:

Es,wo = Annual volumetric natural gas emissions in standard 
          cubic feet from gas well venting during well workovers without 
          hydraulic fracturing.
Nwo = Number of workovers per sub-basin category that do not 
          involve hydraulic fracturing in the reporting year.
EFwo = Emission factor for non-hydraulic fracture well 
          workover venting in standard cubic feet per workover. Use 
          3,114 standard cubic feet natural gas per well workover 
          without hydraulic fracturing.
Es,p = Annual volumetric natural gas emissions in standard 
          cubic feet from gas well venting during well completions 
          without hydraulic fracturing.
p = Well completions 1 through f in a sub-basin.
f = Total number of well completions without hydraulic fracturing in a 
          sub-basin category.
Vp = Average daily gas production rate in standard cubic feet 
          per hour for each well, p, undergoing completion without 
          hydraulic fracturing. This is the total annual gas production 
          volume divided by total number of hours the wells produced to 
          the flow-line. For completed wells that have not established a 
          production rate, you may use the average flow rate from the 
          first 30 days of production. In the event that the well is 
          completed less than 30 days from the end of the calendar year, 
          the first 30 days of the production straddling the current and 
          following calendar years shall be used.
Tp = Time that gas is vented to either the atmosphere or a 
          flare for each well, p, undergoing completion without 
          hydraulic fracturing, in hours during the year.

    (1) Calculate both CH4 and CO2 volumetric 
emissions from natural gas volumetric emissions using calculations in 
paragraph (u) of this section. Calculate both CH4 and 
CO2 mass emissions from volumetric emissions vented to 
atmosphere using calculations in paragraph (v) of this section.
    (2) Calculate annual emissions of CH4, CO2, 
and N2O from gas well venting to flares during well 
completions and workovers not involving hydraulic fracturing as 
specified in paragraphs (h)(2)(i) and (ii) of this section.
    (i) Use the gas well venting volume and gas composition during well 
completions and workovers that are flared as determined using the 
methods specified in paragraphs (h) and (h)(1) of this section.
    (ii) Use the calculation method of flare stacks in paragraph (n) of 
this section to determine emissions from the flare for gas well venting 
to a flare during completions and workovers without hydraulic 
fracturing.
    (i) Blowdown vent stacks. Calculate CO2 and 
CH4 blowdown vent stack emissions from the depressurization 
of

[[Page 835]]

equipment to reduce system pressure for planned or emergency shutdowns 
resulting from human intervention or to take equipment out of service 
for maintenance as specified in either paragraph (i)(2) or (3) of this 
section. You may use the method in paragraph (i)(2) of this section for 
some blowdown vent stacks at your facility and the method in paragraph 
(i)(3) of this section for other blowdown vent stacks at your facility. 
Equipment with a unique physical volume of less than 50 cubic feet as 
determined in paragraph (i)(1) of this section are not subject to the 
requirements in paragraphs (i)(2) through (4) of this section. The 
requirements in this paragraph (i) do not apply to blowdown vent stack 
emissions from depressurizing to a flare, over-pressure relief, 
operating pressure control venting, blowdown of non-GHG gases, and 
desiccant dehydrator blowdown venting before reloading.
    (1) Method for calculating unique physical volumes. You must 
calculate each unique physical volume (including pipelines, compressor 
case or cylinders, manifolds, suction bottles, discharge bottles, and 
vessels) between isolation valves, in cubic feet, by using engineering 
estimates based on best available data.
    (2) Method for determining emissions from blowdown vent stacks 
according to equipment or event type. If you elect to determine 
emissions according to each equipment or event type, using unique 
physical volumes as calculated in paragraph (i)(1) of this section, you 
must calculate emissions as specified in paragraph (i)(2)(i) of this 
section and either paragraph (i)(2)(ii) or, if applicable, paragraph 
(i)(2)(iii) of this section for each equipment or event type. For 
industry segments other than onshore natural gas transmission pipeline, 
equipment or event types must be grouped into the following seven 
categories: Facility piping (i.e., piping within the facility boundary 
other than physical volumes associated with distribution pipelines), 
pipeline venting (i.e., physical volumes associated with distribution 
pipelines vented within the facility boundary), compressors, scrubbers/
strainers, pig launchers and receivers, emergency shutdowns (this 
category includes emergency shutdown blowdown emissions regardless of 
equipment type), and all other equipment with a physical volume greater 
than or equal to 50 cubic feet. If a blowdown event resulted in 
emissions from multiple equipment types and the emissions cannot be 
apportioned to the different equipment types, then categorize the 
blowdown event as the equipment type that represented the largest 
portion of the emissions for the blowdown event. For the onshore natural 
gas transmission pipeline segment, pipeline segments or event types must 
be grouped into the following eight categories: Pipeline integrity work 
(e.g., the preparation work of modifying facilities, ongoing 
assessments, maintenance or mitigation), traditional operations or 
pipeline maintenance, equipment replacement or repair (e.g., valves), 
pipe abandonment, new construction or modification of pipelines 
including commissioning and change of service, operational precaution 
during activities (e.g. excavation near pipelines), emergency shutdowns 
including pipeline incidents as defined in 49 CFR 191.3, and all other 
pipeline segments with a physical volume greater than or equal to 50 
cubic feet. If a blowdown event resulted in emissions from multiple 
categories and the emissions cannot be apportioned to the different 
categories, then categorize the blowdown event in the category that 
represented the largest portion of the emissions for the blowdown event.
    (i) Calculate the total annual natural gas emissions from each 
unique physical volume that is blown down using either Equation W-14A or 
W-14B of this section.
[GRAPHIC] [TIFF OMITTED] TR25NO14.040


[[Page 836]]


Where:

Es,n = Annual natural gas emissions at standard conditions 
          from each unique physical volume that is blown down, in cubic 
          feet.
N = Number of occurrences of blowdowns for each unique physical volume 
          in the calendar year.
V = Unique physical volume between isolation valves, in cubic feet, as 
          calculated in paragraph (i)(1) of this section.
C = Purge factor is 1 if the unique physical volume is not purged, or 0 
          if the unique physical volume is purged using non-GHG gases.
Ts = Temperature at standard conditions (60  deg.F).
Ta = Temperature at actual conditions in the unique physical 
          volume (  deg.F). For emergency blowdowns at onshore petroleum 
          and natural gas gathering and boosting facilities, engineering 
          estimates based on best available information may be used to 
          determine the temperature.
Ps = Absolute pressure at standard conditions (14.7 psia).
Pa = Absolute pressure at actual conditions in the unique 
          physical volume (psia). For emergency blowdowns at onshore 
          petroleum and natural gas gathering and boosting facilities, 
          engineering estimates based on best available information may 
          be used to determine the pressure.
Za = Compressibility factor at actual conditions for natural 
          gas. You may use either a default compressibility factor of 1, 
          or a site-specific compressibility factor based on actual 
          temperature and pressure conditions.

          [GRAPHIC] [TIFF OMITTED] TR25NO14.041
          
Where:

Es,n = Annual natural gas emissions at standard conditions 
          from each unique physical volume that is blown down, in cubic 
          feet.
p = Individual occurrence of blowdown for the same unique physical 
          volume.
N = Number of occurrences of blowdowns for each unique physical volume 
          in the calendar year.
Vp = Unique physical volume between isolation valves, in 
          cubic feet, for each blowdown ``p.''
Ts = Temperature at standard conditions (60  deg.F).
Ta,p = Temperature at actual conditions in the unique 
          physical volume (  deg.F) for each blowdown ``p''.
Ps = Absolute pressure at standard conditions (14.7 psia).
Pa,b,p = Absolute pressure at actual conditions in the unique 
          physical volume (psia) at the beginning of the blowdown ``p''.
Pa,e,p = Absolute pressure at actual conditions in the unique 
          physical volume (psia) at the end of the blowdown ``p''; 0 if 
          blowdown volume is purged using non-GHG gases.
Za = Compressibility factor at actual conditions for natural 
          gas. You may use either a default compressibility factor of 1, 
          or a site-specific compressibility factor based on actual 
          temperature and pressure conditions.

    (ii) Except as allowed in paragraph (i)(2)(iii) of this section, 
calculate annual CH4 and CO2 volumetric and mass 
emissions from each unique physical volume that is blown down by using 
the annual natural gas emission value as calculated in either Equation 
W-14A or Equation W-14B of paragraph (i)(2)(i) of this section and the 
calculation method specified in paragraph (i)(4) of this section. 
Calculate the total annual CH4 and CO2 emissions 
for each equipment or event type by summing the annual CH4 
and CO2 mass emissions for all unique physical volumes 
associated with the equipment or event type.
    (iii) For onshore natural gas transmission compression facilities 
and LNG import and export equipment, as an alternative to using the 
procedures in paragraph (i)(2)(ii) of this section, you may elect to sum 
the annual natural gas emissions as calculated using either Equation W-
14A or Equation W-14B of paragraph (i)(2)(i) of this section for all 
unique physical volumes associated with the equipment type or event 
type. Calculate the total annual CH4 and CO2 
volumetric and mass emissions for each equipment type or event type 
using the sums of the total annual natural gas emissions for each 
equipment type and the calculation method specified in paragraph (i)(4) 
of this section.

[[Page 837]]

    (3) Method for determining emissions from blowdown vent stacks using 
a flow meter. In lieu of determining emissions from blowdown vent stacks 
as specified in paragraph (i)(2) of this section, you may use a flow 
meter and measure blowdown vent stack emissions for any unique physical 
volumes determined according to paragraph (i)(1) of this section to be 
greater than or equal to 50 cubic feet. If you choose to use this 
method, you must measure the natural gas emissions from the blowdown(s) 
through the monitored stack(s) using a flow meter according to methods 
in Sec. 98.234(b), and calculate annual CH4 and 
CO2 volumetric and mass emissions measured by the meters 
according to paragraph (i)(4) of this section.
    (4) Method for converting from natural gas emissions to GHG 
volumetric and mass emissions. Calculate both CH4 and 
CO2 volumetric and mass emissions using the methods specified 
in paragraphs (u) and (v) of this section.
    (j) Onshore production and onshore petroleum and natural gas 
gathering and boosting storage tanks. Calculate CH4, 
CO2, and N2O (when flared) emissions from 
atmospheric pressure fixed roof storage tanks receiving hydrocarbon 
produced liquids from onshore petroleum and natural gas production 
facilities and onshore petroleum and natural gas gathering and boosting 
facilities (including stationary liquid storage not owned or operated by 
the reporter), as specified in this paragraph (j). For gas-liquid 
separators or onshore petroleum and natural gas gathering and boosting 
non-separator equipment (e.g., stabilizers, slug catchers) with annual 
average daily throughput of oil greater than or equal to 10 barrels per 
day, calculate annual CH4 and CO2 using 
Calculation Method 1 or 2 as specified in paragraphs (j)(1) and (2) of 
this section. For wells flowing directly to atmospheric storage tanks 
without passing through a separator with throughput greater than or 
equal to 10 barrels per day, calculate annual CH4 and 
CO2 emissions using Calculation Method 2 as specified in 
paragraph (j)(2) of this section. For hydrocarbon liquids flowing to 
gas-liquid separators or non-separator equipment or directly to 
atmospheric storage tanks with throughput less than 10 barrels per day, 
use Calculation Method 3 as specified in paragraph (j)(3) of this 
section. If you use Calculation Method 1 or Calculation Method 2 for 
separators, you must also calculate emissions that may have occurred due 
to dump valves not closing properly using the method specified in 
paragraph (j)(6) of this section. If emissions from atmospheric pressure 
fixed roof storage tanks are routed to a vapor recovery system, you must 
adjust the emissions downward according to paragraph (j)(4) of this 
section. If emissions from atmospheric pressure fixed roof storage tanks 
are routed to a flare, you must calculate CH4, 
CO2, and N2O annual emissions as specified in 
paragraph (j)(5) of this section.
    (1) Calculation Method 1. Calculate annual CH4 and 
CO2 emissions from onshore production storage tanks and 
onshore petroleum and natural gas gathering and boosting storage tanks 
using operating conditions in the last gas-liquid separator or non-
separator equipment before liquid transfer to storage tanks. Calculate 
flashing emissions with a software program, such as AspenTech 
HYSYS[supreg] or API 4697 E&P Tank, that uses the Peng-Robinson equation 
of state, models flashing emissions, and speciates CH4 and 
CO2 emissions that will result when the oil from the 
separator or non-separator equipment enters an atmospheric pressure 
storage tank. The following parameters must be determined for typical 
operating conditions over the year by engineering estimate and process 
knowledge based on best available data, and must be used at a minimum to 
characterize emissions from liquid transferred to tanks:
    (i) Separator or non-separator equipment temperature.
    (ii) Separator or non-separator equipment pressure.
    (iii) Sales oil or stabilized oil API gravity.
    (iv) Sales oil or stabilized oil production rate.
    (v) Ambient air temperature.
    (vi) Ambient air pressure.
    (vii) Separator or non-separator equipment oil composition and Reid 
vapor pressure. If this data is not available, determine these 
parameters by using one of the methods described in

[[Page 838]]

paragraphs (j)(1)(vii)(A) through (C) of this section.
    (A) If separator or non-separator equipment oil composition and Reid 
vapor pressure default data are provided with the software program, 
select the default values that most closely match your separator or non-
separator equipment pressure first, and API gravity secondarily.
    (B) If separator or non-separator equipment oil composition and Reid 
vapor pressure data are available through your previous analysis, select 
the latest available analysis that is representative of produced crude 
oil or condensate from the sub-basin category for onshore petroleum and 
natural gas production or from the county for onshore petroleum and 
natural gas gathering and boosting.
    (C) Analyze a representative sample of separator or non-separator 
equipment oil in each sub-basin category for onshore petroleum and 
natural gas production or each county for onshore petroleum and natural 
gas gathering and boosting for oil composition and Reid vapor pressure 
using an appropriate standard method published by a consensus-based 
standards organization.
    (2) Calculation Method 2. Calculate annual CH4 and 
CO2 emissions using the methods in paragraph (j)(2)(i) of 
this section for gas-liquid separators with annual average daily 
throughput of oil greater than or equal to 10 barrels per day. Calculate 
annual CH4 and CO2 emissions using the methods in 
paragraph (j)(2)(ii) of this section for wells with annual average daily 
oil production greater than or equal to 10 barrels per day that flow 
directly to atmospheric storage tanks in onshore petroleum and natural 
gas production and onshore petroleum and natural gas gathering and 
boosting (if applicable). Calculate annual CH4 and 
CO2 emissions using the methods in paragraph (j)(2)(iii) of 
this section for non-separator equipment with annual average daily 
hydrocarbon liquids throughput greater than or equal to 10 barrels per 
day that flow directly to atmospheric storage tanks in onshore petroleum 
and natural gas gathering and boosting.
    (i) Flow to storage tank after passing through a separator. Assume 
that all of the CH4 and CO2 in solution at 
separator temperature and pressure is emitted from oil sent to storage 
tanks. You may use an appropriate standard method published by a 
consensus-based standards organization if such a method exists or you 
may use an industry standard practice as described in Sec. 98.234(b) to 
sample and analyze separator oil composition at separator pressure and 
temperature.
    (ii) Flow to storage tank direct from wells. Calculate 
CH4 and CO2 emissions using either of the methods 
in paragraph (j)(2)(ii)(A) or (B) of this section.
    (A) If well production oil and gas compositions are available 
through a previous analysis, select the latest available analysis that 
is representative of produced oil and gas from the sub-basin category 
and assume all of the CH4 and CO2 in both oil and 
gas are emitted from the tank.
    (B) If well production oil and gas compositions are not available, 
use default oil and gas compositions in software programs, such as API 
4697 E&P Tank, that most closely match the well production gas/oil ratio 
and API gravity and assume all of the CH4 and CO2 
in both oil and gas are emitted from the tank.
    (iii) Flow to storage tank direct from non-separator equipment. 
Calculate CH4 and CO2 emissions using either of 
the methods in paragraph (j)(2)(iii)(A) or (B) of this section.
    (A) If other non-separator equipment liquid and gas compositions are 
available through a previous analysis, select the latest available 
analysis that is representative of liquid and gas from non-separator 
equipment in the same county and assume all of the CH4 and 
CO2 in both hydrocarbon liquids and gas are emitted from the 
tank.
    (B) If non-separator equipment liquid and gas compositions are not 
available, use default liquid and gas compositions in software programs, 
such as API 4697 E&P Tank, that most closely match the non-separator 
equipment gas/liquid ratio and API gravity and assume all of the 
CH4 and CO2 in both hydrocarbon liquids and gas 
are emitted from the tank.
    (3) Calculation Method 3. Calculate CH4 and 
CO2 emissions using Equation W-15 of this section:

[[Page 839]]

[GRAPHIC] [TIFF OMITTED] TR22OC15.009

Where:

Es,i = Annual total volumetric GHG emissions (either 
          CO2 or CH4) at standard conditions in 
          cubic feet.
EFi = Population emission factor for separators, wells, or 
          non-separator equipment in thousand standard cubic feet per 
          separator, well, or non-separator equipment per year, for 
          crude oil use 4.2 for CH4 and 2.8 for 
          CO2 at 60[emsp14]  deg.F and 14.7 psia, and for gas 
          condensate use 17.6 for CH4 and 2.8 for 
          CO2 at 60  deg.F and 14.7 psia.
Count = Total number of separators, wells, or non-separator equipment 
          with annual average daily throughput less than 10 barrels per 
          day. Count only separators, wells, or non-separator equipment 
          that feed oil directly to the storage tank.
1,000 = Conversion from thousand standard cubic feet to standard cubic 
          feet.

    (4) Determine if the storage tank receiving your separator oil has a 
vapor recovery system.
    (i) Adjust the emissions estimated in paragraphs (j)(1) through (3) 
of this section downward by the magnitude of emissions recovered using a 
vapor recovery system as determined by engineering estimate based on 
best available data.
    (ii) [Reserved]
    (5) Determine if the storage tank receiving your separator oil is 
sent to flare(s).
    (i) Use your separator flash gas volume and gas composition as 
determined in this section.
    (ii) Use the calculation method of flare stacks in paragraph (n) of 
this section to determine storage tank emissions from the flare.
    (6) If you use Calculation Method 1 or Calculation Method 2 in 
paragraph (j)(1) or (2) of this section, calculate emissions from 
occurrences of gas-liquid separator liquid dump valves not closing 
during the calendar year by using Equation W-16 of this section.
[GRAPHIC] [TIFF OMITTED] TR22OC15.010

Where:

Es,i,o = Annual volumetric GHG emissions at standard 
          conditions from each storage tank in cubic feet that resulted 
          from the dump valve on the gas-liquid separator not closing 
          properly.
En = Storage tank emissions as determined in paragraphs 
          (j)(1), (j)(2) and, if applicable, (j)(4) of this section in 
          standard cubic feet per year.
Tn = Total time a dump valve is not closing properly in the 
          calendar year in hours. Estimate Tn based on 
          maintenance, operations, or routine separator inspections that 
          indicate the period of time when the valve was malfunctioning 
          in open or partially open position.
CFn = Correction factor for tank emissions for time period 
          Tn is 2.87 for crude oil production. Correction 
          factor for tank emissions for time period Tn is 
          4.37 for gas condensate production.
8,760 = Conversion to hourly emissions.


    (7) Calculate both CH4 and CO2 mass emissions 
from natural gas volumetric emissions using calculations in paragraph 
(v) of this section.
    (k) Transmission storage tanks. For vent stacks connected to one or 
more transmission condensate storage tanks, either water or hydrocarbon, 
without vapor recovery, in onshore natural gas transmission compression, 
calculate CH4 and CO2 annual emissions from 
compressor scrubber dump valve leakage as specified in paragraphs (k)(1) 
through (k)(4) of this section. If emissions from compressor scrubber 
dump valve leakage are routed to a flare, you must calculate 
CH4, CO2, and N2O annual emissions as 
specified in paragraph (k)(5) of this section.
    (1) Except as specified in paragraph (k)(1)(iv) of this section, you 
must monitor the tank vapor vent stack annually for emissions using one 
of the

[[Page 840]]

methods specified in paragraphs (k)(1)(i) through (iii) of this section.
    (i) Use an optical gas imaging instrument according to methods set 
forth in Sec. 98.234(a)(1).
    (ii) Measure the tank vent directly using a flow meter or high 
volume sampler according to methods in Sec. 98.234(b) or (d) for a 
duration of 5 minutes.
    (iii) Measure the tank vent using a calibrated bag according to 
methods in Sec. 98.234(c) for a duration of 5 minutes or until the bag 
is full, whichever is shorter.
    (iv) You may annually monitor leakage through compressor scrubber 
dump valve(s) into the tank using an acoustic leak detection device 
according to methods set forth in Sec. 98.234(a)(5).
    (2) If the tank vapors from the vent stack are continuous for 5 
minutes, or the optical gas imaging instrument or acoustic leak 
detection device detects a leak, then you must use one of the methods in 
either paragraph (k)(2)(i) or (ii) of this section.
    (i) Use a flow meter, such as a turbine meter, calibrated bag, or 
high volume sampler to estimate tank vapor volumes from the vent stack 
according to methods set forth in Sec. 98.234(b) through (d). If you do 
not have a continuous flow measurement device, you may install a flow 
measuring device on the tank vapor vent stack. If the vent is directly 
measured for five minutes under paragraph (k)(1)(ii) or (iii) of this 
section to detect continuous leakage, this serves as the measurement.
    (ii) Use an acoustic leak detection device on each scrubber dump 
valve connected to the tank according to the method set forth in Sec. 
98.234(a)(5).
    (3) If a leaking dump valve is identified, the leak must be counted 
as having occurred since the beginning of the calendar year, or from the 
previous test that did not detect leaking in the same calendar year. If 
the leaking dump valve is fixed following leak detection, the leak 
duration will end upon being repaired. If a leaking dump valve is 
identified and not repaired, the leak must be counted as having occurred 
through the rest of the calendar year.
    (4) Use the requirements specified in paragraphs (k)(4)(i) and (ii) 
of this section to quantify annual emissions.
    (i) Use the appropriate gas composition in paragraph (u)(2)(iii) of 
this section.
    (ii) Calculate CH4 and CO2 volumetric and mass 
emissions at standard conditions using calculations in paragraphs (t), 
(u), and (v) of this section, as applicable to the monitoring equipment 
used.
    (5) Calculate annual emissions from storage tanks to flares as 
specified in paragraphs (k)(5)(i) and (ii) of this section.
    (i) Use the storage tank emissions volume and gas composition as 
determined in paragraphs (k)(1) through (4) of this section.
    (ii) Use the calculation method of flare stacks in paragraph (n) of 
this section to determine storage tank emissions sent to a flare.
    (l) Well testing venting and flaring. Calculate CH4 and 
CO2 annual emissions from well testing venting as specified 
in paragraphs (l)(1) through (5) of this section. If emissions from well 
testing venting are routed to a flare, you must calculate 
CH4, CO2, and N2O annual emissions as 
specified in paragraph (l)(6) of this section.
    (1) Determine the gas to oil ratio (GOR) of the hydrocarbon 
production from oil well(s) tested. Determine the production rate from 
gas well(s) tested.
    (2) If GOR cannot be determined from your available data, then you 
must measure quantities reported in this section according to one of the 
procedures specified in paragraph (l)(2)(i) or (ii) of this section to 
determine GOR.
    (i) You may use an appropriate standard method published by a 
consensus-based standards organization if such a method exists.
    (ii) You may use an industry standard practice as described in Sec. 
98.234(b).
    (3) Estimate venting emissions using Equation W-17A (for oil wells) 
or Equation W-17B (for gas wells) of this section.

[[Page 841]]

[GRAPHIC] [TIFF OMITTED] TR25NO14.063

Where:

Ea,n = Annual volumetric natural gas emissions from well(s) 
          testing in cubic feet under actual conditions.
GOR = Gas to oil ratio in cubic feet of gas per barrel of oil; oil here 
          refers to hydrocarbon liquids produced of all API gravities.
FR = Average annual flow rate in barrels of oil per day for the oil 
          well(s) being tested.
PR = Average annual production rate in actual cubic feet per day for the 
          gas well(s) being tested.
D = Number of days during the calendar year that the well(s) is tested.

    (4) Calculate natural gas volumetric emissions at standard 
conditions using calculations in paragraph (t) of this section.
    (5) Calculate both CH4 and CO2 volumetric and 
mass emissions from natural gas volumetric emissions using calculations 
in paragraphs (u) and (v) of this section.
    (6) Calculate emissions from well testing if emissions are routed to 
a flare as specified in paragraphs (l)(6)(i) and (ii) of this section.
    (i) Use the well testing emissions volume and gas composition as 
determined in paragraphs (l)(1) through (4) of this section.
    (ii) Use the calculation method of flare stacks in paragraph (n) of 
this section to determine well testing emissions from the flare.
    (m) Associated gas venting and flaring. Calculate CH4 and 
CO2 annual emissions from associated gas venting not in 
conjunction with well testing (refer to paragraph (l): Well testing 
venting and flaring of this section) as specified in paragraphs (m)(1) 
through (4) of this section. If emissions from associated gas venting 
are routed to a flare, you must calculate CH4, 
CO2, and N2O annual emissions as specified in 
paragraph (m)(5) of this section.
    (1) Determine the GOR of the hydrocarbon production from each well 
whose associated natural gas is vented or flared. If GOR from each well 
is not available, use the GOR from a cluster of wells in the same sub-
basin category.
    (2) If GOR cannot be determined from your available data, then you 
must use one of the procedures specified in paragraphs (m)(2)(i) or (ii) 
of this section to determine GOR.
    (i) You may use an appropriate standard method published by a 
consensus-based standards organization if such a method exists.
    (ii) You may use an industry standard practice as described in Sec. 
98.234(b).
    (3) Estimate venting emissions using Equation W-18 of this section.
    [GRAPHIC] [TIFF OMITTED] TR25NO14.043
    
Where:

Es,n = Annual volumetric natural gas emissions, at the 
          facility level, from associated gas venting at standard 
          conditions, in cubic feet.
GORp,q = Gas to oil ratio, for well p in sub-basin q, in 
          standard cubic feet of gas per barrel of oil; oil here refers 
          to hydrocarbon liquids produced of all API gravities.
Vp,q = Volume of oil produced, for well p in sub-basin q, in 
          barrels in the calendar year during time periods in which 
          associated gas was vented or flared.
SGp,q = Volume of associated gas sent to sales, for well p in 
          sub-basin q, in standard cubic feet of gas in the calendar 
          year during time periods in which associated gas was vented or 
          flared.
x = Total number of wells in sub-basin that vent or flare associated 
          gas.

[[Page 842]]

y = Total number of sub-basins in a basin that contain wells that vent 
          or flare associated gas.

    (4) Calculate both CH4 and CO2 volumetric and 
mass emissions from volumetric natural gas emissions using calculations 
in paragraphs (u) and (v) of this section.
    (5) Calculate emissions from associated natural gas if emissions are 
routed to a flare as specified in paragraphs (m)(5)(i) and (ii) of this 
section.
    (i) Use the associated natural gas volume and gas composition as 
determined in paragraph (m)(1) through (4) of this section.
    (ii) Use the calculation method of flare stacks in paragraph (n) of 
this section to determine associated gas emissions from the flare.
    (n) Flare stack emissions. Calculate CO2, CH4, 
and N2O emissions from a flare stack as specified in 
paragraphs (n)(1) through (9) of this section.
    (1) If you have a continuous flow measurement device on the flare, 
you must use the measured flow volumes to calculate the flare gas 
emissions. If all of the flare gas is not measured by the existing flow 
measurement device, then the flow not measured can be estimated using 
engineering calculations based on best available data or company 
records. If you do not have a continuous flow measurement device on the 
flare, you can use engineering calculations based on process knowledge, 
company records, and best available data.
    (2) If you have a continuous gas composition analyzer on gas to the 
flare, you must use these compositions in calculating emissions. If you 
do not have a continuous gas composition analyzer on gas to the flare, 
you must use the appropriate gas compositions for each stream of 
hydrocarbons going to the flare as specified in paragraphs (n)(2)(i) 
through (iii) of this section.
    (i) For onshore natural gas production and onshore petroleum and 
natural gas gathering and boosting, determine the GHG mole fraction 
using paragraph (u)(2)(i) of this section.
    (ii) For onshore natural gas processing, when the stream going to 
flare is natural gas, use the GHG mole fraction in feed natural gas for 
all streams upstream of the de-methanizer or dew point control, and GHG 
mole fraction in facility specific residue gas to transmission pipeline 
systems for all emissions sources downstream of the de-methanizer 
overhead or dew point control for onshore natural gas processing 
facilities. For onshore natural gas processing plants that solely 
fractionate a liquid stream, use the GHG mole fraction in feed natural 
gas liquid for all streams.
    (iii) For any industry segment required to report to flare stack 
emissions under Sec. 98.232, when the stream going to the flare is a 
hydrocarbon product stream, such as methane, ethane, propane, butane, 
pentane-plus and mixed light hydrocarbons, then you may use a 
representative composition from the source for the stream determined by 
engineering calculation based on process knowledge and best available 
data.
    (3) Determine flare combustion efficiency from manufacturer. If not 
available, assume that flare combustion efficiency is 98 percent.
    (4) Convert GHG volumetric emissions to standard conditions using 
calculations in paragraph (t) of this section.
    (5) Calculate GHG volumetric emissions from flaring at standard 
conditions using Equations W-19 and W-20 of this section.
[GRAPHIC] [TIFF OMITTED] TR25NO14.044


[[Page 843]]


Where:

Es,CH4 = Annual CH4 emissions from flare stack in 
          cubic feet, at standard conditions.
Es,CO2 = Annual CO2 emissions from flare stack in 
          cubic feet, at standard conditions.
Vs = Volume of gas sent to flare in standard cubic feet, 
          during the year as determined in paragraph (n)(1) of this 
          section.
j = Flare combustion efficiency, expressed as fraction of gas combusted 
          by a burning flare (default is 0.98).
XCH4 = Mole fraction of CH4 in the feed gas to the 
          flare as determined in paragraph (n)(2) of this section.
XCO2 = Mole fraction of CO2 in the feed gas to the 
          flare as determined in paragraph (n)(2) of this section.
ZU = Fraction of the feed gas sent to an un-lit flare 
          determined by engineering estimate and process knowledge based 
          on best available data and operating records.
ZL = Fraction of the feed gas sent to a burning flare (equal 
          to 1 - ZU).
Yj = Mole fraction of hydrocarbon constituents j (such as 
          methane, ethane, propane, butane, and pentanes-plus) in the 
          feed gas to the flare as determined in paragraph (n)(1) of 
          this section.
Rj = Number of carbon atoms in the hydrocarbon constituent j 
          in the feed gas to the flare: 1 for methane, 2 for ethane, 3 
          for propane, 4 for butane, and 5 for pentanes-plus).

    (6) Calculate both CH4 and CO2 mass emissions 
from volumetric emissions using calculation in paragraph (v) of this 
section.
    (7) Calculate N2O emissions from flare stacks using 
Equation W-40 in paragraph (z) of this section.
    (8) If you operate and maintain a CEMS that has both a 
CO2 concentration monitor and volumetric flow rate monitor 
for the combustion gases from the flare, you must calculate only 
CO2 emissions for the flare. You must follow the Tier 4 
Calculation Method and all associated calculation, quality assurance, 
reporting, and recordkeeping requirements for Tier 4 in subpart C of 
this part (General Stationary Fuel Combustion Sources). If a CEMS is 
used to calculate flare stack emissions, the requirements specified in 
paragraphs (n)(1) through (7) of this section are not required.
    (9) The flare emissions determined under this paragraph (n) must be 
corrected for flare emissions calculated and reported under other 
paragraphs of this section to avoid double counting of these emissions.
    (o) Centrifugal compressor venting. If you are required to report 
emissions from centrifugal compressor venting as specified in Sec. 
98.232(d)(2), (e)(2), (f)(2), (g)(2), and (h)(2), you must conduct 
volumetric emission measurements specified in paragraph (o)(1) of this 
section using methods specified in paragraphs (o)(2) through (5) of this 
section; perform calculations specified in paragraphs (o)(6) through (9) 
of this section; and calculate CH4 and CO2 mass 
emissions as specified in paragraph (o)(11) of this section. If 
emissions from a compressor source are routed to a flare, paragraphs 
(o)(1) through (11) do not apply and instead you must calculate 
CH4, CO2, and N2O emissions as 
specified in paragraph (o)(12) of this section. If emissions from a 
compressor source are captured for fuel use or are routed to a thermal 
oxidizer, paragraphs (o)(1) through (12) do not apply and instead you 
must calculate and report emissions as specified in subpart C of this 
part. If emissions from a compressor source are routed to vapor 
recovery, paragraphs (o)(1) through (12) do not apply. If you are 
required to report emissions from centrifugal compressor venting at an 
onshore petroleum and natural gas production facility as specified in 
Sec. 98.232(c)(19) or an onshore petroleum and natural gas gathering 
and boosting facility as specified in Sec. 98.232(j)(8), you must 
calculate volumetric emissions as specified in paragraph (o)(10); and 
calculate CH4 and CO2 mass emissions as specified 
in paragraph (o)(11).
    (1) General requirements for conducting volumetric emission 
measurements. You must conduct volumetric emission measurements on each 
centrifugal compressor as specified in this paragraph. Compressor 
sources (as defined in Sec. 98.238) without manifolded vents must use a 
measurement method specified in paragraph (o)(1)(i) or (ii) of this 
section. Manifolded compressor sources (as defined in Sec. 98.238) must 
use a measurement method specified in paragraph (o)(1)(i), (ii), (iii), 
or (iv) of this section.
    (i) Centrifugal compressor source as found measurements. Measure 
venting from each compressor according to either paragraph (o)(1)(i)(A) 
or (B) of this

[[Page 844]]

section at least once annually, based on the compressor mode (as defined 
in Sec. 98.238) in which the compressor was found at the time of 
measurement, except as specified in paragraphs (o)(1)(i)(C) and (D) of 
this section. If additional measurements beyond the required annual 
testing are performed (including duplicate measurements or measurement 
of additional operating modes), then all measurements satisfying the 
applicable monitoring and QA/QC that is required by this paragraph (o) 
must be used in the calculations specified in this section.
    (A) For a compressor measured in operating-mode, you must measure 
volumetric emissions from blowdown valve leakage through the blowdown 
vent as specified in either paragraph (o)(2)(i)(A) or (B) of this 
section and, if the compressor has wet seal oil degassing vents, measure 
volumetric emissions from wet seal oil degassing vents as specified in 
paragraph (o)(2)(ii) of this section.
    (B) For a compressor measured in not-operating-depressurized-mode, 
you must measure volumetric emissions from isolation valve leakage as 
specified in either paragraph (o)(2)(i)(A), (B), or (C) of this section. 
If a compressor is not operated and has blind flanges in place 
throughout the reporting period, measurement is not required in this 
compressor mode.
    (C) You must measure the compressor as specified in paragraph 
(o)(1)(i)(B) of this section at least once in any three consecutive 
calendar years, provided the measurement can be taken during a scheduled 
shutdown. If three consecutive calendar years occur without measuring 
the compressor in not-operating-depressurized-mode, you must measure the 
compressor as specified in paragraph (o)(1)(i)(B) of this section at the 
next scheduled depressurized shutdown. The requirement specified in this 
paragraph does not apply if the compressor has blind flanges in place 
throughout the reporting year. For purposes of this paragraph, a 
scheduled shutdown means a shutdown that requires a compressor to be 
taken off-line for planned or scheduled maintenance. A scheduled 
shutdown does not include instances when a compressor is taken offline 
due to a decrease in demand but must remain available.
    (D) An annual as found measurement is not required in the first year 
of operation for any new compressor that begins operation after as found 
measurements have been conducted for all existing compressors. For only 
the first year of operation of new compressors, calculate emissions 
according to paragraph (o)(6)(ii) of this section.
    (ii) Centrifugal compressor source continuous monitoring. Instead of 
measuring the compressor source according to paragraph (o)(1)(i) of this 
section for a given compressor, you may elect to continuously measure 
volumetric emissions from a compressor source as specified in paragraph 
(o)(3) of this section.
    (iii) Manifolded centrifugal compressor source as found 
measurements. For a compressor source that is part of a manifolded group 
of compressor sources (as defined in Sec. 98.238), instead of measuring 
the compressor source according to paragraph (o)(1)(i), (ii), or (iv) of 
this section, you may elect to measure combined volumetric emissions 
from the manifolded group of compressor sources by conducting 
measurements at the common vent stack as specified in paragraph (o)(4) 
of this section. The measurements must be conducted at the frequency 
specified in paragraphs (o)(1)(iii)(A) and (B) of this section.
    (A) A minimum of one measurement must be taken for each manifolded 
group of compressor sources in a calendar year.
    (B) The measurement may be performed while the compressors are in 
any compressor mode.
    (iv) Manifolded centrifugal compressor source continuous monitoring. 
For a compressor source that is part of a manifolded group of compressor 
sources, instead of measuring the compressor source according to 
paragraph (o)(1)(i), (ii), or (iii) of this section, you may elect to 
continuously measure combined volumetric emissions from the manifolded 
group of compressor sources as specified in paragraph (o)(5) of this 
section.
    (2) Methods for performing as found measurements from individual 
centrifugal

[[Page 845]]

compressor sources. If conducting measurements for each compressor 
source, you must determine the volumetric emissions from blowdown valves 
and isolation valves as specified in paragraph (o)(2)(i) of this 
section, and the volumetric emissions from wet seal oil degassing vents 
as specified in paragraph (o)(2)(ii) of this section.
    (i) For blowdown valves on compressors in operating-mode and for 
isolation valves on compressors in not-operating-depressurized-mode, 
determine the volumetric emissions using one of the methods specified in 
paragraphs (o)(2)(i)(A) through (D) of this section.
    (A) Determine the volumetric flow at standard conditions from the 
blowdown vent using calibrated bagging or high volume sampler according 
to methods set forth in Sec. 98.234(c) and Sec. 98.234(d), 
respectively.
    (B) Determine the volumetric flow at standard conditions from the 
blowdown vent using a temporary meter such as a vane anemometer 
according to methods set forth in Sec. 98.234(b).
    (C) Use an acoustic leak detection device according to methods set 
forth in Sec. 98.234(a)(5).
    (D) You may choose to use any of the methods set forth in Sec. 
98.234(a) to screen for emissions. If emissions are detected using the 
methods set forth in Sec. 98.234(a), then you must use one of the 
methods specified in paragraph (o)(2)(i)(A) through (C) of this section. 
If emissions are not detected using the methods in Sec. 98.234(a), then 
you may assume that the volumetric emissions are zero. For the purposes 
of this paragraph, when using any of the methods in Sec. 98.234(a), 
emissions are detected whenever a leak is detected according to the 
methods.
    (ii) For wet seal oil degassing vents in operating-mode, determine 
vapor volumes at standard conditions, using a temporary meter such as a 
vane anemometer or permanent flow meter according to methods set forth 
in Sec. 98.234(b).
    (3) Methods for continuous measurement from individual centrifugal 
compressor sources. If you elect to conduct continuous volumetric 
emission measurements for an individual compressor source as specified 
in paragraph (o)(1)(ii) of this section, you must measure volumetric 
emissions as specified in paragraphs (o)(3)(i) and (ii) of this section.
    (i) Continuously measure the volumetric flow for the individual 
compressor source at standard conditions using a permanent meter 
according to methods set forth in Sec. 98.234(b).
    (ii) If compressor blowdown emissions are included in the metered 
emissions specified in paragraph (o)(3)(i) of this section, the 
compressor blowdown emissions may be included with the reported 
emissions for the compressor source and do not need to be calculated 
separately using the method specified in paragraph (i) of this section 
for blowdown vent stacks.
    (4) Methods for performing as found measurements from manifolded 
groups of centrifugal compressor sources. If conducting measurements for 
a manifolded group of compressor sources, you must measure volumetric 
emissions as specified in paragraphs (o)(4)(i) and (ii) of this section.
    (i) Measure at a single point in the manifold downstream of all 
compressor inputs and, if practical, prior to comingling with other non-
compressor emission sources.
    (ii) Determine the volumetric flow at standard conditions from the 
common stack using one of the methods specified in paragraphs 
(o)(4)(ii)(A) through (E) of this section.
    (A) A temporary meter such as a vane anemometer according the 
methods set forth in Sec. 98.234(b).
    (B) Calibrated bagging according to methods set forth in Sec. 
98.234(c).
    (C) A high volume sampler according to methods set forth Sec. 
98.234(d).
    (D) An acoustic leak detection device according to methods set forth 
in Sec. 98.234(a)(5).
    (E) You may choose to use any of the methods set forth in Sec. 
98.234(a) to screen for emissions. If emissions are detected using the 
methods set forth in Sec. 98.234(a), then you must use one of the 
methods specified in paragraph (o)(4)(ii)(A) through (o)(4)(ii)(D) of 
this section. If emissions are not detected using the methods in Sec. 
98.234(a), then you may assume that the volumetric emissions are zero. 
For the purposes of this paragraph, when using any of the

[[Page 846]]

methods in Sec. 98.234(a), emissions are detected whenever a leak is 
detected according to the method.
    (5) Methods for continuous measurement from manifolded groups of 
centrifugal compressor sources. If you elect to conduct continuous 
volumetric emission measurements for a manifolded group of compressor 
sources as specified in paragraph (o)(1)(iv) of this section, you must 
measure volumetric emissions as specified in paragraphs (o)(5)(i) 
through (iii) of this section.
    (i) Measure at a single point in the manifold downstream of all 
compressor inputs and, if practical, prior to comingling with other non-
compressor emission sources.
    (ii) Continuously measure the volumetric flow for the manifolded 
group of compressor sources at standard conditions using a permanent 
meter according to methods set forth in Sec. 98.234(b).
    (iii) If compressor blowdown emissions are included in the metered 
emissions specified in paragraph (o)(5)(ii) of this section, the 
compressor blowdown emissions may be included with the reported 
emissions for the manifolded group of compressor sources and do not need 
to be calculated separately using the method specified in paragraph (i) 
of this section for blowdown vent stacks.
    (6) Method for calculating volumetric GHG emissions from as found 
measurements for individual centrifugal compressor sources. For 
compressor sources measured according to paragraph (o)(1)(i) of this 
section, you must calculate annual GHG emissions from the compressor 
sources as specified in paragraphs (o)(6)(i) through (iv) of this 
section.
    (i) Using Equation W-21 of this section, calculate the annual 
volumetric GHG emissions for each centrifugal compressor mode-source 
combination specified in paragraphs (o)(1)(i)(A) and (B) of this section 
that was measured during the reporting year.
[GRAPHIC] [TIFF OMITTED] TR25NO14.064

Where:

Es,i,m = Annual volumetric GHGi (either 
          CH4 or CO2) emissions for measured 
          compressor mode-source combination m, at standard conditions, 
          in cubic feet.
MTs,m = Volumetric gas emissions for measured compressor 
          mode-source combination m, in standard cubic feet per hour, 
          measured according to paragraph (o)(2) of this section. If 
          multiple measurements are performed for a given mode-source 
          combination m, use the average of all measurements.
Tm = Total time the compressor is in the mode-source 
          combination for which Es,i,m is being calculated in 
          the reporting year, in hours.
GHGi,m = Mole fraction of GHGi in the vent gas for 
          measured compressor mode-source combination m; use the 
          appropriate gas compositions in paragraph (u)(2) of this 
          section.
m = Compressor mode-source combination specified in paragraph 
          (o)(1)(i)(A) or (o)(1)(i)(B) of this section that was measured 
          for the reporting year.

    (ii) Using Equation W-22 of this section, calculate the annual 
volumetric GHG emissions from each centrifugal compressor mode-source 
combination specified in paragraph (o)(1)(i)(A) and (B) of this section 
that was not measured during the reporting year.
[GRAPHIC] [TIFF OMITTED] TR25NO14.065

Where:

Es,i,m = Annual volumetric GHGi (either 
          CH4 or CO2) emissions for unmeasured 
          compressor mode-source combination m, at standard conditions, 
          in cubic feet.
EFs,m = Reporter emission factor for compressor mode-source 
          combination m, in standard cubic feet per hour, as calculated 
          in paragraph (o)(6)(iii) of this section.

[[Page 847]]

Tm = Total time the compressor was in the unmeasured mode-
          source combination m, for which Es,i,m is being 
          calculated in the reporting year, in hours.
GHGi,m = Mole fraction of GHGi in the vent gas for 
          unmeasured compressor mode-source combination m; use the 
          appropriate gas compositions in paragraph (u)(2) of this 
          section.
m = Compressor mode-source combination specified in paragraph 
          (o)(1)(i)(A) or (o)(1)(i)(B) of this section that was not 
          measured in the reporting year.

    (iii) Using Equation W-23 of this section, develop an emission 
factor for each compressor mode-source combination specified in 
paragraph (o)(1)(i)(A) and (B) of this section. These emission factors 
must be calculated annually and used in Equation W-22 of this section to 
determine volumetric emissions from a centrifugal compressor in the 
mode-source combinations that were not measured in the reporting year.
[GRAPHIC] [TIFF OMITTED] TR25NO14.045

Where:

EFs,m = Reporter emission factor to be used in Equation W-22 
          of this section for compressor mode-source combination m, in 
          standard cubic feet per hour. The reporter emission factor 
          must be based on all compressors measured in compressor mode-
          source combination m in the current reporting year and the 
          preceding two reporting years.
MTs,m,p = Average volumetric gas emission measurement for 
          compressor mode-source combination m, for compressor p, in 
          standard cubic feet per hour, calculated using all volumetric 
          gas emission measurements (MTs,m in Equation W-21 
          of this section) for compressor mode-source combination m for 
          compressor p in the current reporting year and the preceding 
          two reporting years.
Countm = Total number of compressors measured in compressor 
          mode-source combination m in the current reporting year and 
          the preceding two reporting years.
m = Compressor mode-source combination specified in paragraph 
          (o)(1)(i)(A) or (o)(1)(i)(B) of this section.

    (iv) The reporter emission factor in Equation W-23 of this section 
may be calculated by using all measurements from a single owner or 
operator instead of only using measurements from a single facility. If 
you elect to use this option, the reporter emission factor must be 
applied to all reporting facilities for the owner or operator.
    (7) Method for calculating volumetric GHG emissions from continuous 
monitoring of individual centrifugal compressor sources. For compressor 
sources measured according to paragraph (o)(1)(ii) of this section, you 
must use the continuous volumetric emission measurements taken as 
specified in paragraph (o)(3) of this section and calculate annual 
volumetric GHG emissions associated with the compressor source using 
Equation W-24A of this section.
[GRAPHIC] [TIFF OMITTED] TR25NO14.066

Where:

Es,i,v = Annual volumetric GHGi (either 
          CH4 or CO2) emissions from compressor 
          source v, at standard conditions, in cubic feet.
Qs,v = Volumetric gas emissions from compressor source v, for 
          reporting year, in standard cubic feet.
GHGi,v = Mole fraction of GHGi in the vent gas for 
          compressor source v; use the appropriate gas compositions in 
          paragraph (u)(2) of this section.


[[Page 848]]


    (8) Method for calculating volumetric GHG emissions from as found 
measurements of manifolded groups of centrifugal compressor sources. For 
manifolded groups of compressor sources measured according to paragraph 
(o)(1)(iii) of this section, you must calculate annual volumetric GHG 
emissions using Equation W-24B of this section. If the centrifugal 
compressors included in the manifolded group of compressor sources share 
the manifold with reciprocating compressors, you must follow the 
procedures in either this paragraph (o)(8) or paragraph (p)(8) of this 
section to calculate emissions from the manifolded group of compressor 
sources.
[GRAPHIC] [TIFF OMITTED] TR25NO14.067

Where:

Es,i,g = Annual volumetric GHGi (either 
          CH4 or CO2) emissions for manifolded 
          group of compressor sources g, at standard conditions, in 
          cubic feet.
Tg = Total time the manifolded group of compressor sources g 
          had potential for emissions in the reporting year, in hours. 
          Include all time during which at least one compressor source 
          in the manifolded group of compressor sources g was in a mode-
          source combination specified in either paragraph (o)(1)(i)(A), 
          (o)(1)(i)(B), (p)(1)(i)(A), (p)(1)(i)(B), or (p)(1)(i)(C) of 
          this section. Default of 8760 hours may be used.
MTs,g,avg = Average volumetric gas emissions of all 
          measurements performed in the reporting year according to 
          paragraph (o)(4) of this section for the manifolded group of 
          compressor sources g, in standard cubic feet per hour.
GHGi,g = Mole fraction of GHG i in the vent gas 
          for manifolded group of compressor sources g; use the 
          appropriate gas compositions in paragraph (u)(2) of this 
          section.

    (9) Method for calculating volumetric GHG emissions from continuous 
monitoring of manifolded group of centrifugal compressor sources. For a 
manifolded group of compressor sources measured according to paragraph 
(o)(1)(iv) of this section, you must use the continuous volumetric 
emission measurements taken as specified in paragraph (o)(5) of this 
section and calculate annual volumetric GHG emissions associated with 
each manifolded group of compressor sources using Equation W-24C of this 
section. If the centrifugal compressors included in the manifolded group 
of compressor sources share the manifold with reciprocating compressors, 
you must follow the procedures in either this paragraph (o)(9) or 
paragraph (p)(9) of this section to calculate emissions from the 
manifolded group of compressor sources.
[GRAPHIC] [TIFF OMITTED] TR25NO14.068

Where:

Es,i,g = Annual volumetric GHGi (either 
          CH4 or CO2) emissions from manifolded 
          group of compressor sources g, at standard conditions, in 
          cubic feet.
Qs,g = Volumetric gas emissions from manifolded group of 
          compressor sources g, for reporting year, in standard cubic 
          feet.
GHGi,g = Mole fraction of GHG i in the vent gas 
          for measured manifolded group of compressor sources g; use the 
          appropriate gas compositions in paragraph (u)(2) of this 
          section.

    (10) Method for calculating volumetric GHG emissions from wet seal 
oil degassing vents at an onshore petroleum and natural gas production 
facility or an onshore petroleum and natural gas gathering and boosting 
facility. You must calculate emissions from centrifugal compressor wet 
seal oil degassing vents at an onshore petroleum and natural gas 
production facility or an onshore petroleum and natural gas gathering 
and boosting facility using Equation W-25 of this section.

[[Page 849]]

[GRAPHIC] [TIFF OMITTED] TR22OC15.011

Where:

Es,i = Annual volumetric GHGi (either 
          CH4 or CO2) emissions from centrifugal 
          compressor wet seals, at standard conditions, in cubic feet.
Count = Total number of centrifugal compressors that have wet seal oil 
          degassing vents.
EFi,s = Emission factor for GHGi. Use 1.2 x 10\7\ 
          standard cubic feet per year per compressor for CH4 
          and 5.30 x 10\5\ standard cubic feet per year per compressor 
          for CO2 at 60  deg.F and 14.7 psia.

    (11) Method for converting from volumetric to mass emissions. You 
must calculate both CH4 and CO2 mass emissions 
from volumetric emissions using calculations in paragraph (v) of this 
section.
    (12) General requirements for calculating volumetric GHG emissions 
from centrifugal compressors routed to flares. You must calculate and 
report emissions from all centrifugal compressor sources that are routed 
to a flare as specified in paragraphs (o)(12)(i) through (iii) of this 
section.
    (i) Paragraphs (o)(1) through (11) of this section are not required 
for compressor sources that are routed to a flare.
    (ii) If any compressor sources are routed to a flare, calculate the 
emissions for the flare stack as specified in paragraph (n) of this 
section and report emissions from the flare as specified in Sec. 
98.236(n), without subtracting emissions attributable to compressor 
sources from the flare.
    (iii) Report all applicable activity data for compressors with 
compressor sources routed to flares as specified in Sec. 98.236(o).
    (p) Reciprocating compressor venting. If you are required to report 
emissions from reciprocating compressor venting as specified in Sec. 
98.232(d)(1), (e)(1), (f)(1), (g)(1), and (h)(1), you must conduct 
volumetric emission measurements specified in paragraph (p)(1) of this 
section using methods specified in paragraphs (p)(2) through (5) of this 
section; perform calculations specified in paragraphs (p)(6) through (9) 
of this section; and calculate CH4 and CO2 mass 
emissions as specified in paragraph (p)(11) of this section. If 
emissions from a compressor source are routed to a flare, paragraphs 
(p)(1) through (11) do not apply and instead you must calculate 
CH4, CO2, and N2O emissions as 
specified in paragraph (p)(12) of this section. If emissions from a 
compressor source are captured for fuel use or are routed to a thermal 
oxidizer, paragraphs (p)(1) through (12) do not apply and instead you 
must calculate and report emissions as specified in subpart C of this 
part. If emissions from a compressor source are routed to vapor 
recovery, paragraphs (p)(1) through (12) do not apply. If you are 
required to report emissions from reciprocating compressor venting at an 
onshore petroleum and natural gas production facility as specified in 
Sec. 98.232(c)(11) or an onshore petroleum and natural gas gathering 
and boosting facility as specified in Sec. 98.232(j)(5), you must 
calculate volumetric emissions as specified in paragraph (p)(10); and 
calculate CH4 and CO2 mass emissions as specified 
in paragraph (p)(11).
    (1) General requirements for conducting volumetric emission 
measurements. You must conduct volumetric emission measurements on each 
reciprocating compressor as specified in this paragraph. Compressor 
sources (as defined in Sec. 98.238) without manifolded vents must use a 
measurement method specified in paragraph (p)(1)(i) or (ii) of this 
section. Manifolded compressor sources (as defined in Sec. 98.238) must 
use a measurement method specified in paragraph (p)(1)(i), (ii), (iii), 
or (iv) of this section.
    (i) Reciprocating compressor source as found measurements. Measure 
venting from each compressor according to either paragraph (p)(1)(i)(A), 
(B), or (C) of this section at least once annually, based on the 
compressor mode (as defined in Sec. 98.238) in which the compressor was 
found at the time of measurement, except as specified in paragraphs 
(p)(1)(i)(D) and (E) of this section. If additional measurements beyond 
the required annual testing are

[[Page 850]]

performed (including duplicate measurements or measurement of additional 
operating modes), then all measurements satisfying the applicable 
monitoring and QA/QC that is required by this paragraph (o) must be used 
in the calculations specified in this section.
    (A) For a compressor measured in operating-mode, you must measure 
volumetric emissions from blowdown valve leakage through the blowdown 
vent as specified in either paragraph (p)(2)(i)(A) or (B) of this 
section, and measure volumetric emissions from reciprocating rod packing 
as specified in paragraph (p)(2)(ii) of this section.
    (B) For a compressor measured in standby-pressurized-mode, you must 
measure volumetric emissions from blowdown valve leakage through the 
blowdown vent as specified in either paragraph (p)(2)(i)(A) or (B) of 
this section.
    (C) For a compressor measured in not-operating-depressurized-mode, 
you must measure volumetric emissions from isolation valve leakage as 
specified in either paragraph (p)(2)(i)(A), (B), or (C) of this section. 
If a compressor is not operated and has blind flanges in place 
throughout the reporting period, measurement is not required in this 
compressor mode.
    (D) You must measure the compressor as specified in paragraph 
(p)(1)(i)(C) of this section at least once in any three consecutive 
calendar years, provided the measurement can be taken during a scheduled 
shutdown. If there is no scheduled shutdown within three consecutive 
calendar years, you must measure the compressor as specified in 
paragraph (p)(1)(i)(C) of this section at the next scheduled 
depressurized shutdown. For purposes of this paragraph, a scheduled 
shutdown means a shutdown that requires a compressor to be taken off-
line for planned or scheduled maintenance. A scheduled shutdown does not 
include instances when a compressor is taken offline due to a decrease 
in demand but must remain available.
    (E) An annual as found measurement is not required in the first year 
of operation for any new compressor that begins operation after as found 
measurements have been conducted for all existing compressors. For only 
the first year of operation of new compressors, calculate emissions 
according to paragraph (p)(6)(ii) of this section.
    (ii) Reciprocating compressor source continuous monitoring. Instead 
of measuring the compressor source according to paragraph (p)(1)(i) of 
this section for a given compressor, you may elect to continuously 
measure volumetric emissions from a compressor source as specified in 
paragraph (p)(3) of this section.
    (iii) Manifolded reciprocating compressor source as found 
measurements. For a compressor source that is part of a manifolded group 
of compressor sources (as defined in Sec. 98.238), instead of measuring 
the compressor source according to paragraph (p)(1)(i), (ii), or (iv) of 
this section, you may elect to measure combined volumetric emissions 
from the manifolded group of compressor sources by conducting 
measurements at the common vent stack as specified in paragraph (p)(4) 
of this section. The measurements must be conducted at the frequency 
specified in paragraphs (p)(1)(iii)(A) and (B) of this section.
    (A) A minimum of one measurement must be taken for each manifolded 
group of compressor sources in a calendar year.
    (B) The measurement may be performed while the compressors are in 
any compressor mode.
    (iv) Manifolded reciprocating compressor source continuous 
monitoring. For a compressor source that is part of a manifolded group 
of compressor sources, instead of measuring the compressor source 
according to paragraph (p)(1)(i), (ii), or (iii) of this section, you 
may elect to continuously measure combined volumetric emissions from the 
manifolded group of compressors sources as specified in paragraph (p)(5) 
of this section.
    (2) Methods for performing as found measurements from individual 
reciprocating compressor sources. If conducting measurements for each 
compressor source, you must determine the volumetric emissions from 
blowdown valves and isolation valves as specified in paragraph (p)(2)(i) 
of this section. You must determine the volumetric

[[Page 851]]

emissions from reciprocating rod packing as specified in paragraph 
(p)(2)(ii) or (iii) of this section.
    (i) For blowdown valves on compressors in operating-mode or standby-
pressurized-mode, and for isolation valves on compressors in not-
operating-depressurized-mode, determine the volumetric emissions using 
one of the methods specified in paragraphs (p)(2)(i)(A) through (D) of 
this section.
    (A) Determine the volumetric flow at standard conditions from the 
blowdown vent using calibrated bagging or high volume sampler according 
to methods set forth in Sec. 98.234(c) and (d), respectively.
    (B) Determine the volumetric flow at standard conditions from the 
blowdown vent using a temporary meter such as a vane anemometer, 
according to methods set forth in Sec. 98.234(b).
    (C) Use an acoustic leak detection device according to methods set 
forth in Sec. 98.234(a)(5).
    (D) You may choose to use any of the methods set forth in Sec. 
98.234(a) to screen for emissions. If emissions are detected using the 
methods set forth in Sec. 98.234(a), then you must use one of the 
methods specified in paragraphs (p)(2)(i)(A) through (C) of this 
section. If emissions are not detected using the methods in Sec. 
98.234(a), then you may assume that the volumetric emissions are zero. 
For the purposes of this paragraph, when using any of the methods in 
Sec. 98.234(a), emissions are detected whenever a leak is detected 
according to the method.
    (ii) For reciprocating rod packing equipped with an open-ended vent 
line on compressors in operating-mode, determine the volumetric 
emissions using one of the methods specified in paragraphs (p)(2)(ii)(A) 
through (C) of this section.
    (A) Determine the volumetric flow at standard conditions from the 
open-ended vent line using calibrated bagging or high volume sampler 
according to methods set forth in Sec. 98.234(c) and (d), respectively.
    (B) Determine the volumetric flow at standard conditions from the 
open-ended vent line using a temporary meter such as a vane anemometer, 
according to methods set forth in Sec. 98.234(b).
    (C) You may choose to use any of the methods set forth in Sec. 
98.234(a) to screen for emissions. If emissions are detected using the 
methods set forth in Sec. 98.234(a), then you must use one of the 
methods specified in paragraph (p)(2)(ii)(A) and (p)(4)(ii)(B) of this 
section. If emissions are not detected using the methods in Sec. 
98.234(a), then you may assume that the volumetric emissions are zero. 
For the purposes of this paragraph, when using any of the methods in 
Sec. 98.234(a), emissions are detected whenever a leak is detected 
according to the method.
    (iii) For reciprocating rod packing not equipped with an open-ended 
vent line on compressors in operating-mode, you must determine the 
volumetric emissions using the method specified in paragraphs 
(p)(2)(iii)(A) and (B) of this section.
    (A) You must use the methods described in Sec. 98.234(a) to conduct 
annual leak detection of equipment leaks from the packing case into an 
open distance piece, or for compressors with a closed distance piece, 
conduct annual detection of gas emissions from the rod packing vent, 
distance piece vent, compressor crank case breather cap, or other vent 
emitting gas from the rod packing.
    (B) You must measure emissions found in paragraph (p)(2)(iii)(A) of 
this section using an appropriate meter, calibrated bag, or high volume 
sampler according to methods set forth in Sec. 98.234(b), (c), and (d), 
respectively.
    (3) Methods for continuous measurement from individual reciprocating 
compressor sources. If you elect to conduct continuous volumetric 
emission measurements for an individual compressor source as specified 
in paragraph (p)(1)(ii) of this section, you must measure volumetric 
emissions as specified in paragraphs (p)(3)(i) and (p)(3)(ii) of this 
section.
    (i) Continuously measure the volumetric flow for the individual 
compressor sources at standard conditions using a permanent meter 
according to methods set forth in Sec. 98.234(b).
    (ii) If compressor blowdown emissions are included in the metered 
emissions specified in paragraph (p)(3)(i) of this section, the 
compressor blowdown

[[Page 852]]

emissions may be included with the reported emissions for the compressor 
source and do not need to be calculated separately using the method 
specified in paragraph (i) of this section for blowdown vent stacks.
    (4) Methods for performing as found measurements from manifolded 
groups of reciprocating compressor sources. If conducting measurements 
for a manifolded group of compressor sources, you must measure 
volumetric emissions as specified in paragraphs (p)(4)(i) and (ii) of 
this section.
    (i) Measure at a single point in the manifold downstream of all 
compressor inputs and, if practical, prior to comingling with other non-
compressor emission sources.
    (ii) Determine the volumetric flow at standard conditions from the 
common stack using one of the methods specified in paragraph 
(p)(4)(ii)(A) through (E) of this section.
    (A) A temporary meter such as a vane anemometer according the 
methods set forth in Sec. 98.234(b).
    (B) Calibrated bagging according to methods set forth in Sec. 
98.234(c).
    (C) A high volume sampler according to methods set forth Sec. 
98.234(d).
    (D) An acoustic leak detection device according to methods set forth 
in Sec. 98.234(a)(5).
    (E) You may choose to use any of the methods set forth in Sec. 
98.234(a) to screen for emissions. If emissions are detected using the 
methods set forth in Sec. 98.234(a), then you must use one of the 
methods specified in paragraph (p)(4)(ii)(A) through (D) of this 
section. If emissions are not detected using the methods in Sec. 
98.234(a), then you may assume that the volumetric emissions are zero. 
For the purposes of this paragraph, when using any of the methods in 
Sec. 98.234(a), emissions are detected whenever a leak is detected 
according to the method.
    (5) Methods for continuous measurement from manifolded groups of 
reciprocating compressor sources. If you elect to conduct continuous 
volumetric emission measurements for a manifolded group of compressor 
sources as specified in paragraph (p)(1)(iv) of this section, you must 
measure volumetric emissions as specified in paragraphs (p)(5)(i) 
through (iii) of this section.
    (i) Measure at a single point in the manifold downstream of all 
compressor inputs and, if practical, prior to comingling with other non-
compressor emission sources.
    (ii) Continuously measure the volumetric flow for the manifolded 
group of compressor sources at standard conditions using a permanent 
meter according to methods set forth in Sec. 98.234(b).
    (iii) If compressor blowdown emissions are included in the metered 
emissions specified in paragraph (p)(5)(ii) of this section, the 
compressor blowdown emissions may be included with the reported 
emissions for the manifolded group of compressor sources and do not need 
to be calculated separately using the method specified in paragraph (i) 
of this section for blowdown vent stacks.
    (6) Method for calculating volumetric GHG emissions from as found 
measurements for individual reciprocating compressor sources. For 
compressor sources measured according to paragraph (p)(1)(i) of this 
section, you must calculate GHG emissions from the compressor sources as 
specified in paragraphs (p)(6)(i) through (iv) of this section.
    (i) Using Equation W-26 of this section, calculate the annual 
volumetric GHG emissions for each reciprocating compressor mode-source 
combination specified in paragraphs (p)(1)(i)(A) through (C) of this 
section that was measured during the reporting year.
[GRAPHIC] [TIFF OMITTED] TR25NO14.070

Where:

Es,i,m = Annual volumetric GHGi (either 
          CH4 or CO2) emissions for measured 
          compressor mode-source combination m, at standard conditions, 
          in cubic feet.

[[Page 853]]

MTs,m = Volumetric gas emissions for measured compressor 
          mode-source combination m, in standard cubic feet per hour, 
          measured according to paragraph (p)(2) of this section. If 
          multiple measurements are performed for a given mode-source 
          combination m, use the average of all measurements.
Tm = Total time the compressor is in the mode-source 
          combination m, for which Es,i,m is being calculated 
          in the reporting year, in hours.
GHGi,m = Mole fraction of GHGi in the vent gas for 
          measured compressor mode-source combination m; use the 
          appropriate gas compositions in paragraph (u)(2) of this 
          section.
m = Compressor mode-source combination specified in paragraph 
          (p)(1)(i)(A), (B), or (C) of this section that was measured 
          for the reporting year.

    (ii) Using Equation W-27 of this section, calculate the annual 
volumetric GHG emissions from each reciprocating compressor mode-source 
combination specified in paragraph (p)(1)(i)(A), (B), and (C) of this 
section that was not measured during the reporting year.
[GRAPHIC] [TIFF OMITTED] TR25NO14.046

Where:

Es,i,m = Annual volumetric GHGi (either 
          CH4 or CO2) emissions for unmeasured 
          compressor mode-source combination m, at standard conditions, 
          in cubic feet.
EFs,m = Reporter emission factor for compressor mode-source 
          combination m, in standard cubic feet per hour, as calculated 
          in paragraph (p)(6)(iii) of this section.
Tm = Total time the compressor was in the unmeasured mode-
          source combination m, for which Es,i,m is being 
          calculated in the reporting year, in hours.
GHGi,m = Mole fraction of GHGi in the vent gas for 
          unmeasured compressor mode-source combination m; use the 
          appropriate gas compositions in paragraph (u)(2) of this 
          section.
m = Compressor mode-source combination specified in paragraph 
          (p)(1)(i)(A), (p)(1)(i)(B), or (p)(1)(i)(C) of this section 
          that was not measured for the reporting year.

    (iii) Using Equation W-28 of this section, develop an emission 
factor for each compressor mode-source combination specified in 
paragraph (p)(1)(i)(A), (B), and (C) of this section. These emission 
factors must be calculated annually and used in Equation W-27 of this 
section to determine volumetric emissions from a reciprocating 
compressor in the mode-source combinations that were not measured in the 
reporting year.
[GRAPHIC] [TIFF OMITTED] TR25NO14.047

Where:

EFs,m = Reporter emission factor to be used in Equation W-27 
          of this section for compressor mode-source combination m, in 
          standard cubic feet per hour. The reporter emission factor 
          must be based on all compressors measured in compressor mode-
          source combination m in the current reporting year and the 
          preceding two reporting years.
MTs,m,p = Average volumetric gas emission measurement for 
          compressor mode-source combination m, for compressor p, in 
          standard cubic feet per hour, calculated using all volumetric 
          gas emission measurements (MTs,m in Equation W-26 
          of this section) for compressor mode-source combination m for 
          compressor p in the current reporting year and the preceding 
          two reporting years.
Countm = Total number of compressors measured in compressor 
          mode-source combination m in the current reporting year and 
          the preceding two reporting years.
m = Compressor mode-source combination specified in paragraph 
          (p)(1)(i)(A), (B), or (C) of this section.


[[Page 854]]


    (iv) The reporter emission factor in Equation W-28 of this section 
may be calculated by using all measurements from a single owner or 
operator instead of only using measurements from a single facility. If 
you elect to use this option, the reporter emission factor must be 
applied to all reporting facilities for the owner or operator.
    (7) Method for calculating volumetric GHG emissions from continuous 
monitoring of individual reciprocating compressor sources. For 
compressor sources measured according to paragraph (p)(1)(ii) of this 
section, you must use the continuous volumetric emission measurements 
taken as specified in paragraph (p)(3) of this section and calculate 
annual volumetric GHG emissions associated with the compressor source 
using Equation W-29A of this section.
[GRAPHIC] [TIFF OMITTED] TR25NO14.071

Where:

Es,i,v = Annual volumetric GHGi (either 
          CH4 or CO2) emissions from compressor 
          source v, at standard conditions, in cubic feet.
Qs,v = Volumetric gas emissions from compressor source v, for 
          reporting year, in standard cubic feet.
GHGi,v = Mole fraction of GHGi in the vent gas for 
          compressor source v; use the appropriate gas compositions in 
          paragraph (u)(2) of this section.

    (8) Method for calculating volumetric GHG emissions from as found 
measurements of manifolded groups of reciprocating compressor sources. 
For manifolded groups of compressor sources measured according to 
paragraph (p)(1)(iii) of this section, you must calculate annual GHG 
emissions using Equation W-29B of this section. If the reciprocating 
compressors included in the manifolded group of compressor sources share 
the manifold with centrifugal compressors, you must follow the 
procedures in either this paragraph (p)(8) or paragraph (o)(8) of this 
section to calculate emissions from the manifolded group of compressor 
sources.
[GRAPHIC] [TIFF OMITTED] TR25NO14.072

Where:

Es,i,g = Annual volumetric GHGi (either 
          CH4 or CO2) emissions for manifolded 
          group of compressor sources g, at standard conditions, in 
          cubic feet.
Tg = Total time the manifolded group of compressor sources g 
          had potential for emissions in the reporting year, in hours. 
          Include all time during which at least one compressor source 
          in the manifolded group of compressor sources g was in a mode-
          source combination specified in either paragraph (o)(1)(i)(A), 
          (o)(1)(i)(B), (p)(1)(i)(A), (p)(1)(i)(B), or (p)(1)(i)(C) of 
          this section. Default of 8760 hours may be used.
MTs,g,avg = Average volumetric gas emissions of all 
          measurements performed in the reporting year according to 
          paragraph (p)(4) of this section for the manifolded group of 
          compressor sources g, in standard cubic feet per hour.
GHGi,g = Mole fraction of GHGi in the vent gas for 
          manifolded group of compressor sources g; use the appropriate 
          gas compositions in paragraph (u)(2) of this section.

    (9) Method for calculating volumetric GHG emissions from continuous 
monitoring of manifolded group of reciprocating compressor sources. For 
a manifolded group of compressor sources measured according to paragraph 
(p)(1)(iv) of this section, you must use the continuous volumetric 
emission measurements taken as specified in paragraph (p)(5) of this 
section and calculate annual volumetric GHG emissions associated with 
each manifolded group of compressor sources using Equation W-29C of this

[[Page 855]]

section. If the reciprocating compressors included in the manifolded 
group of compressor sources share the manifold with centrifugal 
compressors, you must follow the procedures in either this paragraph 
(p)(9) or paragraph (o)(9) of this section to calculate emissions from 
the manifolded group of compressor sources.
[GRAPHIC] [TIFF OMITTED] TR25NO14.073

Where:

Es,i,g = Annual volumetric GHGi (either 
          CH4 or CO2) emissions from manifolded 
          group of compressor sources g, at standard conditions, in 
          cubic feet.
Qs,g = Volumetric gas emissions from manifolded group of 
          compressor sources g, for reporting year, in standard cubic 
          feet.
GHGi,g = Mole fraction of GHGi in the vent gas for 
          measured manifolded group of compressor sources g; use the 
          appropriate gas compositions in paragraph (u)(2) of this 
          section.

    (10) Method for calculating volumetric GHG emissions from 
reciprocating compressor venting at an onshore petroleum and natural gas 
production facility or an onshore petroleum and natural gas gathering 
and boosting facility. You must calculate emissions from reciprocating 
compressor venting at an onshore petroleum and natural gas production 
facility or an onshore petroleum and natural gas gathering and boosting 
facility using Equation W-29D of this section.
[GRAPHIC] [TIFF OMITTED] TR22OC15.012

Where:

Es,i = Annual volumetric GHGi (either 
          CH4 or CO2) emissions from reciprocating 
          compressors, at standard conditions, in cubic feet.
Count = Total number of reciprocating compressors.
EFi,s = Emission factor for GHGi. Use 9.48 x 10\3\ 
          standard cubic feet per year per compressor for CH4 
          and 5.27 x 10\2\ standard cubic feet per year per compressor 
          for CO2 at 60  deg.F and 14.7 psia.

    (11) Method for converting from volumetric to mass emissions. You 
must calculate both CH4 and CO2 mass emissions 
from volumetric emissions using calculations in paragraph (v) of this 
section.
    (12) General requirements for calculating volumetric GHG emissions 
from reciprocating compressors routed to flares. You must calculate and 
report emissions from all reciprocating compressor sources that are 
routed to a flare as specified in paragraphs (p)(12)(i) through (iii) of 
this section.
    (i) Paragraphs (p)(1) through (11) of this section are not required 
for compressor sources that are routed to a flare.
    (ii) If any compressor sources are routed to a flare, calculate the 
emissions for the flare stack as specified in paragraph (n) of this 
section and report emissions from the flare as specified in Sec. 
98.236(n), without subtracting emissions attributable to compressor 
sources from the flare.
    (iii) Report all applicable activity data for compressors with 
compressor sources routed to flares as specified in Sec. 98.236(p).
    (q) Equipment leak surveys. You must use the methods described in 
Sec. 98.234(a) to conduct leak detection(s) of equipment leaks from all 
component types listed in Sec. 98.232(d)(7), (e)(7), (f)(5), (g)(3), 
(h)(4), and (i)(1). This paragraph (q) applies to component types in 
streams with gas content greater than 10 percent CH4 plus 
CO2 by weight. Component types in streams with gas content 
less than or equal to 10 percent CH4 plus CO2 by 
weight are exempt from the requirements of this paragraph (q) and do not 
need to be reported. Tubing

[[Page 856]]

systems equal to or less than one half inch diameter are exempt from the 
requirements of this paragraph (q) and do not need to be reported. For 
industry segments listed in Sec. 98.230(a)(3) through (8), if equipment 
leaks are detected for component types listed in this paragraph (q), 
then you must calculate equipment leak emissions per component type per 
reporting facility using Equation W-30 of this section. For the industry 
segment listed in Sec. 98.230(a)(8), the results from Equation W-30 are 
used to calculate population emission factors on a meter/regulator run 
basis using Equation W-31 of this section. If you chose to conduct 
equipment leak surveys at all above grade transmission-distribution 
transfer stations over multiple years, ``n,'' according to paragraph 
(q)(8)(i) of this section, then you must calculate the emissions from 
all above grade transmission-distribution transfer stations as specified 
in paragraph (q)(9) of this section.
[GRAPHIC] [TIFF OMITTED] TR25NO14.048

Where:

Es,p,i = Annual total volumetric emissions of GHGi 
          from specific component type ``p'' (listed in Sec. 
          98.232(d)(7), (e)(7), (f)(5), (g)(3), (h)(4), and (i)(1)) in 
          standard (``s'') cubic feet, as specified in paragraphs (q)(1) 
          through (q)(8) of this section.
xp = Total number of specific component type ``p'' detected 
          as leaking during annual leak surveys.
EFs,p = Leaker emission factor for specific component types 
          listed in Table W-2 through Table W-7 of this subpart.
GHGi = For onshore natural gas processing facilities, 
          concentration of GHGi, CH4 or 
          CO2, in the total hydrocarbon of the feed natural 
          gas; for onshore natural gas transmission compression and 
          underground natural gas storage, GHGi equals 0.975 
          for CH4 and 1.1 x 10-2 for 
          CO2 ; for LNG storage and LNG import and export 
          equipment, GHGi equals 1 for CH4 and 0 
          for CO2 ; and for natural gas distribution, 
          GHGi equals 1 for CH4 and 1.1 x 
          10-2 CO2.
Tp,z = The total time the surveyed component ``z'', component 
          type ``p'', was assumed to be leaking and operational, in 
          hours. If one leak detection survey is conducted in the 
          calendar year, assume the component was leaking for the entire 
          calendar year, accounting for time the component was not 
          operational (i.e., not operating under pressure) using 
          engineering estimate based on best available data. If multiple 
          leak detection surveys are conducted in the calendar year, 
          assume that the component found to be leaking has been leaking 
          since the previous survey (if not found leaking in the 
          previous survey) or the beginning of the calendar year (if it 
          was found leaking in the previous survey), accounting for time 
          the component was not operational using engineering estimate 
          based on best available data. For the last leak detection 
          survey in the calendar year, assume that all leaking 
          components continue to leak until the end of the calendar 
          year, accounting for time the component was not operational 
          using engineering estimate based on best available data.

    (1) You must conduct either one leak detection survey in a calendar 
year or multiple complete leak detection surveys in a calendar year. The 
leak detection surveys selected must be conducted during the calendar 
year.
    (2) Calculate both CO2 and CH4 mass emissions 
using calculations in paragraph (v) of this section.
    (3) Onshore natural gas processing facilities must use the 
appropriate default total hydrocarbon leaker emission factors for 
compressor components in gas service and non-compressor components in 
gas service listed in Table W-2 of this subpart.
    (4) Onshore natural gas transmission compression facilities must use 
the appropriate default total hydrocarbon leaker emission factors for 
compressor components in gas service and non-compressor components in 
gas service listed in Table W-3 of this subpart.
    (5) Underground natural gas storage facilities must use the 
appropriate default total hydrocarbon leaker emission factors for 
storage stations in gas service listed in Table W-4 of this subpart.
    (6) LNG storage facilities must use the appropriate default methane 
leaker

[[Page 857]]

emission factors for LNG storage components in gas service listed in 
Table W-5 of this subpart.
    (7) LNG import and export facilities must use the appropriate 
default methane leaker emission factors for LNG terminals components in 
LNG service listed in Table W-6 of this subpart.
    (8) Natural gas distribution facilities must use Equation W-30 of 
this section and the default methane leaker emission factors for 
transmission-distribution transfer station components in gas service 
listed in Table W-7 of this subpart to calculate component emissions 
from annual equipment leak surveys conducted at above grade 
transmission-distribution transfer stations. Natural gas distribution 
facilities are required to perform equipment leak surveys only at above 
grade stations that qualify as transmission-distribution transfer 
stations. Below grade transmission-distribution transfer stations and 
all metering-regulating stations that do not meet the definition of 
transmission-distribution transfer stations are not required to perform 
equipment leak surveys under this section.
    (i) Natural gas distribution facilities may choose to conduct 
equipment leak surveys at all above grade transmission-distribution 
transfer stations over multiple years ``n'', not exceeding a five year 
period to cover all above grade transmission-distribution transfer 
stations. If the facility chooses to use the multiple year option, then 
the number of transmission-distribution transfer stations that are 
monitored in each year should be approximately equal across all years in 
the cycle.
    (ii) Use Equation W-31 of this section to determine the meter/
regulator run population emission factors for each GHGi. As 
additional survey data become available, you must recalculate the meter/
regulator run population emission factors for each GHGi 
annually according to paragraph (q)(8)(iii) of this section.
[GRAPHIC] [TIFF OMITTED] TR25NO14.049

Where:

EFs,MR,i = Meter/regulator run population emission factor for 
          GHGi based on all surveyed above grade 
          transmission-distribution transfer stations over ``n'' years, 
          in standard cubic feet of GHGi per operational hour 
          of all meter/regulator runs.
Es,p,i,y = Annual total volumetric emissions at standard 
          conditions of GHGi from component type ``p'' during 
          year ``y'' in standard (``s'') cubic feet, as calculated using 
          Equation W-30 of this section.
p = Seven component types listed in Table W-7 of this subpart for 
          transmission-distribution transfer stations.
Tw,y = The total time the surveyed meter/regulator run ``w'' 
          was operational, in hours during survey year ``y'' using 
          engineering estimate based on best available data.
CountMR,y = Count of meter/regulator runs surveyed at above 
          grade transmission-distribution transfer stations in year 
          ``y''.
y = Year of data included in emission factor ``EFs,MR,i'' 
          according to paragraph (q)(8)(iii) of this section.
n = Number of years of data, according to paragraph (q)(8)(i) of this 
          section, whose results are used to calculate emission factor 
          ``EFs,MR,i'' according to paragraph (q)(8)(iii) of 
          this section.

    (iii) The emission factor ``EFs,MR,i'', based on annual 
equipment leak surveys at above grade transmission-distribution transfer 
stations, must be calculated annually. If you chose to conduct equipment 
leak surveys at all above grade transmission-distribution transfer 
stations over multiple years, ``n,'' according to paragraph (q)(8)(i) of 
this section and you have submitted a smaller number of annual reports 
than

[[Page 858]]

the duration of the selected cycle period of 5 years or less, then all 
available data from the current year and previous years must be used in 
the calculation of the emission factor ``EFs,MR,i'' from 
Equation W-31 of this section. After the first survey cycle of ``n'' 
years is completed and beginning in calendar year (n + 1), the survey 
will continue on a rolling basis by including the survey results from 
the current calendar year ``y'' and survey results from all previous (n-
1) calendar years, such that each annual calculation of the emission 
factor ``EFs,MR,i'' from Equation W-31 of this section is 
based on survey results from ``n'' years. Upon completion of a cycle, 
you may elect to change the number of years in the next cycle period (to 
be 5 years or less). If the number of years in the new cycle is greater 
than the number of years in the previous cycle, calculate 
``EFs,MR,i'' from Equation W-31 of this section in each year 
of the new cycle using the survey results from the current calendar year 
and the survey results from the preceding number years that is equal to 
the number of years in the previous cycle period. If the number of 
years, ``nnew'', in the new cycle is smaller than the number 
of years in the previous cycle, ``n'', calculate ``EFs,MR,i'' 
from Equation W-31 of this section in each year of the new cycle using 
the survey results from the current calendar year and survey results 
from all previous (nnew-1) calendar years.
    (9) If you chose to conduct equipment leak surveys at all above 
grade transmission-distribution transfer stations over multiple years, 
``n,'' according to paragraph (q)(8)(i) of this section, you must use 
the meter/regulator run population emission factors calculated using 
Equation W-31 of this section and the total count of all meter/regulator 
runs at above grade transmission-distribution transfer stations to 
calculate emissions from all above grade transmission-distribution 
transfer stations using Equation W-32B in paragraph (r) of this section.
    (r) Equipment leaks by population count. This paragraph (r) applies 
to emissions sources listed in Sec. 98.232 (c)(21), (f)(5), (g)(3), 
(h)(4), (i)(2), (i)(3), (i)(4), (i)(5), (i)(6), (j)(10), and (j)(11) on 
streams with gas content greater than 10 percent CH4 plus 
CO2 by weight. Emissions sources in streams with gas content 
less than or equal to 10 percent CH4 plus CO2 by 
weight are exempt from the requirements of this paragraph (r) and do not 
need to be reported. Tubing systems equal to or less than one half inch 
diameter are exempt from the requirements of paragraph (r) of this 
section and do not need to be reported. You must calculate emissions 
from all emission sources listed in this paragraph using Equation W-32A 
of this section, except for natural gas distribution facility emission 
sources listed in Sec. 98.232(i)(3). Natural gas distribution facility 
emission sources listed in Sec. 98.232(i)(3) must calculate emissions 
using Equation W-32B of this section and according to paragraph 
(r)(6)(ii) of this section.
[GRAPHIC] [TIFF OMITTED] TR22OC15.013

Where:

Es,e,i = Annual volumetric emissions of GHGi from 
          the emission source type in standard cubic feet. The emission 
          source type may be a component (e.g. connector, open-ended 
          line, etc.), below grade metering-regulating station, below 
          grade transmission-distribution transfer station, distribution 
          main, distribution service, or gathering pipeline.
Es,MR,i = Annual volumetric emissions of GHGi from 
          all meter/regulator runs at above grade metering regulating 
          stations that are not above grade transmission-distribution 
          transfer stations or, when used to calculate emissions 
          according to paragraph (q)(9) of this section, the annual 
          volumetric emissions of GHGi from

[[Page 859]]

          all meter/regulator runs at above grade transmission-
          distribution transfer stations, in standard cubic feet.
Counte = Total number of the emission source type at the 
          facility. For onshore petroleum and natural gas production 
          facilities and onshore petroleum and natural gas gathering and 
          boosting facilities, average component counts are provided by 
          major equipment piece in Tables W-1B and Table W-1C of this 
          subpart. Use average component counts as appropriate for 
          operations in Eastern and Western U.S., according to Table W-
          1D of this subpart. Onshore petroleum and natural gas 
          gathering and boosting facilities must also count the miles of 
          gathering pipelines by material type (protected steel, 
          unprotected steel, plastic, or cast iron). Underground natural 
          gas storage facilities must count each component listed in 
          Table W-4 of this subpart. LNG storage facilities must count 
          the number of vapor recovery compressors. LNG import and 
          export facilities must count the number of vapor recovery 
          compressors. Natural gas distribution facilities must count: 
          (1) The number of distribution services by material type; (2) 
          miles of distribution mains by material type; and (3) number 
          of below grade metering-regulating stations, by pressure type; 
          as listed in Table W-7 of this subpart.
CountMR = Total number of meter/regulator runs at above grade 
          metering-regulating stations that are not above grade 
          transmission-distribution transfer stations or, when used to 
          calculate emissions according to paragraph (q)(9) of this 
          section, the total number of meter/regulator runs at above 
          grade transmission-distribution transfer stations.
EFs,e = Population emission factor for the specific emission 
          source type, as listed in Tables W-1A and W-4 through W-7 of 
          this subpart. Use appropriate population emission factor for 
          operations in Eastern and Western U.S., according to Table W-
          1D of this subpart.
EFs,MR,i = Meter/regulator run population emission factor for 
          GHGi based on all surveyed above grade 
          transmission-distribution transfer stations over ``n'' years, 
          in standard cubic feet of GHGi per operational hour 
          of all meter/regulator runs, as determined in Equation W-31 of 
          this section.
GHGi = For onshore petroleum and natural gas production 
          facilities and onshore petroleum and natural gas gathering and 
          boosting facilities, concentration of GHGi, 
          CH4, or CO2, in produced natural gas as 
          defined in paragraph (u)(2) of this section; for onshore 
          natural gas transmission compression and underground natural 
          gas storage, GHGi equals 0.975 for CH4 
          and 1.1 x 10-2 for CO2; for LNG storage 
          and LNG import and export equipment, GHGi equals 1 
          for CH4 and 0 for CO2; and for natural 
          gas distribution, GHGi equals 1 for CH4 
          and 1.1 x 10-2 CO2.
Te = Average estimated time that each emission source type 
          associated with the equipment leak emission was operational in 
          the calendar year, in hours, using engineering estimate based 
          on best available data.
Tw,avg = Average estimated time that each meter/regulator run 
          was operational in the calendar year, in hours per meter/
          regulator run, using engineering estimate based on best 
          available data.

    (1) Calculate both CH4 and CO2 mass emissions 
from volumetric emissions using calculations in paragraph (v) of this 
section.
    (2) Onshore petroleum and natural gas production facilities and 
onshore petroleum and natural gas gathering and boosting facilities must 
use the appropriate default whole gas population emission factors listed 
in Table W-1A of this subpart. Major equipment and components associated 
with gas wells and onshore petroleum and natural gas gathering and 
boosting systems are considered gas service components in reference to 
Table W-1A of this subpart and major natural gas equipment in reference 
to Table W-1B of this subpart. Major equipment and components associated 
with crude oil wells are considered crude service components in 
reference to Table W-1A of this subpart and major crude oil equipment in 
reference to Table W-1C of this subpart. Where facilities conduct EOR 
operations the emissions factor listed in Table W-1A of this subpart 
shall be used to estimate all streams of gases, including recycle 
CO2 stream. The component count can be determined using 
either of the calculation methods described in this paragraph (r)(2), 
except for miles of gathering pipelines by material type, which must be 
determined using Component Count Method 2 in paragraph (r)(2)(ii) of 
this section. The same calculation method must be used for the entire 
calendar year.
    (i) Component Count Method 1. For all onshore petroleum and natural 
gas production operations and onshore petroleum and natural gas 
gathering and boosting operations in the facility perform the following 
activities:

[[Page 860]]

    (A) Count all major equipment listed in Table W-1B and Table W-1C of 
this subpart. For meters/piping, use one meters/piping per well-pad for 
onshore petroleum and natural gas production operations and the number 
of meters in the facility for onshore petroleum and natural gas 
gathering and boosting operations.
    (B) Multiply major equipment counts by the average component counts 
listed in Table W-1B of this subpart for onshore natural gas production 
and onshore petroleum and natural gas gathering and boosting; and Table 
W-1C of this subpart for onshore oil production. Use the appropriate 
factor in Table W-1A of this subpart for operations in Eastern and 
Western U.S. according to the mapping in Table W-1D of this subpart.
    (ii) Component Count Method 2. Count each component individually for 
the facility. Use the appropriate factor in Table W-1A of this subpart 
for operations in Eastern and Western U.S. according to the mapping in 
Table W-1D of this subpart.
    (3) Underground natural gas storage facilities must use the 
appropriate default total hydrocarbon population emission factors for 
storage wellheads in gas service listed in Table W-4 of this subpart.
    (4) LNG storage facilities must use the appropriate default methane 
population emission factor for LNG storage compressors in gas service 
listed in Table W-5 of this subpart.
    (5) LNG import and export facilities must use the appropriate 
default methane population emission factor for LNG terminal compressors 
in gas service listed in Table W-6 of this subpart.
    (6) Natural gas distribution facilities must use the appropriate 
methane emission factors as described in paragraphs (r)(6)(i) and (ii) 
of this section.
    (i) Below grade metering-regulating stations, distribution mains, 
and distribution services must use the appropriate default methane 
population emission factors listed in Table W-7 of this subpart. Below 
grade transmission-distribution transfer stations must use the emission 
factor for below grade metering-regulating stations.
    (ii) Above grade metering-regulating stations that are not above 
grade transmission-distribution transfer stations must use the meter/
regulator run population emission factor calculated in Equation W-31. 
Natural gas distribution facilities that do not have above grade 
transmission-distribution transfer stations are not required to 
calculate emissions for above grade metering-regulating stations and are 
not required to report GHG emissions in Sec. 98.236(r)(2)(v).
    (s) Offshore petroleum and natural gas production facilities. Report 
CO2, CH4, and N2O emissions for 
offshore petroleum and natural gas production from all equipment leaks, 
vented emission, and flare emission source types as identified in the 
data collection and emissions estimation study conducted by BOEMRE in 
compliance with 30 CFR 250.302 through 304.
    (1) Offshore production facilities under BOEMRE jurisdiction shall 
report the same annual emissions as calculated and reported by BOEMRE in 
data collection and emissions estimation study published by BOEMRE 
referenced in 30 CFR 250.302 through 304 (GOADS).
    (i) For any calendar year that does not overlap with the most recent 
BOEMRE emissions study publication year, report the most recent BOEMRE 
reported emissions data published by BOEMRE referenced in 30 CFR 250.302 
through 304 (GOADS). Adjust emissions based on the operating time for 
the facility relative to the operating time in the most recent BOEMRE 
published study.
    (ii) [Reserved]
    (2) Offshore production facilities that are not under BOEMRE 
jurisdiction must use the most recent monitoring methods and calculation 
methods published by BOEMRE referenced in 30 CFR 250.302 through 250.304 
to calculate and report annual emissions (GOADS).
    (i) For any calendar year that does not overlap with the most recent 
BOEMRE emissions study publication, you may report the most recently 
reported emissions data submitted to demonstrate compliance with this 
subpart of part 98, with emissions adjusted based on the operating time 
for the facility relative to operating time in the previous reporting 
period.
    (ii) [Reserved]

[[Page 861]]

    (3) If BOEMRE discontinues or delays their data collection effort by 
more than 4 years, then offshore reporters shall once in every 4 years 
use the most recent BOEMRE data collection and emissions estimation 
methods to estimate emissions. These emission estimates would be used to 
report emissions from the facility sources as required in paragraph 
(s)(1)(i) of this section.
    (4) For either first or subsequent year reporting, offshore 
facilities either within or outside of BOEMRE jurisdiction that were not 
covered in the previous BOEMRE data collection cycle must use the most 
recent BOEMRE data collection and emissions estimation methods published 
by BOEMRE referenced in 30 CFR 250.302 through 250.304 to calculate and 
report emissions.
    (t) GHG volumetric emissions using actual conditions. If equation 
parameters in Sec. 98.233 are already determined at standard conditions 
as provided in the introductory text in Sec. 98.233, which results in 
volumetric emissions at standard conditions, then this paragraph does 
not apply. Calculate volumetric emissions at standard conditions as 
specified in paragraphs (t)(1) or (2) of this section, with actual 
pressure and temperature determined by engineering estimates based on 
best available data unless otherwise specified.
    (1) Calculate natural gas volumetric emissions at standard 
conditions using actual natural gas emission temperature and pressure, 
and Equation W-33 of this section for conversions of Ea,n or 
conversions of FRa (whether sub-sonic or sonic).
[GRAPHIC] [TIFF OMITTED] TR25NO14.050

Where:

Es,n = Natural gas volumetric emissions at standard 
          temperature and pressure (STP) conditions in cubic feet, 
          except Es,n equals FRs,p for each well p 
          when calculating either subsonic or sonic flowrates under 
          Sec. 98.233(g).
Ea,n = Natural gas volumetric emissions at actual conditions 
          in cubic feet, except Ea,n equals FRa,p 
          for each well p when calculating either subsonic or sonic 
          flowrates under Sec. 98.233(g).
Ts = Temperature at standard conditions (60  deg.F).
Ta = Temperature at actual emission conditions (  deg.F).
Ps = Absolute pressure at standard conditions (14.7 psia).
Pa = Absolute pressure at actual conditions (psia).
Za = Compressibility factor at actual conditions for natural 
          gas. You may use either a default compressibility factor of 1, 
          or a site-specific compressibility factor based on actual 
          temperature and pressure conditions.

    (2) Calculate GHG volumetric emissions at standard conditions using 
actual GHG emissions temperature and pressure, and Equation W-34 of this 
section.
[GRAPHIC] [TIFF OMITTED] TR25NO14.051

Where:

Es,i = GHG i volumetric emissions at standard temperature and 
          pressure (STP) conditions in cubic feet.
Ea,i = GHG i volumetric emissions at actual conditions in 
          cubic feet.
Ts = Temperature at standard conditions (60  deg.F).
Ta = Temperature at actual emission conditions (  deg.F).
Ps = Absolute pressure at standard conditions (14.7 psia).
Pa = Absolute pressure at actual conditions (psia).

[[Page 862]]

Za = Compressibility factor at actual conditions for GHG i.

    You may use either a default compressibility factor of 1, or a site-
specific compressibility factor based on actual temperature and pressure 
conditions.
    (3) Reporters using 68  deg.F for standard temperature may use the 
ratio 519.67/527.67 to convert volumetric emissions from 68  deg.F to 60 
 deg.F.
    (u) GHG volumetric emissions at standard conditions. Calculate GHG 
volumetric emissions at standard conditions as specified in paragraphs 
(u)(1) and (2) of this section.
    (1) Estimate CH4 and CO2 emissions from 
natural gas emissions using Equation W-35 of this section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.205

where:

Es,i = GHG i (either CH4 or CO2) 
          volumetric emissions at standard conditions in cubic feet.
Es,n = Natural gas volumetric emissions at standard 
          conditions in cubic feet.
Mi = Mole fraction of GHG i in the natural gas.

    (2) For Equation W-35 of this section, the mole fraction, 
Mi, shall be the annual average mole fraction for each sub-
basin category or facility, as specified in paragraphs (u)(2)(i) through 
(vii) of this section.
    (i) GHG mole fraction in produced natural gas for onshore petroleum 
and natural gas production facilities and onshore petroleum and natural 
gas gathering and boosting facilities. If you have a continuous gas 
composition analyzer for produced natural gas, you must use an annual 
average of these values for determining the mole fraction. If you do not 
have a continuous gas composition analyzer, then you must use an annual 
average gas composition based on your most recent available analysis of 
the sub-basin category or facility, as applicable to the emission 
source.
    (ii) GHG mole fraction in feed natural gas for all emissions sources 
upstream of the de-methanizer or dew point control and GHG mole fraction 
in facility specific residue gas to transmission pipeline systems for 
all emissions sources downstream of the de-methanizer overhead or dew 
point control for onshore natural gas processing facilities. For onshore 
natural gas processing plants that solely fractionate a liquid stream, 
use the GHG mole percent in feed natural gas liquid for all streams. If 
you have a continuous gas composition analyzer on feed natural gas, you 
must use these values for determining the mole fraction. If you do not 
have a continuous gas composition analyzer, then annual samples must be 
taken according to methods set forth in Sec. 98.234(b).
    (iii) GHG mole fraction in transmission pipeline natural gas that 
passes through the facility for the onshore natural gas transmission 
compression industry segment and the onshore natural gas transmission 
pipeline industry segment. You may use either a default 95 percent 
methane and 1 percent carbon dioxide fraction for GHG mole fraction in 
natural gas or site specific engineering estimates based on best 
available data.
    (iv) GHG mole fraction in natural gas stored in the underground 
natural gas storage industry segment. You may use either a default 95 
percent methane and 1 percent carbon dioxide fraction for GHG mole 
fraction in natural gas or site specific engineering estimates based on 
best available data.
    (v) GHG mole fraction in natural gas stored in the LNG storage 
industry segment. You may use either a default 95 percent methane and 1 
percent carbon dioxide fraction for GHG mole fraction in natural gas or 
site specific engineering estimates based on best available data.
    (vi) GHG mole fraction in natural gas stored in the LNG import and 
export industry segment. For export facilities that receive gas from 
transmission pipelines, you may use either a default

[[Page 863]]

95 percent methane and 1 percent carbon dioxide fraction for GHG mole 
fraction in natural gas or site specific engineering estimates based on 
best available data.
    (vii) GHG mole fraction in local distribution pipeline natural gas 
that passes through the facility for natural gas distribution 
facilities. You may use either a default 95 percent methane and 1 
percent carbon dioxide fraction for GHG mole fraction in natural gas or 
site specific engineering estimates based on best available data.
    (v) GHG mass emissions. Calculate GHG mass emissions in metric tons 
by converting the GHG volumetric emissions at standard conditions into 
mass emissions using Equation W-36 of this section.
[GRAPHIC] [TIFF OMITTED] TR25NO14.052

Where:

Massi = GHGi (either CH4, 
          CO2, or N2O) mass emissions in metric 
          tons.
Es,i = GHGi (either CH4, 
          CO2, or N2O) volumetric emissions at 
          standard conditions, in cubic feet.
    ni = Density of GHGi. Use 0.0526 kg/ft\3\ for 
CO2 and N2O, and 0.0192 kg/ft\3\ for 
CH4 at 60  deg.F and 14.7 psia.

    (w) EOR injection pump blowdown. Calculate CO2 pump 
blowdown emissions from each EOR injection pump system as follows:
    (1) Calculate the total injection pump system volume in cubic feet 
(including pipelines, manifolds and vessels) between isolation valves.
    (2) Retain logs of the number of blowdowns per calendar year.
    (3) Calculate the total annual CO2 emissions from each 
EOR injection pump system using Equation W-37 of this section:
[GRAPHIC] [TIFF OMITTED] TR23DE11.022

Where:

MassCO2 = Annual EOR injection pump system emissions in 
          metric tons from blowdowns.
N = Number of blowdowns for the EOR injection pump system in the 
          calendar year.
Vv = Total volume in cubic feet of EOR injection pump system 
          chambers (including pipelines, manifolds and vessels) between 
          isolation valves.
Rc = Density of critical phase EOR injection gas in kg/ft\3\. 
          You may use an appropriate standard method published by a 
          consensus-based standards organization if such a method exists 
          or you may use an industry standard practice to determine 
          density of super critical EOR injection gas.
GHGCO2 = Mass fraction of CO2 in critical phase 
          injection gas.
1 x 10-3 = Conversion factor from kilograms to metric tons.

    (x) EOR hydrocarbon liquids dissolved CO2. Calculate CO2 
emissions downstream of the storage tank from dissolved CO2 
in hydrocarbon liquids produced through EOR operations as follows:
    (1) Determine the amount of CO2 retained in hydrocarbon 
liquids after flashing in tankage at STP conditions. Annual samples of 
hydrocarbon liquids downstream of the storage tank must be taken 
according to methods set forth in Sec. 98.234(b) to determine retention 
of CO2 in hydrocarbon liquids immediately downstream of the 
storage tank. Use the annual analysis for the calendar year.
    (2) Estimate emissions using Equation W-38 of this section.
    [GRAPHIC] [TIFF OMITTED] TR23DE11.023
    

[[Page 864]]


Where:

MassCO2 = Annual CO2 emissions from CO2 
          retained in hydrocarbon liquids produced through EOR 
          operations beyond tankage, in metric tons.
    Shl = Amount of CO2 retained in hydrocarbon 
liquids downstream of the storage tank, in metric tons per barrel, under 
standard conditions.
Vhl = Total volume of hydrocarbon liquids produced at the EOR 
          operations in barrels in the calendar year.

    (y) [Reserved]
    (z) Onshore petroleum and natural gas production, onshore petroleum 
and natural gas gathering and boosting, and natural gas distribution 
combustion emissions. Calculate CO2, CH4, and 
N2O combustion-related emissions from stationary or portable 
equipment, except as specified in paragraphs (z)(3) and (4) of this 
section, as follows:
    (1) If a fuel combusted in the stationary or portable equipment is 
listed in Table C-1 of subpart C of this part, or is a blend containing 
one or more fuels listed in Table C-1, calculate emissions according to 
paragraph (z)(1)(i) of this section. If the fuel combusted is natural 
gas and is of pipeline quality specification and has a minimum high heat 
value of 950 Btu per standard cubic foot, use the calculation method 
described in paragraph (z)(1)(i) of this section and you may use the 
emission factor provided for natural gas as listed in Table C-1. If the 
fuel is natural gas, and is not pipeline quality or has a high heat 
value of less than 950 Btu per standard cubic feet, calculate emissions 
according to paragraph (z)(2) of this section. If the fuel is field gas, 
process vent gas, or a blend containing field gas or process vent gas, 
calculate emissions according to paragraph (z)(2) of this section.
    (i) For fuels listed in Table C-1 or a blend containing one or more 
fuels listed in Table C-1, calculate CO2, CH4, and 
N2O emissions according to any Tier listed in subpart C of 
this part. You must follow all applicable calculation requirements for 
that tier listed in Sec. 98.33, any monitoring or QA/QC requirements 
listed for that tier in Sec. 98.34, any missing data procedures 
specified in Sec. 98.35, and any recordkeeping requirements specified 
in Sec. 98.37.
    (ii) Emissions from fuel combusted in stationary or portable 
equipment at onshore petroleum and natural gas production facilities, at 
onshore petroleum and natural gas gathering and boosting facilities, and 
at natural gas distribution facilities will be reported according to the 
requirements specified in Sec. 98.236(z) and not according to the 
reporting requirements specified in subpart C of this part.
    (2) For fuel combustion units that combust field gas, process vent 
gas, a blend containing field gas or process vent gas, or natural gas 
that is not of pipeline quality or that has a high heat value of less 
than 950 Btu per standard cubic feet, calculate combustion emissions as 
follows:
    (i) You may use company records to determine the volume of fuel 
combusted in the unit during the reporting year.
    (ii) If you have a continuous gas composition analyzer on fuel to 
the combustion unit, you must use these compositions for determining the 
concentration of gas hydrocarbon constituent in the flow of gas to the 
unit. If you do not have a continuous gas composition analyzer on gas to 
the combustion unit, you must use the appropriate gas compositions for 
each stream of hydrocarbons going to the combustion unit as specified in 
the applicable paragraph in (u)(2) of this section.
    (iii) Calculate GHG volumetric emissions at actual conditions using 
Equations W-39A and W-39B of this section:
[GRAPHIC] [TIFF OMITTED] TR23DE11.024


[[Page 865]]


Where:

Ea,CO2 = Contribution of annual CO2 emissions from 
          portable or stationary fuel combustion sources in cubic feet, 
          under actual conditions.
Va = Volume of gas sent to combustion unit in actual cubic 
          feet, during the year.
YCO2 = Mole fraction of CO2 constituent in gas 
          sent to combustion unit.
Ea,CH4 = Contribution of annual CH4 emissions from 
          portable or stationary fuel combustion sources in cubic feet, 
          under actual conditions.
j = Fraction of gas combusted for portable and stationary equipment 
          determined using engineering estimation. For internal 
          combustion devices, a default of 0.995 can be used.
Yj = Mole fraction of gas hydrocarbon constituents j (such as 
          methane, ethane, propane, butane, and pentanes plus) in gas 
          sent to combustion unit.
Rj = Number of carbon atoms in the gas hydrocarbon 
          constituent j; 1 for methane, 2 for ethane, 3 for propane, 4 
          for butane, and 5 for pentanes plus, in gas sent to combustion 
          unit.
YCH4 = Mole fraction of methane constituent in gas sent to 
          combustion unit.

    (iv) Calculate GHG volumetric emissions at standard conditions using 
calculations in paragraph (t) of this section.
    (v) Calculate both combustion-related CH4 and 
CO2 mass emissions from volumetric CH4 and 
CO2 emissions using calculation in paragraph (v) of this 
section.
    (vi) Calculate N2O mass emissions using Equation W-40 of 
this section.
[GRAPHIC] [TIFF OMITTED] TR25NO14.053

Where:

MassN2O = Annual N2O emissions from the combustion 
          of a particular type of fuel (metric tons).
Fuel = Annual mass or volume of the fuel combusted (mass or volume per 
          year, choose appropriately to be consistent with the units of 
          HHV).
HHV = Higher heating value of fuel, mmBtu/unit of fuel (in units 
          consistent with the fuel quantity combusted). For field gas or 
          process vent gas, you may use either a default higher heating 
          value of 1.235 x 10-3 mmBtu/scf or a site-specific 
          higher heating value. For natural gas that is not of pipeline 
          quality or that has a high heat value less than 950 Btu per 
          standard cubic foot, use a site-specific higher heating value.
EF = Use 1.0 x 10-4 kg N2O/mmBtu.
1 x 10-3 = Conversion factor from kilograms to metric tons.

    (3) External fuel combustion sources with a rated heat capacity 
equal to or less than 5 mmBtu/hr do not need to report combustion 
emissions or include these emissions for threshold determination in 
Sec. 98.231(a). You must report the type and number of each external 
fuel combustion unit.
    (4) Internal fuel combustion sources, not compressor-drivers, with a 
rated heat capacity equal to or less than 1 mmBtu/hr (or the equivalent 
of 130 horsepower), do not need to report combustion emissions or 
include these emissions for threshold determination in Sec. 98.231(a). 
You must report the type and number of each internal fuel combustion 
unit.

[75 FR 74488, Nov. 30, 2010, as amended at 76 FR 80575, Dec. 23, 2011; 
77 FR 51490, Aug. 24, 2012; 78 FR 71960, Nov. 29, 2013; 79 FR 70408, 
Nov. 25, 2014; 80 FR 64284, Oct. 22, 2015]



Sec. 98.234  Monitoring and QA/QC requirements.

    The GHG emissions data for petroleum and natural gas emissions 
sources must be quality assured as applicable as specified in this 
section. Offshore petroleum and natural gas production facilities shall 
adhere to the monitoring and QA/QC requirements as set forth in 30 CFR 
250.
    (a) You must use any of the methods described as follows in this 
paragraph to conduct leak detection(s) of equipment leaks and through-
valve leakage from all source types listed in Sec. 98.233(k), (o), (p) 
and (q) that occur during a calendar year.
    (1) Optical gas imaging instrument. Use an optical gas imaging 
instrument for equipment leak detection in accordance with 40 CFR part 
60, subpart A, Sec. 60.18 of the Alternative work practice for 
monitoring equipment leaks,

[[Page 866]]

Sec. 60.18(i)(1)(i); Sec. 60.18(i)(2)(i) except that the monitoring 
frequency shall be annual using the detection sensitivity level of 60 
grams per hour as stated in 40 CFR Part 60, subpart A, Table 1: 
Detection Sensitivity Levels; Sec. 60.18(i)(2)(ii) and (iii) except the 
gas chosen shall be methane, and Sec. 60.18(i)(2)(iv) and (v); Sec. 
60.18(i)(3); Sec. 60.18(i)(4)(i) and (v); including the requirements 
for daily instrument checks and distances, and excluding requirements 
for video records. Any emissions detected by the optical gas imaging 
instrument is a leak unless screened with Method 21 (40 CFR part 60, 
appendix A-7) monitoring, in which case 10,000 ppm or greater is 
designated a leak. In addition, you must operate the optical gas imaging 
instrument to image the source types required by this subpart in 
accordance with the instrument manufacturer's operating parameters. 
Unless using methods in paragraph (a)(2) of this section, an optical gas 
imaging instrument must be used for all source types that are 
inaccessible and cannot be monitored without elevating the monitoring 
personnel more than 2 meters above a support surface.
    (2) Method 21. Use the equipment leak detection methods in 40 CFR 
part 60, appendix A-7, Method 21. If using Method 21 monitoring, if an 
instrument reading of 10,000 ppm or greater is measured, a leak is 
detected. Inaccessible emissions sources, as defined in 40 CFR part 60, 
are not exempt from this subpart. Owners or operators must use 
alternative leak detection devices as described in paragraph (a)(1) or 
(a)(2) of this section to monitor inaccessible equipment leaks or vented 
emissions.
    (3) Infrared laser beam illuminated instrument. Use an infrared 
laser beam illuminated instrument for equipment leak detection. Any 
emissions detected by the infrared laser beam illuminated instrument is 
a leak unless screened with Method 21 monitoring, in which case 10,000 
ppm or greater is designated a leak. In addition, you must operate the 
infrared laser beam illuminated instrument to detect the source types 
required by this subpart in accordance with the instrument 
manufacturer's operating parameters.
    (4) [Reserved]
    (5) Acoustic leak detection device. Use the acoustic leak detection 
device to detect through-valve leakage. When using the acoustic leak 
detection device to quantify the through-valve leakage, you must use the 
instrument manufacturer's calculation methods to quantify the through-
valve leak. When using the acoustic leak detection device, if a leak of 
3.1 scf per hour or greater is calculated, a leak is detected. In 
addition, you must operate the acoustic leak detection device to monitor 
the source valves required by this subpart in accordance with the 
instrument manufacturer's operating parameters. Acoustic stethoscope 
type devices designed to detect through valve leakage when put in 
contact with the valve body and that provide an audible leak signal but 
do not calculate a leak rate can be used to identify non-leakers with 
subsequent measurement required to calculate the rate if through-valve 
leakage is identified. Leaks are reported if a leak rate of 3.1 scf per 
hour or greater is measured.
    (b) You must operate and calibrate all flow meters, composition 
analyzers and pressure gauges used to measure quantities reported in 
Sec. 98.233 according to the procedures in Sec. 98.3(i) and the 
procedures in paragraph (b) of this section. You may use an appropriate 
standard method published by a consensus-based standards organization if 
such a method exists or you may use an industry standard practice. 
Consensus-based standards organizations include, but are not limited to, 
the following: ASTM International, the American National Standards 
Institute (ANSI), the American Gas Association (AGA), the American 
Society of Mechanical Engineers (ASME), the American Petroleum Institute 
(API), and the North American Energy Standards Board (NAESB).
    (c) Use calibrated bags (also known as vent bags) only where the 
emissions are at near-atmospheric pressures and below the maximum 
temperature specified by the vent bag manufacturer such that the bag is 
safe to handle. The bag opening must be of sufficient size that the 
entire emission can be tightly encompassed for measurement till the bag 
is completely filled.

[[Page 867]]

    (1) Hold the bag in place enclosing the emissions source to capture 
the entire emissions and record the time required for completely filling 
the bag. If the bag inflates in less than one second, assume one second 
inflation time.
    (2) Perform three measurements of the time required to fill the bag, 
report the emissions as the average of the three readings.
    (3) Estimate natural gas volumetric emissions at standard conditions 
using calculations in Sec. 98.233(t).
    (4) Estimate CH4 and CO2 volumetric and mass 
emissions from volumetric natural gas emissions using the calculations 
in Sec. 98.233(u) and (v).
    (d) Use a high volume sampler to measure emissions within the 
capacity of the instrument.
    (1) A technician following manufacturer instructions shall conduct 
measurements, including equipment manufacturer operating procedures and 
measurement methods relevant to using a high volume sampler, including 
positioning the instrument for complete capture of the equipment leak 
without creating backpressure on the source.
    (2) If the high volume sampler, along with all attachments available 
from the manufacturer, is not able to capture all the emissions from the 
source then use anti-static wraps or other aids to capture all emissions 
without violating operating requirements as provided in the instrument 
manufacturer's manual.
    (3) Estimate natural gas volumetric emissions at standard conditions 
using calculations in Sec. 98.233(t). Estimate CH4 and 
CO2 volumetric and mass emissions from volumetric natural gas 
emissions using the calculations in Sec. 98.233(u) and (v).
    (4) Calibrate the instrument at 2.5 percent methane with 97.5 
percent air and 100 percent CH4 by using calibrated gas 
samples and by following manufacturer's instructions for calibration.
    (e) Peng Robinson Equation of State means the equation of state 
defined by Equation W-41 of this section:
[GRAPHIC] [TIFF OMITTED] TR23DE11.026

Where:

p = Absolute pressure.
R = Universal gas constant.
T = Absolute temperature.
Vm = Molar volume.
[GRAPHIC] [TIFF OMITTED] TR23DE11.027

Where:

? = Acentric factor of the species.

[[Page 868]]

Tc = Critical temperature.
Pc = Critical pressure.

    (f) Special reporting provisions for best available monitoring 
methods in reporting year 2015--(1) Best available monitoring methods. 
From January 1, 2015 to March 31, 2015, for a facility subject to this 
subpart, you must use the calculation methodologies and equations in 
Sec. 98.233 ``Calculating GHG Emissions'', but you may use the best 
available monitoring method for any parameter for which it is not 
reasonably feasible to acquire, install, and operate a required piece of 
monitoring equipment by January 1, 2015 as specified in paragraphs 
(f)(2) and (3) of this section. Starting no later than April 1, 2015, 
you must discontinue using best available methods and begin following 
all applicable monitoring and QA/QC requirements of this part, except as 
provided in paragraph (f)(4) of this section. Best available monitoring 
methods means any of the following methods:
    (i) Monitoring methods currently used by the facility that do not 
meet the specifications of this subpart.
    (ii) Supplier data.
    (iii) Engineering calculations.
    (iv) Other company records.
    (2) Best available monitoring methods for well-related measurement 
data. You may use best available monitoring methods for well-related 
measurement data identified in paragraphs (f)(2)(i) and (ii) of this 
section that cannot reasonably be measured according to the monitoring 
and QA/QC requirements of this subpart.
    (i) If Calculation Method 1 for liquids unloading in Sec. 
98.233(f)(1) was used in calendar year 2014 and will be used again in 
calendar year 2015, the vented natural gas flow rate for any well in a 
unique tubing diameter group and pressure group combination that has not 
been previously measured.
    (ii) If using Equation W-10A of this subpart to determine natural 
gas emissions from completions and workovers for representative wells, 
the initial and average flowback rates (when using Calculation Method 1 
in Sec. 98.233(g)(1)(i)) or pressures upstream and downstream of the 
choke (when using Calculation Method 2 in Sec. 98.233(g)(1)(ii)) for 
any well in a well type combination that has not been previously 
measured.
    (3) Best available monitoring methods for emissions measurement. You 
may use best available monitoring methods for sources listed in 
paragraphs (f)(3)(i) and (ii) of this section if the required 
measurement data cannot reasonably be obtained according to the 
monitoring and QA/QC requirements of this part.
    (i) Centrifugal compressor as found measurements of manifolded 
emissions from groups of centrifugal compressor sources according to 
Sec. 98.233(o)(4) and (5), in onshore natural gas processing, onshore 
natural gas transmission compression, underground natural gas storage, 
LNG storage, and LNG import and export equipment as specified in Sec. 
98.232(d)(2), (e)(2), (f)(2), (g)(2), and (h)(2).
    (ii) Reciprocating compressor as found measurements of manifolded 
emissions from groups of reciprocating compressor sources according to 
Sec. 98.233(p)(4) and (5), in onshore natural gas processing, onshore 
natural gas transmission compression, underground natural gas storage, 
LNG storage, and LNG import and export equipment as specified in Sec. 
98.232(d)(1), (e)(1), (f)(1), (g)(1), and (h)(1).
    (4) Requests for extension of the use of best available monitoring 
methods beyond March 31, 2015. You may submit a request to the 
Administrator to use one or more best available monitoring methods for 
sources listed in paragraphs (f)(2) and (3) of this section beyond March 
31, 2015.
    (i) Timing of request. The extension request must be submitted to 
EPA no later than January 31, 2015.
    (ii) Content of request. Requests must contain the following 
information:
    (A) A list of specific source types and parameters for which you are 
seeking use of best available monitoring methods.
    (B) For each specific source type for which you are requesting use 
of best available monitoring methods, a description of the reasons that 
the needed equipment could not be obtained and installed before April 1, 
2015.
    (C) A description of the specific actions you will take to obtain 
and install the equipment as soon as reasonably feasible and the 
expected date by

[[Page 869]]

which the equipment will be installed and operating.
    (iii) Approval criteria. To obtain approval to use best available 
monitoring methods after March 31, 2015, you must submit a request 
demonstrating to the Administrator's satisfaction that it is not 
reasonably feasible to acquire, install, and operate a required piece of 
monitoring equipment by April 1, 2015. The use of best available methods 
under paragraph (f) of this section will not be approved beyond December 
31, 2015.
    (g) Special reporting provisions for best available monitoring 
methods in reporting year 2016--(1) Best available monitoring methods. 
From January 1, 2016, to December 31, 2016, you must use the calculation 
methodologies and equations in Sec. 98.233 but you may use the best 
available monitoring method as described in paragraph (g)(2) of this 
section for any parameter specified in paragraphs (g)(3) through (6) of 
this section for which it is not reasonably feasible to acquire, 
install, and operate a required piece of monitoring equipment by January 
1, 2016. Starting no later than January 1, 2017, you must discontinue 
using best available methods and begin following all applicable 
monitoring and QA/QC requirements of this part. For onshore petroleum 
and natural gas production, this paragraph (g)(1) only applies if 
emissions from well completions and workovers of oil wells with 
hydraulic fracturing cause your facility to exceed the reporting 
threshold in Sec. 98.231(a)(1).
    (2) Best available monitoring methods means any of the following 
methods:
    (i) Monitoring methods currently used by the facility that do not 
meet the specifications of this subpart.
    (ii) Supplier data.
    (iii) Engineering calculations.
    (iv) Other company records.
    (3) Best available monitoring methods for well-related measurement 
data for oil wells with hydraulic fracturing. You may use best available 
monitoring methods for any well-related measurement data that cannot 
reasonably be measured according to the monitoring and QA/QC 
requirements of this subpart for venting during well completions and 
workovers of oil wells with hydraulic fracturing.
    (4) Best available monitoring methods for measurement data for 
onshore petroleum and natural gas gathering and boosting facilities. You 
may use best available monitoring methods for any leak detection and/or 
measurement data that cannot reasonably be measured according to the 
monitoring and QA/QC requirements of this subpart for acid gas removal 
vents as specified in Sec. 98.233(d).
    (5) Best available monitoring methods for measurement data for 
natural gas transmission pipelines. You may use best available 
monitoring methods for any measurement data for natural gas transmission 
pipelines that cannot reasonably be obtained according to the monitoring 
and QA/QC requirements of this subpart for blowdown vent stacks.
    (6) Best available monitoring methods for specified activity data. 
You may use best available monitoring methods for activity data as 
listed in paragraphs (g)(6)(i) through (iii) of this section that cannot 
reasonably be obtained according to the monitoring and QA/QC 
requirements of this subpart for well completions and workovers of oil 
wells with hydraulic fracturing, onshore petroleum and natural gas 
gathering and boosting facilities, or natural gas transmission 
pipelines.
    (i) Cumulative hours of venting, days, or times of operation in 
Sec. 98.233(e), (g), (o), (p), and (r).
    (ii) Number of blowdowns, completions, workovers, or other events in 
Sec. 98.233(g) and (i).
    (iii) Cumulative volume produced, volume input or output, or volume 
of fuel used in paragraphs Sec. 98.233(d), (e), (j), (n), and (z).
    (h) For well venting for liquids unloading, if a monitoring period 
other than the full calendar year is used to determine the cumulative 
amount of time in hours of venting for each well (the term 
``Tp'' in Equation W-7A and W-7B of Sec. 98.233) or the 
number of unloading events per well (the term ``Vp'' in 
Equations W-8 and W-9 of Sec. 98.233), then the monitoring period must 
begin before February 1 of the reporting year and must not end before 
December 1 of the reporting year. The end of one monitoring period must 
immediately

[[Page 870]]

precede the start of the next monitoring period for the next reporting 
year. All production days must be monitored and all venting accounted 
for.

[75 FR 74488, Nov. 30, 2010, as amended at 76 FR 22827, Apr. 25, 2011; 
76 FR 59540, Sept. 27, 2011; 76 FR 80586, Dec. 23, 2011; 78 FR 25395, 
May 1, 2013; 79 FR 70410, Nov. 25, 2014; 80 FR 64291, Oct. 22, 2015]



Sec. 98.235  Procedures for estimating missing data.

    Except as specified in Sec. 98.233, whenever a value of a parameter 
is unavailable for a GHG emission calculation required by this subpart 
(including, but not limited to, if a measuring device malfunctions 
during unit operation or activity data are not collected), you must 
follow the procedures specified in paragraphs (a) through (i) of this 
section, as applicable.
    (a) For stationary and portable combustion sources that use the 
calculation methods of subpart C of this part, you must use the missing 
data procedures in subpart C of this part.
    (b) For each missing value of a parameter that should have been 
measured quarterly or more frequently using equipment including, but not 
limited to, a continuous flow meter, composition analyzer, thermocouple, 
or pressure gauge, you must substitute the arithmetic average of the 
quality-assured values of that parameter immediately preceding and 
immediately following the missing data incident. If the ``after'' value 
is not obtained by the end of the reporting year, you may use the 
``before'' value for the missing data substitution. If, for a particular 
parameter, no quality-assured data are available prior to the missing 
data incident, you must use the first quality-assured value obtained 
after the missing data period as the substitute data value. A value is 
quality-assured according to the procedures specified in Sec. 98.234.
    (c) For each missing value of a parameter that should have been 
measured annually, you must repeat the estimation or measurement 
activity for those sources as soon as possible, including in the 
subsequent calendar year if missing data are not discovered until after 
December 31 of the year in which data are collected, until valid data 
for reporting are obtained. Data developed and/or collected in a 
subsequent calendar year to substitute for missing data cannot be used 
for that subsequent year's emissions estimation. Where missing data 
procedures are used for the previous year, at least 30 days must 
separate emissions estimation or measurements for the previous year and 
emissions estimation or measurements for the current year of data 
collection.
    (d) For each missing value of a parameter that should have been 
measured biannually (every two years), you must conduct the estimation 
or measurement activity for those sources as soon as possible in the 
subsequent calendar year if the estimation or measurement was not made 
in the appropriate year (first year of data collection and every two 
years thereafter), until valid data for reporting are obtained. Data 
developed and/or collected in a subsequent calendar year to substitute 
for missing data cannot be used to alternate or postpone subsequent 
biannual emissions estimations or measurements.
    (e) For the first 6 months of required data collection, facilities 
that become newly subject to this subpart W may use best engineering 
estimates for any data that cannot reasonably be measured or obtained 
according to the requirements of this subpart.
    (f) For the first 6 months of required data collection, facilities 
that are currently subject to this subpart W and that acquire new 
sources from another facility that were not previously subject to this 
subpart W may use best engineering estimates for any data related to 
those newly acquired sources that cannot reasonably be measured or 
obtained according to the requirements of this subpart.
    (g) Unless addressed in another paragraph of this section, for each 
missing value of any activity data, you must substitute data value(s) 
using the best available estimate(s) of the parameter(s), based on all 
applicable and available process or other data (including, but not 
limited to, processing rates, operating hours).
    (h) You must report information for all measured and substitute 
values of a parameter, and the procedures used to

[[Page 871]]

substitute an unavailable value of a parameter per the requirements in 
Sec. 98.236(bb).
    (i) You must follow recordkeeping requirements listed in Sec. 
98.237(f).

[79 FR 70410, Nov. 25, 2014]



Sec. 98.236  Data reporting requirements.

    In addition to the information required by Sec. 98.3(c), each 
annual report must contain reported emissions and related information as 
specified in this section. Reporters that use a flow or volume 
measurement system that corrects to standard conditions as provided in 
the introductory text in Sec. 98.233 for data elements that are 
otherwise required to be determined at actual conditions, report gas 
volumes at standard conditions rather the gas volumes at actual 
conditions and report the standard temperature and pressure used by the 
measurement system rather than the actual temperature and pressure.
    (a) The annual report must include the information specified in 
paragraphs (a)(1) through (10) of this section for each applicable 
industry segment. The annual report must also include annual emissions 
totals, in metric tons of each GHG, for each applicable industry segment 
listed in paragraphs (a)(1) through (10), and each applicable emission 
source listed in paragraphs (b) through (z) of this section.
    (1) Onshore petroleum and natural gas production. For the equipment/
activities specified in paragraphs (a)(1)(i) through (xvii) of this 
section, report the information specified in the applicable paragraphs 
of this section.
    (i) Natural gas pneumatic devices. Report the information specified 
in paragraph (b) of this section.
    (ii) Natural gas driven pneumatic pumps. Report the information 
specified in paragraph (c) of this section.
    (iii) Acid gas removal units. Report the information specified in 
paragraph (d) of this section.
    (iv) Dehydrators. Report the information specified in paragraph (e) 
of this section.
    (v) Liquids unloading. Report the information specified in paragraph 
(f) of this section.
    (vi) Completions and workovers with hydraulic fracturing. Report the 
information specified in paragraph (g) of this section.
    (vii) Completions and workovers without hydraulic fracturing. Report 
the information specified in paragraph (h) of this section.
    (viii) Onshore production storage tanks. Report the information 
specified in paragraph (j) of this section.
    (ix) Well testing. Report the information specified in paragraph (l) 
of this section.
    (x) Associated natural gas. Report the information specified in 
paragraph (m) of this section.
    (xi) Flare stacks. Report the information specified in paragraph (n) 
of this section.
    (xii) Centrifugal compressors. Report the information specified in 
paragraph (o) of this section.
    (xiii) Reciprocating compressors. Report the information specified 
in paragraph (p) of this section.
    (xiv) Equipment leaks by population count. Report the information 
specified in paragraph (r) of this section.
    (xv) EOR injection pumps. Report the information specified in 
paragraph (w) of this section.
    (xvi) EOR hydrocarbon liquids. Report the information specified in 
paragraph (x) of this section.
    (xvii) Combustion equipment. Report the information specified in 
paragraph (z) of this section.
    (2) Offshore petroleum and natural gas production. Report the 
information specified in paragraph (s) of this section.
    (3) Onshore natural gas processing. For the equipment/activities 
specified in paragraphs (a)(3)(i) through (vii) of this section, report 
the information specified in the applicable paragraphs of this section.
    (i) Acid gas removal units. Report the information specified in 
paragraph (d) of this section.
    (ii) Dehydrators. Report the information specified in paragraph (e) 
of this section.
    (iii) Blowdown vent stacks. Report the information specified in 
paragraph (i) of this section.
    (iv) Flare stacks. Report the information specified in paragraph (n) 
of this section.

[[Page 872]]

    (v) Centrifugal compressors. Report the information specified in 
paragraph (o) of this section.
    (vi) Reciprocating compressors. Report the information specified in 
paragraph (p) of this section.
    (vii) Equipment leak surveys. Report the information specified in 
paragraph (q) of this section.
    (4) Onshore natural gas transmission compression. For the equipment/
activities specified in paragraphs (a)(4)(i) through (vii) of this 
section, report the information specified in the applicable paragraphs 
of this section.
    (i) Natural gas pneumatic devices. Report the information specified 
in paragraph (b) of this section.
    (ii) Blowdown vent stacks. Report the information specified in 
paragraph (i) of this section.
    (iii) Transmission storage tanks. Report the information specified 
in paragraph (k) of this section.
    (iv) Flare stacks. Report the information specified in paragraph (n) 
of this section.
    (v) Centrifugal compressors. Report the information specified in 
paragraph (o) of this section.
    (vi) Reciprocating compressors. Report the information specified in 
paragraph (p) of this section.
    (vii) Equipment leak surveys. Report the information specified in 
paragraph (q) of this section.
    (5) Underground natural gas storage. For the equipment/activities 
specified in paragraphs (a)(5)(i) through (vi) of this section, report 
the information specified in the applicable paragraphs of this section.
    (i) Natural gas pneumatic devices. Report the information specified 
in paragraph (b) of this section.
    (ii) Flare stacks. Report the information specified in paragraph (n) 
of this section.
    (iii) Centrifugal compressors. Report the information specified in 
paragraph (o) of this section.
    (iv) Reciprocating compressors. Report the information specified in 
paragraph (p) of this section.
    (v) Equipment leak surveys. Report the information specified in 
paragraph (q) of this section.
    (vi) Equipment leaks by population count. Report the information 
specified in paragraph (r) of this section.
    (6) LNG storage. For the equipment/activities specified in 
paragraphs (a)(6)(i) through (v) of this section, report the information 
specified in the applicable paragraphs of this section.
    (i) Flare stacks. Report the information specified in paragraph (n) 
of this section.
    (ii) Centrifugal compressors. Report the information specified in 
paragraph (o) of this section.
    (iii) Reciprocating compressors. Report the information specified in 
paragraph (p) of this section.
    (iv) Equipment leak surveys. Report the information specified in 
paragraph (q) of this section.
    (v) Equipment leaks by population count. Report the information 
specified in paragraph (r) of this section.
    (7) LNG import and export equipment. For the equipment/activities 
specified in paragraphs (a)(7)(i) through (vi) of this section, report 
the information specified in the applicable paragraphs of this section.
    (i) Blowdown vent stacks. Report the information specified in 
paragraph (i) of this section.
    (ii) Flare stacks. Report the information specified in paragraph (n) 
of this section.
    (iii) Centrifugal compressors. Report the information specified in 
paragraph (o) of this section.
    (iv) Reciprocating compressors. Report the information specified in 
paragraph (p) of this section.
    (v) Equipment leak surveys. Report the information specified in 
paragraph (q) of this section.
    (vi) Equipment leaks by population count. Report the information 
specified in paragraph (r) of this section.
    (8) Natural gas distribution. For the equipment/activities specified 
in paragraphs (a)(8)(i) through (iii) of this section, report the 
information specified in the applicable paragraphs of this section.
    (i) Combustion equipment. Report the information specified in 
paragraph (z) of this section.
    (ii) Equipment leak surveys. Report the information specified in 
paragraph (q) of this section.

[[Page 873]]

    (iii) Equipment leaks by population count. Report the information 
specified in paragraph (r) of this section.
    (9) Onshore petroleum and natural gas gathering and boosting. For 
the equipment/activities specified in paragraphs (a)(9)(i) through (xi) 
of this section, report the information specified in the applicable 
paragraphs of this section.
    (i) Natural gas pneumatic devices. Report the information specified 
in paragraph (b) of this section.
    (ii) Natural gas driven pneumatic pumps. Report the information 
specified in paragraph (c) of this section.
    (iii) Acid gas removal units. Report the information specified in 
paragraph (d) of this section.
    (iv) Dehydrators. Report the information specified in paragraph (e) 
of this section.
    (v) Blowdown vent stacks. Report the information specified in 
paragraph (i) of this section.
    (vi) Storage tanks. Report the information specified in paragraph 
(j) of this section.
    (vii) Flare stacks. Report the information specified in paragraph 
(n) of this section.
    (viii) Centrifugal compressors. Report the information specified in 
paragraph (o) of this section.
    (ix) Reciprocating compressors. Report the information specified in 
paragraph (p) of this section.
    (x) Equipment leaks by population count. Report the information 
specified in paragraph (r) of this section.
    (xi) Combustion equipment. Report the information specified in 
paragraph (z) of this section.
    (10) Onshore natural gas transmission pipeline. For blowdown vent 
stacks, report the information specified in paragraph (i) of this 
section.
    (b) Natural gas pneumatic devices. You must indicate whether the 
facility contains the following types of equipment: Continuous high 
bleed natural gas pneumatic devices, continuous low bleed natural gas 
pneumatic devices, and intermittent bleed natural gas pneumatic devices. 
If the facility contains any continuous high bleed natural gas pneumatic 
devices, continuous low bleed natural gas pneumatic devices, or 
intermittent bleed natural gas pneumatic devices, then you must report 
the information specified in paragraphs (b)(1) through (b)(4) of this 
section.
    (1) The number of natural gas pneumatic devices as specified in 
paragraphs (b)(1)(i) and (ii) of this section.
    (i) The total number of devices of each type, determined according 
to Sec. 98.233(a)(1) and (2).
    (ii) If the reported value in paragraph (b)(1)(i) of this section is 
an estimated value determined according to Sec. 98.233(a)(2), then you 
must report the information specified in paragraphs (b)(1)(ii)(A) 
through (C) of this section.
    (A) The number of devices of each type reported in paragraph 
(b)(1)(i) of this section that are counted.
    (B) The number of devices of each type reported in paragraph 
(b)(1)(i) of this section that are estimated (not counted).
    (C) Whether the calendar year is the first calendar year of 
reporting or the second calendar year of reporting.
    (2) For each type of pneumatic device, the estimated average number 
of hours in the calendar year that the natural gas pneumatic devices 
reported in paragraph (b)(1)(i) of this section were operating in the 
calendar year (``Tt'' in Equation W-1 of this subpart).
    (3) Annual CO2 emissions, in metric tons CO2, 
for the natural gas pneumatic devices combined, calculated using 
Equation W-1 of this subpart and Sec. 98.233(a)(4), and reported in 
paragraph (b)(1)(i) of this section.
    (4) Annual CH4 emissions, in metric tons CH4, 
for the natural gas pneumatic devices combined, calculated using 
Equation W-1 of this subpart and Sec. 98.233(a)(4), and reported in 
paragraph (b)(1)(i) of this section.
    (c) Natural gas driven pneumatic pumps. You must indicate whether 
the facility has any natural gas driven pneumatic pumps. If the facility 
contains any natural gas driven pneumatic pumps, then you must report 
the information specified in paragraphs (c)(1) through (4) of this 
section.
    (1) Count of natural gas driven pneumatic pumps.
    (2) Average estimated number of hours in the calendar year the pumps 
were operational (``T'' in Equation W-2 of this subpart).

[[Page 874]]

    (3) Annual CO2 emissions, in metric tons CO2, 
for all natural gas driven pneumatic pumps combined, calculated 
according to Sec. 98.233(c)(1) and (2).
    (4) Annual CH4 emissions, in metric tons CH4, 
for all natural gas driven pneumatic pumps combined, calculated 
according to Sec. 98.233(c)(1) and (2).
    (d) Acid gas removal units. You must indicate whether your facility 
has any acid gas removal units that vent directly to the atmosphere, to 
a flare or engine, or to a sulfur recovery plant. If your facility 
contains any acid gas removal units that vent directly to the 
atmosphere, to a flare or engine, or to a sulfur recovery plant, then 
you must report the information specified in paragraphs (d)(1) and (2) 
of this section.
    (1) You must report the information specified in paragraphs 
(d)(1)(i) through (vi) of this section for each acid gas removal unit.
    (i) A unique name or ID number for the acid gas removal unit. For 
the onshore petroleum and natural gas production and the onshore 
petroleum and natural gas gathering and boosting industry segments, a 
different name or ID may be used for a single acid gas removal unit for 
each location it operates at in a given year.
    (ii) Total feed rate entering the acid gas removal unit, using a 
meter or engineering estimate based on process knowledge or best 
available data, in million cubic feet per year.
    (iii) The calculation method used to calculate CO2 
emissions from the acid gas removal unit, as specified in Sec. 
98.233(d).
    (iv) Whether any CO2 emissions from the acid gas removal 
unit are recovered and transferred outside the facility, as specified in 
Sec. 98.233(d)(11). If any CO2 emissions from the acid gas 
removal unit were recovered and transferred outside the facility, then 
you must report the annual quantity of CO2, in metric tons 
CO2, that was recovered and transferred outside the facility 
under subpart PP of this part.
    (v) Annual CO2 emissions, in metric tons CO2, 
from the acid gas removal unit, calculated using any one of the 
calculation methods specified in Sec. 98.233(d) and as specified in 
Sec. 98.233(d)(10) and (11).
    (vi) Sub-basin ID that best represents the wells supplying gas to 
the unit (for the onshore petroleum and natural gas production industry 
segment only) or name of the county that best represents the equipment 
supplying gas to the unit (for the onshore petroleum and natural gas 
gathering and boosting industry segment only).
    (2) You must report information specified in paragraphs (d)(2)(i) 
through (iii) of this section, applicable to the calculation method 
reported in paragraph (d)(1)(iii) of this section, for each acid gas 
removal unit.
    (i) If you used Calculation Method 1 or Calculation Method 2 as 
specified in Sec. 98.233(d) to calculate CO2 emissions from 
the acid gas removal unit, then you must report the information 
specified in paragraphs (d)(2)(i)(A) and (B) of this section.
    (A) Annual average volumetric fraction of CO2 in the vent 
gas exiting the acid gas removal unit.
    (B) Annual volume of gas vented from the acid gas removal unit, in 
cubic feet.
    (ii) If you used Calculation Method 3 as specified in Sec. 
98.233(d) to calculate CO2 emissions from the acid gas 
removal unit, then you must report the information specified in 
paragraphs (d)(2)(ii)(A) through (D) of this section.
    (A) Indicate which equation was used (Equation W-4A or W-4B).
    (B) Annual average volumetric fraction of CO2 in the 
natural gas flowing out of the acid gas removal unit, as specified in 
Equation W-4A or Equation W-4B of this subpart.
    (C) Annual average volumetric fraction of CO2 content in 
natural gas flowing into the acid gas removal unit, as specified in 
Equation W-4A or Equation W-4B of this subpart.
    (D) The natural gas flow rate used, as specified in Equation W-4A of 
this subpart, reported as either total annual volume of natural gas flow 
into the acid gas removal unit in cubic feet at actual conditions; or 
total annual volume of natural gas flow out of the acid gas removal 
unit, as specified in Equation W-4B of this subpart, in cubic feet at 
actual conditions.
    (iii) If you used Calculation Method 4 as specified in Sec. 
98.233(d) to calculate

[[Page 875]]

CO2 emissions from the acid gas removal unit, then you must 
report the information specified in paragraphs (d)(2)(iii)(A) through 
(L) of this section, as applicable to the simulation software package 
used.
    (A) The name of the simulation software package used.
    (B) Natural gas feed temperature, in degrees Fahrenheit.
    (C) Natural gas feed pressure, in pounds per square inch.
    (D) Natural gas flow rate, in standard cubic feet per minute.
    (E) Acid gas content of the feed natural gas, in mole percent.
    (F) Acid gas content of the outlet natural gas, in mole percent.
    (G) Unit operating hours, excluding downtime for maintenance or 
standby, in hours per year.
    (H) Exit temperature of the natural gas, in degrees Fahrenheit.
    (I) Solvent pressure, in pounds per square inch.
    (J) Solvent temperature, in degrees Fahrenheit.
    (K) Solvent circulation rate, in gallons per minute.
    (L) Solvent weight, in pounds per gallon.
    (e) Dehydrators. You must indicate whether your facility contains 
any of the following equipment: Glycol dehydrators with an annual 
average daily natural gas throughput greater than or equal to 0.4 
million standard cubic feet per day, glycol dehydrators with an annual 
average daily natural gas throughput less than 0.4 million standard 
cubic feet per day, and dehydrators that use desiccant. If your facility 
contains any of the equipment listed in this paragraph (e), then you 
must report the applicable information in paragraphs (e)(1) through (3).
    (1) For each glycol dehydrator that has an annual average daily 
natural gas throughput greater than or equal to 0.4 million standard 
cubic feet per day (as specified in Sec. 98.233(e)(1)), you must report 
the information specified in paragraphs (e)(1)(i) through (xviii) of 
this section for the dehydrator.
    (i) A unique name or ID number for the dehydrator. For the onshore 
petroleum and natural gas production and the onshore petroleum and 
natural gas gathering and boosting industry segments, a different name 
or ID may be used for a single dehydrator for each location it operates 
at in a given year.
    (ii) Dehydrator feed natural gas flow rate, in million standard 
cubic feet per day, determined by engineering estimate based on best 
available data.
    (iii) Dehydrator feed natural gas water content, in pounds per 
million standard cubic feet.
    (iv) Dehydrator outlet natural gas water content, in pounds per 
million standard cubic feet.
    (v) Dehydrator absorbent circulation pump type (e.g., natural gas 
pneumatic, air pneumatic, or electric).
    (vi) Dehydrator absorbent circulation rate, in gallons per minute.
    (vii) Type of absorbent (e.g., triethylene glycol (TEG), diethylene 
glycol (DEG), or ethylene glycol (EG)).
    (viii) Whether stripper gas is used in dehydrator.
    (ix) Whether a flash tank separator is used in dehydrator.
    (x) Total time the dehydrator is operating, in hours.
    (xi) Temperature of the wet natural gas, in degrees Fahrenheit.
    (xii) Pressure of the wet natural gas, in pounds per square inch 
gauge.
    (xiii) Mole fraction of CH4 in wet natural gas.
    (xiv) Mole fraction of CO2 in wet natural gas.
    (xv) Whether any dehydrator emissions are vented to a vapor recovery 
device.
    (xvi) Whether any dehydrator emissions are vented to a flare or 
regenerator firebox/fire tubes. If any emissions are vented to a flare 
or regenerator firebox/fire tubes, report the information specified in 
paragraphs (e)(1)(xvi)(A) through (C) of this section for these 
emissions from the dehydrator.
    (A) Annual CO2 emissions, in metric tons CO2, 
for the dehydrator, calculated according to Sec. 98.233(e)(6).
    (B) Annual CH4 emissions, in metric tons CH4, 
for the dehydrator, calculated according to Sec. 98.233(e)(6).
    (C) Annual N2O emissions, in metric tons N2O, 
for the dehydrator, calculated according to Sec. 98.233(e)(6).
    (xvii) Whether any dehydrator emissions are vented to the atmosphere

[[Page 876]]

without being routed to a flare or regenerator firebox/fire tubes. If 
any emissions are not routed to a flare or regenerator firebox/fire 
tubes, then you must report the information specified in paragraphs 
(e)(1)(xvii)(A) and (B) of this section for those emissions from the 
dehydrator.
    (A) Annual CO2 emissions, in metric tons CO2, 
for the dehydrator when not venting to a flare or regenerator firebox/
fire tubes, calculated according to Sec. 98.233(e)(1), and, if 
applicable, (e)(5).
    (B) Annual CH4 emissions, in metric tons CH4, 
for the dehydrator when not venting to a flare or regenerator firebox/
fire tubes, calculated according to Sec. 98.233(e)(1) and, if 
applicable, (e)(5).
    (xviii) Sub-basin ID that best represents the wells supplying gas to 
the dehydrator (for the onshore petroleum and natural gas production 
industry segment only) or name of the county that best represents the 
equipment supplying gas to the dehydrator (for the onshore petroleum and 
natural gas gathering and boosting industry segment only).
    (2) For glycol dehydrators with an annual average daily natural gas 
throughput less than 0.4 million standard cubic feet per day (as 
specified in Sec. 98.233(e)(2)), you must report the information 
specified in paragraphs (e)(2)(i) through (v) of this section for the 
entire facility.
    (i) The total number of dehydrators at the facility.
    (ii) Whether any dehydrator emissions were vented to a vapor 
recovery device. If any dehydrator emissions were vented to a vapor 
recovery device, then you must report the total number of dehydrators at 
the facility that vented to a vapor recovery device.
    (iii) Whether any dehydrator emissions were vented to a control 
device other than a vapor recovery device or a flare or regenerator 
firebox/fire tubes. If any dehydrator emissions were vented to a control 
device(s) other than a vapor recovery device or a flare or regenerator 
firebox/fire tubes, then you must specify the type of control device(s) 
and the total number of dehydrators at the facility that were vented to 
each type of control device.
    (iv) Whether any dehydrator emissions were vented to a flare or 
regenerator firebox/fire tubes. If any dehydrator emissions were vented 
to a flare or regenerator firebox/fire tubes, then you must report the 
information specified in paragraphs (e)(2)(iv)(A) through (D) of this 
section.
    (A) The total number of dehydrators venting to a flare or 
regenerator firebox/fire tubes.
    (B) Annual CO2 emissions, in metric tons CO2, 
for the dehydrators reported in paragraph (e)(2)(iv)(A) of this section, 
calculated according to Sec. 98.233(e)(6).
    (C) Annual CH4 emissions, in metric tons CH4, 
for the dehydrators reported in paragraph (e)(2)(iv)(A) of this section, 
calculated according to Sec. 98.233(e)(6).
    (D) Annual N2O emissions, in metric tons N2O, 
for the dehydrators reported in paragraph (e)(2)(iv)(A) of this section, 
calculated according to Sec. 98.233(e)(6).
    (v) For dehydrator emissions that were not vented to a flare or 
regenerator firebox/fire tubes, report the information specified in 
paragraphs (e)(2)(v)(A) and (B) of this section.
    (A) Annual CO2 emissions, in metric tons CO2, 
for emissions from all dehydrators reported in paragraph (e)(2)(i) of 
this section that were not vented to a flare or regenerator firebox/fire 
tubes, calculated according to Sec. 98.233(e)(2), (e)(4), and, if 
applicable, (e)(5), where emissions are added together for all such 
dehydrators.
    (B) Annual CH4 emissions, in metric tons CH4, 
for emissions from all dehydrators reported in paragraph (e)(2)(i) of 
this section that were not vented to a flare or regenerator firebox/fire 
tubes, calculated according to Sec. 98.233(e)(2), (e)(4), and, if 
applicable, (e)(5), where emissions are added together for all such 
dehydrators.
    (3) For dehydrators that use desiccant (as specified in Sec. 
98.233(e)(3)), you must report the information specified in paragraphs 
(e)(3)(i) through (iii) of this section for the entire facility.
    (i) The same information specified in paragraphs (e)(2)(i) through 
(iv) of this section for glycol dehydrators, and report the information 
under this paragraph for dehydrators that use desiccant.

[[Page 877]]

    (ii) Annual CO2 emissions, in metric tons CO2, 
for emissions from all desiccant dehydrators reported under paragraph 
(e)(3)(i) of this section that are not venting to a flare or regenerator 
firebox/fire tubes, calculated according to Sec. 98.233(e)(3), (e)(4), 
and, if applicable, (e)(5), and summing for all such dehydrators.
    (iii) Annual CH4 emissions, in metric tons 
CH4, for emissions from all desiccant dehydrators reported in 
paragraph (e)(3)(i) of this section that are not venting to a flare or 
regenerator firebox/fire tubes, calculated according to Sec. 
98.233(e)(3), (e)(4), and, if applicable, (e)(5), and summing for all 
such dehydrators.
    (f) Liquids unloading. You must indicate whether well venting for 
liquids unloading occurs at your facility, and if so, which methods (as 
specified in Sec. 98.233(f)) were used to calculate emissions. If your 
facility performs well venting for liquids unloading and uses 
Calculation Method 1, then you must report the information specified in 
paragraph (f)(1) of this section. If the facility performs liquids 
unloading and uses Calculation Method 2 or 3, then you must report the 
information specified in paragraph (f)(2) of this section.
    (1) For each sub-basin and well tubing diameter and pressure group 
for which you used Calculation Method 1 to calculate natural gas 
emissions from well venting for liquids unloading, report the 
information specified in paragraphs (f)(1)(i) through (xii) of this 
section. Report information separately for wells with plunger lifts and 
wells without plunger lifts.
    (i) Sub-basin ID.
    (ii) Well tubing diameter and pressure group ID and a list of the 
well ID numbers associated with each sub-basin and well tubing diameter 
and pressure group ID.
    (iii) Plunger lift indicator.
    (iv) Count of wells vented to the atmosphere for the sub-basin/well 
tubing diameter and pressure group.
    (v) Percentage of wells for which the monitoring period used to 
determine the cumulative amount of time venting was not the full 
calendar year.
    (vi) Cumulative amount of time wells were vented (sum of 
``Tp'' from Equation W-7A or W-7B of this subpart), in hours.
    (vii) Cumulative number of unloadings vented to the atmosphere for 
each well, aggregated across all wells in the sub-basin/well tubing 
diameter and pressure group.
    (viii) Annual natural gas emissions, in standard cubic feet, from 
well venting for liquids unloading, calculated according to Sec. 
98.233(f)(1).
    (ix) Annual CO2 emissions, in metric tons CO2, 
from well venting for liquids unloading, calculated according to Sec. 
98.233(f)(1) and (4).
    (x) Annual CH4 emissions, in metric tons CH4, 
from well venting for liquids unloading, calculated according to Sec. 
98.233(f)(1) and (4).
    (xi) For each well tubing diameter group and pressure group 
combination, you must report the information specified in paragraphs 
(f)(1)(xi)(A) through (E) of this section for each individual well not 
using a plunger lift that was tested during the year.
    (A) Well ID number of tested well.
    (B) Casing pressure, in pounds per square inch absolute.
    (C) Internal casing diameter, in inches.
    (D) Measured depth of the well, in feet.
    (E) Average flow rate of the well venting over the duration of the 
liquids unloading, in standard cubic feet per hour.
    (xii) For each well tubing diameter group and pressure group 
combination, you must report the information specified in paragraphs 
(f)(1)(xii)(A) through (E) of this section for each individual well 
using a plunger lift that was tested during the year.
    (A) Well ID number.
    (B) The tubing pressure, in pounds per square inch absolute.
    (C) The internal tubing diameter, in inches.
    (D) Measured depth of the well, in feet.
    (E) Average flow rate of the well venting over the duration of the 
liquids unloading, in standard cubic feet per hour.
    (2) For each sub-basin for which you used Calculation Method 2 or 3 
(as specified in Sec. 93.233(f)) to calculate natural gas emissions 
from well venting

[[Page 878]]

for liquids unloading, you must report the information in (f)(2)(i) 
through (x) of this section. Report information separately for each 
calculation method.
    (i) Sub-basin ID and a list of the well ID numbers associated with 
each sub-basin.
    (ii) Calculation method.
    (iii) Plunger lift indicator.
    (iv) Number of wells vented to the atmosphere.
    (v) Cumulative number of unloadings vented to the atmosphere for 
each well, aggregated across all wells.
    (vi) Annual natural gas emissions, in standard cubic feet, from well 
venting for liquids unloading, calculated according to Sec. 
98.233(f)(2) or (3), as applicable.
    (vii) Annual CO2 emissions, in metric tons 
CO2, from well venting for liquids unloading, calculated 
according to Sec. 98.233(f)(2) or (3), as applicable, and Sec. 
98.233(f)(4).
    (viii) Annual CH4 emissions, in metric tons 
CH4, from well venting for liquids unloading, calculated 
according to Sec. 98.233(f)(2) or (3), as applicable, and Sec. 
98.233(f)(4).
    (ix) For wells without plunger lifts, the average internal casing 
diameter, in inches.
    (x) For wells with plunger lifts, the average internal tubing 
diameter, in inches.
    (g) Completions and workovers with hydraulic fracturing. You must 
indicate whether your facility had any well completions or workovers 
with hydraulic fracturing during the calendar year. If your facility had 
well completions or workovers with hydraulic fracturing during the 
calendar year, then you must report information specified in paragraphs 
(g)(1) through (10) of this section, for each sub-basin and well type 
combination. Report information separately for completions and 
workovers.
    (1) Sub-basin ID and a list of the well ID numbers associated with 
each sub-basin that had completions or workovers with hydraulic 
fracturing during the calendar year.
    (2) Well type combination (horizontal or vertical, gas well or oil 
well).
    (3) Number of completions or workovers in the sub-basin and well 
type combination category.
    (4) Calculation method used.
    (5) If you used Equation W-10A of Sec. 98.233 to calculate annual 
volumetric total gas emissions, then you must report the information 
specified in paragraphs (g)(5)(i) through (iii) of this section.
    (i) Cumulative gas flowback time, in hours, from when gas is first 
detected until sufficient quantities are present to enable separation, 
and the cumulative flowback time, in hours, after sufficient quantities 
of gas are present to enable separation (sum of ``Tp,i'' and 
sum of ``Tp,s'' values used in Equation W-10A of Sec. 
98.233). You may delay the reporting of this data element if you 
indicate in the annual report that wildcat wells and/or delineation 
wells are the only wells included in this number. If you elect to delay 
reporting of this data element, you must report by the date specified in 
Sec. 98.236(cc) the total number of hours of flowback from all wells 
during completions or workovers and the well ID number(s) for the 
well(s) included in the number.
    (ii) For the measured well(s), the flowback rate, in standard cubic 
feet per hour (average of ``FRs,p'' values used in Equation 
W-12A of Sec. 98.233), and the well ID numbers of the wells for which 
it is measured. You may delay the reporting of this data element if you 
indicate in the annual report that wildcat wells and/or delineation 
wells are the only wells that can be used for the measurement. If you 
elect to delay reporting of this data element, you must report by the 
date specified in Sec. 98.236(cc) the measured flowback rate during 
well completion or workover and the well ID number(s) for the well(s) 
included in the measurement.
    (iii) If you used Equation W-12C of Sec. 98.233 to calculate the 
average gas production rate for an oil well, then you must report the 
information specified in paragraphs (g)(5)(iii)(A) and (B) of this 
section.
    (A) Gas to oil ratio for the well in standard cubic feet of gas per 
barrel of oil (``GORp'' in Equation W-12C of Sec. 98.233). 
You may delay the reporting of this data element if you indicate in the 
annual report that wildcat wells and/or delineation wells are the only 
wells that can be used for the measurement. If you elect to delay 
reporting of

[[Page 879]]

this data element, you must report by the date specified in Sec. 
98.236(cc) the gas to oil ratio for the well and the well ID number for 
the well.
    (B) Volume of oil produced during the first 30 days of production 
after completions of each newly drilled well or well workover using 
hydraulic fracturing, in barrels (``Vp'' in Equation W-12C of 
Sec. 98.233). You may delay the reporting of this data element if you 
indicate in the annual report that wildcat wells and/or delineation 
wells are the only wells that can be used for the measurement. If you 
elect to delay reporting of this data element, you must report by the 
date specified in Sec. 98.236(cc) the volume of oil produced during the 
first 30 days of production after well completion or workover and the 
well ID number for the well.
    (6) If you used Equation W-10B of Sec. 98.233 to calculate annual 
volumetric total gas emissions, then you must report the information 
specified in paragraphs (g)(6)(i) through (iii) of this section.
    (i) Vented natural gas volume, in standard cubic feet, for each well 
in the sub-basin (``FVs,p'' in Equation W-10B of Sec. 
98.233).
    (ii) Flow rate at the beginning of the period of time when 
sufficient quantities of gas are present to enable separation, in 
standard cubic feet per hour, for each well in the sub-basin 
(``FRp,i'' in Equation W-10B of Sec. 98.233).
    (iii) The well ID number for which vented natural gas volume was 
measured.
    (7) Annual gas emissions, in standard cubic feet 
(``Es,n'' in Equation W-10A or W-10B).
    (8) Annual CO2 emissions, in metric tons CO2.
    (9) Annual CH4 emissions, in metric tons CH4.
    (10) If the well emissions were vented to a flare, then you must 
report the total N2O emissions, in metric tons 
N2O.
    (h) Completions and workovers without hydraulic fracturing. You must 
indicate whether the facility had any gas well completions without 
hydraulic fracturing or any gas well workovers without hydraulic 
fracturing, and if the activities occurred with or without flaring. If 
the facility had gas well completions or workovers without hydraulic 
fracturing, then you must report the information specified in paragraphs 
(h)(1) through (4) of this section, as applicable.
    (1) For each sub-basin with gas well completions without hydraulic 
fracturing and without flaring, report the information specified in 
paragraphs (h)(1)(i) through (vi) of this section.
    (i) Sub-basin ID and a list of the well ID numbers associated with 
each sub-basin for gas well completions without hydraulic fracturing and 
without flaring.
    (ii) Number of well completions that vented gas directly to the 
atmosphere without flaring.
    (iii) Total number of hours that gas vented directly to the 
atmosphere during venting for all completions in the sub-basin category 
(the sum of all ``Tp'' for completions that vented to the 
atmosphere as used in Equation W-13B).
    (iv) Average daily gas production rate for all completions without 
hydraulic fracturing in the sub-basin without flaring, in standard cubic 
feet per hour (average of all ``Vp'' used in Equation W-13B 
of Sec. 98.233). You may delay reporting of this data element if you 
indicate in the annual report that wildcat wells and/or delineation 
wells are the only wells that can be used for the measurement. If you 
elect to delay reporting of this data element, you must report by the 
date specified in Sec. 98.236(cc) the measured average daily gas 
production rate for all wells during completions and the well ID 
number(s) for the well(s) included in the measurement.
    (v) Annual CO2 emissions, in metric tons CO2, 
that resulted from completions venting gas directly to the atmosphere 
(``Es,p'' from Equation W-13B for completions that vented 
directly to the atmosphere, converted to mass emissions according to 
Sec. 98.233(h)(1)).
    (vi) Annual CH4 emissions, in metric tons CH4, 
that resulted from completions venting gas directly to the atmosphere 
(``Es,p'' from Equation W-13B for completions that vented 
directly to the atmosphere, converted to mass emissions according to 
Sec. 98.233(h)(1)).

[[Page 880]]

    (2) For each sub-basin with gas well completions without hydraulic 
fracturing and with flaring, report the information specified in 
paragraphs (h)(2)(i) through (vii) of this section.
    (i) Sub-basin ID and a list of the well ID numbers associated with 
each sub-basin for gas well completions without hydraulic fracturing and 
with flaring.
    (ii) Number of well completions that flared gas.
    (iii) Total number of hours that gas vented to a flare during 
venting for all completions in the sub-basin category (the sum of all 
``Tp'' for completions that vented to a flare from Equation 
W-13B).
    (iv) Average daily gas production rate for all completions without 
hydraulic fracturing in the sub-basin with flaring, in standard cubic 
feet per hour (the average of all ``Vp'' from Equation W-13B 
of Sec. 98.233). You may delay reporting of this data element if you 
indicate in the annual report that wildcat wells and/or delineation 
wells are the only wells that can be used for the measurement. If you 
elect to delay reporting of this data element, you must report by the 
date specified in Sec. 98.236(cc) the measured average daily gas 
production rate for all wells during completions and the well ID 
number(s) for the well(s) included in the measurement.
    (v) Annual CO2 emissions, in metric tons CO2, 
that resulted from completions that flared gas calculated according to 
Sec. 98.233(h)(2).
    (vi) Annual CH4 emissions, in metric tons CH4, 
that resulted from completions that flared gas calculated according to 
Sec. 98.233(h)(2).
    (vii) Annual N2O emissions, in metric tons 
N2O, that resulted from completions that flared gas 
calculated according to Sec. 98.233(h)(2).
    (3) For each sub-basin with gas well workovers without hydraulic 
fracturing and without flaring, report the information specified in 
paragraphs (h)(3)(i) through (iv) of this section.
    (i) Sub-basin ID and a list of the well ID numbers associated with 
each sub-basin for gas well workovers without hydraulic fracturing and 
without flaring.
    (ii) Number of workovers that vented gas to the atmosphere without 
flaring.
    (iii) Annual CO2 emissions, in metric tons CO2 
per year, that resulted from workovers venting gas directly to the 
atmosphere (``Es,wo'' in Equation W-13A for workovers that 
vented directly to the atmosphere, converted to mass emissions as 
specified in Sec. 98.233(h)(1)).
    (iv) Annual CH4 emissions, in metric tons CH4 
per year, that resulted from workovers venting gas directly to the 
atmosphere (``Es,wo'' in Equation W-13A for workovers that 
vented directly to the atmosphere, converted to mass emissions as 
specified in Sec. 98.233(h)(1)).
    (4) For each sub-basin with gas well workovers without hydraulic 
fracturing and with flaring, report the information specified in 
paragraphs (h)(4)(i) through (v) of this section.
    (i) Sub-basin ID and a list of well ID numbers associated with each 
sub-basin for gas well workovers without hydraulic fracturing and with 
flaring.
    (ii) Number of workovers that flared gas.
    (iii) Annual CO2 emissions, in metric tons CO2 
per year, that resulted from workovers that flared gas calculated as 
specified in Sec. 98.233(h)(2).
    (iv) Annual CH4 emissions, in metric tons CH4 
per year, that resulted from workovers that flared gas, calculated as 
specified in Sec. 98.233(h)(2).
    (v) Annual N2O emissions, in metric tons N2O 
per year, that resulted from workovers that flared gas calculated as 
specified in Sec. 98.233(h)(2).
    (i) Blowdown vent stacks. You must indicate whether your facility 
has blowdown vent stacks. If your facility has blowdown vent stacks, 
then you must report whether emissions were calculated by equipment or 
event type or by using flow meters or a combination of both. If you 
calculated emissions by equipment or event type for any blowdown vent 
stacks, then you must report the information specified in paragraph 
(i)(1) of this section considering, in aggregate, all blowdown vent 
stacks for which emissions were calculated by equipment or event type. 
If you calculated emissions using flow meters for any blowdown vent 
stacks, then you must report the information specified in paragraph 
(i)(2) of this section considering, in aggregate, all

[[Page 881]]

blowdown vent stacks for which emissions were calculated using flow 
meters. For the onshore natural gas transmission pipeline segment, you 
must also report the information in paragraph (i)(3) of this section.
    (1) Report by equipment or event type. If you calculated emissions 
from blowdown vent stacks by the seven categories listed in Sec. 
98.233(i)(2) for industry segments other than the onshore natural gas 
transmission pipeline segment, then you must report the equipment or 
event types and the information specified in paragraphs (i)(1)(i) 
through (iii) of this section for each equipment or event type. If a 
blowdown event resulted in emissions from multiple equipment types, and 
the emissions cannot be apportioned to the different equipment types, 
then you may report the information in paragraphs (i)(1)(i) through 
(iii) of this section for the equipment type that represented the 
largest portion of the emissions for the blowdown event. If you 
calculated emissions from blowdown vent stacks by the eight categories 
listed in Sec. 98.233(i)(2) for the onshore natural gas transmission 
pipeline segment, then you must report the pipeline segments or event 
types and the information specified in paragraphs (i)(1)(i) through 
(iii) of this section for each ``equipment or event type'' (i.e., 
category). If a blowdown event resulted in emissions from multiple 
categories, and the emissions cannot be apportioned to the different 
categories, then you may report the information in paragraphs (i)(1)(i) 
through (iii) of this section for the ``equipment or event type'' (i.e., 
category) that represented the largest portion of the emissions for the 
blowdown event.
    (i) Total number of blowdowns in the calendar year for the equipment 
or event type (the sum of equation variable ``N'' from Equation W-14A or 
Equation W-14B of this subpart, for all unique physical volumes for the 
equipment or event type).
    (ii) Annual CO2 emissions for the equipment or event 
type, in metric tons CO2, calculated according to Sec. 
98.233(i)(2)(iii).
    (iii) Annual CH4 emissions for the equipment or event 
type, in metric tons CH4, calculated according to Sec. 
98.233(i)(2)(iii).
    (2) Report by flow meter. If you elect to calculate emissions from 
blowdown vent stacks by using a flow meter according to Sec. 
98.233(i)(3), then you must report the information specified in 
paragraphs (i)(2)(i) and (ii) of this section for the facility.
    (i) Annual CO2 emissions from all blowdown vent stacks at 
the facility for which emissions were calculated using flow meters, in 
metric tons CO2 (the sum of all CO2 mass emission 
values calculated according to Sec. 98.233(i)(3), for all flow meters).
    (ii) Annual CH4 emissions from all blowdown vent stacks 
at the facility for which emissions were calculated using flow meters, 
in metric tons CH4, (the sum of all CH4 mass 
emission values calculated according to Sec. 98.233(i)(3), for all flow 
meters).
    (3) Onshore natural gas transmission pipeline segment. Report the 
information in paragraphs (i)(3)(i) through (iii) of this section for 
each state.
    (i) Annual CO2 emissions in metric tons CO2.
    (ii) Annual CH4 emissions in metric tons CH4.
    (iii) Annual number of blowdown events.
    (j) Onshore production and onshore petroleum and natural gas 
gathering and boosting storage tanks. You must indicate whether your 
facility sends produced oil to atmospheric tanks. If your facility sends 
produced oil to atmospheric tanks, then you must indicate which 
Calculation Method(s) you used to calculate GHG emissions, and you must 
report the information specified in paragraphs (j)(1) and (2) of this 
section as applicable. If you used Calculation Method 1 or Calculation 
Method 2 of Sec. 98.233(j), and any atmospheric tanks were observed to 
have malfunctioning dump valves during the calendar year, then you must 
indicate that dump valves were malfunctioning and you must report the 
information specified in paragraph (j)(3) of this section.
    (1) If you used Calculation Method 1 or Calculation Method 2 of 
Sec. 98.233(j) to calculate GHG emissions, then you must report the 
information specified in paragraphs (j)(1)(i) through (xvi) of

[[Page 882]]

this section for each sub-basin (for onshore production) or county (for 
onshore petroleum and natural gas gathering and boosting) and by 
calculation method. Onshore petroleum and natural gas gathering and 
boosting facilities do not report the information specified in 
paragraphs (j)(1)(ix) and (xi) of this section.
    (i) Sub-basin ID (for onshore production) or county name (for 
onshore petroleum and natural gas gathering and boosting).
    (ii) Calculation method used, and name of the software package used 
if using Calculation Method 1.
    (iii) The total annual oil volume from gas-liquid separators and 
direct from wells or non-separator equipment that is sent to applicable 
onshore production and onshore petroleum and natural gas gathering and 
boosting storage tanks, in barrels. You may delay reporting of this data 
element for onshore production if you indicate in the annual report that 
wildcat wells and delineation wells are the only wells in the sub-basin 
with oil production greater than or equal to 10 barrels per day and 
flowing to gas-liquid separators or direct to storage tanks. If you 
elect to delay reporting of this data element, you must report by the 
date specified in Sec. 98.236(cc) the total volume of oil from all 
wells and the well ID number(s) for the well(s) included in this volume.
    (iv) The average gas-liquid separator or non-separator equipment 
temperature, in degrees Fahrenheit.
    (v) The average gas-liquid separator or non-separator equipment 
pressure, in pounds per square inch gauge.
    (vi) The average sales oil or stabilized oil API gravity, in 
degrees.
    (vii) The minimum and maximum concentration (mole fraction) of 
CO2 in flash gas from onshore production and onshore natural 
gas gathering and boosting storage tanks.
    (viii) The minimum and maximum concentration (mole fraction) of 
CH4 in flash gas from onshore production and onshore natural 
gas gathering and boosting storage tanks.
    (ix) The number of wells sending oil to gas-liquid separators or 
directly to atmospheric tanks.
    (x) The number of atmospheric tanks.
    (xi) An estimate of the number of atmospheric tanks, not on well-
pads, receiving your oil.
    (xii) If any emissions from the atmospheric tanks at your facility 
were controlled with vapor recovery systems, then you must report the 
information specified in paragraphs (j)(1)(xii)(A) through (E) of this 
section.
    (A) The number of atmospheric tanks that control emissions with 
vapor recovery systems.
    (B) Total CO2 mass, in metric tons CO2, that 
was recovered during the calendar year using a vapor recovery system.
    (C) Total CH4 mass, in metric tons CH4, that 
was recovered during the calendar year using a vapor recovery system.
    (D) Annual CO2 emissions, in metric tons CO2, 
from atmospheric tanks equipped with vapor recovery systems.
    (E) Annual CH4 emissions, in metric tons CH4, 
from atmospheric tanks equipped with vapor recovery systems.
    (xiii) If any atmospheric tanks at your facility vented gas directly 
to the atmosphere without using a vapor recovery system or without 
flaring, then you must report the information specified in paragraphs 
(j)(1)(xiii)(A) through (C) of this section.
    (A) The number of atmospheric tanks that vented gas directly to the 
atmosphere without using a vapor recovery system or without flaring.
    (B) Annual CO2 emissions, in metric tons CO2, 
that resulted from venting gas directly to the atmosphere.
    (C) Annual CH4 emissions, in metric tons CH4, 
that resulted from venting gas directly to the atmosphere.
    (xiv) If you controlled emissions from any atmospheric tanks at your 
facility with one or more flares, then you must report the information 
specified in paragraphs (j)(1)(xiv)(A) through (D) of this section.
    (A) The number of atmospheric tanks that controlled emissions with 
flares.
    (B) Annual CO2 emissions, in metric tons CO2, 
from atmospheric tanks that controlled emissions with one or more 
flares.
    (C) Annual CH4 emissions, in metric tons CH4, 
from atmospheric tanks that controlled emissions with one or more 
flares.

[[Page 883]]

    (D) Annual N2O emissions, in metric tons N2O, 
from atmospheric tanks that controlled emissions with one or more 
flares.
    (2) If you used Calculation Method 3 to calculate GHG emissions, 
then you must report the information specified in paragraphs (j)(2)(i) 
through (iii) of this section.
    (i) Report the information specified in paragraphs (j)(2)(i)(A) 
through (F) of this section, at the basin level, for atmospheric tanks 
where emissions were calculated using Calculation Method 3 of Sec. 
98.233(j). Onshore gathering and boosting facilities do not report the 
information specified in paragraphs (j)(2)(i)(E) and (F) of this 
section.
    (A) The total annual oil/condensate throughput that is sent to all 
atmospheric tanks in the basin, in barrels. You may delay reporting of 
this data element for onshore production if you indicate in the annual 
report that wildcat wells and delineation wells are the only wells in 
the sub-basin with oil/condensate production less than 10 barrels per 
day and that send oil/condensate to atmospheric tanks. If you elect to 
delay reporting of this data element, you must report by the date 
specified in Sec. 98.236(cc) the total annual oil/condensate throughput 
from all wells and the well ID number(s) for the well(s) included in 
this volume.
    (B) An estimate of the fraction of oil/condensate throughput 
reported in paragraph (j)(2)(i)(A) of this section sent to atmospheric 
tanks in the basin that controlled emissions with flares.
    (C) An estimate of the fraction of oil/condensate throughput 
reported in paragraph (j)(2)(i)(A) of this section sent to atmospheric 
tanks in the basin that controlled emissions with vapor recovery 
systems.
    (D) The number of atmospheric tanks in the basin.
    (E) The number of wells with gas-liquid separators (``Count'' from 
Equation W-15 of this subpart) in the basin.
    (F) The number of wells without gas-liquid separators (``Count'' 
from Equation W-15 of this subpart) in the basin.
    (ii) Report the information specified in paragraphs (j)(2)(ii)(A) 
through (D) of this section for each sub-basin (for onshore production) 
or county (for onshore petroleum and natural gas gathering and boosting) 
with atmospheric tanks whose emissions were calculated using Calculation 
Method 3 of Sec. 98.233(j) and that did not control emissions with 
flares.
    (A) Sub-basin ID (for onshore production) or county name (for 
onshore petroleum and natural gas gathering and boosting).
    (B) The number of atmospheric tanks in the sub-basin (for onshore 
production) or county (for onshore petroleum and natural gas gathering 
and boosting) that did not control emissions with flares.
    (C) Annual CO2 emissions, in metric tons CO2, 
from atmospheric tanks in the sub-basin (for onshore production) or 
county (for onshore petroleum and natural gas gathering and boosting) 
that did not control emissions with flares, calculated using Equation W-
15 of Sec. 98.233(j) and adjusted for vapor recovery, if applicable.
    (D) Annual CH4 emissions, in metric tons CH4, 
from atmospheric tanks in the sub-basin (for onshore production) or 
county (for onshore petroleum and natural gas gathering and boosting) 
that did not control emissions with flares, calculated using Equation W-
15 of Sec. 98.233(j) and adjusted for vapor recovery, if applicable.
    (iii) Report the information specified in paragraphs (j)(2)(iii)(A) 
through (E) of this section for each sub-basin (for onshore production) 
or county (for onshore petroleum and natural gas gathering and boosting) 
with atmospheric tanks whose emissions were calculated using Calculation 
Method 3 of Sec. 98.233(j) and that controlled emissions with flares.
    (A) Sub-basin ID (for onshore production) or county name (for 
onshore petroleum and natural gas gathering and boosting).
    (B) The number of atmospheric tanks in the sub-basin (for onshore 
production) or county (for onshore petroleum and natural gas gathering 
and boosting) that controlled emissions with flares.
    (C) Annual CO2 emissions, in metric tons CO2, 
from atmospheric tanks that controlled emissions with flares.
    (D) Annual CH4 emissions, in metric tons CH4, 
from atmospheric tanks that controlled emissions with flares.

[[Page 884]]

    (E) Annual N2O emissions, in metric tons N2O, 
from atmospheric tanks that controlled emissions with flares.
    (3) If you used Calculation Method 1 or Calculation Method 2 of 
Sec. 98.233(j), and any gas-liquid separator liquid dump values did not 
close properly during the calendar year, then you must report the 
information specified in paragraphs (j)(3)(i) through (iv) of this 
section for each sub-basin (for onshore production) or county (for 
onshore petroleum and natural gas gathering and boosting).
    (i) The total number of gas-liquid separators whose liquid dump 
valves did not close properly during the calendar year.
    (ii) The total time the dump valves on gas-liquid separators did not 
close properly in the calendar year, in hours (sum of the 
``Tn'' values used in Equation W-16 of this subpart).
    (iii) Annual CO2 emissions, in metric tons 
CO2, that resulted from dump valves on gas-liquid separators 
not closing properly during the calendar year, calculated using Equation 
W-16 of this subpart.
    (iv) Annual CH4 emissions, in metric tons CH4, 
that resulted from the dump valves on gas-liquid separators not closing 
properly during the calendar year, calculated using Equation W-16 of 
this subpart.
    (k) Transmission storage tanks. You must indicate whether your 
facility contains any transmission storage tanks. If your facility 
contains at least one transmission storage tank, then you must report 
the information specified in paragraphs (k)(1) through (3) of this 
section for each transmission storage tank vent stack.
    (1) For each transmission storage tank vent stack, report the 
information specified in (k)(1)(i) through (iv) of this section.
    (i) The unique name or ID number for the transmission storage tank 
vent stack.
    (ii) Method used to determine if dump valve leakage occurred.
    (iii) Indicate whether scrubber dump valve leakage occurred for the 
transmission storage tank vent according to Sec. 98.233(k)(2).
    (iv) Indicate if there is a flare attached to the transmission 
storage tank vent stack.
    (2) If scrubber dump valve leakage occurred for a transmission 
storage tank vent stack, as reported in paragraph (k)(1)(iii) of this 
section, and the vent stack vented directly to the atmosphere during the 
calendar year, then you must report the information specified in 
paragraphs (k)(2)(i) through (v) of this section for each transmission 
storage vent stack where scrubber dump valve leakage occurred.
    (i) Method used to measure the leak rate.
    (ii) Measured leak rate (average leak rate from a continuous flow 
measurement device), in standard cubic feet per hour.
    (iii) Duration of time that the leak is counted as having occurred, 
in hours, as determined in Sec. 98.233(k)(3) (may use best available 
data if a continuous flow measurement device was used).
    (iv) Annual CO2 emissions, in metric tons CO2, 
that resulted from venting gas directly to the atmosphere, calculated 
according to Sec. 98.233(k)(1) through (4).
    (v) Annual CH4 emissions, in metric tons CH4, 
that resulted from venting gas directly to the atmosphere, calculated 
according to Sec. 98.233(k)(1) through (4).
    (3) If scrubber dump valve leakage occurred for a transmission 
storage tank vent stack, as reported in paragraph (k)(1)(iii), and the 
vent stack vented to a flare during the calendar year, then you must 
report the information specified in paragraphs (k)(3)(i) through (vi) of 
this section.
    (i) Method used to measure the leak rate.
    (ii) Measured leakage rate (average leak rate from a continuous flow 
measurement device) in standard cubic feet per hour.
    (iii) Duration of time that flaring occurred in hours, as defined in 
Sec. 98.233(k)(3) (may use best available data if a continuous flow 
measurement device was used).
    (iv) Annual CO2 emissions, in metric tons CO2, 
that resulted from flaring gas, calculated according to Sec. 
98.233(k)(5).

[[Page 885]]

    (v) Annual CH4 emissions, in metric tons CH4, 
that resulted from flaring gas, calculated according to Sec. 
98.233(k)(5).
    (vi) Annual N2O emissions, in metric tons N2O, 
that resulted from flaring gas, calculated according to Sec. 
98.233(k)(5).
    (l) Well testing. You must indicate whether you performed gas well 
or oil well testing, and if the testing of gas wells or oil wells 
resulted in vented or flared emissions during the calendar year. If you 
performed well testing that resulted in vented or flared emissions 
during the calendar year, then you must report the information specified 
in paragraphs (l)(1) through (4) of this section, as applicable.
    (1) If you used Equation W-17A of Sec. 98.233 to calculate annual 
volumetric natural gas emissions at actual conditions from oil wells and 
the emissions are not vented to a flare, then you must report the 
information specified in paragraphs (l)(1)(i) through (vii) of this 
section.
    (i) Number of wells tested in the calendar year.
    (ii) Well ID numbers for the wells tested in the calendar year.
    (iii) Average number of well testing days per well for well(s) 
tested in the calendar year.
    (iv) Average gas to oil ratio for well(s) tested, in cubic feet of 
gas per barrel of oil.
    (v) Average flow rate for well(s) tested, in barrels of oil per day. 
You may delay reporting of this data element if you indicate in the 
annual report that wildcat wells and/or delineation wells are the only 
wells that are tested. If you elect to delay reporting of this data 
element, you must report by the date specified in Sec. 98.236(cc) the 
measured average flow rate for well(s) tested and the well ID number(s) 
for the well(s) included in the measurement.
    (vi) Annual CO2 emissions, in metric tons CO2, 
calculated according to Sec. 98.233(l).
    (vii) Annual CH4 emissions, in metric tons 
CH4, calculated according to Sec. 98.233(l).
    (2) If you used Equation W-17A of Sec. 98.233 to calculate annual 
volumetric natural gas emissions at actual conditions from oil wells and 
the emissions are vented to a flare, then you must report the 
information specified in paragraphs (l)(2)(i) through (viii) of this 
section.
    (i) Number of wells tested in the calendar year.
    (ii) Well ID numbers for the wells tested in the calendar year.
    (iii) Average number of well testing days per well for well(s) 
tested in the calendar year.
    (iv) Average gas to oil ratio for well(s) tested, in cubic feet of 
gas per barrel of oil.
    (v) Average flow rate for well(s) tested, in barrels of oil per day. 
You may delay reporting of this data element if you indicate in the 
annual report that wildcat wells and/or delineation wells are the only 
wells that are tested. If you elect to delay reporting of this data 
element, you must report by the date specified in Sec. 98.236(cc) the 
measured average flow rate for well(s) tested and the well ID number(s) 
for the well(s) included in the measurement.
    (vi) Annual CO2 emissions, in metric tons CO2, 
calculated according to Sec. 98.233(l).
    (vii) Annual CH4 emissions, in metric tons 
CH4, calculated according to Sec. 98.233(l).
    (viii) Annual N2O emissions, in metric tons 
N2O, calculated according to Sec. 98.233(l).
    (3) If you used Equation W-17B of Sec. 98.233 to calculate annual 
volumetric natural gas emissions at actual conditions from gas wells and 
the emissions were not vented to a flare, then you must report the 
information specified in paragraphs (l)(3)(i) through (vi) of this 
section.
    (i) Number of wells tested in the calendar year.
    (ii) Well ID numbers for the wells tested in the calendar year.
    (iii) Average number of well testing days per well for well(s) 
tested in the calendar year.
    (iv) Average annual production rate for well(s) tested, in actual 
cubic feet per day. You may delay reporting of this data element if you 
indicate in the annual report that wildcat wells and/or delineation 
wells are the only wells that are tested. If you elect to delay 
reporting of this data element, you must report by the date specified in

[[Page 886]]

Sec. 98.236(cc) the measured average annual production rate for well(s) 
tested and the well ID number(s) for the well(s) included in the 
measurement.
    (v) Annual CO2 emissions, in metric tons CO2, 
calculated according to Sec. 98.233(l).
    (vi) Annual CH4 emissions, in metric tons CH4, 
calculated according to Sec. 98.233(l).
    (4) If you used Equation W-17B of Sec. 98.233 to calculate annual 
volumetric natural gas emissions at actual conditions from gas wells and 
the emissions were vented to a flare, then you must report the 
information specified in paragraphs (l)(4)(i) through (vii) of this 
section.
    (i) Number of wells tested in calendar year.
    (ii) Well ID numbers for the wells tested in the calendar year.
    (iii) Average number of well testing days per well for well(s) 
tested in the calendar year.
    (iv) Average annual production rate for well(s) tested, in actual 
cubic feet per day. You may delay reporting of this data element if you 
indicate in the annual report that wildcat wells and/or delineation 
wells are the only wells that are tested. If you elect to delay 
reporting of this data element, you must report by the date specified in 
Sec. 98.236(cc) the measured average annual production rate for well(s) 
tested and the well ID number(s) for the well(s) included in the 
measurement.
    (v) Annual CO2 emissions, in metric tons CO2, 
calculated according to Sec. 98.233(l).
    (vi) Annual CH4 emissions, in metric tons CH4, 
calculated according to Sec. 98.233(l).
    (vii) Annual N2O emissions, in metric tons 
N2O, calculated according to Sec. 98.233(l).
    (m) Associated natural gas. You must indicate whether any associated 
gas was vented or flared during the calendar year. If associated gas was 
vented or flared during the calendar year, then you must report the 
information specified in paragraphs (m)(1) through (8) of this section 
for each sub-basin.
    (1) Sub-basin ID and a list of well ID numbers for wells for which 
associated gas was vented or flared.
    (2) Indicate whether any associated gas was vented directly to the 
atmosphere without flaring.
    (3) Indicate whether any associated gas was flared.
    (4) Average gas to oil ratio, in standard cubic feet of gas per 
barrel of oil (average of the ``GOR'' values used in Equation W-18 of 
this subpart).
    (5) Volume of oil produced, in barrels, in the calendar year during 
the time periods in which associated gas was vented or flared (the sum 
of ``Vp,q'' used in Equation W-18 of Sec. 98.233). You may 
delay reporting of this data element if you indicate in the annual 
report that wildcat wells and/or delineation wells are the only wells 
from which associated gas was vented or flared. If you elect to delay 
reporting of this data element, you must report by the date specified in 
Sec. 98.236(cc) the volume of oil produced for well(s) with associated 
gas venting and flaring and the well ID number(s) for the well(s) 
included in the measurement.
    (6) Total volume of associated gas sent to sales, in standard cubic 
feet, in the calendar year during time periods in which associated gas 
was vented or flared (the sum of ``SG'' values used in Equation W-18 of 
Sec. 98.233(m)). You may delay reporting of this data element if you 
indicate in the annual report that wildcat wells and/or delineation 
wells from which associated gas was vented or flared. If you elect to 
delay reporting of this data element, you must report by the date 
specified in Sec. 98.236(cc) the measured total volume of associated 
gas sent to sales for well(s) with associated gas venting and flaring 
and the well ID number(s) for the well(s) included in the measurement.
    (7) If you had associated gas emissions vented directly to the 
atmosphere without flaring, then you must report the information 
specified in paragraphs (m)(7)(i) through (iii) of this section for each 
sub-basin.
    (i) Total number of wells for which associated gas was vented 
directly to the atmosphere without flaring and a list of their well ID 
numbers.
    (ii) Annual CO2 emissions, in metric tons CO2, 
calculated according to Sec. 98.233(m)(3) and (4).

[[Page 887]]

    (iii) Annual CH4 emissions, in metric tons 
CH4, calculated according to Sec. 98.233(m)(3) and (4).
    (8) If you had associated gas emissions that were flared, then you 
must report the information specified in paragraphs (m)(8)(i) through 
(iv) of this section for each sub-basin.
    (i) Total number of wells for which associated gas was flared and a 
list of their well ID numbers.
    (ii) Annual CO2 emissions, in metric tons CO2, 
calculated according to Sec. 98.233(m)(5).
    (iii) Annual CH4 emissions, in metric tons 
CH4, calculated according to Sec. 98.233(m)(5).
    (iv) Annual N2O emissions, in metric tons N2O, 
calculated according to Sec. 98.233(m)(5).
    (n) Flare stacks. You must indicate if your facility contains any 
flare stacks. You must report the information specified in paragraphs 
(n)(1) through (12) of this section for each flare stack at your 
facility, and for each industry segment applicable to your facility.
    (1) Unique name or ID for the flare stack. For the onshore petroleum 
and natural gas production and onshore petroleum and natural gas 
gathering and boosting industry segments, a different name or ID may be 
used for a single flare stack for each location where it operates at in 
a given calendar year.
    (2) Indicate whether the flare stack has a continuous flow 
measurement device.
    (3) Indicate whether the flare stack has a continuous gas 
composition analyzer on feed gas to the flare.
    (4) Volume of gas sent to the flare, in standard cubic feet 
(``Vs'' in Equations W-19 and W-20 of this subpart).
    (5) Fraction of the feed gas sent to an un-lit flare 
(``Zu'' in Equation W-19 of this subpart).
    (6) Flare combustion efficiency, expressed as the fraction of gas 
combusted by a burning flare.
    (7) Mole fraction of CH4 in the feed gas to the flare 
(``XCH4'' in Equation W-19 of this subpart).
    (8) Mole fraction of CO2 in the feed gas to the flare 
(``XCO2'' in Equation W-20 of this subpart).
    (9) Annual CO2 emissions, in metric tons CO2 
(refer to Equation W-20 of this subpart).
    (10) Annual CH4 emissions, in metric tons CH4 
(refer to Equation W-19 of this subpart).
    (11) Annual N2O emissions, in metric tons N2O 
(refer to Equation W-40 of this subpart).
    (12) Indicate whether a CEMS was used to measure emissions from the 
flare. If a CEMS was used to measure emissions from the flare, then you 
are not required to report N2O and CH4 emissions 
for the flare stack.
    (o) Centrifugal compressors. You must indicate whether your facility 
has centrifugal compressors. You must report the information specified 
in paragraphs (o)(1) and (2) of this section for all centrifugal 
compressors at your facility. For each compressor source or manifolded 
group of compressor sources that you conduct as found leak measurements 
as specified in Sec. 98.233(o)(2) or (4), you must report the 
information specified in paragraph (o)(3) of this section. For each 
compressor source or manifolded group of compressor sources that you 
conduct continuous monitoring as specified in Sec. 98.233(o)(3) or (5), 
you must report the information specified in paragraph (o)(4) of this 
section. Centrifugal compressors in onshore petroleum and natural gas 
production and onshore petroleum and natural gas gathering and boosting 
are not required to report information in paragraphs (o)(1) through (4) 
of this section and instead must report the information specified in 
paragraph (o)(5) of this section.
    (1) Compressor activity data. Report the information specified in 
paragraphs (o)(1)(i) through (xiv) of this section for each centrifugal 
compressor located at your facility.
    (i) Unique name or ID for the centrifugal compressor.
    (ii) Hours in operating-mode.
    (iii) Hours in not-operating-depressurized-mode.
    (iv) Indicate whether the compressor was measured in operating-mode.
    (v) Indicate whether the compressor was measured in not-operating-
depressurized-mode.
    (vi) Indicate which, if any, compressor sources are part of a 
manifolded group of compressor sources.

[[Page 888]]

    (vii) Indicate which, if any, compressor sources are routed to a 
flare.
    (viii) Indicate which, if any, compressor sources have vapor 
recovery.
    (ix) Indicate which, if any, compressor source emissions are 
captured for fuel use or are routed to a thermal oxidizer.
    (x) Indicate whether the compressor has blind flanges installed and 
associated dates.
    (xi) Indicate whether the compressor has wet or dry seals.
    (xii) If the compressor has wet seals, the number of wet seals.
    (xiii) Power output of the compressor driver (hp).
    (xiv) Indicate whether the compressor had a scheduled depressurized 
shutdown during the reporting year.
    (2) Compressor source. (i) For each compressor source at each 
compressor, report the information specified in paragraphs (o)(2)(i)(A) 
through (C) of this section.
    (A) Centrifugal compressor name or ID. Use the same ID as in 
paragraph (o)(1)(i) of this section.
    (B) Centrifugal compressor source (wet seal, isolation valve, or 
blowdown valve).
    (C) Unique name or ID for the leak or vent. If the leak or vent is 
connected to a manifolded group of compressor sources, use the same leak 
or vent ID for each compressor source in the manifolded group. If 
multiple compressor sources are released through a single vent for which 
continuous measurements are used, use the same leak or vent ID for each 
compressor source released via the measured vent. For a single 
compressor using as found measurements, you must provide a different 
leak or vent ID for each compressor source.
    (ii) For each leak or vent, report the information specified in 
paragraphs (o)(2)(ii)(A) through (E) of this section.
    (A) Indicate whether the leak or vent is for a single compressor 
source or manifolded group of compressor sources and whether the 
emissions from the leak or vent are released to the atmosphere, routed 
to a flare, combustion (fuel or thermal oxidizer), or vapor recovery.
    (B) Indicate whether an as found measurement(s) as identified in 
Sec. 98.233(o)(2) or (4) was conducted on the leak or vent.
    (C) Indicate whether continuous measurements as identified in Sec. 
98.233(o)(3) or (5) were conducted on the leak or vent.
    (D) Report emissions as specified in paragraphs (o)(2)(ii)(D)(1) and 
(2) of this section for the leak or vent. If the leak or vent is routed 
to a flare, combustion, or vapor recovery, you are not required to 
report emissions under this paragraph.
    (1) Annual CO2 emissions, in metric tons CO2.
    (2) Annual CH4 emissions, in metric tons CH4.
    (E) If the leak or vent is routed to flare, combustion, or vapor 
recovery, report the percentage of time that the respective device was 
operational when the compressor source emissions were routed to the 
device.
    (3) As found measurement sample data. If the measurement methods 
specified in Sec. 98.233(o)(2) or (4) are conducted, report the 
information specified in paragraph (o)(3)(i) of this section. If the 
calculation specified in Sec. 98.233(o)(6)(ii) is performed, report the 
information specified in paragraph (o)(3)(ii) of this section.
    (i) For each as found measurement performed on a leak or vent, 
report the information specified in paragraphs (o)(3)(i)(A) through (F) 
of this section.
    (A) Name or ID of leak or vent. Use same leak or vent ID as in 
paragraph (o)(2)(i)(C) of this section.
    (B) Measurement date.
    (C) Measurement method. If emissions were not detected when using a 
screening method, report the screening method. If emissions were 
detected using a screening method, report only the method subsequently 
used to measure the volumetric emissions.
    (D) Measured flow rate, in standard cubic feet per hour.
    (E) For each compressor attached to the leak or vent, report the 
compressor mode during which the measurement was taken.
    (F) If the measurement is for a manifolded group of compressor 
sources, indicate whether the measurement location is prior to or after 
comingling with non-compressor emission sources.

[[Page 889]]

    (ii) For each compressor mode-source combination where a reporter 
emission factor as calculated in Equation W-23 was used to calculate 
emissions in Equation W-22, report the information specified in 
paragraphs (o)(3)(ii)(A) through (D) of this section.
    (A) The compressor mode-source combination.
    (B) The compressor mode-source combination reporter emission factor, 
in standard cubic feet per hour (EFs,m in Equation W-23).
    (C) The total number of compressors measured in the compressor mode-
source combination in the current reporting year and the preceding two 
reporting years (Countm in Equation W-23).
    (D) Indicate whether the compressor mode-source combination reporter 
emission factor is facility-specific or based on all of the reporter's 
applicable facilities.
    (4) Continuous measurement data. If the measurement methods 
specified in Sec. 98.233(o)(3) or (5) are conducted, report the 
information specified in paragraphs (o)(4)(i) through (iv) of this 
section for each continuous measurement conducted on each leak or vent 
associated with each compressor source or manifolded group of compressor 
sources.
    (i) Name or ID of leak or vent. Use same leak or vent ID as in 
paragraph (o)(2)(i)(C) of this section.
    (ii) Measured volume of flow during the reporting year, in million 
standard cubic feet.
    (iii) Indicate whether the measured volume of flow during the 
reporting year includes compressor blowdown emissions as allowed for in 
Sec. 98.233(o)(3)(ii) and (o)(5)(iii).
    (iv) If the measurement is for a manifolded group of compressor 
sources, indicate whether the measurement location is prior to or after 
comingling with non-compressor emission sources.
    (5) Onshore petroleum and natural gas production and onshore 
petroleum and natural gas gathering and boosting. Centrifugal 
compressors with wet seal degassing vents in onshore petroleum and 
natural gas production and onshore petroleum and natural gas gathering 
and boosting must report the information specified in paragraphs 
(o)(5)(i) through (iii) of this section.
    (i) Number of centrifugal compressors that have wet seal oil 
degassing vents.
    (ii) Annual CO2 emissions, in metric tons CO2, 
from centrifugal compressors with wet seal oil degassing vents.
    (iii) Annual CH4 emissions, in metric tons 
CH4, from centrifugal compressors with wet seal oil degassing 
vents.
    (p) Reciprocating compressors. You must indicate whether your 
facility has reciprocating compressors. You must report the information 
specified in paragraphs (p)(1) and (2) of this section for all 
reciprocating compressors at your facility. For each compressor source 
or manifolded group of compressor sources that you conduct as found leak 
measurements as specified in Sec. 98.233(p)(2) or (4), you must report 
the information specified in paragraph (p)(3) of this section. For each 
compressor source or manifolded group of compressor sources that you 
conduct continuous monitoring as specified in Sec. 98.233(p)(3) or (5), 
you must report the information specified in paragraph (p)(4) of this 
section. Reciprocating compressors in onshore petroleum and natural gas 
production and onshore petroleum and natural gas gathering and boosting 
are not required to report information in paragraphs (p)(1) through (4) 
of this section and instead must report the information specified in 
paragraph (p)(5) of this section.
    (1) Compressor activity data. Report the information specified in 
paragraphs (p)(1)(i) through (xiv) of this section for each 
reciprocating compressor located at your facility.
    (i) Unique name or ID for the reciprocating compressor.
    (ii) Hours in operating-mode.
    (iii) Hours in standby-pressurized-mode.
    (iv) Hours in not-operating-depressurized-mode.
    (v) Indicate whether the compressor was measured in operating-mode.
    (vi) Indicate whether the compressor was measured in standby-
pressurized-mode.
    (vii) Indicate whether the compressor was measured in not-operating-
depressurized-mode.

[[Page 890]]

    (viii) Indicate which, if any, compressor sources are part of a 
manifolded group of compressor sources.
    (ix) Indicate which, if any, compressor sources are routed to a 
flare.
    (x) Indicate which, if any, compressor sources have vapor recovery.
    (xi) Indicate which, if any, compressor source emissions are 
captured for fuel use or are routed to a thermal oxidizer.
    (xii) Indicate whether the compressor has blind flanges installed 
and associated dates.
    (xiii) Power output of the compressor driver (hp).
    (xiv) Indicate whether the compressor had a scheduled depressurized 
shutdown during the reporting year.
    (2) Compressor source. (i) For each compressor source at each 
compressor, report the information specified in paragraphs (p)(2)(i)(A) 
through (C) of this section.
    (A) Reciprocating compressor name or ID. Use the same ID as in 
paragraph (p)(1)(i) of this section.
    (B) Reciprocating compressor source (isolation valve, blowdown 
valve, or rod packing).
    (C) Unique name or ID for the leak or vent. If the leak or vent is 
connected to a manifolded group of compressor sources, use the same leak 
or vent ID for each compressor source in the manifolded group. If 
multiple compressor sources are released through a single vent for which 
continuous measurements are used, use the same leak or vent ID for each 
compressor source released via the measured vent. For a single 
compressor using as found measurements, you must provide a different 
leak or vent ID for each compressor source.
    (ii) For each leak or vent, report the information specified in 
paragraphs (p)(2)(ii)(A) through (E) of this section.
    (A) Indicate whether the leak or vent is for a single compressor 
source or manifolded group of compressor sources and whether the 
emissions from the leak or vent are released to the atmosphere, routed 
to a flare, combustion (fuel or thermal oxidizer), or vapor recovery.
    (B) Indicate whether an as found measurement(s) as identified in 
Sec. 98.233(p)(2) or (4) was conducted on the leak or vent.
    (C) Indicate whether continuous measurements as identified in Sec. 
98.233(p)(3) or (5) were conducted on the leak or vent.
    (D) Report emissions as specified in paragraphs (p)(2)(ii)(D)(1) and 
(2) of this section for the leak or vent. If the leak or vent is routed 
to flare, combustion, or vapor recovery, you are not required to report 
emissions under this paragraph.
    (1) Annual CO2 emissions, in metric tons CO2.
    (2) Annual CH4 emissions, in metric tons CH4.
    (E) If the leak or vent is routed to flare, combustion, or vapor 
recovery, report the percentage of time that the respective device was 
operational when the compressor source emissions were routed to the 
device.
    (3) As found measurement sample data. If the measurement methods 
specified in Sec. 98.233(p)(2) or (4) are conducted, report the 
information specified in paragraph (p)(3)(i) of this section. If the 
calculation specified in Sec. 98.233(p)(6)(ii) is performed, report the 
information specified in paragraph (p)(3)(ii) of this section.
    (i) For each as found measurement performed on a leak or vent, 
report the information specified in paragraphs (p)(3)(i)(A) through (F) 
of this section.
    (A) Name or ID of leak or vent. Use same leak or vent ID as in 
paragraph (p)(2)(i)(C) of this section.
    (B) Measurement date.
    (C) Measurement method. If emissions were not detected when using a 
screening method, report the screening method. If emissions were 
detected using a screening method, report only the method subsequently 
used to measure the volumetric emissions.
    (D) Measured flow rate, in standard cubic feet per hour.
    (E) For each compressor attached to the leak or vent, report the 
compressor mode during which the measurement was taken.
    (F) If the measurement is for a manifolded group of compressor 
sources, indicate whether the measurement location is prior to or after 
comingling with non-compressor emission sources.

[[Page 891]]

    (ii) For each compressor mode-source combination where a reporter 
emission factor as calculated in Equation W-28 was used to calculate 
emissions in Equation W-27, report the information specified in 
paragraphs (p)(3)(ii)(A) through (D) of this section
    (A) The compressor mode-source combination.
    (B) The compressor mode-source combination reporter emission factor, 
in standard cubic feet per hour (EFs,m in Equation W-28).
    (C) The total number of compressors measured in the compressor mode-
source combination in the current reporting year and the preceding two 
reporting years (Countm in Equation W-28).
    (D) Indicate whether the compressor mode-source combination reporter 
emission factor is facility-specific or based on all of the reporter's 
applicable facilities.
    (4) Continuous measurement data. If the measurement methods 
specified in Sec. 98.233(p)(3) or (5) are conducted, report the 
information specified in paragraphs (p)(4)(i) through (iv) of this 
section for each continuous measurement conducted on each leak or vent 
associated with each compressor source or manifolded group of compressor 
sources.
    (i) Name or ID of leak or vent. Use same leak or vent ID as in 
paragraph (p)(2)(i)(C) of this section.
    (ii) Measured volume of flow during the reporting year, in million 
standard cubic feet.
    (iii) Indicate whether the measured volume of flow during the 
reporting year includes compressor blowdown emissions as allowed for in 
Sec. 98.233(p)(3)(ii) and (p)(5)(iii).
    (iv) If the measurement is for a manifolded group of compressor 
sources, indicate whether the measurement location is prior to or after 
comingling with non-compressor emission sources.
    (5) Onshore petroleum and natural gas production and onshore 
petroleum and natural gas gathering and boosting. Reciprocating 
compressors in onshore petroleum and natural gas production and onshore 
petroleum and natural gas gathering and boosting must report the 
information specified in paragraphs (p)(5)(i) through (iii) of this 
section.
    (i) Number of reciprocating compressors.
    (ii) Annual CO2 emissions, in metric tons CO2, 
from reciprocating compressors.
    (iii) Annual CH4 emissions, in metric tons 
CH4, from reciprocating compressors.
    (q) Equipment leak surveys. If your facility is subject to the 
requirements of Sec. 98.233(q), then you must report the information 
specified in paragraphs (q)(1) and (2) of this section. Natural gas 
distribution facilities with emission sources listed in Sec. 
98.232(i)(1) must also report the information specified in paragraph 
(q)(3) of this section.
    (1) You must report the information specified in paragraphs 
(q)(1)(i) and (ii) of this section.
    (i) Except as specified in paragraph (q)(1)(ii) of this section, the 
number of complete equipment leak surveys performed during the calendar 
year.
    (ii) Natural gas distribution facilities performing equipment leak 
surveys across a multiple year leak survey cycle must report the number 
of years in the leak survey cycle.
    (2) You must indicate whether your facility contains any of the 
component types listed in Sec. 98.232(d)(7), (e)(7), (f)(5), (g)(3), 
(h)(4), or (i)(1), for your facility's industry segment. For each 
component type that is located at your facility, you must report the 
information specified in paragraphs (q)(2)(i) through (v) of this 
section. If a component type is located at your facility and no leaks 
were identified from that component, then you must report the 
information in paragraphs (q)(2)(i) through (v) of this section but 
report a zero (``0'') for the information required according to 
paragraphs (q)(2)(iii), (iv), and (v) of this section.
    (i) Component type.
    (ii) Total number of the surveyed component type that were 
identified as leaking in the calendar year (``xp'' in 
Equation W-30 of this subpart for the component type).
    (iii) Average time the surveyed components are assumed to be leaking 
and operational, in hours (average of ``Tp,z'' from Equation 
W-30 of this subpart for the component type).

[[Page 892]]

    (iv) Annual CO2 emissions, in metric tons CO2, 
for the component type as calculated using Equation W-30 (for surveyed 
components only).
    (v) Annual CH4 emissions, in metric tons CH4, 
for the component type as calculated using Equation W-30 (for surveyed 
components only).
    (3) Natural gas distribution facilities with emission sources listed 
in Sec. 98.232(i)(1) must also report the information specified in 
paragraphs (q)(3)(i) through (viii) and, if applicable, (q)(3)(ix) of 
this section.
    (i) Number of above grade transmission-distribution transfer 
stations surveyed in the calendar year.
    (ii) Number of meter/regulator runs at above grade transmission-
distribution transfer stations surveyed in the calendar year 
(``CountMR,y'' from Equation W-31 of this subpart, for the 
current calendar year).
    (iii) Average time that meter/regulator runs surveyed in the 
calendar year were operational, in hours (average of ``Tw,y'' 
from Equation W-31 of this subpart, for the current calendar year).
    (iv) Number of above grade transmission-distribution transfer 
stations surveyed in the current leak survey cycle.
    (v) Number of meter/regulator runs at above grade transmission-
distribution transfer stations surveyed in current leak survey cycle 
(sum of ``CountMR,y'' from Equation W-31 of this subpart, for 
all calendar years in the current leak survey cycle).
    (vi) Average time that meter/regulator runs surveyed in the current 
leak survey cycle were operational, in hours (average of 
``Tw,y'' from Equation W-31 of this subpart, for all years 
included in the leak survey cycle).
    (vii) Meter/regulator run CO2 emission factor based on 
all surveyed transmission-distribution transfer stations in the current 
leak survey cycle, in standard cubic feet of CO2 per 
operational hour of all meter/regulator runs (``EFs,MR,i'' 
for CO2 calculated using Equation W-31 of this subpart).
    (viii) Meter/regulator run CH4 emission factor based on 
all surveyed transmission-distribution transfer stations in the current 
leak survey cycle, in standard cubic feet of CH4 per 
operational hour of all meter/regulator runs (``EFs,MR,i'' 
for CH4 calculated using Equation W-31 of this subpart).
    (ix) If your natural gas distribution facility performs equipment 
leak surveys across a multiple year leak survey cycle, you must also 
report:
    (A) The total number of meter/regulator runs at above grade 
transmission-distribution transfer stations at your facility 
(``CountMR'' in Equation W-32B of this subpart).
    (B) Average estimated time that each meter/regulator run at above 
grade transmission-distribution transfer stations was operational in the 
calendar year, in hours per meter/regulator run (``Tw,avg'' 
in Equation W-32B of this subpart).
    (C) Annual CO2 emissions, in metric tons CO2, 
for all above grade transmission-distribution transfer stations at your 
facility.
    (D) Annual CH4 emissions, in metric tons CH4, 
for all above grade transmission-distribution transfer stations at your 
facility.
    (r) Equipment leaks by population count. If your facility is subject 
to the requirements of Sec. 98.233(r), then you must report the 
information specified in paragraphs (r)(1) through (3) of this section, 
as applicable.
    (1) You must indicate whether your facility contains any of the 
emission source types required to use Equation W-32A of Sec. 98.233. 
You must report the information specified in paragraphs (r)(1)(i) 
through (v) of this section separately for each emission source type 
required to use Equation W-32A that is located at your facility. Onshore 
petroleum and natural gas production facilities and onshore petroleum 
and natural gas gathering and boosting facilities must report the 
information specified in paragraphs (r)(1)(i) through (v) separately by 
component type, service type, and geographic location (i.e., Eastern 
U.S. or Western U.S.).
    (i) Emission source type. Onshore petroleum and natural gas 
production facilities and onshore petroleum and natural gas gathering 
and boosting facilities must report the component type, service type and 
geographic location.
    (ii) Total number of the emission source type at the facility 
(``Counte'' in Equation W-32A of this subpart).

[[Page 893]]

    (iii) Average estimated time that the emission source type was 
operational in the calendar year, in hours (``Te'' in 
Equation W-32A of this subpart).
    (iv) Annual CO2 emissions, in metric tons CO2, 
for the emission source type.
    (v) Annual CH4 emissions, in metric tons CH4, 
for the emission source type.
    (2) Natural gas distribution facilities must also report the 
information specified in paragraphs (r)(2)(i) through (v) of this 
section.
    (i) Number of above grade transmission-distribution transfer 
stations at the facility.
    (ii) Number of above grade metering-regulating stations that are not 
transmission-distribution transfer stations at the facility.
    (iii) Total number of meter/regulator runs at above grade metering-
regulating stations that are not above grade transmission-distribution 
transfer stations (``CountMR'' in Equation W-32B of this 
subpart).
    (iv) Average estimated time that each meter/regulator run at above 
grade metering-regulating stations that are not above grade 
transmission-distribution transfer stations was operational in the 
calendar year, in hours per meter/regulator run (``Tw,avg'' 
in Equation W-32B of this subpart).
    (v) If your facility has above grade metering-regulating stations 
that are not above grade transmission-distribution transfer stations and 
your facility also has above grade transmission-distribution transfer 
stations, you must also report:
    (A) Annual CO2 emissions, in metric tons CO2, 
from above grade metering-regulating stations that are not above grade 
transmission-distribution transfer stations.
    (B) Annual CH4 emissions, in metric tons CH4, 
from above grade metering regulating stations that are not above grade 
transmission-distribution transfer stations.
    (3) Onshore petroleum and natural gas production facilities and 
onshore petroleum and natural gas gathering and boosting facilities must 
also report the information specified in paragraphs (r)(3)(i) and (ii) 
of this section.
    (i) Calculation method used.
    (ii) Onshore petroleum and natural gas production facilities and 
onshore petroleum and natural gas gathering and boosting facilities must 
report the information specified in paragraphs (r)(3)(ii)(A) and (B) of 
this section, for each major equipment type, production type (i.e., 
natural gas or crude oil), and geographic location combination in Tables 
W-1B and W-1C of this subpart.
    (A) An indication of whether the facility contains the major 
equipment type.
    (B) If the facility does contain the equipment type, the count of 
the major equipment type.
    (s) Offshore petroleum and natural gas production. You must report 
the information specified in paragraphs (s)(1) through (3) of this 
section for each emission source type listed in the most recent BOEMRE 
study.
    (1) Annual CO2 emissions, in metric tons CO2.
    (2) Annual CH4 emissions, in metric tons CH4.
    (3) Annual N2O emissions, in metric tons N2O.
    (t) [Reserved]
    (u) [Reserved]
    (v) [Reserved]
    (w) EOR injection pumps. You must indicate whether CO2 
EOR injection was used at your facility during the calendar year and if 
any EOR injection pump blowdowns occurred during the year. If any EOR 
injection pump blowdowns occurred during the calendar year, then you 
must report the information specified in paragraphs (w)(1) through (8) 
of this section for each EOR injection pump system.
    (1) Sub-basin ID.
    (2) EOR injection pump system identifier.
    (3) Pump capacity, in barrels per day.
    (4) Total volume of EOR injection pump system equipment chambers, in 
cubic feet (``Vv'' in Equation W-37 of this subpart).
    (5) Number of blowdowns for the EOR injection pump system in the 
calendar year.
    (6) Density of critical phase EOR injection gas, in kilograms per 
cubic foot (``Rc'' in Equation W-37 of this subpart).
    (7) Mass fraction of CO2 in critical phase EOR injection 
gas (``GHGCO2'' in Equation W-37 of this subpart).

[[Page 894]]

    (8) Annual CO2 emissions, in metric tons CO2, 
from EOR injection pump system blowdowns.
    (x) EOR hydrocarbon liquids. You must indicate whether hydrocarbon 
liquids were produced through EOR operations. If hydrocarbon liquids 
were produced through EOR operations, you must report the information 
specified in paragraphs (x)(1) through (4) of this section for each sub-
basin category with EOR operations.
    (1) Sub-basin ID.
    (2) Total volume of hydrocarbon liquids produced through EOR 
operations in the calendar year, in barrels (``Vhl'' in 
Equation W-38 of this subpart).
    (3) Average CO2 retained in hydrocarbon liquids 
downstream of the storage tank, in metric tons per barrel under standard 
conditions (``Shl'' in Equation W-38 of this subpart).
    (4) Annual CO2 emissions, in metric tons CO2, 
from CO2 retained in hydrocarbon liquids produced through EOR 
operations downstream of the storage tank (``MassCO2'' in 
Equation W-38 of this subpart).
    (y) [Reserved]
    (z) Combustion equipment at onshore petroleum and natural gas 
production facilities, onshore petroleum and natural gas gathering and 
boosting facilities, and natural gas distribution facilities. If your 
facility is required by Sec. 98.232(c)(22), (i)(7), or (j)(12) to 
report emissions from combustion equipment, then you must indicate 
whether your facility has any combustion units subject to reporting 
according to paragraph (a)(1)(xvii), (a)(8)(i), or (a)(9)(xi) of this 
section. If your facility contains any combustion units subject to 
reporting according to paragraph (a)(1)(xvii), (a)(8)(i), or (a)(9)(xi) 
of this section, then you must report the information specified in 
paragraphs (z)(1) and (2) of this section, as applicable.
    (1) Indicate whether the combustion units include: External fuel 
combustion units with a rated heat capacity less than or equal to 5 
million Btu per hour; or, internal fuel combustion units that are not 
compressor-drivers, with a rated heat capacity less than or equal to 1 
mmBtu/hr (or the equivalent of 130 horsepower). If the facility contains 
external fuel combustion units with a rated heat capacity less than or 
equal to 5 million Btu per hour or internal fuel combustion units that 
are not compressor-drivers, with a rated heat capacity less than or 
equal to 1 million Btu per hour (or the equivalent of 130 horsepower), 
then you must report the information specified in paragraphs (z)(1)(i) 
and (ii) of this section for each unit type.
    (i) The type of combustion unit.
    (ii) The total number of combustion units.
    (2) Indicate whether the combustion units include: External fuel 
combustion units with a rated heat capacity greater than 5 million Btu 
per hour; internal fuel combustion units that are not compressor-
drivers, with a rated heat capacity greater than 1 million Btu per hour 
(or the equivalent of 130 horsepower); or, internal fuel combustion 
units of any heat capacity that are compressor-drivers. If your facility 
contains: External fuel combustion units with a rated heat capacity 
greater than 5 mmBtu/hr; internal fuel combustion units that are not 
compressor-drivers, with a rated heat capacity greater than 1 million 
Btu per hour (or the equivalent of 130 horsepower); or internal fuel 
combustion units of any heat capacity that are compressor-drivers, then 
you must report the information specified in paragraphs (z)(2)(i) 
through (vi) of this section for each combustion unit type and fuel type 
combination.
    (i) The type of combustion unit.
    (ii) The type of fuel combusted.
    (iii) The quantity of fuel combusted in the calendar year, in 
thousand standard cubic feet, gallons, or tons.
    (iv) Annual CO2 emissions, in metric tons CO2, 
calculated according to Sec. 98.233(z)(1) and (2).
    (v) Annual CH4 emissions, in metric tons CH4, 
calculated according to Sec. 98.233(z)(1) and (2).
    (vi) Annual N2O emissions, in metric tons N2O, 
calculated according to Sec. 98.233(z)(1) and (2).
    (aa) Each facility must report the information specified in 
paragraphs (aa)(1) through (11) of this section, for each applicable 
industry segment, by using best available data. If a quantity required 
to be reported is zero, you must report zero as the value.

[[Page 895]]

    (1) For onshore petroleum and natural gas production, report the 
data specified in paragraphs (aa)(1)(i) and (ii) of this section.
    (i) Report the information specified in paragraphs (aa)(1)(i)(A) 
through (C) of this section for the basin as a whole.
    (A) The quantity of gas produced in the calendar year from wells, in 
thousand standard cubic feet. This includes gas that is routed to a 
pipeline, vented or flared, or used in field operations. This does not 
include gas injected back into reservoirs or shrinkage resulting from 
lease condensate production.
    (B) The quantity of gas produced in the calendar year for sales, in 
thousand standard cubic feet.
    (C) The quantity of crude oil and condensate produced in the 
calendar year for sales, in barrels.
    (ii) Report the information specified in paragraphs (aa)(1)(ii)(A) 
through (M) of this section for each unique sub-basin category.
    (A) State.
    (B) County.
    (C) Formation type.
    (D) The number of producing wells at the end of the calendar year 
and a list of the well ID numbers (exclude only those wells permanently 
taken out of production, i.e., plugged and abandoned).
    (E) The number of producing wells acquired during the calendar year 
and a list of the well ID numbers.
    (F) The number of producing wells divested during the calendar year 
and a list of the well ID numbers.
    (G) The number of wells completed during the calendar year and a 
list of the well ID numbers.
    (H) The number of wells permanently taken out of production (i.e., 
plugged and abandoned) during the calendar year and a list of the well 
ID numbers.
    (I) Average mole fraction of CH4 in produced gas.
    (J) Average mole fraction of CO2 in produced gas.
    (K) If an oil sub-basin, report the average GOR of all wells, in 
thousand standard cubic feet per barrel.
    (L) If an oil sub-basin, report the average API gravity of all 
wells.
    (M) If an oil sub-basin, report average low pressure separator 
pressure, in pounds per square inch gauge.
    (2) For offshore production, report the quantities specified in 
paragraphs (aa)(2)(i) and (ii) of this section.
    (i) The total quantity of gas handled at the offshore platform in 
the calendar year, in thousand standard cubic feet, including production 
volumes and volumes transferred via pipeline from another location.
    (ii) The total quantity of oil and condensate handled at the 
offshore platform in the calendar year, in barrels, including production 
volumes and volumes transferred via pipeline from another location.
    (3) For natural gas processing, report the information specified in 
paragraphs (aa)(3)(i) through (vii) of this section.
    (i) The quantity of natural gas received at the gas processing plant 
in the calendar year, in thousand standard cubic feet.
    (ii) The quantity of processed (residue) gas leaving the gas 
processing plant in the calendar year, in thousand standard cubic feet.
    (iii) The cumulative quantity of all NGLs (bulk and fractionated) 
received at the gas processing plant in the calendar year, in barrels.
    (iv) The cumulative quantity of all NGLs (bulk and fractionated) 
leaving the gas processing plant in the calendar year, in barrels.
    (v) Average mole fraction of CH4 in natural gas received.
    (vi) Average mole fraction of CO2 in natural gas 
received.
    (vii) Indicate whether the facility fractionates NGLs.
    (4) For natural gas transmission compression, report the quantity 
specified in paragraphs (aa)(4)(i) through (v) of this section.
    (i) The quantity of gas transported through the compressor station 
in the calendar year, in thousand standard cubic feet.
    (ii) Number of compressors.
    (iii) Total compressor power rating of all compressors combined, in 
horsepower.
    (iv) Average upstream pipeline pressure, in pounds per square inch 
gauge.
    (v) Average downstream pipeline pressure, in pounds per square inch 
gauge.
    (5) For underground natural gas storage, report the quantities 
specified in

[[Page 896]]

paragraphs (aa)(5)(i) through (iii) of this section.
    (i) The quantity of gas injected into storage in the calendar year, 
in thousand standard cubic feet.
    (ii) The quantity of gas withdrawn from storage in the calendar 
year, in thousand standard cubic feet.
    (iii) Total storage capacity, in thousand standard cubic feet.
    (6) For LNG import equipment, report the quantity of LNG imported in 
the calendar year, in thousand standard cubic feet.
    (7) For LNG export equipment, report the quantity of LNG exported in 
the calendar year, in thousand standard cubic feet.
    (8) For LNG storage, report the quantities specified in paragraphs 
(aa)(8)(i) through (iii) of this section.
    (i) The quantity of LNG added into storage in the calendar year, in 
thousand standard cubic feet.
    (ii) The quantity of LNG withdrawn from storage in the calendar 
year, in thousand standard cubic feet.
    (iii) Total storage capacity, in thousand standard cubic feet.
    (9) For natural gas distribution, report the quantities specified in 
paragraphs (aa)(9)(i) through (vii) of this section.
    (i) The quantity of natural gas received at all custody transfer 
stations in the calendar year, in thousand standard cubic feet. This 
value may include meter corrections, but only for the calendar year 
covered by the annual report.
    (ii) The quantity of natural gas withdrawn from in-system storage in 
the calendar year, in thousand standard cubic feet.
    (iii) The quantity of natural gas added to in-system storage in the 
calendar year, in thousand standard cubic feet.
    (iv) The quantity of natural gas delivered to end users, in thousand 
standard cubic feet. This value does not include stolen gas, or gas that 
is otherwise unaccounted for.
    (v) The quantity of natural gas transferred to third parties such as 
other LDCs or pipelines, in thousand standard cubic feet. This value 
does not include stolen gas, or gas that is otherwise unaccounted for.
    (vi) The quantity of natural gas consumed by the LDC for operational 
purposes, in thousand standard cubic feet.
    (vii) The estimated quantity of gas stolen in the calendar year, in 
thousand standard cubic feet.
    (10) For onshore petroleum and natural gas gathering and boosting 
facilities, report the quantities specified in paragraphs (aa)(10)(i) 
through (iv) of this section.
    (i) The quantity of gas received by the gathering and boosting 
facility in the calendar year, in thousand standard cubic feet.
    (ii) The quantity of gas transported to a natural gas processing 
facility, a natural gas transmission pipeline, a natural gas 
distribution pipeline, or another gathering and boosting facility in the 
calendar year, in thousand standard cubic feet.
    (iii) The quantity of all hydrocarbon liquids received by the 
gathering and boosting facility in the calendar year, in barrels.
    (iv) The quantity of all hydrocarbon liquids transported to a 
natural gas processing facility, a natural gas transmission pipeline, a 
natural gas distribution pipeline, or another gathering and boosting 
facility in the calendar year, in barrels.
    (11) For onshore natural gas transmission pipeline facilities, 
report the quantities specified in paragraphs (aa)(11)(i) through (vi) 
of this section.
    (i) The quantity of natural gas received at all custody transfer 
stations in the calendar year, in thousand standard cubic feet. This 
value may include meter corrections, but only for the calendar year 
covered by the annual report.
    (ii) The quantity of natural gas withdrawn from in-system storage in 
the calendar year, in thousand standard cubic feet.
    (iii) The quantity of natural gas added to in-system storage in the 
calendar year, in thousand standard cubic feet.
    (iv) The quantity of natural gas transferred to third parties such 
as LDCs or other transmission pipelines, in thousand standard cubic 
feet.

[[Page 897]]

    (v) The quantity of natural gas consumed by the transmission 
pipeline facility for operational purposes, in thousand standard cubic 
feet.
    (vi) The miles of transmission pipeline for each state in the 
facility.
    (bb) For any missing data procedures used, report the information in 
Sec. 98.3(c)(8) except as provided in paragraphs (bb)(1) and (2) of 
this section.
    (1) For quarterly measurements, report the total number of quarters 
that a missing data procedure was used for each data element rather than 
the total number of hours.
    (2) For annual or biannual (once every two years) measurements, you 
do not need to report the number of hours that a missing data procedure 
was used for each data element.
    (cc) If you elect to delay reporting the information in paragraph 
(g)(5)(i), (g)(5)(ii), (g)(5)(iii)(A), (g)(5)(iii)(B), (h)(1)(iv), 
(h)(2)(iv), (j)(1)(iii), (j)(2)(i)(A), (l)(1)(iv), (l)(2)(iv), 
(l)(3)(iii), (l)(4)(iii), (m)(5), or (m)(6) of this section, you must 
report the information required in that paragraph no later than the date 
2 years following the date specified in Sec. 98.3(b) introductory text.

[79 FR 70411, Nov. 24, 2014, as amended at 80 FR 64291, Oct. 22, 2015]



Sec. 98.237  Records that must be retained.

    Monitoring Plans, as described in Sec. 98.3(g)(5), must be 
completed by April 1, 2011. In addition to the information required by 
Sec. 98.3(g), you must retain the following records:
    (a) Dates on which measurements were conducted.
    (b) Results of all emissions detected and measurements.
    (c) Calibration reports for detection and measurement instruments 
used.
    (d) Inputs and outputs of calculations or emissions computer model 
runs used for engineering estimation of emissions.
    (e) The records required under Sec. 98.3(g)(2)(i) shall include an 
explanation of how company records, engineering estimation, or best 
available information are used to calculate each applicable parameter 
under this subpart.
    (f) For each time a missing data procedure was used, keep a record 
listing the emission source type, a description of the circumstance that 
resulted in the need to use missing data procedures, the missing data 
provisions in Sec. 98.235 that apply, the calculation or analysis used 
to develop the substitute value, and the substitute value.

[75 FR 74488, Nov. 30, 2010, as amended at 76 FR 80590, Dec. 23, 2011; 
79 FR 70424, Nov. 25, 2014]



Sec. 98.238  Definitions.

    Except as provided in this section, all terms used in this subpart 
have the same meaning given in the Clean Air Act and subpart A of this 
part.
    Acid gas means hydrogen sulfide (H2S) and/or carbon 
dioxide (CO2) contaminants that are separated from sour 
natural gas by an acid gas removal unit.
    Acid gas removal unit (AGR) means a process unit that separates 
hydrogen sulfide and/or carbon dioxide from sour natural gas using 
liquid or solid absorbents or membrane separators.
    Acid gas removal vent emissions mean the acid gas separated from the 
acid gas absorbing medium (e.g., an amine solution) and released with 
methane and other light hydrocarbons to the atmosphere or a flare.
    Associated gas venting or flaring means the venting or flaring of 
natural gas which originates at wellheads that also produce hydrocarbon 
liquids and occurs either in a discrete gaseous phase at the wellhead or 
is released from the liquid hydrocarbon phase by separation. This does 
not include venting or flaring resulting from activities that are 
reported elsewhere, including tank venting, well completions, and well 
workovers.
    Associated with a single well-pad means associated with the 
hydrocarbon stream as produced from one or more wells located on that 
single well-pad. The association ends where the stream from a single 
well-pad is combined with streams from one or more additional single 
well-pads, where the point of combination is located off that single 
well-pad. Onshore production storage tanks on or associated with a 
single well-pad are considered a part of the onshore production 
facility.

[[Page 898]]

    Basin means geologic provinces as defined by the American 
Association of Petroleum Geologists (AAPG) Geologic Note: AAPG-CSD 
Geologic Provinces Code Map: AAPG Bulletin, Prepared by Richard F. 
Meyer, Laure G. Wallace, and Fred J. Wagner, Jr., Volume 75, Number 10 
(October 1991) (incorporated by reference, see Sec. 98.7) and the 
Alaska Geological Province Boundary Map, Compiled by the American 
Association of Petroleum Geologists Committee on Statistics of Drilling 
in Cooperation with the USGS, 1978 (incorporated by reference, see Sec. 
98.7).
    Compressor means any machine for raising the pressure of a natural 
gas or CO2 by drawing in low pressure natural gas or 
CO2 and discharging significantly higher pressure natural gas 
or CO2.
    Compressor mode means the operational and pressurized status of a 
compressor. For a centrifugal compressor, ``mode'' refers to either 
operating-mode or not-operating-depressurized-mode. For a reciprocating 
compressor, ``mode'' refers to either: Operating-mode, standby-
pressurized-mode, or not-operating-depressurized-mode.
    Compressor source means the source of certain venting or leaking 
emissions from a centrifugal or reciprocating compressor. For 
centrifugal compressors, ``source'' refers to blowdown valve leakage 
through the blowdown vent, unit isolation valve leakage through an open 
blowdown vent without blind flanges, and wet seal oil degassing vents. 
For reciprocating compressors, ``source'' refers to blowdown valve 
leakage through the blowdown vent, unit isolation valve leakage through 
an open blowdown vent without blind flanges, and rod packing emissions.
    Condensate means hydrocarbon and other liquid, including both water 
and hydrocarbon liquids, separated from natural gas that condenses due 
to changes in the temperature, pressure, or both, and remains liquid at 
storage conditions.
    Delineation well means a well drilled in order to determine the 
boundary of a field or producing reservoir.
    Distribution pipeline means a pipeline that is designated as such by 
the Pipeline and Hazardous Material Safety Administration (PHMSA) 49 CFR 
192.3.
    Engineering estimation, for purposes of subpart W, means an estimate 
of emissions based on engineering principles applied to measured and/or 
approximated physical parameters such as dimensions of containment, 
actual pressures, actual temperatures, and compositions.
    Enhanced oil recovery (EOR) means the use of certain methods such as 
water flooding or gas injection into existing wells to increase the 
recovery of crude oil from a reservoir. In the context of this subpart, 
EOR applies to injection of critical phase or immiscible carbon dioxide 
into a crude oil reservoir to enhance the recovery of oil.
    External combustion means fired combustion in which the flame and 
products of combustion are separated from contact with the process fluid 
to which the energy is delivered. Process fluids may be air, hot water, 
or hydrocarbons. External combustion equipment may include fired 
heaters, industrial boilers, and commercial and domestic combustion 
units.
    Facility with respect to natural gas distribution for purposes of 
reporting under this subpart and for the corresponding subpart A 
requirements means the collection of all distribution pipelines and 
metering-regulating stations that are operated by a Local Distribution 
Company (LDC) within a single state that is regulated as a separate 
operating company by a public utility commission or that are operated as 
an independent municipally-owned distribution system.
    Facility with respect to natural gas distribution for purposes of 
reporting under this subpart and for the corresponding subpart A 
requirements means the collection of all distribution pipelines and 
metering-regulating stations that are operated by a Local Distribution 
Company (LDC) within a single state that is regulated as a separate 
operating company by a public utility commission or that are operated as 
an independent municipally-owned distribution system.
    Facility with respect to onshore petroleum and natural gas gathering 
and boosting for purposes of reporting under this subpart and for the 
corresponding

[[Page 899]]

subpart A requirements means all gathering pipelines and other equipment 
located along those pipelines that are under common ownership or common 
control by a gathering and boosting system owner or operator and that 
are located in a single hydrocarbon basin as defined in this section. 
Where a person owns or operates more than one gathering and boosting 
system in a basin (for example, separate gathering lines that are not 
connected), then all gathering and boosting equipment that the person 
owns or operates in the basin would be considered one facility. Any 
gathering and boosting equipment that is associated with a single 
gathering and boosting system, including leased, rented, or contracted 
activities, is considered to be under common control of the owner or 
operator of the gathering and boosting system that contains the 
pipeline. The facility does not include equipment and pipelines that are 
part of any other industry segment defined in this subpart.
    Facility with respect to onshore petroleum and natural gas 
production for purposes of reporting under this subpart and for the 
corresponding subpart A requirements means all petroleum or natural gas 
equipment on a single well-pad or associated with a single well-pad and 
CO2 EOR operations that are under common ownership or common 
control including leased, rented, or contracted activities by an onshore 
petroleum and natural gas production owner or operator and that are 
located in a single hydrocarbon basin as defined in Sec. 98.238. Where 
a person or entity owns or operates more than one well in a basin, then 
all onshore petroleum and natural gas production equipment associated 
with all wells that the person or entity owns or operates in the basin 
would be considered one facility.
    Facility with respect to the onshore natural gas transmission 
pipeline segment means the total U.S. mileage of natural gas 
transmission pipelines, as defined in this section, owned and operated 
by an onshore natural gas transmission pipeline owner or operator as 
defined in this section. The facility does not include pipelines that 
are part of any other industry segment defined in this subpart.
    Farm Taps are pressure regulation stations that deliver gas directly 
from transmission pipelines to generally rural customers. In some cases 
a nearby LDC may handle the billing of the gas to the customer(s).
    Field means oil and gas fields identified in the United States as 
defined by the Energy Information Administration Oil and Gas Field Code 
Master List 2008, DOE/EIA 0370(08) (incorporated by reference, see Sec. 
98.7).
    Flare, for the purposes of subpart W, means a combustion device, 
whether at ground level or elevated, that uses an open or closed flame 
to combust waste gases without energy recovery.
    Flare combustion efficiency means the fraction of hydrocarbon gas, 
on a volume or mole basis, that is combusted at the flare burner tip.
    Flare stack emissions means CO2 and N2O from 
partial combustion of hydrocarbon gas sent to a flare plus 
CH4 emissions resulting from the incomplete combustion of 
hydrocarbon gas in flares.
    Forced extraction of natural gas liquids means removal of ethane or 
higher carbon number hydrocarbons existing in the vapor phase in natural 
gas, by removing ethane or heavier hydrocarbons derived from natural gas 
into natural gas liquids by means of a forced extraction process. Forced 
extraction processes include but are not limited to refrigeration, 
absorption (lean oil), cryogenic expander, and combinations of these 
processes. Forced extraction does not include in and of itself; natural 
gas dehydration, or the collection or gravity separation of water or 
hydrocarbon liquids from natural gas at ambient temperature or heated 
above ambient temperatures, or the condensation of water or hydrocarbon 
liquids through passive reduction in pressure or temperature, or 
portable dewpoint suppression skids.
    Gathering and boosting system means a single network of pipelines, 
compressors and process equipment, including equipment to perform 
natural gas compression, dehydration, and acid gas removal, that has one 
or more connection points to gas and oil production and a downstream 
endpoint, typically a gas processing plant, transmission

[[Page 900]]

pipeline, LDC pipeline, or other gathering and boosting system.
    Gathering and boosting system owner or operator means any person 
that holds a contract in which they agree to transport petroleum or 
natural gas from one or more onshore petroleum and natural gas 
production wells to a natural gas processing facility, another gathering 
and boosting system, a natural gas transmission pipeline, or a 
distribution pipeline, or any person responsible for custody of the 
petroleum or natural gas transported.
    Horizontal well means a well bore that has a planned deviation from 
primarily vertical to a primarily horizontal inclination or declination 
tracking in parallel with and through the target formation.
    Internal combustion means the combustion of a fuel that occurs with 
an oxidizer (usually air) in a combustion chamber. In an internal 
combustion engine the expansion of the high-temperature and -pressure 
gases produced by combustion applies direct force to a component of the 
engine, such as pistons, turbine blades, or a nozzle. This force moves 
the component over a distance, generating useful mechanical energy. 
Internal combustion equipment may include gasoline and diesel industrial 
engines, natural gas-fired reciprocating engines, and gas turbines.
    Liquefied natural gas (LNG) means natural gas (primarily methane) 
that has been liquefied by reducing its temperature to -260 degrees 
Fahrenheit at atmospheric pressure.
    LNG boil-off gas means natural gas in the gaseous phase that vents 
from LNG storage tanks due to ambient heat leakage through the tank 
insulation and heat energy dissipated in the LNG by internal pumps.
    Manifolded compressor source means a compressor source (as defined 
in this section) that is manifolded to a common vent that routes gas 
from multiple compressors.
    Manifolded group of compressor sources means a collection of any 
combination of manifolded compressor sources (as defined in this 
section) that are manifolded to a common vent.
    Meter/regulator run means a series of components used in regulating 
pressure or metering natural gas flow, or both, in the natural gas 
distribution industry segment. At least one meter, at least one 
regulator, or any combination of both on a single run of piping is 
considered one meter/regulator run.
    Metering-regulating station means a station that meters the 
flowrate, regulates the pressure, or both, of natural gas in a natural 
gas distribution facility. This does not include customer meters, 
customer regulators, or farm taps.
    Natural gas means a naturally occurring mixture or process 
derivative of hydrocarbon and non-hydrocarbon gases found in geologic 
formations beneath the earth's surface, of which its constituents 
include, but are not limited to, methane, heavier hydrocarbons and 
carbon dioxide. Natural gas may be field quality, pipeline quality, or 
process gas.
    Offshore means seaward of the terrestrial borders of the United 
States, including waters subject to the ebb and flow of the tide, as 
well as adjacent bays, lakes or other normally standing waters, and 
extending to the outer boundaries of the jurisdiction and control of the 
United States under the Outer Continental Shelf Lands Act.
    Onshore natural gas transmission pipeline owner or operator means, 
for interstate pipelines, the person identified as the transmission 
pipeline owner or operator on the Certificate of Public Convenience and 
Necessity issued under 15 U.S.C. 717f, or, for intrastate pipelines, the 
person identified as the owner or operator on the transmission 
pipeline's Statement of Operating Conditions under section 311 of the 
Natural Gas Policy Act, or for pipelines that fall under the ``Hinshaw 
Exemption'' as referenced in section 1(c) of the Natural Gas Act, 15 
U.S.C. 717-717 (w)(1994), the person identified as the owner or operator 
on blanket certificates issued under 18 CFR 284.224. If an intrastate 
pipeline is not subject to section 311 of the Natural Gas Policy Act 
(NGPA), the onshore natural gas transmission pipeline owner or operator 
is the person identified as the owner or operator on reports to the 
state regulatory body regulating rates and charges for the sale of 
natural gas to consumers.
    Onshore petroleum and natural gas production owner or operator means 
the

[[Page 901]]

person or entity who holds the permit to operate petroleum and natural 
gas wells on the drilling permit or an operating permit where no 
drilling permit is issued, which operates an onshore petroleum and/or 
natural gas production facility (as described in Sec. 98.230(a)(2). 
Where petroleum and natural gas wells operate without a drilling or 
operating permit, the person or entity that pays the State or Federal 
business income taxes is considered the owner or operator.
    Operating pressure means the containment pressure that characterizes 
the normal state of gas or liquid inside a particular process, pipeline, 
vessel or tank.
    Pressure groups as applicable to each sub-basin are defined as 
follows: Less than or equal to 25 psig; greater than 25 psig and less 
than or equal to 60 psig; greater than 60 psig and less than or equal to 
110 psig; greater than 110 psig and less than or equal to 200 psig; and 
greater than 200 psig. The pressure in the context of pressure groups is 
either the well shut-in pressure; well casing pressure; or you may use 
the casing-to-tubing pressure of one well from the same sub-basin 
multiplied by the tubing pressure for each well in the sub-basin.
    Pump means a device used to raise pressure, drive, or increase flow 
of liquid streams in closed or open conduits.
    Pump seals means any seal on a pump drive shaft used to keep methane 
and/or carbon dioxide containing light liquids from escaping the inside 
of a pump case to the atmosphere.
    Pump seal emissions means hydrocarbon gas released from the seal 
face between the pump internal chamber and the atmosphere.
    Reduced emissions completion means a well completion following 
hydraulic fracturing where gas flowback emissions from the gas outlet of 
the separator that are otherwise vented are captured, cleaned, and 
routed to the flow line or collection system, re-injected into the well 
or another well, used as an on-site fuel source, or used for other 
useful purpose that a purchased fuel or raw material would serve, with 
de minimis direct venting to the atmosphere. Short periods of flaring 
during a reduced emissions completion may occur.
    Reduced emissions workover means a well workover with hydraulic 
fracturing (i.e., refracturing) where gas flowback emissions from the 
gas outlet of the separator that are otherwise vented are captured, 
cleaned, and routed to the flow line or collection system, re-injected 
into the well or another well, used as an on-site fuel source, or used 
for other useful purpose that a purchased fuel or raw material would 
serve, with de minimis direct venting to the atmosphere. Short periods 
of flaring during a reduced emissions workover may occur.
    Reservoir means a porous and permeable underground natural formation 
containing significant quantities of hydrocarbon liquids and/or gases.
    Residue Gas and Residue Gas Compression mean, respectively, 
production lease natural gas from which gas liquid products and, in some 
cases, non-hydrocarbon components have been extracted such that it meets 
the specifications set by a pipeline transmission company, and/or a 
distribution company; and the compressors operated by the processing 
facility, whether inside the processing facility boundary fence or 
outside the fence-line, that deliver the residue gas from the processing 
facility to a transmission pipeline.
    Separator means a vessel in which streams of multiple phases are 
gravity separated into individual streams of single phase.
    Sub-basin category, for onshore natural gas production, means a 
subdivision of a basin into the unique combination of wells with the 
surface coordinates within the boundaries of an individual county and 
subsurface completion in one or more of each of the following five 
formation types: Oil, high permeability gas, shale gas, coal seam, or 
other tight gas reservoir rock. The distinction between high 
permeability gas and tight gas reservoirs shall be designated as 
follows: High permeability gas reservoirs with 0.1 millidarcy 
permeability, and tight gas reservoirs with <=0.1 millidarcy 
permeability. Permeability for a reservoir type shall be determined by 
engineering estimate. Wells that produce only from high permeability 
gas, shale gas, coal seam, or

[[Page 902]]

other tight gas reservoir rock are considered gas wells; gas wells 
producing from more than one of these formation types shall be 
classified into only one type based on the formation with the most 
contribution to production as determined by engineering knowledge. All 
wells that produce hydrocarbon liquids (with or without gas) and do not 
meet the definition of a gas well in this sub-basin category definition 
are considered to be in the oil formation. All emission sources that 
handle condensate from gas wells in high permeability gas, shale gas, or 
tight gas reservoir rock formations are considered to be in the 
formation that the gas well belongs to and not in the oil formation.
    Transmission-distribution (T-D) transfer station means a metering-
regulating station where a local distribution company takes part or all 
of the natural gas from a transmission pipeline and puts it into a 
distribution pipeline.
    Transmission pipeline means a Federal Energy Regulatory Commission 
rate-regulated Interstate pipeline, a state rate-regulated Intrastate 
pipeline, or a pipeline that falls under the ``Hinshaw Exemption'' as 
referenced in section 1(c) of the Natural Gas Act, 15 U.S.C. 717-717 
(w)(1994).
    Tubing diameter groups are defined as follows: Outer diameter less 
than or equal to 1 inch; outer diameter greater than 1 inch and less 
than 2.375 inch; and outer diameter greater than or equal to 2.375 inch.
    Tubing systems means piping equal to or less than one half inch 
diameter as per nominal pipe size.
    Turbine meter means a flow meter in which a gas or liquid flow rate 
through the calibrated tube spins a turbine from which the spin rate is 
detected and calibrated to measure the fluid flow rate.
    Vented emissions means intentional or designed releases of 
CH4 or CO2 containing natural gas or hydrocarbon 
gas (not including stationary combustion flue gas), including process 
designed flow to the atmosphere through seals or vent pipes, equipment 
blowdown for maintenance, and direct venting of gas used to power 
equipment (such as pneumatic devices).
    Vertical well means a well bore that is primarily vertical but has 
some unintentional deviation or one or more intentional deviations to 
enter one or more subsurface targets that are off-set horizontally from 
the surface location, intercepting the targets either vertically or at 
an angle.
    Well identification (ID) number means the unique and permanent 
identification number assigned to a petroleum or natural gas well. If 
the well has been assigned a US Well Number, the well ID number required 
in this subpart is the US Well Number. If a US Well Number has not been 
assigned to the well, the well ID number is the identifier established 
by the well's permitting authority.
    Well testing venting and flaring means venting and/or flaring of 
natural gas at the time the production rate of a well is determined for 
regulatory, commercial, or technical purposes. If well testing is 
conducted immediately after well completion or workover, then it is 
considered part of well completion or workover.
    Wildcat well means a well outside known fields or the first well 
drilled in an oil or gas field where no other oil and gas production 
exists.

[75 FR 74488, Nov. 30, 2010, as amended at 76 FR 80590, Dec. 23, 2011; 
79 FR 63794, Oct. 24, 2014; 79 FR 70424, Nov. 25, 2014; 80 FR 64296, 
Oct. 22, 2015]



  Sec. Table W-1A to Subpart W of Part 98--Default Whole Gas Emission 
Factors for Onshore Petroleum and Natural Gas Production Facilities and 
   Onshore Petroleum and Natural Gas Gathering and Boosting Facilities

[[Page 903]]



 Table W-1A to Subpart W of Part 98--Default Whole Gas Emission Factors
 for Onshore Petroleum and Natural Gas Production Facilities and Onshore
       Petroleum and Natural Gas Gathering and Boosting Facilities
------------------------------------------------------------------------
  Onshore petroleum and natural gas production
and Onshore petroleum and natural gas gathering   Emission factor  (scf/
                  and boosting                       hour/component)
------------------------------------------------------------------------
                              Eastern U.S.
------------------------------------------------------------------------
      Population Emission Factors--All Components, Gas Service \1\
------------------------------------------------------------------------
Valve..........................................                    0.027
Connector......................................                    0.003
Open-ended Line................................                    0.061
Pressure Relief Valve..........................                    0.040
Low Continuous Bleed Pneumatic Device Vents \2\                     1.39
High Continuous Bleed Pneumatic Device Vents                        37.3
 \2\...........................................
Intermittent Bleed Pneumatic Device Vents \2\..                     13.5
Pneumatic Pumps \3\............................                     13.3
------------------------------------------------------------------------
  Population Emission Factors--All Components, Light Crude Service \4\
------------------------------------------------------------------------
Valve..........................................                     0.05
Flange.........................................                    0.003
Connector......................................                    0.007
Open-ended Line................................                     0.05
Pump...........................................                     0.01
Other \5\......................................                     0.30
------------------------------------------------------------------------
  Population Emission Factors--All Components, Heavy Crude Service \6\
------------------------------------------------------------------------
Valve..........................................                   0.0005
Flange.........................................                   0.0009
Connector (other)..............................                   0.0003
Open-ended Line................................                    0.006
Other \5\......................................                    0.003
------------------------------------------------------------------------
 Population Emission Factors--Gathering Pipelines, by Material Type \7\
------------------------------------------------------------------------
Protected Steel................................                     0.47
Unprotected Steel..............................                    16.59
Plastic/Composite..............................                     2.50
Cast Iron......................................                    27.60
------------------------------------------------------------------------
                              Western U.S.
------------------------------------------------------------------------
      Population Emission Factors--All Components, Gas Service \1\
------------------------------------------------------------------------
Valve..........................................                    0.121
Connector......................................                    0.017
Open-ended Line................................                    0.031
Pressure Relief Valve..........................                    0.193
Low Continuous Bleed Pneumatic Device Vents \2\                     1.39
High Continuous Bleed Pneumatic Device Vents                        37.3
 \2\...........................................
Intermittent Bleed Pneumatic Device Vents \2\..                     13.5
Pneumatic Pumps \3\............................                     13.3
------------------------------------------------------------------------
  Population Emission Factors--All Components, Light Crude Service \4\
------------------------------------------------------------------------
Valve..........................................                     0.05
Flange.........................................                    0.003
Connector (other)..............................                    0.007
Open-ended Line................................                     0.05
Pump...........................................                     0.01
Other \5\......................................                     0.30
------------------------------------------------------------------------

[[Page 904]]

 
  Population Emission Factors--All Components, Heavy Crude Service \6\
------------------------------------------------------------------------
Valve..........................................                   0.0005
Flange.........................................                   0.0009
Connector (other)..............................                   0.0003
Open-ended Line................................                    0.006
Other \5\......................................                    0.003
------------------------------------------------------------------------
  Population Emission Factors--Gathering Pipelines by Material Type \7\
------------------------------------------------------------------------
Protected Steel................................                     0.47
Unprotected Steel..............................                    16.59
Plastic/Composite..............................                     2.50
Cast Iron......................................                    27.60
------------------------------------------------------------------------
\1\ For multi-phase flow that includes gas, use the gas service
  emissions factors.
\2\ Emission Factor is in units of ``scf/hour/device.''
\3\ Emission Factor is in units of ``scf/hour/pump.''
\4\ Hydrocarbon liquids greater than or equal to 20 deg.API are
  considered ``light crude.''
\5\ ``Others'' category includes instruments, loading arms, pressure
  relief valves, stuffing boxes, compressor seals, dump lever arms, and
  vents.
\6\ Hydrocarbon liquids less than 20 deg.API are considered ``heavy
  crude.''
\7\ Emission factors are in units of ``scf/hour/mile of pipeline.''


[80 FR 64297, Oct. 22, 2015]



   Sec. Table W-1B to Subpart W of Part 98--Default Average Component 
 Counts for Major Onshore Natural Gas Production Equipment and Onshore 
       Petroleum and Natural Gas Gathering and Boosting Equipment

----------------------------------------------------------------------------------------------------------------
                                                                                    Open-ended       Pressure
                 Major equipment                      Valves        Connectors         lines       relief valves
----------------------------------------------------------------------------------------------------------------
                                                  Eastern U.S.
----------------------------------------------------------------------------------------------------------------
Wellheads.......................................               8              38             0.5               0
Separators......................................               1               6               0               0
Meters/piping...................................              12              45               0               0
Compressors.....................................              12              57               0               0
In-line heaters.................................              14              65               2               1
Dehydrators.....................................              24              90               2               2
----------------------------------------------------------------------------------------------------------------
                                                  Western U.S.
----------------------------------------------------------------------------------------------------------------
Wellheads.......................................              11              36               1               0
Separators......................................              34             106               6               2
Meters/piping...................................              14              51               1               1
Compressors.....................................              73             179               3               4
In-line heaters.................................              14              65               2               1
Dehydrators.....................................              24              90               2               2
----------------------------------------------------------------------------------------------------------------


[75 FR 74488, Nov. 30, 2010, as amended at 80 FR 64298, Oct. 22, 2015]

[[Page 905]]



   Sec. Table W-1C to Subpart W of Part 98--Default Average Component 
             Counts For Major Crude Oil Production Equipment

----------------------------------------------------------------------------------------------------------------
                                                                                    Open-ended         Other
         Major equipment              Valves          Flanges       Connectors         lines        components
----------------------------------------------------------------------------------------------------------------
                                                  Eastern U.S.
----------------------------------------------------------------------------------------------------------------
Wellhead........................               5              10               4               0               1
Separator.......................               6              12              10               0               0
Heater-treater..................               8              12              20               0               0
Header..........................               5              10               4               0               0
----------------------------------------------------------------------------------------------------------------
                                                  Western U.S.
----------------------------------------------------------------------------------------------------------------
Wellhead........................               5              10               4               0               1
Separator.......................               6              12              10               0               0
Heater-treater..................               8              12              20               0               0
Header..........................               5              10               4               0               0
----------------------------------------------------------------------------------------------------------------



  Sec. Table W-1D to Subpart W of Part 98--Designation Of Eastern And 
                              Western U.S.

------------------------------------------------------------------------
               Eastern U.S.                         Western U.S.
------------------------------------------------------------------------
Connecticut...............................  Alabama
Delaware..................................  Alaska
Florida...................................  Arizona
Georgia...................................  Arkansas
Illinois..................................  California
Indiana...................................  Colorado
Kentucky..................................  Hawaii
Maine.....................................  Idaho
Maryland..................................  Iowa
Massachusetts.............................  Kansas
Michigan..................................  Louisiana
New Hampshire.............................  Minnesota
New Jersey................................  Mississippi
New York..................................  Missouri
North Carolina............................  Montana
Ohio......................................  Nebraska
Pennsylvania..............................  Nevada
Rhode Island..............................  New Mexico
South Carolina............................  North Dakota
Tennessee.................................  Oklahoma
Vermont...................................  Oregon
Virginia..................................  South Dakota
West Virginia.............................  Texas
Wisconsin.................................  Utah
                                            Washington
                                            Wyoming
------------------------------------------------------------------------



   Sec. Table W-2 to Subpart W of Part 98--Default Total Hydrocarbon 
           Emission Factors for Onshore Natural Gas Processing

------------------------------------------------------------------------
                                                        Emission factor
        Onshore natural gas processing plants              (scf/hour/
                                                           component)
------------------------------------------------------------------------
Leaker Emission Factors--Compressor Components, Gas Service
------------------------------------------------------------------------
    Valve \1\........................................              14.84
    Connector........................................               5.59
    Open-Ended Line..................................              17.27
    Pressure Relief Valve............................              39.66
    Meter............................................              19.33
------------------------------------------------------------------------
Leaker Emission Factors--Non-Compressor Components, Gas Service
------------------------------------------------------------------------
    Valve \1\........................................               6.42
    Connector........................................               5.71
    Open-Ended Line..................................              11.27
    Pressure Relief Valve............................               2.01
    Meter............................................               2.93
------------------------------------------------------------------------
\1\ Valves include control valves, block valves and regulator valves.


[76 FR 80592, Dec. 23, 2011]

[[Page 906]]



   Sec. Table W-3 to Subpart W of Part 98--Default Total Hydrocarbon 
    Emission Factors for Onshore Natural Gas Transmission Compression

------------------------------------------------------------------------
                                                        Emission factor
     Onshore natural gas transmission compression          (scf/hour/
                                                           component)
------------------------------------------------------------------------
Leaker Emission Factors--Compressor Components, Gas Service
------------------------------------------------------------------------
    Valve \1\........................................              14.84
    Connector........................................               5.59
    Open-Ended Line..................................              17.27
    Pressure Relief Valve............................              39.66
    Meter............................................              19.33
------------------------------------------------------------------------
Leaker Emission Factors--Non-Compressor Components, Gas Service
------------------------------------------------------------------------
    Valve \1\........................................               6.42
    Connector........................................               5.71
    Open-Ended Line..................................              11.27
    Pressure Relief Valve............................               2.01
    Meter............................................               2.93
------------------------------------------------------------------------
Population Emission Factors--Gas Service
------------------------------------------------------------------------
    Low Continuous Bleed Pneumatic Device Vents \2\..               1.37
    High Continuous Bleed Pneumatic Device Vents \2\.              18.20
    Intermittent Bleed Pneumatic Device Vents \2\....               2.35
------------------------------------------------------------------------
\1\ Valves include control valves, block valves and regulator valves.
\2\ Emission Factor is in units of ``scf/hour/device.''


[76 FR 80593, Dec. 23, 2011]



   Sec. Table W-4 to Subpart W of Part 98--Default Total Hydrocarbon 
          Emission Factors for Underground Natural Gas Storage

------------------------------------------------------------------------
                                                        Emission factor
           Underground natural gas storage                (scf/hour/
                                                          component)
------------------------------------------------------------------------
Leaker Emission Factors--Storage Station, Gas Service
------------------------------------------------------------------------
    Valve \1\.......................................              14.84
    Connector.......................................               5.59
    Open-Ended Line.................................              17.27
    Pressure Relief Valve...........................              39.66
    Meter...........................................              19.33
------------------------------------------------------------------------
Population Emission Factors--Storage Wellheads, Gas Service
------------------------------------------------------------------------
    Connector.......................................               0.01
    Valve...........................................               0.1
    Pressure Relief Valve...........................               0.17
    Open Ended Line.................................               0.03
------------------------------------------------------------------------
Population Emission Factors--Other Components, Gas Service
------------------------------------------------------------------------
    Low Continuous Bleed Pneumatic Device Vents \2\.               1.37
    High Continuous Bleed Pneumatic Device Vents \2\              18.20
    Intermittent Bleed Pneumatic Device Vents \2\...               2.35
------------------------------------------------------------------------
\1\ Valves include control valves, block valves and regulator valves.
\2\ Emission Factor is in units of ``scf/hour/device.''


[76 FR 80593, Dec. 23, 2011]



Sec. Table W-5 to Subpart W of Part 98--Default Methane Emission Factors 
                 for Liquefied Natural Gas (LNG) Storage

------------------------------------------------------------------------
                                                        Emission factor
                     LNG storage                           (scf/hour/
                                                           component)
------------------------------------------------------------------------
Leaker Emission Factors--LNG Storage Components, LNG Service
------------------------------------------------------------------------
    Valve............................................               1.19

[[Page 907]]

 
    Pump Seal........................................               4.00
    Connector........................................               0.34
    Other \1\........................................               1.77
------------------------------------------------------------------------
Population Emission Factors--LNG Storage Compressor, Gas Service
------------------------------------------------------------------------
    Vapor Recovery Compressor \2\....................               4.17
------------------------------------------------------------------------
\1\ ``Other'' equipment type should be applied for any equipment type
  other than connectors, pumps, or valves.
\2\ Emission Factor is in units of ``scf/hour/device.''


[76 FR 80594, Dec. 23, 2011, as amended at 77 FR 51495, Aug. 24, 2012]



Sec. Table W-6 to Subpart W of Part 98--Default Methane Emission Factors 
                   for LNG Import and Export Equipment

------------------------------------------------------------------------
                                                        Emission factor
           LNG import and export equipment                 (scf/hour/
                                                           component)
------------------------------------------------------------------------
Leaker Emission Factors--LNG Terminals Components, LNG Service
------------------------------------------------------------------------
    Valve............................................               1.19
    Pump Seal........................................               4.00
    Connector........................................               0.34
    Other \1\........................................               1.77
------------------------------------------------------------------------
Population Emission Factors--LNG Terminals Compressor, Gas Service
------------------------------------------------------------------------
    Vapor Recovery Compressor \2\....................               4.17
------------------------------------------------------------------------
\1\ ``Other'' equipment type should be applied for any equipment type
  other than connectors, pumps, or valves.
\2\ Emission Factors is in units of ``scf/hour/compressor.''


[76 FR 80594, Dec. 23, 2011]



Sec. Table W-7 to Subpart W of Part 98--Default Methane Emission Factors 
                      for Natural Gas Distribution

------------------------------------------------------------------------
                                                        Emission factor
              Natural gas distribution                    (scf/hour/
                                                          component)
------------------------------------------------------------------------
Leaker Emission Factors--Transmission-Distribution Transfer Station 1
 Components, Gas Service
------------------------------------------------------------------------
    Connector.......................................              1.69
    Block Valve.....................................              0.557
    Control Valve...................................              9.34
    Pressure Relief Valve...........................              0.27
    Orifice Meter...................................              0.212
    Regulator.......................................              0.772
    Open-ended Line.................................             26.131
------------------------------------------------------------------------
Population Emission Factors--Below Grade Metering-Regulating station 1
 Components, Gas Service 2
------------------------------------------------------------------------
    Below Grade M&R Station, Inlet Pressure 300 psig....................................
    Below Grade M&R Station, Inlet Pressure 100 to                0.20
     300 psig.......................................
    Below Grade M&R Station, Inlet Pressure <100                  0.10
     psig...........................................
------------------------------------------------------------------------
Population Emission Factors--Distribution Mains, Gas Service 3
------------------------------------------------------------------------
    Unprotected Steel...............................             12.58
    Protected Steel.................................              0.35
    Plastic.........................................              1.13
    Cast Iron.......................................             27.25
------------------------------------------------------------------------
Population Emission Factors--Distribution Services, Gas Service 4
------------------------------------------------------------------------
    Unprotected Steel...............................              0.19
    Protected Steel.................................              0.02
    Plastic.........................................              0.001
    Copper..........................................              0.03
------------------------------------------------------------------------
\1\ Excluding customer meters.

[[Page 908]]

 
\2\ Emission Factor is in units of ``scf/hour/station.''
\3\ Emission Factor is in units of ``scf/hour/mile.''
\4\ Emission Factor is in units of ``scf/hour/number of services.''


[76 FR 80594, Dec. 23, 2011]



                   Subpart X_Petrochemical Production



Sec. 98.240  Definition of the source category.

    (a) The petrochemical production source category consists of all 
processes that produce acrylonitrile, carbon black, ethylene, ethylene 
dichloride, ethylene oxide, or methanol, except as specified in 
paragraphs (b) through (g) of this section. The source category includes 
processes that produce the petrochemical as an intermediate in the on-
site production of other chemicals as well as processes that produce the 
petrochemical as an end product for sale or shipment off site.
    (b) A process that produces a petrochemical as a byproduct is not 
part of the petrochemical production source category.
    (c) A facility that makes methanol, hydrogen, and/or ammonia from 
synthesis gas is part of the petrochemical source category if the annual 
mass of methanol produced exceeds the individual annual mass production 
levels of both hydrogen recovered as product and ammonia. The facility 
is part of subpart P of this part (Hydrogen Production) if the annual 
mass of hydrogen recovered as product exceeds the individual annual mass 
production levels of both methanol and ammonia. The facility is part of 
subpart G of this part (Ammonia Manufacturing) if the annual mass of 
ammonia produced exceeds the individual annual mass production levels of 
both hydrogen recovered as product and methanol.
    (d) A direct chlorination process that is operated independently of 
an oxychlorination process to produce ethylene dichloride is not part of 
the petrochemical production source category.
    (e) A process that produces bone black is not part of the 
petrochemical source category.
    (f) A process that produces a petrochemical from bio-based feedstock 
is not part of the petrochemical production source category.
    (g) A process that solely distills or recycles waste solvent that 
contains a petrochemical is not part of the petrochemical production 
source category.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79157, Dec. 17, 2010; 
76 FR 80590, Dec. 23, 2011]



Sec. 98.241  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains a petrochemical process as specified in Sec. 98.240, and the 
facility meets the requirements of either Sec. 98.2(a)(1) or (2).



Sec. 98.242  GHGs to report.

    You must report the information in paragraphs (a) through (c) of 
this section:
    (a) CO2 CH4, and N2O process 
emissions from each petrochemical process unit. Process emissions 
include CO2 generated by reaction in the process and by 
combustion of process off-gas in stationary combustion units and flares.
    (1) If you comply with Sec. 98.243(b) or (d), report under this 
subpart the calculated CO2, CH4, and 
N2O emissions for each stationary combustion source and flare 
that burns any amount of petrochemical process off-gas. If you comply 
with Sec. 98.243(b), also report under this subpart the measured 
CO2 emissions from process vents routed to stacks that are 
not associated with stationary combustion units.
    (2) If you comply with Sec. 98.243(c), report under this subpart 
the calculated CO2 emissions for each petrochemical process 
unit.
    (b) CO2, CH4, and N2O combustion 
emissions from stationary combustion units.
    (1) If you comply with Sec. 98.243(b) or (d), report these 
emissions from stationary combustion units that are associated with 
petrochemical process units and burn only supplemental fuel under 
subpart C of this part (General Stationary Fuel Combustion Sources)

[[Page 909]]

by following the requirements of subpart C.
    (2) If you comply with Sec. 98.243(c), report CO2, 
CH4, and N2O combustion emissions under subpart C 
of this part (General Stationary Fuel Combustion Sources) by following 
the requirements of subpart C for all fuels, except emissions from 
burning petrochemical process off-gas in any combustion unit, including 
units that are not part of the petrochemical process unit, are not to be 
reported under subpart C of this part. Determine the applicable Tier in 
subpart C of this part (General Stationary Fuel Combustion Sources) 
based on the maximum rated heat input capacity of the stationary 
combustion source.
    (c) CO2 captured. You must report the mass of 
CO2 captured under, subpart PP of this part (Suppliers of 
Carbon Dioxide (CO2) by following the requirements of subpart 
PP.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79157, Dec. 17, 2010; 
78 FR 71960, Nov. 29, 2013]



Sec. 98.243  Calculating GHG emissions.

    (a) If you route all process vent emissions and emissions from 
combustion of process off-gas to one or more stacks and use CEMS on each 
stack to measure CO2 emissions (except flare stacks), then 
you must determine process-based GHG emissions in accordance with 
paragraph (b) of this section. Otherwise, determine process-based GHG 
emissions in accordance with the procedures specified in paragraph (c) 
or (d) of this section.
    (b) Continuous emission monitoring system (CEMS). Route all process 
vent emissions and emissions from stationary combustion units that burn 
any amount of process off-gas to one or more stacks and determine GHG 
emissions as specified in paragraphs (b)(1) through (3) of this section.
    (1) Determine CO2 emissions from each stack (except flare 
stacks) according to the Tier 4 Calculation Methodology requirements in 
subpart C of this part.
    (2) For each stack (except flare stacks) that includes emissions 
from combustion of petrochemical process off-gas, calculate 
CH4 and N2O emissions in accordance with subpart C 
of this part (use Equation C-10 and the ``fuel gas'' emission factors in 
Table C-2 of subpart C of this part).
    (3) For each flare, calculate CO2, CH4, and 
N2O emissions using the methodology specified in Sec. 
98.253(b)(1) through (3).
    (c) Mass balance for each petrochemical process unit. Calculate the 
emissions of CO2 from each process unit, for each calendar 
month as described in paragraphs (c)(1) through (c)(5) of this section.
    (1) For each gaseous and liquid feedstock and product, measure the 
volume or mass used or produced each calendar month with a flow meter by 
following the procedures specified in Sec. 98.244(b)(2). Alternatively, 
for liquids, you may calculate the volume used or collected in each 
month based on measurements of the liquid level in a storage tank at 
least once per month (and just prior to each change in direction of the 
level of the liquid) following the procedures specified in Sec. 
98.244(b)(3). Fuels used for combustion purposes are not considered to 
be feedstocks.
    (2) For each solid feedstock and product, measure the mass used or 
produced each calendar month by following the procedures specified in 
Sec. 98.244(b)(1).
    (3) Collect a sample of each feedstock and product at least once per 
month and determine the carbon content of each sample according to the 
procedures of Sec. 98.244(b)(4). If multiple valid carbon content 
measurements are made during the monthly measurement period, average 
them arithmetically. However, if a particular liquid or solid feedstock 
is delivered in lots, and if multiple deliveries of the same feedstock 
are received from the same supply source in a given calendar month, only 
one representative sample is required. Alternatively, you may use the 
results of analyses conducted by a feedstock supplier, or product 
customer, provided the sampling and analysis is conducted at least once 
per month using any of the procedures specified in Sec. 98.244(b)(4).
    (4) If you determine that the monthly average concentration of a 
specific compound in a feedstock or product is greater than 99.5 percent 
by volume or mass, then as an alternative to the

[[Page 910]]

sampling and analysis specified in paragraph (c)(3) of this section, you 
may determine carbon content in accordance with paragraphs (c)(4)(i) 
through (iii) of this section.
    (i) Calculate the carbon content assuming 100 percent of that 
feedstock or product is the specific compound.
    (ii) Maintain records of any determination made in accordance with 
this paragraph (c)(4) along with all supporting data, calculations, and 
other information.
    (iii) Reevaluate determinations made under this paragraph (c)(4) 
after any process change that affects the feedstock or product 
composition. Keep records of the process change and the corresponding 
composition determinations. If the feedstock or product composition 
changes so that the average monthly concentration falls below 99.5 
percent, you are no longer permitted to use this alternative method.
    (5) Calculate the CO2 mass emissions for each 
petrochemical process unit using Equations X-1 through X-4 of this 
section.
    (i) Gaseous feedstocks and products. Use Equation X-1 of this 
section to calculate the net annual carbon input or output from gaseous 
feedstocks and products. Note that the result will be a negative value 
if there are no gaseous feedstocks in the process but there are gaseous 
products.
[GRAPHIC] [TIFF OMITTED] TR29NO13.017


Where:

Cg = Annual net contribution to calculated emissions from 
          carbon (C) in gaseous materials, including streams containing 
          CO2 recovered for sale or use in another process 
          (kg/yr).
(Fgf)i,n = Volume or mass of gaseous feedstock i 
          introduced in month ``n'' (scf or kg). If you measure mass, 
          the term (MWf)i,n/MVC is replaced with 
          ``1''.
(CCgf)i,n = Average carbon content of the gaseous 
          feedstock i for month ``n'' (kg C per kg of feedstock).
(MWf)i,n = Molecular weight of gaseous feedstock i 
          in month ``n''(kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf per kg-mole at 68  deg.F 
          and 14.7 pounds per square inch absolute or 836.6 scf/kg-mole 
          at 60  deg.F and 14.7 pounds per square inch absolute).
(Pgp)i,n = Volume or mass of gaseous product i 
          produced in month ``n'' (scf or kg). If you measure mass, the 
          term (MWp)i,n/MVC is replaced with 
          ``1''.
(CCgp)i,n = Average carbon content of gaseous 
          product i, including streams containing CO2 
          recovered for sale or use in another process, for month ``n'' 
          (kg C per kg of product).
(MWp)i,n = Molecular weight of gaseous product i 
          in month ``n'' (kg/kg-mole).
j = Number of feedstocks.
k = Number of products.

    (ii) Liquid feedstocks and products. Use Equation X-2 of this 
section to calculate the net carbon input or output from liquid 
feedstocks and products. Note that the result will be a negative value 
if there are no liquid feedstocks in the process but there are liquid 
products.
[GRAPHIC] [TIFF OMITTED] TR30OC09.084

Where:

Cl = Annual net contribution to calculated emissions from 
          carbon in liquid materials, including liquid organic wastes 
          (kg/yr).
(Flf)i,n = Volume or mass of liquid feedstock i 
          introduced in month ``n'' (gallons or kg).
(CClf)i,n = Average carbon content of liquid 
          feedstock i for month ``n'' (kg C per gallon or kg of 
          feedstock).

[[Page 911]]

(Plp)i,n = Volume or mass of liquid product i 
          produced in month ``n'' (gallons or kg).
(CClp)i,n = Average carbon content of liquid 
          product i, including organic liquid wastes, for month ``n'' 
          (kg C per gallon or kg of product).
j = Number of feedstocks.
k = Number of products.

    (iii) Solid feedstocks and products. Use Equation X-3 of this 
section to calculate the net annual carbon input or output from solid 
feedstocks and products. Note that the result will be a negative value 
if there are no solid feedstocks in the process but there are solid 
products.

[GRAPHIC] [TIFF OMITTED] TR30OC09.085

Where:

Cs = Annual net contribution to calculated emissions from 
          carbon in solid materials (kg/yr).
(Fsf)i,n = Mass of solid feedstock i introduced in 
          month ``n'' (kg).
(CCsf)i,n = Average carbon content of solid 
          feedstock i for month ``n'' (kg C per kg of feedstock).
(Psp)i,n = Mass of solid product i produced in 
          month ``n'' (kg).
(CCsp)i,n = Average carbon content of solid 
          product i in month ``n'' (kg C per kg of product).
j = Number of feedstocks.
k = Number of products.

    (iv) Annual emissions. Use the results from Equations X-1 through X-
3 of this section, as applicable, in Equation X-4 of this section to 
calculate annual CO2 emissions.
[GRAPHIC] [TIFF OMITTED] TR30OC09.086

Where:

CO2 = Annual CO2 mass emissions from process 
          operations and process off-gas combustion (metric tons/year).
0.001 = Conversion factor from kg to metric tons.
44 = Molecular weight of CO2 (kg/kg-mole).
12 = Atomic weight of carbon (C) (kg/kg-mole).

    (d) Optional combustion methodology for ethylene production 
processes. For each ethylene production process, calculate GHG emissions 
from combustion units that burn fuel that contains any off-gas from the 
ethylene process as specified in paragraphs (d)(1) through (d)(5) of 
this section.
    (1) Except as specified in paragraphs (d)(2) and (d)(5) of this 
section, calculate CO2 emissions using the Tier 3 or Tier 4 
methodology in subpart C of this part.
    (2) You may use either Equation C-1 or Equation C-2a in subpart C of 
this part to calculate CO2 emissions from combustion of any 
ethylene process off-gas streams that meet either of the conditions in 
paragraphs (d)(2)(i) or (d)(2)(ii) of this section (for any default 
values in the calculation, use the defaults for fuel gas in Table C-1 of 
subpart C of this part). Follow the otherwise applicable procedures in 
subpart C to calculate emissions from combustion of all other fuels in 
the combustion unit.
    (i) The annual average flow rate of fuel gas (that contains ethylene 
process off-gas) in the fuel gas line to the combustion unit, prior to 
any split to individual burners or ports, does not exceed 345 standard 
cubic feet per minute at 60  deg.F and 14.7 pounds per square inch 
absolute, and a flow meter is not installed at any point in the line 
supplying fuel gas or an upstream common pipe. Calculate the annual 
average flow rate using company records assuming total flow is evenly 
distributed over 525,600 minutes per year.

[[Page 912]]

    (ii) The combustion unit has a maximum rated heat input capacity of 
less than 30 mmBtu/hr, and a flow meter is not installed at any point in 
the line supplying fuel gas (that contains ethylene process off-gas) or 
an upstream common pipe.
    (3) Except as specified in paragraph (d)(5) of this section, 
calculate CH4 and N2O emissions using the 
applicable procedures in Sec. 98.33(c) for the same tier methodology 
that you used for calculating CO2 emissions.
    (i) For all gaseous fuels that contain ethylene process off-gas, use 
the emission factors for ``Fuel Gas'' in Table C-2 of subpart C of this 
part (General Stationary Fuel Combustion Sources).
    (ii) For Tier 3, use either the default high heat value for fuel gas 
in Table C-1 of subpart C of this part or a calculated HHV, as allowed 
in Equation C-8 of subpart C of this part.
    (4) You are not required to use the same Tier for each stationary 
combustion unit that burns ethylene process off-gas.
    (5) For each flare, calculate CO2, CH4, and 
N2O emissions using the methodology specified in Sec. Sec. 
98.253(b)(1) through (b)(3).

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79157, Dec. 17, 2010; 
78 FR 71961, Nov. 29, 2013]



Sec. 98.244  Monitoring and QA/QC requirements.

    (a) If you use CEMS to determine emissions from process vents, you 
must comply with the procedures specified in Sec. 98.34(c).
    (b) If you use the mass balance methodology in Sec. 98.243(c), use 
the procedures specified in paragraphs (b)(1) through (b)(4) of this 
section to determine feedstock and product flows and carbon contents.
    (1) Operate, maintain, and calibrate belt scales or other weighing 
devices as described in Specifications, Tolerances, and Other Technical 
Requirements for Weighing and Measuring Devices NIST Handbook 44 (2009) 
(incorporated by reference, see Sec. 98.7), or follow procedures 
specified by the measurement device manufacturer. You must recalibrate 
each weighing device according to one of the following frequencies. You 
may recalibrate either at the minimum frequency specified by the 
manufacturer or biennially (i.e., once every two years).
    (2) Operate and maintain all flow meters used for gas and liquid 
feedstocks and products according to the manufacturer's recommended 
procedures. You must calibrate each of these flow meters as specified in 
paragraphs (b)(2)(i) and (b)(2)(ii) of this section:
    (i) You may use either the calibration methods specified by the flow 
meter manufacturer or an industry consensus standard method. Each flow 
meter must meet the applicable accuracy specification in Sec. 98.3(i), 
except as otherwise specified in Sec. Sec. 98.3(i)(4) through (i)(6).
    (ii) You must recalibrate each flow meter according to one of the 
following frequencies. You may recalibrate at the minimum frequency 
specified by the manufacturer, biennially (every two years), or at the 
interval specified by the industry consensus standard practice used.
    (3) You must perform tank level measurements (if used to determine 
feedstock or product flows) according to one of the following methods. 
You may use any standard method published by a consensus-based standards 
organization or you may use an industry standard practice. Consensus-
based standards organizations include, but are not limited to, the 
following: ASTM International (100 Barr Harbor Drive, P.O. Box CB700, 
West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373, http://
www.astm.org), the American National Standards Institute (ANSI, 1819 L 
Street, NW., 6th Floor, Washington, DC 20036, (202) 293-8020, http://
www.ansi.org), the American Gas Association (AGA, 400 North Capitol 
Street, NW., 4th Floor, Washington, DC 20001, (202) 824-7000, http://
www.aga.org), the American Society of Mechanical Engineers (ASME, Three 
Park Avenue, New York, NY 10016-5990, (800) 843-2763, http://
www.asme.org), the American Petroleum Institute (API, 1220 L Street, 
NW., Washington, DC 20005-4070, (202) 682-8000, http://www.api.org,) and 
the North American Energy Standards Board (NAESB, 801 Travis Street, 
Suite 1675, Houston, TX 77002, (713) 356-0060, http://www.api.org).

[[Page 913]]

    (4) Beginning January 1, 2010, use any applicable methods specified 
in paragraphs (b)(4)(i) through (xv) of this section to determine the 
carbon content or composition of feedstocks and products and the average 
molecular weight of gaseous feedstocks and products. Calibrate 
instruments in accordance with paragraphs (b)(4)(i) through (xv) of this 
section, as applicable. For coal used as a feedstock, the samples for 
carbon content determinations shall be taken at a location that is 
representative of the coal feedstock used during the corresponding 
monthly period. For carbon black products, samples shall be taken of 
each grade or type of product produced during the monthly period. 
Samples of coal feedstock or carbon black product for carbon content 
determinations may be either grab samples collected and analyzed monthly 
or a composite of samples collected more frequently and analyzed 
monthly. Analyses conducted in accordance with methods specified in 
paragraphs (b)(4)(i) through (xv) of this section may be performed by 
the owner or operator, by an independent laboratory, by the supplier of 
a feedstock, or by a product customer.
    (i) ASTM D1945-03, Standard Test Method for Analysis of Natural Gas 
by Gas Chromatography (incorporated by reference, see Sec. 98.7).
    (ii) ASTM D6060-96 (Reapproved 2001) Standard Practice for Sampling 
of Process Vents With a Portable Gas Chromatograph (incorporated by 
reference, see Sec. 98.7).
    (iii) ASTM D2505-88(Reapproved 2004)e1 Standard Test Method for 
Ethylene, Other Hydrocarbons, and Carbon Dioxide in High-Purity Ethylene 
by Gas Chromatography (incorporated by reference, see Sec. 98.7).
    (iv) ASTM UOP539-97 Refinery Gas Analysis by Gas Chromatography 
(incorporated by reference, see Sec. 98.7).
    (v) ASTM D3176-89 (Reapproved 2002) Standard Practice Method for 
Ultimate Analysis of Coal and Coke (incorporated by reference, see Sec. 
98.7).
    (vi) ASTM D5291-02 (Reapproved 2007) Standard Test Methods for 
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in 
Petroleum Products and Lubricants (incorporated by reference, see Sec. 
98.7).
    (vii) ASTM D5373-08 Standard Test Methods for Instrumental 
Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of 
Coal (incorporated by reference, see Sec. 98.7).
    (viii) Method 8015C, Method 8021B, Method 8031, or Method 9060A (all 
incorporated by reference, see Sec. 98.7).
    (ix) Method 18 at 40 CFR part 60, appendix A-6.
    (x) Performance Specification 9 in 40 CFR part 60, appendix B for 
continuous online gas analyzers. The 7-day calibration error test period 
must be completed prior to the effective date of the rule.
    (xi) ASTM D2593-93 (Reapproved 2009) Standard Test Method for 
Butadiene Purity and Hydrocarbon Impurities by Gas Chromatography 
(incorporated by reference, see Sec. 98.7).
    (xii) ASTM D7633-10 Standard Test Method for Carbon Black--Carbon 
Content (incorporated by reference, see Sec. 98.7).
    (xiii) The results of chromatographic analysis of a feedstock or 
product, provided that the chromatograph is operated, maintained, and 
calibrated according to the manufacturer's instructions.
    (xiv) The results of mass spectrometer analysis of a feedstock or 
product, provided that the mass spectrometer is operated, maintained, 
and calibrated according to the manufacturer's instructions.
    (xv) Beginning on January 1, 2010, the methods specified in 
paragraphs (b)(4)(xv)(A) and (B) of this section may be used as 
alternatives for the methods specified in paragraphs (b)(4)(i) through 
(b)(4)(xiv) of this section.
    (A) An industry standard practice or a method published by a 
consensus-based standards organization if such a method exists for 
carbon black feedstock oils and carbon black products. Consensus-based 
standards organizations include, but are not limited to, the following: 
ASTM International (100 Barr Harbor Drive, P.O. Box CB700, West 
Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373, http://
www.astm.org), the American National Standards Institute (ANSI, 1819 L 
Street, NW., 6th floor, Washington, DC 20036, (202) 293-8020, http://
www.ansi.org), the American Gas Association (AGA,

[[Page 914]]

400 North Capitol Street NW., 4th Floor, Washington, DC 20001, (202) 
824-7000, http://www.aga.org), the American Society of Mechanical 
Engineers (ASME, Three Park Avenue, New York, NY 10016-5990, (800) 843-
2763, http://www.asme.org), the American Petroleum Institute (API, 1220 
L Street NW., Washington, DC 20005-4070, (202) 682-8000, http://
www.api.org), and the North American Energy Standards Board (NAESB, 801 
Travis Street, Suite 1675, Houston, TX 77002, (713) 356-0060, http://
www.naesb.org). The method(s) used shall be documented in the monitoring 
plan required under Sec. 98.3(g)(5).
    (B) Modifications of existing analytical methods or other methods 
that are applicable to your process provided that the methods listed in 
paragraphs (b)(4)(i) through (b)(4)(xiv) of this section are not 
appropriate because the relevant compounds cannot be detected, the 
quality control requirements are not technically feasible, or use of the 
method would be unsafe.
    (c) If you comply with Sec. 98.243(b) or (d), conduct monitoring 
and QA/QC for flares in accordance with Sec. 98.254(b) through (e) for 
each flare gas flow meter, gas composition meter, and/or heating value 
monitor that you use to comply with Sec. 98.253(b)(1) through (b)(3). 
You must implement all applicable QA/QC requirements specified in this 
paragraph (c) beginning no later than January 1, 2015.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79158, Dec. 17, 2010; 
78 FR 71961, Nov. 29, 2013]



Sec. 98.245  Procedures for estimating missing data.

    For missing feedstock and product flow rates, use the same 
procedures as for missing fuel usage as specified in Sec. 98.35(b)(2). 
For missing feedstock and product carbon contents and missing molecular 
weights for gaseous feedstocks and products, use the same procedures as 
for missing carbon contents and missing molecular weights for fuels as 
specified in Sec. 98.35(b)(1).
    For missing flare data, follow the procedures in Sec. 98.255(b) and 
(c).

[78 FR 71962, Nov. 29, 2013]



Sec. 98.246  Data reporting requirements.

    In addition to the information required by Sec. 98.3(c), each 
annual report must contain the information specified in paragraphs (a), 
(b), or (c) of this section, as appropriate for each process unit.
    (a) If you use the mass balance methodology in Sec. 98.243(c), you 
must report the information specified in paragraphs (a)(1) through (13) 
of this section for each type of petrochemical produced, reported by 
process unit.
    (1) The petrochemical process unit ID number or other appropriate 
descriptor.
    (2) The type of petrochemical produced, names of products, and names 
of carbon-containing feedstocks.
    (3) Annual CO2 emissions calculated using Equation X-4 of 
this subpart.
    (4) The temperature (in  deg.F) at which the gaseous feedstock and 
product volumes used in Equation X-1 of Sec. 98.243 were determined.
    (5) Annual quantity of each type of petrochemical produced from each 
process unit (metric tons).
    (6) For each feedstock and product, provide the information 
specified in paragraphs (a)(6)(i) through (a)(6)(iii) of this section.
    (i) Name of each method used to determine carbon content or 
molecular weight in accordance with Sec. 98.244(b)(4);
    (ii) Description of each type of device (e.g., flow meter, weighing 
device) used to determine flow or mass in accordance with Sec. 
98.244(b)(1) through (3).
    (iii) Identification of each method (i.e., method number, title, or 
other description) used to determine flow or mass in accordance with 
Sec. 98.244(b)(1) through (3).
    (7) [Reserved]
    (8) Identification of each combustion unit that burned both process 
off-gas and supplemental fuel, including combustion units that are not 
part of the petrochemical process unit.
    (9) The number of days during which off-specification product was 
produced if the alternative to sampling and analysis specified in Sec. 
98.243(c)(4) is used for a product, and, if applicable, the date of any 
process change that reduced the monthly average composition to less than 
99.5 percent for each product or feedstock for which you comply with

[[Page 915]]

the alternative to sampling and analysis specified in Sec. 
98.243(c)(4).
    (10) You may elect to report the flow and carbon content of 
wastewater, and you may elect to report the annual mass of carbon 
released in fugitive emissions and in process vents that are not 
controlled with a combustion device. These values may be estimated based 
on engineering analyses. These values are not to be used in the mass 
balance calculation.
    (11) If you determine carbon content or composition of a feedstock 
or product using a method under Sec. 98.244(b)(4)(xv)(B), report the 
information listed in paragraphs (a)(11)(i) through (a)(11)(iii) of this 
section. Include the information in paragraph (a)(11)(i) of this section 
in each annual report. Include the information in paragraphs (a)(11)(ii) 
and (a)(11)(iii) of this section only in the first applicable annual 
report, and provide any changes to this information in subsequent annual 
reports.
    (i) Name or title of the analytical method.
    (ii) A copy of the method. If the method is a modification of a 
method listed in Sec. Sec. 98.244(b)(4)(i) through (xiv), you may 
provide a copy of only the sections that differ from the listed method.
    (iii) An explanation of why an alternative to the methods listed in 
Sec. Sec. 98.244(b)(4)(i) through (xiv) is needed.
    (12) Name and annual quantity (in metric tons) of each carbon-
containing feedstock included in Equations X-1, X-2, and X-3 of Sec. 
98.243.
    (13) Name and annual quantity (in metric tons) of each product 
included in Equations X-1, X-2, and X-3.
    (b) If you measure emissions in accordance with Sec. 98.243(b), 
then you must report the information listed in paragraphs (b)(1) through 
(10) of this section.
    (1) The petrochemical process unit ID or other appropriate 
descriptor, and the type of petrochemical produced.
    (2) For CEMS used on stacks that include emissions from stationary 
combustion units that burn any amount of off-gas from the petrochemical 
process, report the relevant information required under Sec. 
98.36(c)(2) and (e)(2)(vi) for the Tier 4 calculation methodology. 
Sections 98.36(c)(2)(ii) and (c)(2)(ix) do not apply for the purposes of 
this subpart.
    (3) For CEMS used on stacks that do not include emissions from 
stationary combustion units, report the information required under Sec. 
98.36(b)(6), (b)(7), and (e)(2)(vi).
    (4) For each CEMS monitoring location that meets the conditions in 
paragraph (b)(2) or (3) of this section, provide an estimate based on 
engineering judgment of the fraction of the total CO2 
emissions that results from CO2 directly emitted by the 
petrochemical process unit plus CO2 generated by the 
combustion of off-gas from the petrochemical process unit.
    (5) For each CEMS monitoring location that meets the conditions in 
paragraph (b)(2) of this section, report the CH4 and 
N2O emissions expressed in metric tons of each gas. For each 
CEMS monitoring location, provide an estimate based on engineering 
judgment of the fraction of the total CH4 and N2O 
emissions that is attributable to combustion of off-gas from the 
petrochemical process unit.
    (6) [Reserved]
    (7) Information listed in Sec. 98.256(e) of subpart Y of this part 
for each flare that burns process off-gas.
    (8) Annual quantity of each type of petrochemical produced from each 
process unit (metric tons).
    (9) Name and annual quantity (in metric tons) of each carbon-
containing feedstock.
    (10) Name and annual quantity (in metric tons) of each product.
    (c) If you comply with the combustion methodology specified in Sec. 
98.243(d), you must report under this subpart the information listed in 
paragraphs (c)(1) through (c)(5) of this section.
    (1) The ethylene process unit ID or other appropriate descriptor.
    (2) For each stationary combustion unit that burns ethylene process 
off-gas (or group of stationary sources with a common pipe), except 
flares, the relevant information listed in Sec. 98.36 for the 
applicable Tier methodology. For each stationary combustion unit or 
group of units (as applicable) that burns ethylene process off-gas, 
provide

[[Page 916]]

an estimate based on engineering judgment of the fraction of the total 
emissions that is attributable to combustion of off-gas from the 
ethylene process unit.
    (3) Information listed in Sec. 98.256(e) of subpart Y of this part 
for each flare that burns ethylene process off-gas.
    (4) Name and annual quantity of each feedstock (metric tons).
    (5) Annual quantity of ethylene produced from each process unit 
(metric tons).

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79159, Dec. 17, 2010; 
78 FR 71962, Nov. 29, 2013; 79 FR 63794, Oct. 24, 2014]



Sec. 98.247  Records that must be retained.

    In addition to the recordkeeping requirements in Sec. 98.3(g), you 
must retain the records specified in paragraphs (a) through (d) of this 
section, as applicable.
    (a) If you comply with the CEMS measurement methodology in Sec. 
98.243(b), then you must retain under this subpart the records required 
for the Tier 4 Calculation Methodology in Sec. 98.37, records of the 
procedures used to develop estimates of the fraction of total emissions 
attributable to combustion of petrochemical process off-gas as required 
in Sec. 98.246(b), and records of any annual average HHV calculations.
    (b) If you comply with the mass balance methodology in Sec. 
98.243(c), then you must retain records of the information listed in 
paragraphs (b)(1) through (4) of this section.
    (1) Results of feedstock or product composition determinations 
conducted in accordance with Sec. 98.243(c)(4).
    (2) Start and end times for time periods when off-specification 
product is produced, if you comply with the alternative methodology in 
Sec. 98.243(c)(4) for determining carbon content of product.
    (3) As part of the monitoring plan required under Sec. 98.3(g)(5), 
record the estimated accuracy of measurement devices and the technical 
basis for these estimates.
    (4) The dates and results (e.g., percent calibration error) of the 
calibrations of each measurement device.
    (c) If you comply with the combustion methodology in Sec. 
98.243(d), then you must retain under this subpart the records required 
for the applicable Tier Calculation Methodologies in Sec. 98.37. If you 
comply with Sec. 98.243(d)(2), you must also keep records of the annual 
average flow calculations.
    (d) Verification software records. You must keep a record of the 
file generated by the verification software specified in Sec. 98.5(b) 
for the applicable data specified in paragraphs (d)(1) through (30) of 
this section. Retention of this file satisfies the recordkeeping 
requirement for the data in paragraphs (d)(1) through (30) of this 
section.
    (1) Indicate whether the feedstock is measured as mass or volume 
(Equation X-1 of Sec. 98.243).
    (2) Indicate whether you used the alternative to sampling and 
analysis specified in Sec. 98.243(c)(4) (Equation X-1).
    (3) Volume of gaseous feedstock introduced per month (scf) (Equation 
X-1).
    (4) Mass of gaseous feedstock introduced per month (kg) (Equation X-
1).
    (5) Average carbon content of the gaseous feedstock per month (kg C 
per kg of feedstock) (Equation X-1).
    (6) Molecular weight of gaseous feedstock per month (kg per kg-mole) 
(Equation X-1).
    (7) Indicate whether the gaseous product is measured as mass or 
volume (Equation X-1).
    (8) Volume of gaseous product produced per month (scf) (Equation X-
1).
    (9) Mass of gaseous product produced per month (kg) (Equation X-1).
    (10) Average carbon content of gaseous product (including streams 
containing CO2 recovered for sale or use in another process) 
per month (kg C per kg of product) (Equation X-1).
    (11) Molecular weight of gaseous product per month (kg per kg-mole) 
(Equation X-1).
    (12) Molar volume conversion factor of product (scf per kg-mole) 
(Equation X-1).
    (13) Indicate whether feedstock is measured as mass or volume 
(Equation X-2 of Sec. 98.243).
    (14) Indicate whether you used the alternative to sampling and 
analysis specified in Sec. 98.243(c)(4) (Equation X-2).
    (15) Volume of liquid feedstock introduced per month (gallons) 
(Equation X-2).

[[Page 917]]

    (16) Mass of liquid feedstock introduced per month (kg) (Equation X-
2).
    (17) Average carbon content of liquid feedstock per month (kg C per 
gallon) (Equation X-2).
    (18) Average carbon content of liquid feedstock per month (kg C per 
kg of feedstock) (Equation X-2).
    (19) Indicate whether product is measured as mass or volume per 
month (Equation X-2).
    (20) Volume of liquid product produced per month (gallons) (Equation 
X-2).
    (21) Mass of liquid product produced per month (kg) (Equation X-2).
    (22) Average carbon content of liquid product per month, including 
organic liquid wastes (kg C per gallon) (Equation X-2).
    (23) Average carbon content of liquid product, including organic 
liquid wastes (kg C per kg of product) (Equation X-2).
    (24) Indicate whether you used the alternative to sampling and 
analysis specified in Sec. 98.243(c)(4) (Equation X-3 of Sec. 98.243).
    (25) Mass of solid feedstock introduced per month (kg) (Equation X-
3).
    (26) Average carbon content of solid feedstock per month (kg C per 
kg of feedstock) (Equation X-3).
    (27) Mass of solid product produced per month (kg) (Equation X-3).
    (28) Average carbon content of solid product per month (kg C per kg 
of product) (Equation X-3).
    (29) Records required in Sec. 98.257(b)(1) through (8) of this 
section for each flare that burns ethylene process off-gas.
    (30) Records required in Sec. 98.37 for each stationary fuel 
combustion unit (or group of stationary sources with a common pipe) that 
burns ethylene process off-gas, except flares.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79160, Dec. 17, 2010; 
78 FR 71962, Nov. 29, 2013; 79 FR 63794, Oct. 24, 2014]



Sec. 98.248  Definitions.

    Except as specified in this section, all terms used in this subpart 
have the same meaning given in the Clean Air Act and subpart A of this 
part.
    Product, as used in Sec. 98.243, means each of the following 
carbon-containing outputs from a process: the petrochemical, recovered 
byproducts, and liquid organic wastes that are not combusted onsite. 
Product does not include process vent emissions, fugitive emissions, or 
wastewater.

[74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71963, Nov. 29, 2013]



                     Subpart Y_Petroleum Refineries



Sec. 98.250  Definition of source category.

    (a) A petroleum refinery is any facility engaged in producing 
gasoline, gasoline blending stocks, naphtha, kerosene, distillate fuel 
oils, residual fuel oils, lubricants, or asphalt (bitumen) through 
distillation of petroleum or through redistillation, cracking, or 
reforming of unfinished petroleum derivatives, except as provided in 
paragraph (b) of this section.
    (b) For the purposes of this subpart, facilities that distill only 
pipeline transmix (off-spec material created when different 
specification products mix during pipeline transportation) are not 
petroleum refineries, regardless of the products produced.
    (c) This source category consists of the following sources at 
petroleum refineries: Catalytic cracking units; fluid coking units; 
delayed coking units; catalytic reforming units; coke calcining units; 
asphalt blowing operations; blowdown systems; storage tanks; process 
equipment components (compressors, pumps, valves, pressure relief 
devices, flanges, and connectors) in gas service; marine vessel, barge, 
tanker truck, and similar loading operations; flares; sulfur recovery 
plants; and non-merchant hydrogen plants (i.e., hydrogen plants that are 
owned or under the direct control of the refinery owner and operator).



Sec. 98.251  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains a petroleum refineries process and the facility meets the 
requirements of either Sec. 98.2(a)(1) or (a)(2).



Sec. 98.252  GHGs to report.

    You must report:
    (a) CO2, CH4, and N2O combustion 
emissions from stationary combustion units and from each flare. 
Calculate

[[Page 918]]

and report the emissions from stationary combustion units under subpart 
C of this part (General Stationary Fuel Combustion Sources) by following 
the requirements of subpart C, except for emissions from combustion of 
fuel gas. For CO2 emissions from combustion of fuel gas, use 
either Equation C-5 in subpart C of this part or the Tier 4 methodology 
in subpart C of this part, unless either of the conditions in paragraphs 
(a)(1) or (2) of this section are met, in which case use either 
Equations C-1 or C-2a in subpart C of this part. For CH4 and 
N2O emissions from combustion of fuel gas, use the applicable 
procedures in Sec. 98.33(c) for the same tier methodology that was used 
for calculating CO2 emissions. (Use the default 
CH4 and N2O emission factors for ``Fuel Gas'' in 
Table C-2 of this part. For Tier 3, use either the default high heat 
value for fuel gas in Table C-1 of subpart C of this part or a 
calculated HHV, as allowed in Equation C-8 of subpart C of this part.) 
You may aggregate units, monitor common stacks, or monitor common (fuel) 
pipes as provided in Sec. 98.36(c) when calculating and reporting 
emissions from stationary combustion units. Calculate and report the 
emissions from flares under this subpart.
    (1) The annual average fuel gas flow rate in the fuel gas line to 
the combustion unit, prior to any split to individual burners or ports, 
does not exceed 345 standard cubic feet per minute at 60  deg.F and 14.7 
pounds per square inch absolute and either of the conditions in 
paragraph (a)(1)(i) or (ii) of this section exist. Calculate the annual 
average flow rate using company records assuming total flow is evenly 
distributed over 525,600 minutes per year.
    (i) A flow meter is not installed at any point in the line supplying 
fuel gas or an upstream common pipe.
    (ii) The fuel gas line contains only vapors from loading or 
unloading, waste or wastewater handling, and remediation activities that 
are combusted in a thermal oxidizer or thermal incinerator.
    (2) The combustion unit has a maximum rated heat input capacity of 
less than 30 mmBtu/hr and either of the following conditions exist:
    (i) A flow meter is not installed at any point in the line supplying 
fuel gas or an upstream common pipe; or
    (ii) The fuel gas line contains only vapors from loading or 
unloading, waste or wastewater handling, and remediation activities that 
are combusted in a thermal oxidizer or thermal incinerator.
    (b) CO2, CH4, and N2O coke burn-off 
emissions from each catalytic cracking unit, fluid coking unit, and 
catalytic reforming unit under this subpart.
    (c) CO2 emissions from sour gas sent off site for sulfur 
recovery operations under this subpart. You must follow the calculation 
methodologies from Sec. 98.253(f) and the monitoring and QA/QC methods, 
missing data procedures, reporting requirements, and recordkeeping 
requirements of this subpart.
    (d) CO2 process emissions from each on-site sulfur 
recovery plant under this subpart.
    (e) CO2, CH4, and N2O emissions 
from each coke calcining unit under this subpart.
    (f) CO2 and CH4 emissions from asphalt blowing 
operations under this subpart.
    (g) CH4 emissions from equipment leaks, storage tanks, 
loading operations, delayed coking units, and uncontrolled blowdown 
systems under this subpart.
    (h) CO2, CH4, and N2O emissions 
from each process vent not specifically included in paragraphs (a) 
through (g) of this section under this subpart.
    (i) CO2 emissions from non-merchant hydrogen production 
process units (not including hydrogen produced from catalytic reforming 
units) following the calculation methodologies, monitoring and QA/QC 
methods, missing data procedures, reporting requirements, and 
recordkeeping requirements of subpart P of this part.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79160, Dec. 17, 2010; 
78 FR 71963, Nov. 29, 2013]



Sec. 98.253  Calculating GHG emissions.

    (a) Calculate GHG emissions required to be reported in Sec. 
98.252(b) through (i) using the applicable methods in paragraphs (b) 
through (n) of this section.
    (b) For flares, calculate GHG emissions according to the 
requirements in

[[Page 919]]

paragraphs (b)(1) through (b)(3) of this section.
    (1) Calculate the CO2 emissions according to the 
applicable requirements in paragraphs (b)(1)(i) through (b)(1)(iii) of 
this section.
    (i) Flow measurement. If you have a continuous flow monitor on the 
flare, you must use the measured flow rates when the monitor is 
operational and the flow rate is within the calibrated range of the 
measurement device to calculate the flare gas flow. If you do not have a 
continuous flow monitor on the flare and for periods when the monitor is 
not operational or the flow rate is outside the calibrated range of the 
measurement device, you must use engineering calculations, company 
records, or similar estimates of volumetric flare gas flow.
    (ii) Heat value or carbon content measurement. If you have a 
continuous higher heating value monitor or gas composition monitor on 
the flare or if you monitor these parameters at least weekly, you must 
use the measured heat value or carbon content value in calculating the 
CO2 emissions from the flare using the applicable methods in 
paragraphs (b)(1)(ii)(A) and (b)(1)(ii)(B).
    (A) If you monitor gas composition, calculate the CO2 
emissions from the flare using either Equation Y-1a or Equation Y-1b of 
this section. If daily or more frequent measurement data are available, 
you must use daily values when using Equation Y-1a or Equation Y-1b of 
this section; otherwise, use weekly values.
[GRAPHIC] [TIFF OMITTED] TR17DE10.005

where:

CO2 = Annual CO2 emissions for a specific fuel 
          type (metric tons/year).
0.98 = Assumed combustion efficiency of a flare.
0.001 = Unit conversion factor (metric tons per kilogram, mt/kg).
n = Number of measurement periods. The minimum value for n is 52 (for 
          weekly measurements); the maximum value for n is 366 (for 
          daily measurements during a leap year).
p = Measurement period index.
44 = Molecular weight of CO2 (kg/kg-mole).
12 = Atomic weight of C (kg/kg-mole).
(Flare)p = Volume of flare gas combusted during measurement 
          period (standard cubic feet per period, scf/period). If a mass 
          flow meter is used, measure flare gas flow rate in kg/period 
          and replace the term ``(MW)p/MVC'' with ``1''.
(MW)p = Average molecular weight of the flare gas combusted 
          during measurement period (kg/kg-mole). If measurements are 
          taken more frequently than daily, use the arithmetic average 
          of measurement values within the day to calculate a daily 
          average.
MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68  deg.F and 
          14.7 pounds per square inch absolute (psia) or 836.6 scf/kg-
          mole at 60  deg.F and 14.7 psia).
(CC)p = Average carbon content of the flare gas combusted 
          during measurement period (kg C per kg flare gas). If 
          measurements are taken more frequently than daily, use the 
          arithmetic average of measurement values within the day to 
          calculate a daily average.
          [GRAPHIC] [TIFF OMITTED] TR17DE10.006
          
where:

CO2 = Annual CO2 emissions for a specific fuel 
          type (metric tons/year).

[[Page 920]]

n = Number of measurement periods. The minimum value for n is 52 (for 
          weekly measurements); the maximum value for n is 366 (for 
          daily measurements during a leap year).
p = Measurement period index.
(Flare)p = Volume of flare gas combusted during measurement 
          period (standard cubic feet per period, scf/period). If a mass 
          flow meter is used, you must determine the average molecular 
          weight of the flare gas during the measurement period and 
          convert the mass flow to a volumetric flow.
44 = Molecular weight of CO2 (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68  deg.F and 
          14.7 psia or 836.6 scf/kg-mole at 60  deg.F and 14.7 psia).
0.001 = Unit conversion factor (metric tons per kilogram, mt/kg).
(%CO2)p = Mole percent CO2 
          concentration in the flare gas stream during the measurement 
          period (mole percent = percent by volume).
y = Number of carbon-containing compounds other than CO2 in 
          the flare gas stream.
x = Index for carbon-containing compounds other than CO2.
0.98 = Assumed combustion efficiency of a flare (mole CO2 per 
          mole carbon).
(%CX)p = Mole percent concentration of compound 
          ``x'' in the flare gas stream during the measurement period 
          (mole percent = percent by volume)
CMNX = Carbon mole number of compound ``x'' in the flare gas 
          stream (mole carbon atoms per mole compound). E.g., CMN for 
          ethane (C2H6) is 2; CMN for propane 
          (C3H8) is 3.

    (B) If you monitor heat content but do not monitor gas composition, 
calculate the CO2 emissions from the flare using Equation Y-2 
of this section. If daily or more frequent measurement data are 
available, you must use daily values when using Equation Y-2 of this 
section; otherwise, use weekly values.
[GRAPHIC] [TIFF OMITTED] TR30OC09.088

Where:

CO2 = Annual CO2 emissions for a specific fuel 
          type (metric tons/year).
0.98 = Assumed combustion efficiency of a flare.
0.001 = Unit conversion factor (metric tons per kilogram, mt/kg).
n = Number of measurement periods. The minimum value for n is 52 (for 
          weekly measurements); the maximum value for n is 366 (for 
          daily measurements during a leap year).
p = Measurement period index.
(Flare)p = Volume of flare gas combusted during measurement 
          period (million (MM) scf/period). If a mass flow meter is 
          used, you must also measure molecular weight and convert the 
          mass flow to a volumetric flow as follows: Flare[MMscf] = 
          0.000001 x Flare[kg] x MVC/(MW)p, where MVC is the 
          molar volume conversion factor [849.5 scf/kg-mole at 68  deg.F 
          and 14.7 psia or 836.6 scf/kg-mole at 60  deg.F and 14.7 psia 
          depending on the standard conditions used when determining 
          (HHV)p] and (MW)p is the average 
          molecular weight of the flare gas combusted during measurement 
          period (kg/kg-mole).
(HHV)p = Higher heating value for the flare gas combusted 
          during measurement period (British thermal units per scf, Btu/
          scf = MMBtu/MMscf). If measurements are taken more frequently 
          than daily, use the arithmetic average of measurement values 
          within the day to calculate a daily average.
EmF = Default CO2 emission factor of 60 kilograms 
          CO2/MMBtu (HHV basis).

    (iii) Alternative to heat value or carbon content measurements. If 
you do not measure the higher heating value or carbon content of the 
flare gas at least weekly, determine the quantity of gas discharged to 
the flare separately for periods of routine flare operation and for 
periods of start-up, shutdown, or malfunction, and calculate the 
CO2 emissions as specified in paragraphs (b)(1)(iii)(A) 
through (b)(1)(iii)(C) of this section.
    (A) For periods of start-up, shutdown, or malfunction, use 
engineering calculations and process knowledge to estimate the carbon 
content of the flared gas for each start-up, shutdown, or malfunction 
event exceeding 500,000 scf/day.
    (B) For periods of normal operation, use the average heating value 
measured for the fuel gas for the heating value of the flare gas. If 
heating value

[[Page 921]]

is not measured, the heating value may be estimated from historic data 
or engineering calculations.
    (C) Calculate the CO2 emissions using Equation Y-3 of 
this section. 
[GRAPHIC] [TIFF OMITTED] TR30OC09.089

Where:

CO2 = Annual CO2 emissions for a specific fuel 
          type (metric tons/year).
0.98 = Assumed combustion efficiency of a flare.
0.001 = Unit conversion factor (metric tons per kilogram, mt/kg).
FlareNorm = Annual volume of flare gas combusted during 
          normal operations from company records, (million (MM) standard 
          cubic feet per year, MMscf/year).
HHV = Higher heating value for fuel gas or flare gas from company 
          records (British thermal units per scf, Btu/scf = MMBtu/
          MMscf).
EmF = Default CO2 emission factor for flare gas of 60 
          kilograms CO2/MMBtu (HHV basis).
n = Number of start-up, shutdown, and malfunction events during the 
          reporting year exceeding 500,000 scf/day.
p = Start-up, shutdown, and malfunction event index.
44 = Molecular weight of CO2 (kg/kg-mole).
12 = Atomic weight of C (kg/kg-mole).
(FlareSSM)p = Volume of flare gas combusted during 
          indexed start-up, shutdown, or malfunction event from 
          engineering calculations, (scf/event).
(MW)p = Average molecular weight of the flare gas, from the 
          analysis results or engineering calculations for the event 
          (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68  deg.F and 
          14.7 psia or 836.6 scf/kg-mole at 60  deg.F and 14.7 psia).
(CC)p = Average carbon content of the flare gas, from 
          analysis results or engineering calculations for the event (kg 
          C per kg flare gas).

    (2) Calculate CH4 using Equation Y-4 of this section. 
    [GRAPHIC] [TIFF OMITTED] TR30OC09.090
    
Where:

CH4 = Annual methane emissions from flared gas (metric tons 
          CH4/year).
CO2 = Emission rate of CO2 from flared gas 
          calculated in paragraph (b)(1) of this section (metric tons/
          year).
EmFCH4 = Default CH4 emission factor for ``Fuel 
          Gas'' from Table C-2 of subpart C of this part (General 
          Stationary Fuel Combustion Sources) (kg CH4/MMBtu).
EmF = Default CO2 emission factor for flare gas of 60 kg 
          CO2/MMBtu (HHV basis).
0.02/0.98 = Correction factor for flare combustion efficiency.
16/44 = Correction factor ratio of the molecular weight of 
          CH4 to CO2.
fCH4 = Weight fraction of carbon in the flare gas prior to 
          combustion that is contributed by methane from measurement 
          values or engineering calculations (kg C in methane in flare 
          gas/kg C in flare gas); default is 0.4.

    (3) Calculate N2O emissions using Equation Y-5 of this 
section. 
[GRAPHIC] [TIFF OMITTED] TR30OC09.091

Where:

N2O = Annual nitrous oxide emissions from flared gas (metric 
          tons N2O/year).
CO2 = Emission rate of CO2 from flared gas 
          calculated in paragraph (b)(1) of this section (metric tons/
          year).
EmFN2O = Default N2O emission factor for ``Fuel 
          Gas'' from Table C-2 of subpart C of this part (General 
          Stationary Fuel Combustion Sources) (kg N2O/MMBtu).
EmF = Default CO2 emission factor for flare gas of 60 kg 
          CO2/MMBtu (HHV basis).


[[Page 922]]


    (c) For catalytic cracking units and traditional fluid coking units, 
calculate the GHG emissions using the applicable methods described in 
paragraphs (c)(1) through (c)(5) of this section.
    (1) If you operate and maintain a CEMS that measures CO2 
emissions according to subpart C of this part (General Stationary Fuel 
Combustion Sources), you must calculate and report CO2 
emissions as provided in paragraphs (c)(1)(i) and (c)(1)(ii) of this 
section. Other catalytic cracking units and traditional fluid coking 
units must either install a CEMS that complies with the Tier 4 
Calculation Methodology in subpart C of this part (General Stationary 
Combustion Sources), or follow the requirements of paragraphs (c)(2) or 
(3) of this section.
    (i) Calculate CO2 emissions by following the Tier 4 
Calculation Methodology specified in Sec. 98.33(a)(4) and all 
associated requirements for Tier 4 in subpart C of this part (General 
Stationary Fuel Combustion Sources).
    (ii) For catalytic cracking units whose process emissions are 
discharged through a combined stack with other CO2 emissions 
(e.g., co-mingled with emissions from a CO boiler) you must also 
calculate the other CO2 emissions using the applicable 
methods for the applicable subpart (e.g., subpart C of this part in the 
case of a CO boiler). Calculate the process emissions from the catalytic 
cracking unit or fluid coking unit as the difference in the 
CO2 CEMS emissions and the calculated emissions associated 
with the additional units discharging through the combined stack.
    (2) For catalytic cracking units and fluid coking units with rated 
capacities greater than 10,000 barrels per stream day (bbls/sd) that do 
not use a continuous CO2 CEMS for the final exhaust stack, 
you must continuously or no less frequently than hourly monitor the 
O2, CO2, and (if necessary) CO concentrations in 
the exhaust stack from the catalytic cracking unit regenerator or fluid 
coking unit burner prior to the combustion of other fossil fuels and 
calculate the CO2 emissions according to the requirements of 
paragraphs (c)(2)(i) through (c)(2)(iii) of this section:
    (i) Calculate the CO2 emissions from each catalytic 
cracking unit and fluid coking unit using Equation Y-6 of this section. 
[GRAPHIC] [TIFF OMITTED] TR30OC09.092

Where:

CO2 = Annual CO2 mass emissions (metric tons/
          year).
Qr = Volumetric flow rate of exhaust gas from the fluid 
          catalytic cracking unit regenerator or fluid coking unit 
          burner prior to the combustion of other fossil fuels (dry 
          standard cubic feet per hour, dscfh).
%CO2 = Hourly average percent CO2 concentration in 
          the exhaust gas stream from the fluid catalytic cracking unit 
          regenerator or fluid coking unit burner (percent by volume--
          dry basis).
%CO = Hourly average percent CO concentration in the exhaust gas stream 
          from the fluid catalytic cracking unit regenerator or fluid 
          coking unit burner (percent by volume--dry basis). When there 
          is no post-combustion device, assume %CO to be zero.
44 = Molecular weight of CO2 (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68  deg.F and 
          14.7 psia or 836.6 scf/kg-mole at 60  deg.F and 14.7 psia).
0.001 = Conversion factor (metric ton/kg).
n = Number of hours in calendar year.

    (ii) Either continuously monitor the volumetric flow rate of exhaust 
gas from the fluid catalytic cracking unit regenerator or fluid coking 
unit burner prior to the combustion of other fossil fuels or calculate 
the volumetric flow rate of this exhaust gas stream using either 
Equation Y-7a or Equation Y-7b of this section.

[[Page 923]]

[GRAPHIC] [TIFF OMITTED] TR17DE10.007

where:

Qr = Volumetric flow rate of exhaust gas from the fluid 
          catalytic cracking unit regenerator or fluid coking unit 
          burner prior to the combustion of other fossil fuels (dscfh).
Qa = Volumetric flow rate of air to the fluid catalytic 
          cracking unit regenerator or fluid coking unit burner, as 
          determined from control room instrumentation (dscfh).
Qoxy = Volumetric flow rate of oxygen enriched air to the 
          fluid catalytic cracking unit regenerator or fluid coking unit 
          burner as determined from control room instrumentation 
          (dscfh).
%O2 = Hourly average percent oxygen concentration in exhaust 
          gas stream from the fluid catalytic cracking unit regenerator 
          or fluid coking unit burner (percent by volume--dry basis).
%Ooxy = O2 concentration in oxygen enriched gas 
          stream inlet to the fluid catalytic cracking unit regenerator 
          or fluid coking unit burner based on oxygen purity 
          specifications of the oxygen supply used for enrichment 
          (percent by volume--dry basis).
%CO2 = Hourly average percent CO2 concentration in 
          the exhaust gas stream from the fluid catalytic cracking unit 
          regenerator or fluid coking unit burner (percent by volume--
          dry basis).
%CO = Hourly average percent CO concentration in the exhaust gas stream 
          from the fluid catalytic cracking unit regenerator or fluid 
          coking unit burner (percent by volume--dry basis). When no 
          auxiliary fuel is burned and a continuous CO monitor is not 
          required under 40 CFR part 63 subpart UUU, assume %CO to be 
          zero.
          [GRAPHIC] [TIFF OMITTED] TR17DE10.008
          
where:

Qr = Volumetric flow rate of exhaust gas from the fluid 
          catalytic cracking unit regenerator or fluid coking unit 
          burner prior to the combustion of other fossil fuels (dscfh).
Qa = Volumetric flow rate of air to the fluid catalytic 
          cracking unit regenerator or fluid coking unit burner, as 
          determined from control room instrumentation (dscfh).
Qoxy = Volumetric flow rate of oxygen enriched air to the 
          fluid catalytic cracking unit regenerator or fluid coking unit 
          burner as determined from control room instrumentation 
          (dscfh).
%N2,oxy = N2 concentration in oxygen enriched gas 
          stream inlet to the fluid catalytic cracking unit regenerator 
          or fluid coking unit burner based on measured value or maximum 
          N2 impurity specifications of the oxygen supply 
          used for enrichment (percent by volume--dry basis).

%N2,exhaust = Hourly average percent N2 
          concentration in the exhaust gas stream from the fluid 
          catalytic cracking unit regenerator or fluid coking unit 
          burner (percent by volume--dry basis).

    (iii) If you have a CO boiler that uses auxiliary fuels or combusts 
materials other than catalytic cracking unit or fluid coking unit 
exhaust gas, you must determine the CO2 emissions resulting 
from the combustion of these fuels or other materials following the 
requirements in subpart C and report those emissions by following the 
requirements of subpart C of this part.
    (3) For catalytic cracking units and fluid coking units with rated 
capacities of 10,000 barrels per stream day (bbls/sd) or less that do 
not use a continuous CO2 CEMS for the final exhaust stack, 
comply with the requirements in paragraph (c)(3)(i) of this section or 
paragraphs (c)(3)(ii) and (c)(3)(iii) of this section, as applicable.
    (i) If you continuously or no less frequently than daily monitor the 
O2, CO2, and (if necessary) CO concentrations in

[[Page 924]]

the exhaust stack from the catalytic cracking unit regenerator or fluid 
coking unit burner prior to the combustion of other fossil fuels, you 
must calculate the CO2 emissions according to the 
requirements of paragraphs (c)(2)(i) through (c)(2)(iii) of this 
section, except that daily averages are allowed and the summation can be 
performed on a daily basis.
    (ii) If you do not monitor at least daily the O2, 
CO2, and (if necessary) CO concentrations in the exhaust 
stack from the catalytic cracking unit regenerator or fluid coking unit 
burner prior to the combustion of other fossil fuels, calculate the 
CO2 emissions from each catalytic cracking unit and fluid 
coking unit using Equation Y-8 of this section. 
[GRAPHIC] [TIFF OMITTED] TR30OC09.094

Where:

CO2 = Annual CO2 mass emissions (metric tons/
          year).
Qunit = Annual throughput of unit from company records 
          (barrels (bbls) per year, bbl/yr).
CBF = Coke burn-off factor from engineering calculations (kg coke per 
          barrel of feed); default for catalytic cracking units = 7.3; 
          default for fluid coking units = 11.
0.001 = Conversion factor (metric ton/kg).
CC = Carbon content of coke based on measurement or engineering estimate 
          (kg C per kg coke); default = 0.94.
44/12 = Ratio of molecular weight of CO2 to C (kg 
          CO2 per kg C).

    (iii) If you have a CO boiler that uses auxiliary fuels or combusts 
materials other than catalytic cracking unit or fluid coking unit 
exhaust gas, you must determine the CO2 emissions resulting 
from the combustion of these fuels or other materials following the 
requirements in subpart C of this part (General Stationary Fuel 
Combustion Sources) and report those emissions by following the 
requirements of subpart C of this part.
    (4) Calculate CH4 emissions using either unit specific 
measurement data, a unit-specific emission factor based on a source test 
of the unit, or Equation Y-9 of this section. 
[GRAPHIC] [TIFF OMITTED] TR30OC09.095

Where:

CH4 = Annual methane emissions from coke burn-off (metric 
          tons CH4/year).
CO2 = Emission rate of CO2 from coke burn-off 
          calculated in paragraphs (c)(1), (c)(2), (e)(1), (e)(2), 
          (g)(1), or (g)(2) of this section, as applicable (metric tons/
          year).
EmF1 = Default CO2 emission factor for petroleum 
          coke from Table C-1 of subpart C of this part (General 
          Stationary Fuel Combustion Sources) (kg CO2/MMBtu).
EmF2 = Default CH4 emission factor for 
          ``PetroleumProducts'' from Table C-2 of subpart C of this part 
          (General Stationary Fuel Combustion Sources) (kg 
          CH4/MMBtu).

    (5) Calculate N2O emissions using either unit specific 
measurement data, a unit-specific emission factor based on a source test 
of the unit, or Equation Y-10 of this section. 
[GRAPHIC] [TIFF OMITTED] TR30OC09.096

Where:

N2O = Annual nitrous oxide emissions from coke burn-off (mt 
          N2O/year).
CO2 = Emission rate of CO2 from coke burn-off 
          calculated in paragraphs (c)(1), (c)(2), (e)(1), (e)(2), 
          (g)(1), or (g)(2) of this section, as applicable (metric tons/
          year).
EmF1 = Default CO2 emission factor for petroleum 
          coke from Table C-1 of subpart C of this part (General 
          Stationary Fuel Combustion Sources) (kg CO2/MMBtu).
EmF3 = Default N2O emission factor for 
          ``PetroleumProducts'' from Table C-2 of subpart C of this part 
          (kg N2O/MMBtu).

    (d) For fluid coking units that use the flexicoking design, the GHG 
emissions from the resulting use of the low value fuel gas must be 
accounted for only once. Typically, these emissions will be accounted 
for using the methods described in subpart C of this part (General 
Stationary Fuel Combustion Sources). Alternatively, you may use

[[Page 925]]

the methods in paragraph (c) of this section provided that you do not 
otherwise account for the subsequent combustion of this low value fuel 
gas.
    (e) For catalytic reforming units, calculate the CO2 
emissions using the applicable methods described in paragraphs (e)(1) 
through (e)(3) of this section and calculate the CH4 and 
N2O emissions using the methods described in paragraphs 
(c)(4) and (c)(5) of this section, respectively.
    (1) If you operate and maintain a CEMS that measures CO2 
emissions according to subpart C of this part (General Stationary Fuel 
Combustion Sources), you must calculate CO2 emissions as 
provided in paragraphs (c)(1)(i) and (c)(1)(ii) of this section. Other 
catalytic reforming units must either install a CEMS that complies with 
the Tier 4 Calculation Methodology in subpart C of this part, or follow 
the requirements of paragraph (e)(2) or (e)(3) of this section.
    (2) If you continuously or no less frequently than daily monitor the 
O2, CO2, and (if necessary) CO concentrations in 
the exhaust stack from the catalytic reforming unit catalyst regenerator 
prior to the combustion of other fossil fuels, you must calculate the 
CO2 emissions according to the requirements of paragraphs 
(c)(2)(i) through (c)(2)(iii) of this section.
    (3) Calculate CO2 emissions from the catalytic reforming 
unit catalyst regenerator using Equation Y-11 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.097

Where:

CO2 = Annual CO2 emissions (metric tons/year).
CBQ = Coke burn-off quantity per regeneration cycle or 
          measurement period from engineering estimates (kg coke/cycle 
          or kg coke/measurement period).
n = Number of regeneration cycles or measurement periods in the calendar 
          year.
CC = Carbon content of coke based on measurement or engineering estimate 
          (kg C per kg coke); default = 0.94.
44/12 = Ratio of molecular weight of CO2 to C (kg 
          CO2 per kg C).
0.001 = Conversion factor (metric ton/kg).

    (f) For on-site sulfur recovery plants and for sour gas sent off 
site for sulfur recovery, calculate and report CO2 process 
emissions from sulfur recovery plants according to the requirements in 
paragraphs (f)(1) through (f)(5) of this section, or, for non-Claus 
sulfur recovery plants, according to the requirements in paragraph (j) 
of this section regardless of the concentration of CO2 in the 
vented gas stream. Combustion emissions from the sulfur recovery plant 
(e.g., from fuel combustion in the Claus burner or the tail gas 
treatment incinerator) must be reported under subpart C of this part 
(General Stationary Fuel Combustion Sources). For the purposes of this 
subpart, the sour gas stream for which monitoring is required according 
to paragraphs (f)(2) through (f)(5) of this section is not considered a 
fuel.
    (1) If you operate and maintain a CEMS that measures CO2 
emissions according to subpart C of this part, you must calculate 
CO2 emissions under this subpart by following the Tier 4 
Calculation Methodology specified in Sec. 98.33(a)(4) and all 
associated requirements for Tier 4 in subpart C of this part (General 
Stationary Fuel Combustion Sources). You must monitor fuel use in the 
Claus burner, tail gas incinerator, or other combustion sources that 
discharge via the final exhaust stack from the sulfur recovery plant and 
calculate the combustion emissions from the fuel use according to 
subpart C of this part. Calculate the process emissions from the sulfur 
recovery plant as the difference in the CO2 CEMS emissions 
and the calculated combustion emissions associated with the sulfur 
recovery plant final exhaust stack. Other sulfur recovery plants must 
either install a CEMS

[[Page 926]]

that complies with the Tier 4 Calculation Methodology in subpart C, or 
follow the requirements of paragraphs (f)(2) through (f)(5) of this 
section, or (for non-Claus sulfur recovery plants only) follow the 
requirements in paragraph (j) of this section to determine 
CO2 emissions for the sulfur recovery plant.
    (2) Flow measurement. If you have a continuous flow monitor on the 
sour gas feed to the sulfur recovery plant or the sour gas feed sent for 
off-site sulfur recovery, you must use the measured flow rates when the 
monitor is operational to calculate the sour gas flow rate. If you do 
not have a continuous flow monitor on the sour gas feed to the sulfur 
recovery plant or the sour gas feed sent for off-site sulfur recovery, 
you must use engineering calculations, company records, or similar 
estimates of volumetric sour gas flow.
    (3) Carbon content. If you have a continuous gas composition monitor 
capable of measuring carbon content on the sour gas feed to the sulfur 
recovery plant or the sour gas feed sent for off-site for sulfur 
recovery, or if you monitor gas composition for carbon content on a 
routine basis, you must use the measured carbon content value. 
Alternatively, you may develop a site-specific carbon content factor 
using limited measurement data or engineering estimates or use the 
default factor of 0.20.
    (4) Calculate the CO2 emissions from each on-site sulfur 
recovery plant and for sour gas sent off-site for sulfur recovery using 
Equation Y-12 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.098

Where:

CO2 = Annual CO2 emissions (metric tons/year).
FSG = Volumetric flow rate of sour gas (including sour water 
          stripper gas) fed to the sulfur recovery plant or the sour gas 
          feed sent off-site for sulfur recovery (scf/year).
44 = Molecular weight of CO2 (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68  deg.F and 
          14.7 psia or 836.6 scf/kg-mole at 60  deg.F and 14.7 psia).
MFC = Mole fraction of carbon in the sour gas fed to the 
          sulfur recovery plant or the sour gas feed sent off-site for 
          sulfur recovery (kg-mole C/kg-mole gas); default = 0.20.
0.001 = Conversion factor, kg to metric tons.

    (5) If tail gas is recycled to the front of the sulfur recovery 
plant and the recycled flow rate and carbon content is included in the 
measured data under paragraphs (f)(2) and (f)(3) of this section, 
respectively, then the annual CO2 emissions calculated in 
paragraph (f)(4) of this section must be corrected to avoid double 
counting these emissions. You may use engineering estimates to perform 
this correction or assume that the corrected CO2 emissions 
are 95 percent of the uncorrected value calculated using Equation Y-12 
of this section.
    (g) For coke calcining units, calculate GHG emissions according to 
the applicable provisions in paragraphs (g)(1) through (g)(3) of this 
section.
    (1) If you operate and maintain a CEMS that measures CO2 
emissions according to subpart C of this part, you must calculate and 
report CO2 emissions under this subpart by following the Tier 
4 Calculation Methodology specified in Sec. 98.33(a)(4) and all 
associated requirements for Tier 4 in subpart C of this part (General 
Stationary Fuel Combustion Sources). You must monitor fuel use in the 
coke calcining unit that discharges via the final exhaust stack from the 
coke calcining unit and calculate the combustion emissions from the fuel 
use according to subpart C of this part. Calculate the process emissions 
from the coke calcining unit as the difference in the CO2 
CEMS emissions and the calculated combustion emissions associated with 
the coke calcining unit final exhaust stack. Other coke calcining units 
must either install a CEMS that complies

[[Page 927]]

with the Tier 4 Calculation Methodology in subpart C of this part, or 
follow the requirements of paragraph (g)(2) of this section.
    (2) Calculate the CO2 emissions from the coke calcining 
unit using Equation Y-13 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.099

Where:

CO2 = Annual CO2 emissions (metric tons/year).
Min = Annual mass of green coke fed to the coke calcining 
          unit from facility records (metric tons/year).
CCGC = Average mass fraction carbon content of green coke 
          from facility measurement data (metric ton carbon/metric ton 
          green coke).
Mout = Annual mass of marketable petroleum coke produced by 
          the coke calcining unit from facility records (metric tons 
          petroleum coke/year).
Mdust = Annual mass of petroleum coke dust removed from the 
          process through the dust collection system of the coke 
          calcining unit from facility records (metric ton petroleum 
          coke dust/year). For coke calcining units that recycle the 
          collected dust, the mass of coke dust removed from the process 
          is the mass of coke dust collected less the mass of coke dust 
          recycled to the process.
CCMPC = Average mass fraction carbon content of marketable 
          petroleum coke produced by the coke calcining unit from 
          facility measurement data (metric ton carbon/metric ton 
          petroleum coke).
44 = Molecular weight of CO2 (kg/kg-mole).
12 = Atomic weight of C (kg/kg-mole).

    (3) For all coke calcining units, use the CO2 emissions 
from the coke calcining unit calculated in paragraphs (g)(1) or (g)(2), 
as applicable, and calculate CH4 using the methods described 
in paragraph (c)(4) of this section and N2O emissions using 
the methods described in paragraph (c)(5) of this section.
    (h) For asphalt blowing operations, calculate CO2 and 
CH4 emissions according to the requirements in paragraph (j) 
of this section regardless of the CO2 and CH4 
concentrations or according to the applicable provisions in paragraphs 
(h)(1) and (h)(2) of this section.
    (1) For uncontrolled asphalt blowing operations or asphalt blowing 
operations controlled by vapor scrubbing, calculate CO2 and 
CH4 emissions using Equations Y-14 and Y-15 of this section, 
respectively.
[GRAPHIC] [TIFF OMITTED] TR30OC09.100

Where:

CO2 = Annual CO2 emissions from uncontrolled 
          asphalt blowing (metric tons CO2/year).
QAB = Quantity of asphalt blown (million barrels per year, 
          MMbbl/year).
EFAB,CO2 = Emission factor for CO2 from 
          uncontrolled asphalt blowing from facility-specific test data 
          (metric tons CO2/MMbbl asphalt blown); default = 
          1,100.
          [GRAPHIC] [TIFF OMITTED] TR30OC09.101
          
Where:

CH4 = Annual methane emissions from uncontrolled asphalt 
          blowing (metric tons CH4/year).
QAB = Quantity of asphalt blown (million barrels per year, 
          MMbbl/year).
EFAB,CH4 = Emission factor for CH4 from 
          uncontrolled asphalt blowing from facility-specific test data 
          (metric tons CH4/MMbbl asphalt blown); default = 
          580.

    (2) For asphalt blowing operations controlled by thermal oxidizer or 
flare, calculate CO2 using either Equation Y-16a or Equation 
Y-16b of this section and calculate CH4 emissions using 
Equation Y-17 of this section, provided these emissions are not already 
included in the flare emissions calculated in paragraph (b) of this 
section or in the stationary combustion unit emissions required under 
subpart C of this part (General Stationary Fuel Combustion Sources).

[[Page 928]]

[GRAPHIC] [TIFF OMITTED] TR17DE10.009

where:

CO2 = Annual CO2 emissions from controlled asphalt 
          blowing (metric tons CO2/year).
0.98 = Assumed combustion efficiency of thermal oxidizer or flare.
QAB = Quantity of asphalt blown (MMbbl/year).
CEFAB = Carbon emission factor from asphalt blowing from 
          facility-specific test data (metric tons C/MMbbl asphalt 
          blown); default = 2,750.
44 = Molecular weight of CO2 (kg/kg-mole).
12 = Atomic weight of C (kg/kg-mole).
[GRAPHIC] [TIFF OMITTED] TR17DE10.010

where:

CO2 = Annual CO2 emissions from controlled asphalt 
          blowing (metric tons CO2/year).
QAB = Quantity of asphalt blown (MMbbl/year).
0.98 = Assumed combustion efficiency of thermal oxidizer or flare.
EFAB,CO2 = Emission factor for CO2 from 
          uncontrolled asphalt blowing from facility-specific test data 
          (metric tons CO2/MMbbl asphalt blown); default = 
          1,100.
CEFAB = Carbon emission factor from asphalt blowing from 
          facility-specific test data (metric tons C/MMbbl asphalt 
          blown); default = 2,750.
44 = Molecular weight of CO2 (kg/kg-mole).
12 = Atomic weight of C (kg/kg-mole).
[GRAPHIC] [TIFF OMITTED] TR17DE10.011

where:

CH4 = Annual methane emissions from controlled asphalt 
          blowing (metric tons CH4/year).
0.02 = Fraction of methane uncombusted in thermal oxidizer or flare 
          based on assumed 98% combustion efficiency.
QAB = Quantity of asphalt blown (million barrels per year, 
          MMbbl/year).
EFAB,CH4 = Emission factor for CH4 from 
          uncontrolled asphalt blowing from facility-specific test data 
          (metric tons CH4/MMbbl asphalt blown); default = 
          580.

    (i) For delayed coking units, calculate the CH4 emissions 
from the depressurization of the coking unit vessel (i.e., the ``coke 
drum'') to atmosphere using either of the methods provided in paragraphs 
(i)(1) or (i)(2), provided no water or steam is added to the vessel once 
it is vented to the atmosphere. You must use the method in paragraph 
(i)(1) of this section if you add water or steam to the vessel after it 
is vented to the atmosphere.
    (1) Use the process vent method in paragraph (j) of this section to 
calculate the CH4 emissions from the depressurization of the 
coke drum or vessel regardless of the CH4 concentration and 
also calculate the CH4 emissions from the subsequent opening 
of the vessel for coke cutting operations using Equation Y-18 of this 
section. If you have coke drums or vessels of different dimensions, use 
the process vent method in paragraph (j) of this section and Equation Y-
18 for each set of coke drums or vessels of the same size and sum the 
resultant emissions across each set of coke drums or vessels to 
calculate the CH4 emissions for all delayed coking units.

[[Page 929]]

[GRAPHIC] [TIFF OMITTED] TR30OC09.104

Where:

CH4 = Annual methane emissions from the delayed coking unit 
          vessel opening (metric ton/year).
N = Cumulative number of vessel openings for all delayed coking unit 
          vessels of the same dimensions during the year.
H = Height of coking unit vessel (feet).
PCV = Gauge pressure of the coking vessel when opened to the 
          atmosphere prior to coke cutting or, if the alternative method 
          provided in paragraph (i)(2) of this section is used, gauge 
          pressure of the coking vessel when depressurization gases are 
          first routed to the atmosphere (pounds per square inch gauge, 
          psig).
14.7 = Assumed atmospheric pressure (pounds per square inch, psi).
fvoid = Volumetric void fraction of coking vessel prior to 
          steaming (cf gas/cf of vessel); default = 0.6.
D = Diameter of coking unit vessel (feet).
16 = Molecular weight of CH4 (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68  deg.F and 
          14.7 psia or 836.6 scf/kg-mole at 60  deg.F and 14.7 psia).
MFCH4 = Mole fraction of methane in coking vessel gas (kg-
          mole CH4/kg-mole gas, wet basis); default value is 
          0.01.
0.001 = Conversion factor (metric ton/kg).

    (2) Calculate the CH4 emissions from the depressurization 
vent and subsequent opening of the vessel for coke cutting operations 
using Equation Y-18 of this section and the pressure of the coking 
vessel when the depressurization gases are first routed to the 
atmosphere. If you have coke drums or vessels of different dimensions, 
use Equation Y-18 for each set of coke drums or vessels of the same size 
and sum the resultant emissions across each set of coke drums or vessels 
to calculate the CH4 emissions for all delayed coking units.
    (j) For each process vent not covered in paragraphs (a) through (i) 
of this section that can reasonably be expected to contain greater than 
2 percent by volume CO2 or greater than 0.5 percent by volume 
of CH4 or greater than 0.01 percent by volume (100 parts per 
million) of N2O, calculate GHG emissions using Equation Y-19 
of this section. You must also use Equation Y-19 of this section to 
calculate CH4 emissions for catalytic reforming unit 
depressurization and purge vents when methane is used as the purge gas, 
CH4 emissions if you elected to use the method in paragraph 
(i)(1) of this section, and CO2 and/or CH4 
emissions, as applicable, if you elected this method as an alternative 
to the methods in paragraphs (f), (h), or (k) of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.105

Where:

EX = Annual emissions of each GHG from process vent (metric 
          ton/yr).
N = Number of venting events per year.
P = Index of venting events.
(VR)p = Average volumetric flow rate of process gas during 
          the event (scf per hour) from measurement data, process 
          knowledge, or engineering estimates.
(MFX)p = Mole fraction of GHG x in process vent 
          during the event (kg-mol of GHG x/kg-mol vent gas) from 
          measurement data, process knowledge, or engineering estimates.
MWX = Molecular weight of GHG x (kg/kg-mole); use 44 for 
          CO2 or N2O and 16 for CH4.
MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68  deg.F and 
          14.7 psia or 836.6 scf/kg-mole at 60  deg.F and 14.7 psia).
(VT)p = Venting time for the event, (hours).
0.001 = Conversion factor (metric ton/kg).

    (k) For uncontrolled blowdown systems, you must calculate 
CH4 emissions either using the methods for process vents in 
paragraph (j) of this

[[Page 930]]

section regardless of the CH4 concentration or using Equation 
Y-20 of this section. Blowdown systems where the uncondensed gas stream 
is routed to a flare or similar control device are considered to be 
controlled and are not required to estimate emissions under this 
paragraph (k).
[GRAPHIC] [TIFF OMITTED] TR30OC09.106

Where:

CH4 = Methane emission rate from blowdown systems (mt 
          CH4/year).
QRef = Quantity of crude oil plus the quantity of 
          intermediate products received from off site that are 
          processed at the facility (MMbbl/year).
EFBD = Methane emission factor for uncontrolled blown systems 
          (scf CH4/MMbbl); default is 137,000.
16 = Molecular weight of CH4 (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68  deg.F and 
          14.7 psia or 836.6 scf/kg-mole at 60  deg.F and 14.7 psia).
0.001 = Conversion factor (metric ton/kg).

    (l) For equipment leaks, calculate CH4 emissions using 
the method specified in either paragraph (l)(1) or (l)(2) of this 
section.
    (1) Use process-specific methane composition data (from measurement 
data or process knowledge) and any of the emission estimation procedures 
provided in the Protocol for Equipment Leak Emissions Estimates (EPA-
453/R-95-017, NTIS PB96-175401).
    (2) Use Equation Y-21 of this section.
    [GRAPHIC] [TIFF OMITTED] TR30OC09.107
    
Where:

CH4 = Annual methane emissions from equipment leaks (metric 
          tons/year).
NCD = Number of atmospheric crude oil distillation columns at 
          the facility.
NPU1 = Cumulative number of catalytic cracking units, coking 
          units (delayed or fluid), hydrocracking, and full-range 
          distillation columns (including depropanizer and debutanizer 
          distillation columns) at the facility.
NPU2 = Cumulative number of hydrotreating/hydrorefining 
          units, catalytic reforming units, and visbreaking units at the 
          facility.
NH2 = Total number of hydrogen plants at the facility.
NFGS = Total number of fuel gas systems at the facility.

    (m) For storage tanks, except as provided in paragraph (m)(3) of 
this section, calculate CH4 emissions using the applicable 
methods in paragraphs (m)(1) and (2) of this section.
    (1) For storage tanks other than those processing unstabilized crude 
oil, you must either calculate CH4 emissions from storage 
tanks that have a vapor-phase methane concentration of 0.5 volume 
percent or more using tank-specific methane composition data (from 
measurement data or product knowledge) and the emission estimation 
methods provided in AP 42, Section 7.1 (incorporated by reference, see 
Sec. 98.7) or estimate CH4 emissions from storage tanks 
using Equation Y-22 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.108

Where:

CH4 = Annual methane emissions from storage tanks (metric 
          tons/year).
0.1 = Default emission factor for storage tanks (metric ton 
          CH4/MMbbl).
QRef = Quantity of crude oil plus the quantity of 
          intermediate products received from off site that are 
          processed at the facility (MMbbl/year).

    (2) For storage tanks that process unstabilized crude oil, calculate 
CH4 emissions from the storage of unstabilized crude oil 
using either tank-specific methane composition

[[Page 931]]

data (from measurement data or product knowledge) and direct measurement 
of the gas generation rate or by using Equation Y-23 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.109

Where:

CH4 = Annual methane emissions from storage tanks (metric 
          tons/year).
Qun = Quantity of unstabilized crude oil received at the 
          facility (MMbbl/year).
FP = Pressure differential from the previous storage pressure to 
          atmospheric pressure (pounds per square inch, psi).
MFCH4 = Average mole fraction of CH4 in vent gas 
          from the unstabilized crude oil storage tanks from facility 
          measurements (kg-mole CH4/kg-mole gas); use 0.27 as 
          a default if measurement data are not available.
995,000 = Correlation Equation factor (scf gas per MMbbl per psi).
16 = Molecular weight of CH4 (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68  deg.F and 
          14.7 psia or 836.6 scf/kg-mole at 60  deg.F and 14.7 psia).
0.001 = Conversion factor (metric ton/kg).

    (3) You do not need to calculate CH4 emissions from 
storage tanks that meet any of the following descriptions:
    (i) Units permanently attached to conveyances such as trucks, 
trailers, rail cars, barges, or ships;
    (ii) Pressure vessels designed to operate in excess of 204.9 
kilopascals and without emissions to the atmosphere;
    (iii) Bottoms receivers or sumps;
    (iv) Vessels storing wastewater; or
    (v) Reactor vessels associated with a manufacturing process unit.
    (n) For crude oil, intermediate, or product loading operations for 
which the vapor-phase concentration of methane is 0.5 volume percent or 
more, calculate CH4 emissions from loading operations using 
vapor-phase methane composition data (from measurement data or process 
knowledge) and the emission estimation procedures provided in AP 42, 
Section 5.2 (incorporated by reference, see Sec. 98.7). For loading 
operations in which the vapor-phase concentration of methane is less 
than 0.5 volume percent, you may assume zero methane emissions.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79160, Dec. 17, 2010; 
78 FR 71963, Nov. 29, 2013]



Sec. 98.254  Monitoring and QA/QC requirements.

    (a) Fuel flow meters, gas composition monitors, and heating value 
monitors that are associated with sources that use a CEMS to measure 
CO2 emissions according to subpart C of this part or that are 
associated with stationary combustion sources must meet the applicable 
monitoring and QA/QC requirements in Sec. 98.34.
    (b) All gas flow meters, gas composition monitors, and heating value 
monitors that are used to provide data for the GHG emissions 
calculations in this subpart for sources other than those subject to the 
requirements in paragraph (a) of this section shall be calibrated 
according to the procedures specified by the manufacturer, or according 
to the procedures in the applicable methods specified in paragraphs (c) 
through (g) of this section. In the case of gas flow meters, all gas 
flow meters must meet the calibration accuracy requirements in Sec. 
98.3(i). All gas flow meters, gas composition monitors, and heating 
value monitors must be recalibrated at the applicable frequency 
specified in paragraph (b)(1) or (b)(2) of this section.
    (1) You must recalibrate each gas flow meter according to one of the 
following frequencies. You may recalibrate at the minimum frequency 
specified by the manufacturer, biennially (every two years), or at the 
interval specified by the industry consensus standard practice used.
    (2) You must recalibrate each gas composition monitor and heating 
value

[[Page 932]]

monitor according to one of the following frequencies. You may 
recalibrate at the minimum frequency specified by the manufacturer, 
annually, or at the interval specified by the industry standard practice 
used.
    (c) For flare or sour gas flow meters and gas flow meters used to 
comply with the requirements in Sec. 98.253(j), operate, calibrate, and 
maintain the flow meter according to one of the following. You may use 
the procedures specified by the flow meter manufacturer, or a method 
published by a consensus-based standards organization. Consensus-based 
standards organizations include, but are not limited to, the following: 
ASTM International (100 Barr Harbor Drive, P.O. Box CB700, West 
Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373, http://
www.astm.org), the American National Standards Institute (ANSI, 1819 L 
Street, NW., 6th floor, Washington, DC 20036, (202) 293-8020, http://
www.ansi.org), the American Gas Association (AGA, 400 North Capitol 
Street, NW., 4th Floor, Washington, DC 20001, (202) 824-7000, http://
www.aga.org), the American Society of Mechanical Engineers (ASME, Three 
Park Avenue, New York, NY 10016-5990, (800) 843-2763, http://
www.asme.org), the American Petroleum Institute (API, 1220 L Street, 
NW., Washington, DC 20005-4070, (202) 682-8000, http://www.api.org), and 
the North American Energy Standards Board (NAESB, 801 Travis Street, 
Suite 1675, Houston, TX 77002, (713) 356-0060, http://www.api.org).
    (d) Except as provided in paragraph (g) of this section, determine 
gas composition and, if required, average molecular weight of the gas 
using any of the following methods. Alternatively, the results of 
chromatographic analysis of the fuel may be used, provided that the gas 
chromatograph is operated, maintained, and calibrated according to the 
manufacturer's instructions; and the methods used for operation, 
maintenance, and calibration of the gas chromatograph are documented in 
the written Monitoring Plan for the unit under Sec. 98.3(g)(5).
    (1) Method 18 at 40 CFR part 60, appendix A-6.
    (2) ASTM D1945-03 Standard Test Method for Analysis of Natural Gas 
by Gas Chromatography (incorporated by reference, see Sec. 98.7).
    (3) ASTM D1946-90 (Reapproved 2006) Standard Practice for Analysis 
of Reformed Gas by Gas Chromatography (incorporated by reference, see 
Sec. 98.7).
    (4) GPA 2261-00 Analysis for Natural Gas and Similar Gaseous 
Mixtures by Gas Chromatography (incorporated by reference, see Sec. 
98.7).
    (5) UOP539-97 Refinery Gas Analysis by Gas Chromatography 
(incorporated by reference, see Sec. 98.7).
    (6) ASTM D2503-92 (Reapproved 2007) Standard Test Method for 
Relative Molecular Mass (Molecular Weight) of Hydrocarbons by 
Thermoelectric Measurement of Vapor Pressure (incorporated by reference, 
see Sec. 98.7).
    (e) Determine flare gas higher heating value using any of the 
following methods. Alternatively, the results of chromatographic 
analysis of the fuel may be used, provided that the gas chromatograph is 
operated, maintained, and calibrated according to the manufacturer's 
instructions; and the methods used for operation, maintenance, and 
calibration of the gas chromatograph are documented in the written 
Monitoring Plan for the unit under Sec. 98.3(g)(5).
    (1) ASTM D4809-06 Standard Test Method for Heat of Combustion of 
Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method) 
(incorporated by reference, see Sec. 98.7).
    (2) ASTM D240-02 (Reapproved 2007) Standard Test Method for Heat of 
Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter (incorporated 
by reference, see Sec. 98.7).
    (3) ASTM D1826-94 (Reapproved 2003) Standard Test Method for 
Calorific (Heating) Value of Gases in Natural Gas Range by Continuous 
Recording Calorimeter (incorporated by reference, see Sec. 98.7).
    (4) ASTM D3588-98 (Reapproved 2003) Standard Practice for 
Calculating Heat Value, Compressibility Factor, and Relative Density of 
Gaseous Fuels (incorporated by reference, see Sec. 98.7).
    (5) ASTM D4891-89 (Reapproved 2006) Standard Test Method for Heating 
Value of Gases in Natural Gas Range by Stoichiometric Combustion 
(incorporated by reference, see Sec. 98.7).

[[Page 933]]

    (f) For gas flow meters used to comply with the requirements in 
Sec. 98.253(c)(2)(ii), install, operate, calibrate, and maintain each 
gas flow meter according to the requirements in 40 CFR 63.1572(c) and 
the following requirements.
    (1) Locate the flow monitor at a site that provides representative 
flow rates. Avoid locations where there is swirling flow or abnormal 
velocity distributions due to upstream and downstream disturbances.
    (2) [Reserved]
    (3) Use a continuous monitoring system capable of correcting for the 
temperature, pressure, and moisture content to output flow in dry 
standard cubic feet (standard conditions as defined in Sec. 98.6).
    (g) For exhaust gas CO2/CO/O2 composition 
monitors used to comply with the requirements in Sec. 98.253(c)(2), 
install, operate, calibrate, and maintain exhaust gas composition 
monitors according to the requirements in 40 CFR 60.105a(b)(2) or 40 CFR 
63.1572(c) or according to the manufacturer's specifications and 
requirements.
    (h) Determine the mass of petroleum coke as required by Equation Y-
13 of this subpart using mass measurement equipment meeting the 
requirements for commercial weighing equipment as described in 
Specifications, Tolerances, and Other Technical Requirements For 
Weighing and Measuring Devices, NIST Handbook 44 (2009) (incorporated by 
reference, see Sec. 98.7). Calibrate the measurement device according 
to the procedures specified by NIST handbook 44 (incorporated by 
reference, see Sec. 98.7) or the procedures specified by the 
manufacturer. Recalibrate either biennially or at the minimum frequency 
specified by the manufacturer.
    (i) Determine the carbon content of petroleum coke as required by 
Equation Y-13 of this subpart using any one of the following methods. 
Calibrate the measurement device according to procedures specified by 
the method or procedures specified by the measurement device 
manufacturer.
    (1) ASTM D3176-89 (Reapproved 2002) Standard Practice for Ultimate 
Analysis of Coal and Coke (incorporated by reference, see Sec. 98.7).
    (2) ASTM D5291-02 (Reapproved 2007) Standard Test Methods for 
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in 
Petroleum Products and Lubricants (incorporated by reference, see Sec. 
98.7).
    (3) ASTM D5373-08 Standard Test Methods for Instrumental 
Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of 
Coal (incorporated by reference, see Sec. 98.7).
    (j) Determine the quantity of petroleum process streams using 
company records. These quantities include the quantity of asphalt blown, 
quantity of crude oil plus the quantity of intermediate products 
received from off site, and the quantity of unstabilized crude oil 
received at the facility.
    (k) The owner or operator shall document the procedures used to 
ensure the accuracy of the estimates of fuel usage, gas composition, and 
heating value including but not limited to calibration of weighing 
equipment, fuel flow meters, and other measurement devices. The 
estimated accuracy of measurements made with these devices shall also be 
recorded, and the technical basis for these estimates shall be provided.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79163, Dec. 17, 2010]



Sec. 98.255  Procedures for estimating missing data.

    A complete record of all measured parameters used in the GHG 
emissions calculations is required (e.g., concentrations, flow rates, 
fuel heating values, carbon content values). Therefore, whenever a 
quality-assured value of a required parameter is unavailable (e.g., if a 
CEMS malfunctions during unit operation or if a required fuel sample is 
not taken), a substitute data value for the missing parameter shall be 
used in the calculations.
    (a) For stationary combustion sources, use the missing data 
procedures in subpart C of this part.
    (b) For each missing value of the heat content, carbon content, or 
molecular weight of the fuel, substitute the arithmetic average of the 
quality-assured values of that parameter immediately preceding and 
immediately following the missing data incident. If the ``after'' value 
is not obtained by

[[Page 934]]

the end of the reporting year, you may use the ``before'' value for the 
missing data substitution. If, for a particular parameter, no quality-
assured data are available prior to the missing data incident, the 
substitute data value shall be the first quality-assured value obtained 
after the missing data period.
    (c) For missing CO2, CO, O2, CH4, 
or N2O concentrations, gas flow rate, and percent moisture, 
the substitute data values shall be the best available estimate(s) of 
the parameter(s), based on all available process data (e.g., processing 
rates, operating hours, etc.). The owner or operator shall document and 
keep records of the procedures used for all such estimates.
    (d) For hydrogen plants, use the missing data procedures in subpart 
P of this part.



Sec. 98.256  Data reporting requirements.

    In addition to the reporting requirements of Sec. 98.3(c), you must 
report the information specified in paragraphs (a) through (q) of this 
section.
    (a) For combustion sources, follow the data reporting requirements 
under subpart C of this part (General Stationary Fuel Combustion 
Sources).
    (b) For hydrogen plants, follow the data reporting requirements 
under subpart P of this part (Hydrogen Production).
    (c)-(d) [Reserved]
    (e) For flares, owners and operators shall report:
    (1) The flare ID number (if applicable).
    (2) A description of the type of flare (steam assisted, air-
assisted).
    (3) A description of the flare service (general facility flare, unit 
flare, emergency only or back-up flare).
    (4) The calculated CO2, CH4, and 
N2O annual emissions for each flare, expressed in metric tons 
of each pollutant emitted.
    (5) A description of the method used to calculate the CO2 
emissions for each flare (e.g., reference section and equation number).
    (6) If you use Equation Y-1a of Sec. 98.253, an indication of 
whether daily or weekly measurement periods are used, the annual volume 
of flare gas combusted (in scf/year) and the annual average molecular 
weight (in kg/kg-mole), and annual average carbon content of the flare 
gas (in kg carbon per kg flare gas).
    (7) If you use Equation Y-1b of Sec. 98.253, an indication of 
whether daily or weekly measurement periods are used, the annual volume 
of flare gas combusted (in scf/year), the annual average CO2 
concentration (volume or mole percent), the number of carbon containing 
compounds other than CO2 in the flare gas stream, and for 
each of the carbon containing compounds other than CO2 in the 
flare gas stream:
    (i) The annual average concentration of the compound (volume or mole 
percent).
    (ii) [Reserved]
    (8) If you use Equation Y-2 of this subpart, an indication of 
whether daily or weekly measurement periods are used, the annual volume 
of flare gas combusted (in million (MM) scf/year), the annual average 
higher heating value of the flare gas (in mmBtu/mmscf), and an 
indication of whether the annual volume of flare gas combusted and the 
annual average higher heating value of the flare gas were determined 
using standard conditions of 68  deg.F and 14.7 psia or 60  deg.F and 
14.7 psia.
    (9) If you use Equation Y-3 of Sec. 98.253, the number of SSM 
events exceeding 500,000 scf/day.
    (10) The basis for the value of the fraction of carbon in the flare 
gas contributed by methane used in Equation Y-4 of Sec. 98.253.
    (f) For catalytic cracking units, traditional fluid coking units, 
and catalytic reforming units, owners and operators shall report:
    (1) The unit ID number (if applicable).
    (2) A description of the type of unit (fluid catalytic cracking 
unit, thermal catalytic cracking unit, traditional fluid coking unit, or 
catalytic reforming unit).
    (3) Maximum rated throughput of the unit, in bbl/stream day.
    (4) The calculated CO2, CH4, and 
N2O annual emissions for each unit, expressed in metric tons 
of each pollutant emitted.
    (5) A description of the method used to calculate the CO2 
emissions for each unit (e.g., reference section and equation number).

[[Page 935]]

    (6) If you use a CEMS, the relevant information required under Sec. 
98.36 for the Tier 4 Calculation Methodology, the CO2 annual 
emissions as measured by the CEMS (unadjusted to remove CO2 
combustion emissions associated with additional units, if present) and 
the process CO2 emissions as calculated according to Sec. 
98.253(c)(1)(ii). Report the CO2 annual emissions associated 
with sources other than those from the coke burn-off in accordance with 
the applicable subpart (e.g., subpart C of this part in the case of a CO 
boiler).
    (7) If you use Equation Y-6 of Sec. 98.253, the annual average 
exhaust gas flow rate, %CO2, and %CO.
    (8) If you use Equation Y-7a of this subpart, the annual average 
flow rate of inlet air and oxygen-enriched air, %O2, 
%Ooxy, %CO2, and %CO.
    (9) If you use Equation Y-7b of this subpart, the annual average 
flow rate of inlet air and oxygen-enriched air, %N2,oxy, and 
%N2,exhaust.
    (10) If you use Equation Y-8 of Sec. 98.253, the basis for the 
value of the average carbon content of coke.
    (11) Indicate whether you use a measured value, a unit-specific 
emission factor, or a default for CH4 emissions. If you use a 
unit-specific emission factor for CH4, report the basis for 
the factor.
    (12) Indicate whether you use a measured value, a unit-specific 
emission factor, or a default emission factor for N2O 
emissions. If you use a unit-specific emission factor for 
N2O, report the basis for the factor.
    (13) If you use Equation Y-11 of Sec. 98.253, the number of 
regeneration cycles or measurement periods during the reporting year and 
the average coke burn-off quantity per cycle or measurement period.
    (g) For fluid coking unit of the flexicoking type, the owner or 
operator shall report:
    (1) The unit ID number (if applicable).
    (2) A description of the type of unit.
    (3) Maximum rated throughput of the unit, in bbl/stream day.
    (4) Indicate whether the GHG emissions from the low heat value gas 
are accounted for in subpart C of this part or Sec. 98.253(c).
    (5) If the GHG emissions for the low heat value gas are calculated 
at the flexicoking unit, also report the calculated annual 
CO2, CH4, and N2O emissions for each 
unit, expressed in metric tons of each pollutant emitted, and the 
applicable equation input parameters specified in paragraphs (f)(7) 
through (f)(13) of this section.
    (h) For on-site sulfur recovery plants and for emissions from sour 
gas sent off-site for sulfur recovery, the owner and operator shall 
report:
    (1) The plant ID number (if applicable).
    (2) For each on-site sulfur recovery plant, the maximum rated 
throughput (metric tons sulfur produced/stream day), a description of 
the type of sulfur recovery plant, and an indication of the method used 
to calculate CO2 annual emissions for the sulfur recovery 
plant (e.g., CO2 CEMS, Equation Y-12, or process vent method 
in Sec. 98.253(j)).
    (3) The calculated CO2 annual emissions for each on-site 
sulfur recovery plant, expressed in metric tons. The calculated annual 
CO2 emissions from sour gas sent off-site for sulfur 
recovery, expressed in metric tons.
    (4) [Reserved]
    (5) If you recycle tail gas to the front of the sulfur recovery 
plant, indicate whether the recycled flow rate and carbon content are 
included in the measured data under Sec. 98.253(f)(2) and (3). Indicate 
whether a correction for CO2 emissions in the tail gas was 
used in Equation Y-12 of Sec. 98.253. If so, then report:
    (i) Indicate whether you used the default (95 percent) or a unit 
specific correction, and if a unit-specific correction was used, report 
the value of the correction and the approach used.
    (ii) If the following data are not used to calculate the recycling 
correction factor, report the information specified in paragraphs 
(h)(5)(ii)(A) through (B) of this section.
    (A) The annual volume of recycled tail gas (in scf/year) only.
    (B) The annual average mole fraction of carbon in the tail gas (in 
kg-mole C/kg-mole gas).
    (6) If you use a CEMS, the relevant information required under Sec. 
98.36 for the Tier 4 Calculation Methodology, the CO2 annual 
emissions as measured

[[Page 936]]

by the CEMS and the annual process CO2 emissions calculated 
according to Sec. 98.253(f)(1). Report the CO2 annual 
emissions associated with fuel combustion in accordance with subpart C 
of this part (General Stationary Fuel Combustion Sources).
    (7) If you use the process vent method in Sec. 98.253(j) for a non-
Claus sulfur recovery plant, the relevant information required under 
paragraph (l)(5) of this section.
    (i) For coke calcining units, the owner and operator shall report:
    (1) The unit ID number (if applicable).
    (2) Maximum rated throughput of the unit, in metric tons coke 
calcined/stream day.
    (3) The calculated CO2, CH4, and 
N2O annual emissions for each unit, expressed in metric tons 
of each pollutant emitted.
    (4) A description of the method used to calculate the CO2 
emissions for each unit (e.g., reference section and equation number).
    (5) If you use Equation Y-13 of Sec. 98.253, an indication of 
whether coke dust is recycled to the unit (e.g., all dust is recycled, a 
portion of the dust is recycled, or none of the dust is recycled).
    (6) If you use a CEMS, the relevant information required under Sec. 
98.36 for the Tier 4 Calculation Methodology, the CO2 annual 
emissions as measured by the CEMS and the annual process CO2 
emissions calculated according to Sec. 98.253(g)(1).
    (7) Indicate whether you use a measured value, a unit-specific 
emission factor or a default emission factor for CH4 
emissions. If you use a unit-specific emission factor for 
CH4, report the basis for the factor.
    (8) Indicate whether you use a measured value, a unit-specific 
emission factor, or a default emission factor for N2O 
emissions. If you use a unit-specific emission factor for 
N2O, report the basis for the factor.
    (j) For asphalt blowing operations, the owner or operator shall 
report:
    (1) The unit ID number (if applicable).
    (2) [Reserved]
    (3) The type of control device used to reduce methane (and other 
organic) emissions from the unit.
    (4) The calculated annual CO2 and CH4 
emissions for each unit, expressed in metric tons of each pollutant 
emitted.
    (5) If you use Equation Y-14 of Sec. 98.253, the basis for the 
CO2 emission factor used.
    (6) If you use Equation Y-15 of Sec. 98.253, the basis for the 
CH4 emission factor used.
    (7) If you use Equation Y-16a of Sec. 98.253, the basis for the 
carbon emission factor used.
    (8) If you use Equation Y-16b of Sec. 98.253, the basis for the 
CO2 emission factor used and the basis for the carbon 
emission factor used.
    (9) If you use Equation Y-17 of Sec. 98.253, the basis for the 
CH4 emission factor used.
    (10) If you use Equation Y-19 of this subpart, the relevant 
information required under paragraph (l)(5) of this section.
    (k) For delayed coking units, the owner or operator shall report:
    (1) The cumulative annual CH4 emissions (in metric tons 
of CH4) for all delayed coking units at the facility.
    (2) A description of the method used to calculate the CH4 
emissions for each unit (e.g., reference section and equation number).
    (3) The total number of delayed coking units at the facility; the 
total number of delayed coking drums at the facility; and, for each coke 
drum or vessel, the typical drum outage (i.e. the unfilled distance from 
the top of the drum, in feet).
    (4) For each set of coking drums that are the same dimensions, the 
number of coking drums in the set, and the mole fraction of methane in 
coking gas (in kg-mole CH4/kg-mole gas, wet basis).
    (5) The basis for the volumetric void fraction of the coke vessel 
prior to steaming and the basis for the mole fraction of methane in the 
coking gas.
    (6) If you use Equation Y-19 of this subpart, the relevant 
information required under paragraph (l)(5) of this section for each set 
of coke drums or vessels of the same size.

[[Page 937]]

    (l) For each process vent subject to Sec. 98.253(j), the owner or 
operator shall report:
    (1) The vent ID number (if applicable).
    (2) The unit or operation associated with the emissions.
    (3) The type of control device used to reduce methane (and other 
organic) emissions from the unit, if applicable.
    (4) The calculated annual CO2, CH4, and 
N2O emissions for each vent, expressed in metric tons of each 
pollutant emitted.
    (5) The annual volumetric flow discharged to the atmosphere (in 
scf), and an indication of the measurement or estimation method, annual 
average mole fraction of each GHG above the concentration threshold or 
otherwise required to be reported and an indication of the measurement 
or estimation method, and for intermittent vents, the number of venting 
events and the cumulative venting time.
    (m) For uncontrolled blowdown systems, the owner or operator shall 
report:
    (1) An indication of whether the uncontrolled blowdown emission are 
reported under Sec. 98.253(k) or Sec. 98.253(j) or a statement that 
the facility does not have any uncontrolled blowdown systems.
    (2) The cumulative annual CH4 emissions (in metric tons 
of CH4) for uncontrolled blowdown systems.
    (3) For uncontrolled blowdown systems reporting under Sec. 
98.253(k), the basis for the value of the methane emission factor used 
for uncontrolled blowdown systems.
    (4) For uncontrolled blowdown systems reporting under Sec. 
98.253(j), the relevant information required under paragraph (l)(5) of 
this section.
    (n) For equipment leaks, the owner or operator shall report:
    (1) The cumulative CH4 emissions (in metric tons of each 
pollutant emitted) for all equipment leak sources.
    (2) The method used to calculate the reported equipment leak 
emissions.
    (3) The number of each type of emission source listed in Equation Y-
21 of this subpart at the facility.
    (o) For storage tanks, the owner or operator shall report:
    (1) The cumulative annual CH4 emissions (in metric tons 
of CH4) for all storage tanks, except for those used to 
process unstabilized crude oil.
    (2) For storage tanks other than those processing unstabilized crude 
oil:
    (i) The method used to calculate the reported storage tank emissions 
for storage tanks other than those processing unstabilized crude (i.e., 
either AP 42, Section 7.1 (incorporated by reference, see Sec. 98.7), 
or Equation Y-22 of this section).
    (ii) [Reserved]
    (3) The cumulative CH4 emissions (in metric tons of 
CH4) for storage tanks used to process unstabilized crude oil 
or a statement that the facility did not receive any unstabilized crude 
oil during the reporting year.
    (4) For storage tanks that process unstabilized crude oil:
    (i) The method used to calculate the reported unstabilized crude oil 
storage tank emissions.
    (ii)-(iv) [Reserved]
    (v) The basis for the mole fraction of CH4 in vent gas 
from unstabilized crude oil storage tanks.
    (vi) If you did not use Equation Y-23, the tank-specific methane 
composition data and the annual gas generation volume (scf/yr) used to 
estimate the cumulative CH4 emissions for storage tanks used 
to process unstabilized crude oil.
    (5)-(7) [Reserved]
    (p) For loading operations, the owner or operator shall report:
    (1) The cumulative annual CH4 emissions (in metric tons 
of each pollutant emitted) for loading operations.
    (2) The types of materials loaded that have an equilibrium vapor-
phase concentration of methane of 0.5 volume percent or greater, and the 
type of vessel (barge, tanker, marine vessel, etc.) in which each type 
of material is loaded.
    (3) The type of control system used to reduce emissions from the 
loading of material with an equilibrium vapor-phase concentration of 
methane of 0.5 volume percent or greater, if any (submerged loading, 
vapor balancing, etc.).

[[Page 938]]

    (q) Name of each method listed in Sec. 98.254 or a description of 
manufacturer's recommended method used to determine a measured 
parameter.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79164, Dec. 17, 2010; 
78 FR 71963, Nov. 29, 2013; 79 FR 63795, Oct. 24, 2014]



Sec. 98.257  Records that must be retained.

    In addition to the records required by Sec. 98.3(g), you must 
retain the records specified in paragraphs (a) and (b) of this section.
    (a) The records of all parameters monitored under Sec. 98.255. If 
you comply with the combustion methodology in Sec. 98.252(a), then you 
must retain under this subpart the records required for the Tier 3 and/
or Tier 4 Calculation Methodologies in Sec. 98.37 and you must keep 
records of the annual average flow calculations.
    (b) Verification software records. You must keep a record of the 
file generated by the verification software specified in Sec. 98.5(b) 
for the applicable data specified in paragraphs (b)(1) through (67) of 
this section. Retention of this file satisfies the recordkeeping 
requirement for the data in paragraphs (b)(1) through (67) of this 
section.
    (1) Volume of flare gas combusted during measurement period (scf) 
(Equation Y-1b of Sec. 98.253).
    (2) Mole percent CO2 concentration in the flare gas 
stream during the measurement period (mole percent) (Equation Y-1b).
    (3) Mole percent concentration of compound ``x'' in the flare gas 
stream during the measurement period (mole percent) (Equation Y-1b).
    (4) Carbon mole number of compound ``x'' in the flare gas stream 
during the measurement period (mole carbon atoms per mole compound) 
(Equation Y-1b).
    (5) Molar volume conversion factor (scf per kg-mole) (Equation Y-
1b).
    (6) Annual volume of flare gas combusted for each flare during 
normal operations from company records (million (MM) standard cubic feet 
per year, MMscf/year) (Equation Y-3 of Sec. 98.253).
    (7) Higher heating value for fuel gas or flare gas for each flare 
from company records (British thermal units per scf, Btu/scf = MMBtu/
MMscf) (Equation Y-3).
    (8) Volume of flare gas combusted during indexed start-up, shutdown, 
or malfunction event from engineering calculations (scf) (Equation Y-3).
    (9) Average molecular weight of the flare gas, from the analysis 
results or engineering calculations for the event (kg/kg-mole) (Equation 
Y-3).
    (10) Molar volume conversion factor (scf per kg-mole) (Equation Y-
3).
    (11) Average carbon content of the flare gas, from analysis results 
or engineering calculations for the event (kg C per kg flare gas) 
(Equation Y-3).
    (12) Weight fraction of carbon in the flare gas prior to combustion 
in each flare that is contributed by methane from measurement values or 
engineering calculations (kg C in methane in flare gas/kg C in flare 
gas) (Equation Y-4 of Sec. 98.253).
    (13) Annual throughput of unit from company records for each 
catalytic cracking unit or fluid coking unit (barrels/year) (Equation Y-
8 of Sec. 98.253).
    (14) Coke burn-off factor from engineering calculations (default for 
catalytic cracking units = 7.3; default for fluid coking units = 11) (kg 
coke per barrel of feed) (Equation Y-8).
    (15) Carbon content of coke based on measurement or engineering 
estimate (kg C per kg coke) (Equation Y-8).
    (16) Value of unit-specific CH4 emission factor, 
including the units of measure, for each catalytic cracking unit, 
traditional fluid coking unit, catalytic reforming unit, and coke 
calcining unit (calculation method in Sec. 98.253(c)(4)).
    (17) Annual activity data (e.g., input or product rate), including 
the units of measure, in units of measure consistent with the emission 
factor, for each catalytic cracking unit, traditional fluid coking unit, 
catalytic reforming unit, and coke calcining unit (calculation method in 
Sec. 98.253(c)(4)).
    (18) Value of unit-specific N2O emission factor, 
including the units of measure, for each catalytic cracking unit, 
traditional fluid coking unit, catalytic reforming unit, and coke 
calcining unit (calculation method in Sec. 98.253(c)(5)).
    (19) Annual activity data (e.g., input or product rate), including 
the units of

[[Page 939]]

measure, in units of measure consistent with the emission factor, for 
each catalytic cracking unit, traditional fluid coking unit, catalytic 
reforming unit, and coke calcining unit (calculation method in Sec. 
98.253(c)(5)).
    (20) Carbon content of coke based on measurement or engineering 
estimate (default = 0.94) (kg C per kg coke) (Equation Y-11 of Sec. 
98.253).
    (21) Volumetric flow rate of sour gas (including sour water stripper 
gas) feed sent off site for sulfur recovery in the year (scf/year) 
(Equation Y-12 of Sec. 98.253).
    (22) Mole fraction of carbon in the sour gas feed sent off site for 
sulfur recovery (kg-mole C/kg-mole gas) (Equation Y-12).
    (23) Molar volume conversion factor for sour gas sent off site (scf 
per kg-mole) (Equation Y-12).
    (24) Volumetric flow rate of sour gas (including sour water stripper 
gas) fed to the onsite sulfur recovery plant (scf/year) (Equation Y-12).
    (25) Mole fraction of carbon in the sour gas fed to the onsite 
sulfur recovery plant (kg-mole C/kg-mole gas) (Equation Y-12).
    (26) Molar volume conversion factor for onsite sulfur recovery plant 
(scf per kg-mole) (Equation Y-12).
    (27) Annual mass of green coke fed to the coke calcining unit from 
facility records (metric tons/year) (Equation Y-13 of Sec. 98.253).
    (28) Annual mass of marketable petroleum coke produced by the coke 
calcining unit from facility records (metric tons/year) (Equation Y-13).
    (29) Annual mass of petroleum coke dust removed from the process 
through the dust collection system of the coke calcining unit from 
facility records. For coke calcining units that recycle the collected 
dust, the mass of coke dust removed from the process is the mass of coke 
dust collected less the mass of coke dust recycled to the process 
(metric tons/year) (Equation Y-13).
    (30) Average mass fraction carbon content of green coke from 
facility measurement data (metric tons C per metric ton green coke) 
(Equation Y-13).
    (31) Average mass fraction carbon content of marketable petroleum 
coke produced by the coke calcining unit from facility measurement data 
(metric tons C per metric ton petroleum coke (Equation Y-13).
    (32) Quantity of asphalt blown for each asphalt blowing unit 
(million barrels per year (MMbbl/year)) (Equation Y-14 of Sec. 98.253).
    (33) Emission factor for CO2 from uncontrolled asphalt 
blowing from facility-specific test data for each asphalt blowing unit 
(metric tons CO2/MMbbl asphalt blown) (Equation Y-14).
    (34) Emission factor for CH4 from uncontrolled asphalt 
blowing from facility-specific test data for each asphalt blowing unit 
(metric tons CH4/MMbbl asphalt blown) (Equation Y-15 of Sec. 
98.253).
    (35) Quantity of asphalt blown (million barrels/year (MMbbl/year)) 
(Equation Y-16a of Sec. 98.253).
    (36) Carbon emission factor from asphalt blowing from facility-
specific test data (metric tons C/MMbbl asphalt blown) (Equation Y-16a).
    (37) Quantity of asphalt blown for each asphalt blowing unit 
(million barrels per year (MMbbl/year)) (Equation Y-16b of Sec. 
98.253).
    (38) Emission factor for CO2 from uncontrolled asphalt 
blowing from facility-specific test data for each asphalt blowing unit 
(metric tons CO2/MMbbl asphalt blown) (Equation Y-16b).
    (39) Carbon emission factor from asphalt blowing from facility-
specific test data for each asphalt blowing unit (metric tons C/MMbbl 
asphalt blown) (Equation Y-16b).
    (40) Emission factor for CH4 from uncontrolled asphalt 
blowing from facility-specific test data for each asphalt blowing unit 
(metric tons CH4/MMbbl asphalt blown) (Equation Y-17 of Sec. 
98.253).
    (41) Cumulative number of vessel openings for all delayed coking 
unit vessels of the same dimensions during the year (Equation Y-18 of 
Sec. 98.253).
    (42) Height of coking unit vessel for each set of coke drums or 
vessels of the same size (feet) (Equation Y-18).
    (43) Gauge pressure of the coking vessel when opened to the 
atmosphere prior to coke cutting or, if the alternative method provided 
in Sec. 98.253(i)(2) is used, gauge pressure of the coking vessel when 
depressurization gases are first routed to the atmosphere for each

[[Page 940]]

set of coke drums or vessels of the same size (pounds per square inch 
gauge (psig)) (Equation Y-18).
    (44) Volumetric void fraction of coking vessel prior to steaming for 
each set of coke drums or vessels of the same size (cf gas/cf of vessel) 
(Equation Y-18).
    (45) Diameter of coking unit vessel for each set of coke drums or 
vessels of the same size (feet) (Equation Y-18).
    (46) Molar volume conversion factor for each set of coke drums or 
vessels of the same size (scf per kg-mole) (Equation Y-18).
    (47) Average volumetric flow rate of process gas during the event 
from measurement data, process knowledge, or engineering estimates for 
each set of coke drums or vessels of the same size (scf per hour) 
(Equation Y-19 of Sec. 98.253).
    (48) Mole fraction of methane in process vent during the event from 
measurement data, process knowledge, or engineering estimates for each 
set of coke drums or vessels of the same size (kg-mole CH4/
kg-mole gas) (Equation Y-19).
    (49) Venting time for the event for each set of coke drums or 
vessels of the same size (hours) (Equation Y-19).
    (50) Molar volume conversion factor for each set of coke drums or 
vessels of the same size (scf per kg-mole) (Equation Y-19).
    (51) Quantity of crude oil plus the quantity of intermediate 
products received from off site that are processed at the facility 
(MMbbl/year) (Equation Y-20 of Sec. 98.253).
    (52) Molar volume conversion factor (scf per kg-mole) (Equation Y-
20).
    (53) Methane emission factor for uncontrolled blown systems (scf 
CH4/MMbbl) (Equation Y-20).
    (54) Quantity of crude oil plus the quantity of intermediate 
products received from off site that are processed at the facility 
(MMbbl/year) (Equation Y-22 of Sec. 98.253).
    (55) Quantity of unstabilized crude oil received at the facility 
(MMbbl/year) (Equation Y-23 of Sec. 98.253).
    (56) Pressure differential from the previous storage pressure to 
atmospheric pressure (psi) (Equation Y-23).
    (57) Average mole fraction of CH4 in vent gas from the 
unstabilized crude oil storage tanks from facility measurements (kg-mole 
CH4/kg-mole gas) (Equation Y-23).
    (58) Molar volume conversion factor (scf per kg-mole) (Equation Y-
23).
    (59) Specify whether the calculated or default loading factor L 
specified in Sec. 98.253(n) is entered, for each liquid loaded to each 
(methods specified in Sec. 98.253(n)).
    (60) Saturation factor specified in Sec. 98.253(n), for each liquid 
loaded to each vessel (methods specified in Sec. 98.253(n)).
    (61) True vapor pressure of liquid loaded, for each liquid loaded to 
each vessel (psia) (methods specified in Sec. 98.253(n)).
    (62) Molecular weight of vapors (lb per lb-mole), for each liquid 
loaded to each vessel (methods specified in Sec. 98.253(n)).
    (63) Temperature of bulk liquid loaded, for each liquid loaded to 
each vessel ( deg.R, degrees Rankine) (methods specified in Sec. 
98.253(n)).
    (64) Total loading loss (without efficiency correction), for each 
liquid loaded to each vessel (pounds per 1000 gallons loaded) (methods 
specified in Sec. 98.253(n)).
    (65) Overall emission control system reduction efficiency, including 
the vapor collection system efficiency and the vapor recovery or 
destruction efficiency (enter zero if no emission controls), for each 
liquid loaded to each vessel (percent) (methods specified Sec. 
98.253(n)).
    (66) Vapor phase concentration of methane in liquid loaded, for each 
liquid loaded to each vessel (percent by volume) (methods specified in 
Sec. 98.253(n)).
    (67) Quantity of material loaded, for each liquid loaded to each 
vessel (thousand gallon per year) (methods specified in Sec. 
98.253(n)).

[79 FR 63796, Oct. 24, 2014]



Sec. 98.258  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.

[[Page 941]]



                  Subpart Z_Phosphoric Acid Production



Sec. 98.260  Definition of the source category.

    The phosphoric acid production source category consists of 
facilities with a wet-process phosphoric acid process line used to 
produce phosphoric acid. A wet-process phosphoric acid process line is 
the production unit or units identified by an individual identification 
number in an operating permit and/or any process unit or group of 
process units at a facility reacting phosphate rock from a common supply 
source with acid.



Sec. 98.261  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains a phosphoric acid production process and the facility meets the 
requirements of either Sec. 98.2(a)(1) or (a)(2).



Sec. 98.262  GHGs to report.

    (a) You must report CO2 process emissions from each wet-
process phosphoric acid process line.
    (b) You must report under subpart C of this part (General Stationary 
Fuel Combustion Sources) the emissions of CO2, 
CH4, and N2O from each stationary combustion unit 
following the requirements of subpart C of this part.



Sec. 98.263  Calculating GHG emissions.

    You must calculate and report the annual process CO2 
emissions from each wet-process phosphoric acid process line using the 
procedures in either paragraph (a) or (b) of this section.
    (a) Calculate and report under this subpart the process 
CO2 emissions by operating and maintaining a CEMS according 
to the Tier 4 Calculation Methodology specified in Sec. 98.33(a)(4) and 
all associated requirements for Tier 4 in subpart C of this part 
(General Stationary Fuel Combustion Sources).
    (b) Calculate and report under this subpart the process 
CO2 emissions using the procedures in paragraphs (b)(1) and 
(b)(2) of this section.
    (1) Calculate the annual CO2 mass emissions from each 
wet-process phosphoric acid process line using the methods in paragraphs 
(b)(1)(i) or (ii) of this section, as applicable.
    (i) If your process measurement provides the inorganic carbon 
content of phosphate rock as an output, calculate and report the process 
CO2 emissions from each wet-process phosphoric acid process 
line using Equation Z-1a of this section:
[GRAPHIC] [TIFF OMITTED] TR28OC10.031

where:

Em = Annual CO2 mass emissions from a wet-process 
          phosphoric acid process line m according to this Equation Z-1a 
          (metric tons).
ICn,i = Inorganic carbon content of a grab sample batch of 
          phosphate rock by origin i obtained during month n, from the 
          carbon analysis results (percent by weight, expressed as a 
          decimal fraction).
Pn,i = Mass of phosphate rock by origin i consumed in month n 
          by wet-process phosphoric acid process line m (tons).
z = Number of months during which the process line m operates.
b = Number of different types of phosphate rock in month, by origin. If 
          the grab sample is a composite sample of rock from more than 
          one origin, b = 1.
2000/2205 = Conversion factor to convert tons to metric tons.
44/12 = Ratio of molecular weights, CO2 to carbon.

    (ii) If your process measurement provides the CO2 content 
directly as an output, calculate and report the process CO2 
emissions from each wet-process phosphoric acid process line using 
Equation Z-1b of this section:

[[Page 942]]

[GRAPHIC] [TIFF OMITTED] TR28OC10.032

where:

Em = Annual CO2 mass emissions from a wet-process 
          phosphoric acid process line m according to this Equation Z-1b 
          (metric tons).
CO2n,i = Carbon dioxide content of a grab sample batch of 
          phosphate rock by origin i obtained during month n (percent by 
          weight, expressed as a decimal fraction).
Pn,i = Mass of phosphate rock by origin i consumed in month n 
          by wet-process phosphoric acid process line m (tons).
z = Number of months during which the process line m operates.
b = Number of different types of phosphate rock in month, by origin. If 
          the grab sample is a composite sample of rock from more than 
          one origin, b = 1.
2000/2205 = Conversion factor to convert tons to metric tons.
    (2) You must determine the total emissions from the facility using 
Equation Z-2 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.111

Where:

CO2 = Annual process CO2 emissions from phosphoric 
          acid production facility (metric tons/year).
Em = Annual process CO2 emissions from wet-process 
          phosphoric acid process line m (metric tons/year).
p = Number of wet-process phosphoric acid process lines.

    (c) If GHG emissions from a wet-process phosphoric acid process line 
are vented through the same stack as any combustion unit or process 
equipment that reports CO2 emissions using a CEMS that 
complies with the Tier 4 Calculation Methodology in subpart C of this 
part (General Stationary Fuel Combustion Sources), then the calculation 
methodology in paragraph (b) of this section shall not be used to 
calculate process emissions. The owner or operator shall report under 
this subpart the combined stack emissions according to the Tier 4 
Calculation Methodology in Sec. 98.33(a)(4) and all associated 
requirements for Tier 4 in subpart C of this part.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66468, Oct. 28, 2010; 
78 FR 71964, Nov. 29, 2013]



Sec. 98.264  Monitoring and QA/QC requirements.

    (a) You must obtain a monthly grab sample of phosphate rock directly 
from the rock being fed to the process line before it enters the mill 
using one of the following methods. You may conduct the representative 
bulk sampling using a method published by a consensus standards 
organization, or you may use industry consensus standard practice 
methods, including but not limited to the Phosphate Mining States 
Methods Used and Adopted by the Association of Fertilizer and Phosphate 
Chemists (AFPC). If phosphate rock is obtained from more than one origin 
in a month, you must obtain a sample from each origin of rock or obtain 
a composite representative sample.
    (b) You must determine the carbon dioxide or inorganic carbon 
content of each monthly grab sample of phosphate rock (consumed in the 
production of phosphoric acid). You may use a method published by a 
consensus standards organization, or you may use industry consensus 
standard practice methods, including but not limited to the Phosphate 
Mining States Methods Used and Adopted by AFPC.
    (c) You must determine the mass of phosphate rock consumed each 
month (by origin) in each wet-process phosphoric acid process line. You 
can use existing plant procedures that are used for accounting purposes 
(such as sales records) or you can use data from existing monitoring 
equipment that is used to measure total mass flow of phosphorous-bearing 
feed under 40 CFR part 60 or part 63.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66468, Oct. 28, 2010; 
78 FR 71964, Nov. 29, 2013]

[[Page 943]]



Sec. 98.265  Procedures for estimating missing data.

    A complete record of all measured parameters used in the GHG 
emissions calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable, a substitute data 
value for the missing parameter must be used in the calculations as 
specified in paragraphs (a) and (b) of this section.
    (a) For each missing value of the inorganic carbon content or 
CO2 content of phosphate rock (by origin), you must use the 
appropriate default factor provided in Table Z-1 of this subpart. 
Alternatively, you must determine a substitute data value by calculating 
the arithmetic average of the quality-assured values of inorganic carbon 
contents or CO2 contents of phosphate rock of origin i (see 
Equation Z-1a or Z-1b of this subpart) from samples immediately 
preceding and immediately following the missing data incident. If no 
quality-assured data on inorganic carbon contents or CO2 
contents of phosphate rock of origin i are available prior to the 
missing data incident, the substitute data value shall be the first 
quality-assured value for inorganic carbon contents or CO2 
contents for phosphate rock of origin i obtained after the missing data 
period.
    (b) For each missing value of monthly mass consumption of phosphate 
rock (by origin), you must use the best available estimate based on all 
available process data or data used for accounting purposes.

[78 FR 71964, Nov. 29, 2013]



Sec. 98.266  Data reporting requirements.

    In addition to the information required by Sec. 98.3(c), each 
annual report must contain the information specified in paragraphs (a) 
through (f) of this section.
    (a) Annual phosphoric acid production, by origin of the phosphate 
rock (tons).
    (b) Annual phosphoric acid production capacity (tons).
    (c) Annual arithmetic average percent inorganic carbon or carbon 
dioxide in phosphate rock from monthly records (percent by weight, 
expressed as a decimal fraction).
    (d) Annual phosphate rock consumption from monthly measurement 
records by origin (tons).
    (e) If you use a CEMS to measure CO2 emissions, then you 
must report the information in paragraphs (e)(1) and (e)(2) of this 
section.
    (1) The identification number of each wet-process phosphoric acid 
process line.
    (2) The annual CO2 emissions from each wet-process 
phosphoric acid process line (metric tons) and the relevant information 
required under 40 CFR 98.36 (e)(2)(vi) for the Tier 4 Calculation 
Methodology.
    (f) If you do not use a CEMS to measure emissions, then you must 
report the information in paragraphs (f)(1) through (9) of this section.
    (1) Identification number of each wet-process phosphoric acid 
process line.
    (2) Annual CO2 emissions from each wet-process phosphoric 
acid process line (metric tons) as calculated by either Equation Z-1a or 
Equation Z-1b of this subpart.
    (3) Annual phosphoric acid permitted production capacity (tons) for 
each wet-process phosphoric acid process line (metric tons).
    (4) Method used to estimate any missing values of inorganic carbon 
content or carbon dioxide content of phosphate rock for each wet-process 
phosphoric acid process line.
    (5) [Reserved]
    (6) [Reserved]
    (7) Number of wet-process phosphoric acid process lines.
    (8) Number of times missing data procedures were used to estimate 
phosphate rock consumption (months), inorganic carbon contents of the 
phosphate rock (months), and CO2 contents of the phosphate 
rock (months).
    (9) Annual process CO2 emissions from phosphoric acid 
production facility (metric tons).

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66469, Oct. 28, 2010; 
78 FR 71964, Nov. 29, 2013; 79 FR 63797, Oct. 24, 2014]



Sec. 98.267  Records that must be retained.

    In addition to the records required by Sec. 98.3(g), you must 
retain the records specified in paragraphs (a) through (d)

[[Page 944]]

of this section for each wet-process phosphoric acid production 
facility.
    (a) Monthly mass of phosphate rock consumed by origin (tons).
    (b) Records of all phosphate rock purchases and/or deliveries (if 
vertically integrated with a mine).
    (c) Documentation of the procedures used to ensure the accuracy of 
monthly phosphate rock consumption by origin.
    (d) Verification software records. You must keep a record of the 
file generated by the verification software specified in Sec. 98.5(b) 
for the applicable data specified in paragraphs (d)(1) through (4) of 
this section. Retention of this file satisfies the recordkeeping 
requirement for the data in paragraphs (d)(1) through (4) of this 
section.
    (1) Inorganic carbon content of a grab sample batch of phosphate 
rock by origin obtained during month by wet-process phosphoric acid 
process line, from the carbon analysis results (percent by weight, 
expressed as a decimal fraction) (Equation Z-1a of Sec. 98.263).
    (2) Mass of phosphate rock by origin consumed in month by wet-
process phosphoric acid process line (tons) (Equation Z-1a).
    (3) Carbon dioxide content of a grab sample batch of phosphate rock 
by origin obtained during month by wet-process phosphoric acid process 
line (percent by weight, expressed as a decimal fraction) (Equation Z-1b 
of Sec. 98.263).
    (4) Mass of phosphate rock by origin consumed in month by wet-
process phosphoric acid process line (tons) (Equation Z-1b).

[74 FR 56374, Oct. 30, 2009, as amended at 79 FR 63797, Oct. 24, 2014]



Sec. 98.268  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.

[74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71965, Nov. 29, 2013]



Sec. Table Z-1 to Subpart Z of Part 98--Default Chemical Composition of 
                        Phosphate Rock by Origin

------------------------------------------------------------------------
                                                                Total
                                                                carbon
                           Origin                            (percent by
                                                               weight)
------------------------------------------------------------------------
Central Florida............................................          1.6
North Florida..............................................         1.76
North Carolina (Calcined)..................................         0.76
Idaho (Calcined)...........................................         0.60
Morocco....................................................         1.56
------------------------------------------------------------------------



                 Subpart AA_Pulp and Paper Manufacturing



Sec. 98.270  Definition of source category.

    (a) The pulp and paper manufacturing source category consists of 
facilities that produce market pulp (i.e., stand-alone pulp facilities), 
manufacture pulp and paper (i.e., integrated facilities), produce paper 
products from purchased pulp, produce secondary fiber from recycled 
paper, convert paper into paperboard products (e.g., containers), or 
operate coating and laminating processes.
    (b) The emission units for which GHG emissions must be reported are 
listed in paragraphs (b)(1) through (b)(5) of this section:
    (1) Chemical recovery furnaces at kraft and soda mills (including 
recovery furnaces that burn spent pulping liquor produced by both the 
kraft and semichemical process).
    (2) Chemical recovery combustion units at sulfite facilities.
    (3) Chemical recovery combustion units at stand-alone semichemical 
facilities.
    (4) Pulp mill lime kilns at kraft and soda facilities.
    (5) Systems for adding makeup chemicals (CaCO3, 
Na2CO3) in the chemical recovery areas of chemical 
pulp mills.



Sec. 98.271  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains a pulp and paper manufacturing process and the facility meets 
the requirements of either Sec. 98.2(a)(1) or (a)(2).



Sec. 98.272  GHGs to report.

    You must report the emissions listed in paragraphs (a) through (f) 
of this section:
    (a) CO2, biogenic CO2, CH4, and 
N2O emissions from each kraft or soda chemical recovery 
furnace.

[[Page 945]]

    (b) CO2, biogenic CO2, CH4, and 
N2O emissions from each sulfite chemical recovery combustion 
unit.
    (c) CO2, biogenic CO2, CH4, and 
N2O emissions from each stand-alone semichemical chemical 
recovery combustion unit.
    (d) CO2, biogenic CO2, CH4, and 
N2O emissions from each kraft or soda pulp mill lime kiln.
    (e) CO2 emissions from addition of makeup chemicals 
(CaCO3, Na2CO3) in the chemical 
recovery areas of chemical pulp mills.
    (f) CO2, CH4, and N2O combustion 
emissions from each stationary combustion unit. You must calculate and 
report these emissions under subpart C of this part (General Stationary 
Fuel Combustion Sources) by following the requirements of subpart C.



Sec. 98.273  Calculating GHG emissions.

    (a) For each chemical recovery furnace located at a kraft or soda 
facility, you must determine CO2, biogenic CO2, 
CH4, and N2O emissions using the procedures in 
paragraphs (a)(1) through (a)(3) of this section. CH4 and 
N2O emissions must be calculated as the sum of emissions from 
combustion of fossil fuels and combustion of biomass in spent liquor 
solids.
    (1) Calculate fossil fuel-based CO2 emissions from direct 
measurement of fossil fuels consumed and default emissions factors 
according to the Tier 1 methodology for stationary combustion sources in 
Sec. 98.33(a)(1). A higher tier from Sec. 98.33(a) may be used to 
calculate fossil fuel-based CO2 emissions if the respective 
monitoring and QA/QC requirements described in Sec. 98.34 are met.
    (2) Calculate fossil fuel-based CH4 and N2O 
emissions from direct measurement of fossil fuels consumed, default or 
site-specific HHV, and default emissions factors and convert to metric 
tons of CO2 equivalent according to the methodology for 
stationary combustion sources in Sec. 98.33(c).
    (3) Calculate biogenic CO2 emissions and emissions of 
CH4 and N2O from biomass using measured quantities 
of spent liquor solids fired, site-specific HHV, and default emissions 
factors, according to Equation AA-1 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.112

Where:

CO2, CH4, or N2O, from Biomass = 
          Biogenic CO2 emissions or emissions of 
          CH4 or N2O from spent liquor solids 
          combustion (metric tons per year).
Solids = Mass of spent liquor solids combusted (short tons per year) 
          determined according to Sec. 98.274(b).
HHV = Annual high heat value of the spent liquor solids (mmBtu per 
          kilogram) determined according to Sec. 98.274(b).
(EF) = Default emission factor for CO2, CH4, or 
          N2O, from Table AA-1 of this subpart (kg 
          CO2, CH4, or N2O per mmBtu).
0.90718 = Conversion factor from short tons to metric tons.

    (b) For each chemical recovery combustion unit located at a sulfite 
or stand-alone semichemical facility, you must determine CO2, 
CH4, and N2O emissions using the procedures in 
paragraphs (b)(1) through (b)(4) of this section:
    (1) Calculate fossil CO2 emissions from fossil fuels from 
direct measurement of fossil fuels consumed and default emissions 
factors according to the Tier 1 Calculation Methodology for stationary 
combustion sources in Sec. 98.33(a)(1). A higher tier from Sec. 
98.33(a) may be used to calculate fossil fuel-based CO2 
emissions if the respective monitoring and QA/QC requirements described 
in Sec. 98.34 are met.
    (2) Calculate CH4 and N2O emissions from 
fossil fuels from direct measurement of fossil fuels consumed, default 
or site-specific HHV, and default emissions factors and convert to 
metric tons of CO2 equivalent according to the methodology 
for stationary combustion sources in Sec. 98.33(c).
    (3) Calculate biogenic CO2 emissions using measured 
quantities of spent liquor solids fired and the carbon content

[[Page 946]]

of the spent liquor solids, according to Equation AA-2 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.113

Where:

Biogenic CO2 = Annual CO2 mass emissions for spent 
          liquor solids combustion (metric tons per year).
Solids = Mass of the spent liquor solids combusted (short tons per year) 
          determined according to Sec. 98.274(b).
CC = Annual carbon content of the spent liquor solids, determined 
          according to Sec. 98.274(b) (percent by weight, expressed as 
          a decimal fraction, e.g., 95% = 0.95).
44/12 = Ratio of molecular weights, CO2 to carbon.
0.90718 = Conversion from short tons to metric tons.

    (4) Calculate CH4 and N2O emissions from 
biomass using Equation AA-1 of this section and the default 
CH4 and N2O emissions factors for kraft facilities 
in Table AA-1 of this subpart and convert the CH4 or 
N2O emissions to metric tons of CO2 equivalent by 
multiplying each annual CH4 and N2O emissions 
total by the appropriate global warming potential (GWP) factor from 
Table A-1 of subpart A of this part.
    (c) For each pulp mill lime kiln located at a kraft or soda 
facility, you must determine CO2, CH4, and 
N2O emissions using the procedures in paragraphs (c)(1) 
through (c)(3) of this section:
    (1) Calculate CO2 emissions from fossil fuel from direct 
measurement of fossil fuels consumed and default HHV and default 
emissions factors, according to the Tier 1 Calculation Methodology for 
stationary combustion sources in Sec. 98.33(a)(1). A higher tier from 
Sec. 98.33(a) may be used to calculate fossil fuel-based CO2 
emissions if the respective monitoring and QA/QC requirements described 
in Sec. 98.34 are met.
    (2) Calculate CH4 and N2O emissions from 
fossil fuel from direct measurement of fossil fuels consumed, default or 
site-specific HHV, and default emissions factors and convert to metric 
tons of CO2 equivalent according to the methodology for 
stationary combustion sources in Sec. 98.33(c); use the default HHV 
listed in Table C-1 of subpart C and the default CH4 and 
N2O emissions factors listed in Table AA-2 of this subpart.
    (3) Biogenic CO2 emissions from conversion of 
CaCO3 to CaO are included in the biogenic CO2 
estimates calculated for the chemical recovery furnace in paragraph 
(a)(3) of this section.
    (d) For makeup chemical use, you must calculate CO2 
emissions by using direct or indirect measurement of the quantity of 
chemicals added and ratios of the molecular weights of CO2 
and the makeup chemicals, according to Equation AA-3 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.114

Where:

CO2 = CO2 mass emissions from makeup chemicals 
          (kilograms/yr).
M (CaCO3) = Make-up quantity of CaCO3 used for the 
          reporting year (metric tons per year).
M (NaCO3) = Make-up quantity of Na2CO3 
          used for the reporting year (metric tons per year).
44 = Molecular weight of CO2.
100 = Molecular weight of CaCO3.
105.99 = Molecular weight of Na2CO3.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79166, Dec. 17, 2010; 
78 FR 71965, Nov. 29, 2013]

[[Page 947]]



Sec. 98.274  Monitoring and QA/QC requirements.

    (a) Each facility subject to this subpart must quality assure the 
GHG emissions data according to the applicable requirements in Sec. 
98.34. All QA/QC data must be available for inspection upon request.
    (b) Fuel properties needed to perform the calculations in Equations 
AA-1 and AA-2 of this subpart must be determined according to paragraphs 
(b)(1) through (b)(3) of this section.
    (1) High heat values of black liquor must be determined no less than 
annually using T684 om-06 Gross Heating Value of Black Liquor, TAPPI 
(incorporated by reference, see Sec. 98.7). If measurements are 
performed more frequently than annually, then the high heat value used 
in Equation AA-1 of this subpart must be based on the average of the 
representative measurements made during the year.
    (2) The annual mass of spent liquor solids must be determined using 
either of the methods specified in paragraph (b)(2)(i) or (b)(2)(ii) of 
this section.
    (i) Measure the mass of spent liquor solids annually (or more 
frequently) using T-650 om-05 Solids Content of Black Liquor, TAPPI 
(incorporated by reference in Sec. 98.7). If measurements are performed 
more frequently than annually, then the mass of spent liquor solids used 
in Equation AA-1 of this subpart must be based on the average of the 
representative measurements made during the year.
    (ii) Determine the annual mass of spent liquor solids based on 
records of measurements made with an online measurement system that 
determines the mass of spent liquor solids fired in a chemical recovery 
furnace or chemical recovery combustion unit.
    (3) Carbon analyses for spent pulping liquor must be determined no 
less than annually using ASTM D5373-08 Standard Test Methods for 
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in 
Laboratory Samples of Coal (incorporated by reference, see Sec. 98.7). 
If measurements using ASTM D5373-08 are performed more frequently than 
annually, then the spent pulping liquor carbon content used in Equation 
AA-2 of this subpart must be based on the average of the representative 
measurements made during the year.
    (c) Each facility must keep records that include a detailed 
explanation of how company records of measurements are used to estimate 
GHG emissions. The owner or operator must also document the procedures 
used to ensure the accuracy of the measurements of fuel, spent liquor 
solids, and makeup chemical usage, including, but not limited to 
calibration of weighing equipment, fuel flow meters, and other 
measurement devices. The estimated accuracy of measurements made with 
these devices must be recorded and the technical basis for these 
estimates must be provided. The procedures used to convert spent pulping 
liquor flow rates to units of mass (i.e., spent liquor solids firing 
rates) also must be documented.
    (d) Records must be made available upon request for verification of 
the calculations and measurements.



Sec. 98.275  Procedures for estimating missing data.

    A complete record of all measured parameters used in the GHG 
emissions calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable (e.g., if a meter 
malfunctions during unit operation or if a required sample is not 
taken), a substitute data value for the missing parameter shall be used 
in the calculations, according to the requirements of paragraphs (a) 
through (c) of this section:
    (a) There are no missing data procedures for measurements of heat 
content and carbon content of spent pulping liquor. A re-test must be 
performed if the data from any annual measurements are determined to be 
invalid.
    (b) For missing measurements of the mass of spent liquor solids or 
spent pulping liquor flow rates, use the lesser value of either the 
maximum mass or fuel flow rate for the combustion unit, or the maximum 
mass or flow rate that the fuel meter can measure.
    (c) For the use of makeup chemicals (carbonates), the substitute 
data value shall be the best available estimate of makeup chemical 
consumption, based on available data (e.g., past accounting records, 
production rates). The owner

[[Page 948]]

or operator shall document and keep records of the procedures used for 
all such estimates.



Sec. 98.276  Data reporting requirements.

    In addition to the information required by Sec. 98.3(c) and the 
applicable information required by Sec. 98.36, each annual report must 
contain the information in paragraphs (a) through (l) of this section as 
applicable:
    (a) Annual emissions of CO2, biogenic CO2, 
CH4, biogenic CH4 N2O, and biogenic 
N2O (metric tons per year).
    (b) [Reserved]
    (c) Basis for determining the annual mass of the spent liquor solids 
combusted (whether based on T650 om-05 Solids Content of Black Liquor, 
TAPPI (incorporated by reference, see Sec. 98.7) or an online 
measurement system).
    (d) [Reserved]
    (e) The default emission factor for CO2, CH4, 
or N2O, used in Equation AA-1 of this subpart (kg 
CO2, CH4, or N2O per mmBtu).
    (f)-(i) [Reserved]
    (j) Annual steam purchases (pounds of steam per year).
    (k) Total annual production of unbleached virgin chemical pulp 
produced onsite during the reporting year in air-dried metric tons per 
year. This total annual production value is the sum of all kraft, 
semichemical, soda, and sulfite pulp produced onsite, prior to 
bleaching, through all virgin pulping lines. Do not include mechanical 
pulp or secondary fiber repulped for paper production in the virgin pulp 
production total.
    (l) For each pulp mill lime kiln, report the information specified 
in paragraphs (l)(1) and (2) of this section.
    (1) The quantity of calcium oxide (CaO) produced (metric tons).
    (2) The percent of annual heat input, individually for each fossil 
fuel type.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79166, Dec. 17, 2010; 
78 FR 71965, Nov. 29, 2013; 79 FR 63797, Oct. 24, 2014]



Sec. 98.277  Records that must be retained.

    In addition to the information required by Sec. 98.3(g), you must 
retain the records in paragraphs (a) through (g) of this section.
    (a) GHG emission estimates (including separate estimates of biogenic 
CO2) for each emissions source listed under Sec. 98.270(b).
    (b) Annual analyses of spent pulping liquor HHV for each chemical 
recovery furnace at kraft and soda facilities.
    (c) Annual analyses of spent pulping liquor carbon content for each 
chemical recovery combustion unit at a sulfite or semichemical pulp 
facility.
    (d) Annual quantity of spent liquor solids combusted in each 
chemical recovery furnace and chemical recovery combustion unit, and the 
basis for detemining the annual quantity of the spent liquor solids 
combusted (whether based on T650 om-05 Solids Content of Black Liquor, 
TAPPI (incorporated by reference, see Sec. 98.7) or an online 
measurement system). If an online measurement system is used, you must 
retain records of the calculations used to determine the annual quantity 
of spent liquor solids combusted from the continuous measurements.
    (e) Annual steam purchases.
    (f) Annual quantities of makeup chemicals used.
    (g) Verification software records. You must keep a record of the 
file generated by the verification software specified in Sec. 98.5(b) 
for the applicable data specified in paragraphs (g)(1) through (27) of 
this section. Retention of this file satisfies the recordkeeping 
requirement for the data in paragraphs (g)(1) through (27) of this 
section.
    (1) Mass of the solid fuel combusted (tons/year) (Equation C-1 of 
Sec. 98.33).
    (2) Volume of the liquid fuel combusted (gallons/year) (Equation C-
1).
    (3) Volume of the gaseous fuel combusted (scf/year) (Equation C-1).
    (4) Annual natural gas usage (therms/year) (Equation C-1a of Sec. 
98.33).
    (5) Annual natural gas usage (mmBtu/year) (Equation C-1b of Sec. 
98.33).
    (6) Mass of the solid fuel combusted (tons/year) (Equation C-2a of 
Sec. 98.33).
    (7) Volume of the liquid fuel combusted (gallons/year) (Equation C-
2a).
    (8) Volume of the gaseous fuel combusted (scf/year) (Equation C-2a).
    (9) Annual mass of the solid fuel combusted (short tons/year) 
(Equation C-3 of Sec. 98.33).

[[Page 949]]

    (10) Annual average carbon content of the solid fuel (percent by 
weight, expressed as a decimal fraction) (Equation C-3).
    (11) Annual volume of the liquid fuel combusted (gallons/year) 
(Equation C-4 of Sec. 98.33).
    (12) Annual average carbon content of the liquid fuel (kg C per 
gallon of fuel) (Equation C-4).
    (13) Annual volume of the gaseous fuel combusted (scf/year) 
(Equation C-5 of Sec. 98.33).
    (14) Annual average carbon content of the gaseous fuel (kg C per kg 
of fuel) (Equation C-5).
    (15) Annual average molecular weight of the gaseous fuel (kg/kg-
mole) (Equation C-5).
    (16) Molar volume conversion factor at standard conditions, as 
defined in Sec. 98.6 (scf per kg-mole) (Equation C-5).
    (17) Identify if you will use the default high heat value from Table 
C-1 of subpart C of this part, or actual HHV data (Equation C-8 of Sec. 
98.33).
    (18) High heat value of the fuel (mmBTU/tons) (Equation C-8).
    (19) High heat value of the fuel (mmBTU/gallons) (Equation C-8).
    (20) High heat value of the fuel (mmBTU/scf) (Equation C-8).
    (21) Mass of spent liquor solids combusted from each chemical 
recovery furnace located at a kraft or soda facility, in short tons in 
year, determined according to Sec. 98.274(b) (tons/year) (Equation AA-1 
of Sec. 98.273).
    (22) Annual high heat value of the spent liquor solids from each 
chemical recovery furnace located at a kraft or soda facility determined 
according to Sec. 98.274(b) (mmBtu per kilogram) (Equation AA-1).
    (23) Annual high heat value of the spent liquor solids from each 
chemical recovery combustion unit located at a sulfite or stand-alone 
semichemical facility, determined according to Sec. 98.274(b) (mmBtu 
per kilogram) (Equation AA-1).
    (24) Mass of the spent liquor solids combusted in short tons per 
year determined according to Sec. 98.274(b) (tons/year) (Equation AA-2 
of Sec. 98.273).
    (25) Annual carbon content of the spent liquor solids, determined 
according to Sec. 98.274(b) (percent by weight, expressed as a decimal 
fraction (e.g., 95% = 0.95)) (Equation AA-2).
    (26) Make-up quantity of CaCO3 used for the reporting 
year (metric tons/year) (Equation AA-3 of Sec. 98.273).
    (27) Make-up quantity of Na2CO3 used for the 
reporting year metric tons/year) (Equation AA-3).

[74 FR 56374, Oct. 30, 2009, as amended at 79 FR 63798, Oct. 24, 2014]



Sec. 98.278  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.



Sec. Table AA-1 to Subpart AA of Part 98--Kraft Pulping Liquor Emissions 
     Factors for Biomass-Based CO2, CH4, and 
                             N2O

----------------------------------------------------------------------------------------------------------------
                                                                      Biomass-based emissions factors (kg/mmBtu
                                                                                        HHV)
                           Wood furnish                            ---------------------------------------------
                                                                      \a\ CO2        CH4              N2O
----------------------------------------------------------------------------------------------------------------
North American Softwood...........................................         94.4       0.0019             0.00042
North American Hardwood...........................................         93.7       0.0019             0.00042
Bagasse...........................................................         95.5       0.0019             0.00042
Bamboo............................................................         93.7       0.0019             0.00042
Straw.............................................................         95.1       0.0019             0.00042
----------------------------------------------------------------------------------------------------------------
\a\ Includes emissions from both the recovery furnace and pulp mill lime kiln.


[78 FR 71965, Nov. 29, 2013]

[[Page 950]]



 Sec. Table AA-2 to Subpart AA of Part 98--Kraft Lime Kiln and Calciner 
         Emissions Factors for CH4 and N2O

----------------------------------------------------------------------------------------------------------------
                                                 Fossil fuel-based emissions factors (kg/mmBtu HHV)
                                  ------------------------------------------------------------------------------
               Fuel                         Kraft lime kilns                        Kraft calciners
                                  ------------------------------------------------------------------------------
                                            CH4              N2O               CH4                   N2O
----------------------------------------------------------------------------------------------------------------
Residual Oil (any type)..........  0.0027..............            0  0.0027..............  0.0003
Distillate Oil (any type)........  0.0027..............            0  0.0027..............  0.0004
Natural Gas......................  0.0027..............            0  0.0027..............  0.0001
Biogas...........................  0.0027..............            0  0.0027..............  0.0001
Petroleum coke...................  0.0027..............            0  \a\NA...............  \a\NA
Other Fuels......................  See Table C-2.......            0  See Table C-2.......  See Table C-2
----------------------------------------------------------------------------------------------------------------
\a\ Emission factors for kraft calciners are not available.


[78 FR 71965, Nov. 29, 2013]



                  Subpart BB_Silicon Carbide Production



Sec. 98.280  Definition of the source category.

    Silicon carbide production includes any process that produces 
silicon carbide for abrasive purposes.



Sec. 98.281  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains a silicon carbide production process and the facility meets the 
requirements of either Sec. 98.2(a)(1) or (a)(2).



Sec. 98.282  GHGs to report.

    You must report:
    (a) CO2 process emissions from all silicon carbide 
process units or furnaces combined.
    (b) CO2, CH4, and N2O emissions 
from each stationary combustion unit. You must report these emissions 
under subpart C of this part (General Stationary Fuel Combustion 
Sources) by following the requirements of subpart C.

[74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71966, Nov. 29, 2013]



Sec. 98.283  Calculating GHG emissions.

    You must calculate and report the combined annual process 
CO2 emissions from all silicon carbide process units and 
production furnaces using the procedures in either paragraph (a) or (b) 
of this section.
    (a) Calculate and report under this subpart the combined annual 
process CO2 emissions by operating and maintaining CEMS 
according to the Tier 4 Calculation Methodology specified in Sec. 
98.33(a)(4) and all associated requirements for Tier 4 in subpart C of 
this part (General Stationary Fuel Combustion Sources).
    (b) Calculate and report under this subpart the combined annual 
process CO2 emissions using the procedures in paragraphs 
(b)(1) and (b)(2) of this section.
    (1) Use Equation BB-1 of this section to calculate the facility-
specific emissions factor for determining CO2 emissions. The 
carbon content must be measured monthly and used to calculate a monthly 
CO2 emissions factor:
[GRAPHIC] [TIFF OMITTED] TR30OC09.115

Where:

EFCO2,n = CO2 emissions factor in month n (metric 
          tons CO2/metric ton of petroleum coke consumed).
0.65 = Adjustment factor for the amount of carbon in silicon carbide 
          product (assuming 35 percent of carbon input is in the carbide 
          product).

[[Page 951]]

CCFn = Carbon content factor for petroleum coke consumed in 
          month n from the supplier or as measured by the applicable 
          method incorporated by reference in Sec. 98.7 according to 
          Sec. 98.284(c) (percent by weight expressed as a decimal 
          fraction).
44/12 = Ratio of molecular weights, CO2 to carbon.

    (2) Calculate annual CO2 process emissions from the 
silicon carbide production facility according to Equation BB-2 of this 
section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.116

Where:

CO2 = Annual CO2 emissions from silicon carbide 
          production facility (metric tons CO2).
Tn = Petroleum coke consumption in calendar month n (tons).
EFCO2,n = CO2 emissions factor from month n 
          (calculated in Equation BB-1 of this section).
2000/2205 = Conversion factor to convert tons to metric tons.
n = Number of month.

    (c) If GHG emissions from a silicon carbide production furnace or 
process unit are vented through the same stack as any combustion unit or 
process equipment that reports CO2 emissions using a CEMS 
that complies with the Tier 4 Calculation Methodology in subpart C of 
this part (General Stationary Fuel Combustion Sources), then the 
calculation methodology in paragraph (b) of this section shall not be 
used to calculate process emissions. The owner or operator shall report 
under this subpart the combined stack emissions according to the Tier 4 
Calculation Methodology in Sec. 98.33(a)(4) and all associated 
requirements for Tier 4 in subpart C of this part.

[74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71966, Nov. 29, 2013]



Sec. 98.284  Monitoring and QA/QC requirements.

    (a) You must measure your consumption of petroleum coke using plant 
instruments used for accounting purposes including direct measurement 
weighing the petroleum coke fed into your process (by belt scales or a 
similar device) or through the use of purchase records.
    (b) You must document the procedures used to ensure the accuracy of 
monthly petroleum coke consumption measurements.
    (c) For CO2 process emissions, you must determine the 
monthly carbon content of the petroleum coke using reports from the 
supplier. Alternatively, facilities can measure monthly carbon contents 
of the petroleum coke using ASTM D3176-89 (Reapproved 2002) Standard 
Practice for Ultimate Analysis of Coal and Coke (incorporated by 
reference, see Sec. 98.7) and ASTM D5373-08 Standard Test Methods for 
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in 
Laboratory Samples of Coal (incorporated by reference, see Sec. 98.7).
    (d) For quality assurance and quality control of the supplier data, 
you must conduct an annual measurement of the carbon content of the 
petroleum coke using ASTM D3176-89 and ASTM D5373-08 Standard Test 
Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen 
in Laboratory Samples of Coal (incorporated by reference, see Sec. 
98.7).



Sec. 98.285  Procedures for estimating missing data.

    For the petroleum coke input procedure in Sec. 98.283(b), a 
complete record of all measured parameters used in the GHG emissions 
calculations is required (e.g., carbon content values, etc.). Therefore, 
whenever a quality-assured value of a required parameter is unavailable, 
a substitute data value for the missing parameter shall be used in the 
calculations as specified in the paragraphs (a) and (b) of this section. 
You must document and keep records of the procedures used for all such 
estimates.

[[Page 952]]

    (a) For each missing value of the monthly carbon content of 
petroleum coke, the substitute data value shall be the arithmetic 
average of the quality-assured values of carbon contents immediately 
preceding and immediately following the missing data incident. If no 
quality-assured data on carbon contents are available prior to the 
missing data incident, the substitute data value shall be the first 
quality-assured value for carbon contents obtained after the missing 
data period.
    (b) For each missing value of the monthly petroleum coke 
consumption, the substitute data value shall be the best available 
estimate of the petroleum coke consumption based on all available 
process data or information used for accounting purposes (such as 
purchase records).



Sec. 98.286  Data reporting requirements.

    In addition to the information required by Sec. 98.3(c), each 
annual report must contain the information specified in paragraphs (a) 
or (b) of this section, as applicable for each silicon carbide 
production facility.
    (a) If a CEMS is used to measure process CO2 emissions, 
you must report under this subpart the relevant information required for 
the Tier 4 Calculation Methodology in Sec. 98.36 and the information 
listed in this paragraph (a):
    (1) Annual consumption of petroleum coke (tons).
    (2) Annual production of silicon carbide (tons).
    (3) Annual production capacity of silicon carbide (tons).
    (b) If a CEMS is not used to measure process CO2 
emissions, you must report the information in paragraph (b)(1) through 
(8) of this section for all silicon carbide process units or production 
furnaces combined:
    (1) [Reserved]
    (2) Annual production of silicon carbide (tons).
    (3) Annual production capacity of silicon carbide (tons).
    (4) [Reserved]
    (5) Whether carbon content of the petroleum coke is based on reports 
from the supplier or through self measurement using applicable ASTM 
standard method.
    (6) [Reserved]
    (7) Sampling analysis results for carbon content of consumed 
petroleum coke as determined for QA/QC of supplier data under Sec. 
98.284(d) (percent by weight expressed as a decimal fraction).
    (8) Number of times in the reporting year that missing data 
procedures were followed to measure the carbon contents of petroleum 
coke (number of months) and petroleum coke consumption (number of 
months).

[74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71966, Nov. 29, 2013; 
79 FR 63798, Oct. 24, 2014]



Sec. 98.287  Records that must be retained.

    In addition to the records required by Sec. 98.3(g), you must 
retain the records specified in paragraphs (a) through (c) of this 
section for each silicon carbide production facility.
    (a) If a CEMS is used to measure CO2 emissions, you must 
retain under this subpart the records required for the Tier 4 
Calculation Methodology in Sec. 98.37 and the information listed in 
this paragraph (a):
    (1) Records of all petroleum coke purchases.
    (2) Annual operating hours.
    (b) If a CEMS is not used to measure emissions, you must retain 
records for the information listed in this paragraph (b):
    (1) Records of all analyses and calculations conducted for reported 
data listed in Sec. 98.286(b).
    (2) Records of all petroleum coke purchases.
    (3) Annual operating hours.
    (c) Verification software records. You must keep a record of the 
file generated by the verification software specified in Sec. 98.5(b) 
for the applicable data specified in paragraphs (c)(1) and (2) of this 
section. Retention of this file satisfies the recordkeeping requirement 
for the data in paragraphs (c)(1) and (2) of this section.
    (1) Carbon content factor for petroleum coke consumed in month from 
the supplier or as measured by the applicable method (percent by weight 
expressed as a decimal fraction) (Equation BB-1 of Sec. 98.283).

[[Page 953]]

    (2) Petroleum coke consumption in month (tons) (Equation BB-2 of 
Sec. 98.283).

[74 FR 56374, Oct. 30, 2009, as amended at 79 FR 63798, Oct. 24, 2014]



Sec. 98.288  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.



                    Subpart CC_Soda Ash Manufacturing



Sec. 98.290  Definition of the source category.

    (a) A soda ash manufacturing facility is any facility with a 
manufacturing line that produces soda ash by one of the methods in 
paragraphs (a)(1) through (3) of this section:
    (1) Calcining trona.
    (2) Calcining sodium sesquicarbonate.
    (3) Using a liquid alkaline feedstock process that directly produces 
CO2.
    (b) In the context of the soda ash manufacturing sector, 
``calcining'' means the thermal/chemical conversion of the bicarbonate 
fraction of the feedstock to sodium carbonate.



Sec. 98.291  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains a soda ash manufacturing process and the facility meets the 
requirements of either Sec. 98.2(a)(1) or (a)(2).



Sec. 98.292  GHGs to report.

    You must report:
    (a) CO2 process emissions from each soda ash 
manufacturing line combined.
    (b) CO2 combustion emissions from each soda ash 
manufacturing line.
    (c) CH4 and N2O combustion emissions from each 
soda ash manufacturing line. You must calculate and report these 
emissions under subpart C of this part (General Stationary Fuel 
Combustion Sources) by following the requirements of subpart C.
    (d) CO2, CH4, and N2O emissions 
from each stationary combustion unit other than soda ash manufacturing 
lines. You must calculate and report these emissions under subpart C of 
this part (General Stationary Fuel Combustion Sources) by following the 
requirements of subpart C.



Sec. 98.293  Calculating GHG emissions.

    You must calculate and report the annual process CO2 
emissions from each soda ash manufacturing line using the procedures 
specified in paragraph (a) or (b) of this section.
    (a) For each soda ash manufacturing line that meets the conditions 
specified in Sec. 98.33(b)(4)(ii) or (b)(4)(iii), you must calculate 
and report under this subpart the combined process and combustion 
CO2 emissions by operating and maintaining a CEMS to measure 
CO2 emissions according to the Tier 4 Calculation Methodology 
specified in Sec. 98.33(a)(4) and all associated requirements for Tier 
4 in subpart C of this part (General Stationary Fuel Combustion 
Sources).
    (b) For each soda ash manufacturing line that is not subject to the 
requirements in paragraph (a) of this section, calculate and report the 
process CO2 emissions from the soda ash manufacturing line by 
using the procedure in either paragraphs (b)(1), (b)(2), or (b)(3) of 
this section; and the combustion CO2 emissions using the 
procedure in paragraph (b)(4) of this section.
    (1) Calculate and report under this subpart the combined process and 
combustion CO2 emissions by operating and maintaining a CEMS 
to measure CO2 emissions according to the Tier 4 Calculation 
Methodology specified in Sec. 98.33(a)(4) and all associated 
requirements for Tier 4 in subpart C of this part (General Stationary 
Fuel Combustion Sources).
    (2) Use either Equation CC-1 or Equation CC-2 of this section to 
calculate annual CO2 process emissions from each 
manufacturing line that calcines trona to produce soda ash:

[[Page 954]]

[GRAPHIC] [TIFF OMITTED] TR30OC09.118

[GRAPHIC] [TIFF OMITTED] TR30OC09.119

Where:

Ek = Annual CO2 process emissions from each 
          manufacturing line, k (metric tons).
(ICT)n = Inorganic carbon content (percent by 
          weight, expressed as a decimal fraction) in trona input, from 
          the carbon analysis results for month n. This represents the 
          ratio of trona to trona ore.
(ICsa)n = Inorganic carbon content (percent by 
          weight, expressed as a decimal fraction) in soda ash output, 
          from the carbon analysis results for month n. This represents 
          the purity of the soda ash produced.
(Tt)n = Mass of trona input in month n (tons).
(Tsa)n = Mass of soda ash output in month n 
          (tons).
2000/2205 = Conversion factor to convert tons to metric tons.
0.097/1 = Ratio of ton of CO2 emitted for each ton of trona.
0.138/1 = Ratio of ton of CO2 emitted for each ton of soda 
          ash produced.

    (3) Site-specific emission factor method. Use Equations CC-3, CC-4, 
and CC-5 of this section to determine annual CO2 process 
emissions from manufacturing lines that use the liquid alkaline 
feedstock process to produce soda ash. You must conduct an annual 
performance test and measure CO2 emissions and flow rates at 
all process vents from the mine water stripper/evaporator for each 
manufacturing line and calculate CO2 emissions as described 
in paragraphs (b)(3)(i) through (b)(3)(iv) of this section.
    (i) During the performance test, you must measure the process vent 
flow from each process vent during the test and calculate the average 
rate for the test period in metric tons per hour.
    (ii) Using the test data, you must calculate the hourly 
CO2 emission rate using Equation CC-3 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.120

Where:

ERCO2 = CO2 mass emission rate (metric tons/hour).
CCO2 = Hourly CO2 concentration (percent 
          CO2) as determined by Sec. 98.294(c).
10000 = Parts per million per percent
2.59 x 10-9 = Conversion factor (pounds-mole/dscf/ppm).
44 = Pounds per pound-mole of carbon dioxide.
Q = Stack gas volumetric flow rate per minute (dscfm).
60 = Minutes per hour
4.53 x 10 -4 = Conversion factor (metric tons/pound)

    (iii) Using the test data, you must calculate a CO2 
emission factor for the process using Equation CC-4 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.121

Where:

EFCO2 = CO2 emission factor (metric tons 
          CO2/metric ton of process vent flow from mine water 
          stripper/evaporator).
ERCO2 = CO2 mass emission rate (metric tons/hour).
Vt = Process vent flow rate from mine water stripper/
          evaporator during annual performance test (pounds/hour).
4.53 x 10-4 = Conversion factor (metric tons/pound)

    (iv) You must calculate annual CO2 process emissions from 
each manufacturing line using Equation CC-5 of this section:

[[Page 955]]

[GRAPHIC] [TIFF OMITTED] TR30OC09.122

Where:

Ek = Annual CO2 process emissions for each 
          manufacturing line, k (metric tons).
EFCO2 = CO2 emission factor (metric tons 
          CO2/metric ton of process vent flow from mine water 
          stripper/evaporator).
Va = Annual process vent flow rate from mine water stripper/
          evaporator (thousand pounds/hour).
H = Annual operating hours for the each manufacturing line.
0.453 = Conversion factor (metric tons/thousand pounds).

    (4) Calculate and report under subpart C of this part (General 
Stationary Fuel Combustion Sources) the combustion CO2, 
CH4, and N2O emissions in the soda ash 
manufacturing line according to the applicable requirements in subpart 
C.



Sec. 98.294  Monitoring and QA/QC requirements.

    Section 98.293 provides three different procedures for emission 
calculations. The appropriate paragraphs (a) through (c) of this section 
should be used for the procedure chosen.
    (a) If you determine your emissions using Sec. 98.293(b)(2) 
(Equation CC-1 of this subpart) you must:
    (1) Determine the monthly inorganic carbon content of the trona from 
a weekly composite analysis for each soda ash manufacturing line, using 
a modified version of ASTM E359-00 (Reapproved 2005)e1, Standard Test 
Methods for Analysis of Soda Ash (Sodium Carbonate) (incorporated by 
reference, see Sec. 98.7). ASTM E359-00(Reapproved 2005) e1 is designed 
to measure the total alkalinity in soda ash not in trona. The modified 
method referred to above adjusts the regular ASTM method to express the 
results in terms of trona. Although ASTM E359-00 (Reapproved 2005) e1 
uses manual titration, suitable autotitrators may also be used for this 
determination.
    (2) Measure the mass of trona input produced by each soda ash 
manufacturing line on a monthly basis using belt scales or methods used 
for accounting purposes.
    (3) Document the procedures used to ensure the accuracy of the 
monthly measurements of trona consumed.
    (b) If you calculate CO2 process emissions based on soda 
ash production (Sec. 98.293(b)(2) Equation CC-2 of this subpart), you 
must:
    (1) Determine the inorganic carbon content of the soda ash (i.e., 
soda ash purity) using ASTM E359-00 (Reapproved 2005) e1 Standard Test 
Methods for Analysis of Soda Ash (Sodium Carbonate) (incorporated by 
reference, see Sec. 98.7). Although ASTM E359-00 (Reapproved 2005) e1 
uses manual titration, suitable autotitrators may also be used for this 
determination.
    (2) Measure the mass of soda ash produced by each soda ash 
manufacturing line on a monthly basis using belt scales, by weighing the 
soda ash at the truck or rail loadout points of your facility, or 
methods used for accounting purposes.
    (3) Document the procedures used to ensure the accuracy of the 
monthly measurements of soda ash produced.
    (c) If you calculate CO2 emissions using the site-
specific emission factor method in Sec. 98.293(b)(3), you must:
    (1) Conduct an annual performance test that is based on 
representative performance (i.e., performance based on normal operating 
conditions) of the affected process.
    (2) Sample the stack gas and conduct three emissions test runs of 1 
hour each.
    (3) Conduct the stack test using EPA Method 3A at 40 CFR part 60, 
appendix A-2 to measure the CO2 concentration, Method 2, 2A, 
2C, 2D, or 2F at 40 CFR part 60, appendix A-1 or Method 26 at 40 CFR 
part 60, appendix A-2 to determine the stack gas volumetric flow rate. 
All QA/QC procedures specified in the reference test methods and any 
associated performance specifications apply. For each test, the facility 
must prepare an emission factor determination report that must include 
the items in paragraphs (c)(3)(i) through (c)(3)(iii) of this section.
    (i) Analysis of samples, determination of emissions, and raw data.

[[Page 956]]

    (ii) All information and data used to derive the emissions 
factor(s).
    (iii) You must determine the average process vent flow rate from the 
mine water stripper/evaporater during each test and document how it was 
determined.
    (4) You must also determine the annual vent flow rate from the mine 
water stripper/evaporater from monthly information using the same plant 
instruments or procedures used for accounting purposes (i.e., volumetric 
flow meter).

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66469, Oct. 28, 2010]



Sec. 98.295  Procedures for estimating missing data.

    For the emission calculation methodologies in Sec. 98.293(b)(2) and 
(b)(3), a complete record of all measured parameters used in the GHG 
emissions calculations is required (e.g., inorganic carbon content 
values, etc.). Therefore, whenever a quality-assured value of a required 
parameter is unavailable, a substitute data value for the missing 
parameter shall be used in the calculations as specified in the 
paragraphs (a) through (d) of this section. You must document and keep 
records of the procedures used for all such missing value estimates.
    (a) For each missing value of the weekly composite of inorganic 
carbon content of either soda ash or trona, the substitute data value 
shall be the arithmetic average of the quality-assured values of 
inorganic carbon contents from the week immediately preceding and the 
week immediately following the missing data incident. If no quality-
assured data on inorganic carbon contents are available prior to the 
missing data incident, the substitute data value shall be the first 
quality-assured value for carbon contents obtained after the missing 
data period.
    (b) For each missing value of either the monthly soda ash production 
or the trona consumption, the substitute data value shall be the best 
available estimate(s) of the parameter(s), based on all available 
process data or data used for accounting purposes.
    (c) For each missing value collected during the performance test 
(hourly CO2 concentration, stack gas volumetric flow rate, or 
average process vent flow from mine water stripper/evaporator during 
performance test), you must repeat the annual performance test following 
the calculation and monitoring and QA/QC requirements under Sec. Sec. 
98.293(b)(3) and 98.294(c).
    (d) For each missing value of the monthly process vent flow rate 
from mine water stripper/evaporator, the subsititute data value shall be 
the best available estimate(s) of the parameter(s), based on all 
available process data or the lesser of the maximum capacity of the 
system or the maximum rate the meter can measure.



Sec. 98.296  Data reporting requirements.

    In addition to the information required by Sec. 98.3(c), each 
annual report must contain the information specified in paragraphs (a) 
or (b) of this section, as appropriate for each soda ash manufacturing 
facility.
    (a) If a CEMS is used to measure CO2 emissions, then you 
must report under this subpart the relevant information required under 
Sec. 98.36 and the following information in this paragraph (a):
    (1) Annual consumption of trona or liquid alkaline feedstock for 
each manufacturing line (tons).
    (2) Annual production of soda ash for each manufacturing line 
(tons).
    (3) Annual production capacity of soda ash for each manufacturing 
line (tons).
    (4) Identification number of each manufacturing line.
    (b) If a CEMS is not used to measure CO2 emissions, then 
you must report the information listed in this paragraph (b):
    (1) Identification number of each manufacturing line.
    (2) Annual process CO2 emissions from each soda ash 
manufacturing line (metric tons).
    (3) Annual production of soda ash for each manufacturing line 
(tons).
    (4) Annual production capacity of soda ash for each manufacturing 
line (tons).
    (5)-(7) [Reserved]
    (8) Whether CO2 emissions for each manufacturing line 
were calculated

[[Page 957]]

using a trona input method as described in Equation CC-1 of this 
subpart, a soda ash output method as described in Equation CC-2 of this 
subpart, or a site-specific emission factor method as described in 
Equations CC-3 through CC-5 of this subpart.
    (9) Number of manufacturing lines located used to produce soda ash.
    (10) If you produce soda ash using the liquid alkaline feedstock 
process and use the site-specific emission factor method (Sec. 
98.293(b)(3)) to estimate emissions then you must report the following 
relevant information for each manufacturing line or stack:
    (i) Stack gas volumetric flow rate during performance test (dscfm).
    (ii) Hourly CO2 concentration during performance test 
(percent CO2).
    (iii) CO2 emission factor (metric tons CO2/
metric tons of process vent flow from mine water stripper/evaporator).
    (iv) CO2 mass emission rate during performance test 
(metric tons/hour).
    (v) Average process vent flow from mine water stripper/evaporator 
during performance test (pounds/hour).
    (vi) Annual process vent flow rate from mine water stripper/
evaporator (thousand pounds/hour).
    (11) Number of times missing data procedures were used and for which 
parameter as specified in this paragraph (b)(11):
    (i) Trona or soda ash (number of months).
    (ii) Inorganic carbon contents of trona or soda ash (weeks).
    (iii) Process vent flow rate from mine water stripper/evaporator 
(number of months).

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66469, Oct. 28, 2010; 
79 FR 63798, Oct. 24, 2014]



Sec. 98.297  Records that must be retained.

    In addition to the records required by Sec. 98.3(g), you must 
retain the records specified in paragraphs (a) through (c) of this 
section for each soda ash manufacturing line.
    (a) If a CEMS is used to measure CO2 emissions, then you 
must retain under this subpart the records required for the Tier 4 
Calculation Methodology specified in subpart C of this part and the 
information listed in this paragraph (a):
    (1) Monthly production of soda ash (tons)
    (2) Monthly consumption of trona or liquid alkaline feedstock (tons)
    (3) Annual operating hours (hours).
    (b) If a CEMS is not used to measure emissions, then you must retain 
records for the information listed in this paragraph (b):
    (1) Records of all analyses and calculations conducted for 
determining all reported data as listed in Sec. 98.296(b).
    (2) If using Equation CC-1 or CC-2 of this subpart, weekly inorganic 
carbon content factor of trona or soda ash, depending on method chosen, 
as measured by the applicable method in Sec. 98.294(b) (percent by 
weight expressed as a decimal fraction).
    (3) Annual operating hours for each manufacturing line used to 
produce soda ash (hours).
    (4) You must document the procedures used to ensure the accuracy of 
the monthly trona consumption or soda ash production measurements 
including, but not limited to, calibration of weighing equipment and 
other measurement devices. The estimated accuracy of measurements made 
with these devices must also be recorded, and the technical basis for 
these estimates must be provided.
    (5) If you produce soda ash using the liquid alkaline feedstock 
process and use the site-specific emission factor method to estimate 
emissions (Sec. 98.293(b)(3)) then you must also retain the following 
relevant information:
    (i) Records of performance test results.
    (ii) You must document the procedures used to ensure the accuracy of 
the annual average vent flow measurements including, but not limited to, 
calibration of flow rate meters and other measurement devices. The 
estimated accuracy of measurements made with these devices must also be 
recorded, and the technical basis for these estimates must be provided.
    (c) Verification software records. You must keep a record of the 
file generated by the verification software specified in Sec. 98.5(b) 
for the applicable data specified in paragraphs (c)(1) through (4) of 
this section. Retention

[[Page 958]]

of this file satisfies the recordkeeping requirement for the data in 
paragraphs (c)(1) through (4) of this section
    (1) Inorganic carbon content in trona input, from the carbon 
analysis results for month (percent by weight, expressed as a decimal 
fraction) (Equation CC-1 of Sec. 98.293).
    (2) Mass of trona input in month (tons) (Equation CC-1).
    (3) Inorganic carbon content in soda ash output, from the carbon 
analysis results for month (percent by weight, expressed as a decimal 
fraction) (Equation CC-2 of Sec. 98.293).
    (4) Mass of soda ash output in month (tons) (Equation CC-2).

[74 FR 56374, Oct. 30, 2009, as amended at 79 FR 63798, Oct. 24, 2014]



Sec. 98.298  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.



    Subpart DD_Electrical Transmission and Distribution Equipment Use

    Source: 75 FR 74855, Dec. 1, 2010, unless otherwise noted.



Sec. 98.300  Definition of the source category.

    (a) The electrical transmission and distribution equipment use 
source category consists of all electric transmission and distribution 
equipment and servicing inventory insulated with or containing sulfur 
hexafluoride (SF6) or perfluorocarbons (PFCs) used within an 
electric power system. Electric transmission and distribution equipment 
and servicing inventory includes, but is not limited to:
    (1) Gas-insulated substations.
    (2) Circuit breakers.
    (3) Switchgear, including closed-pressure and hermetically sealed-
pressure switchgear and gas-insulated lines containing SF6 or 
PFCs.
    (4) Gas containers such as pressurized cylinders.
    (5) Gas carts.
    (6) Electric power transformers.
    (7) Other containers of SF6 or PFC.



Sec. 98.301  Reporting threshold.

    (a) You must report GHG emissions from an electric power system if 
the total nameplate capacity of SF6 and PFC containing 
equipment (excluding hermetically sealed-pressure equipment) located 
within the facility, when added to the total nameplate capacity of 
SF6 and PFC containing equipment (excluding hermetically 
sealed-pressure equipment) that is not located within the facility but 
is under common ownership or control, exceeds 17,820 pounds and the 
facility meets the requirements of Sec. 98.2(a)(1).
    (b) A facility other than an electric power system that is subject 
to this part because of emissions from any other source category listed 
in Table A-3 or A-4 in subpart A of this part is not required to report 
emissions under subpart DD of this part unless the total nameplate 
capacity of SF6 and PFC containing equipment located within 
that facility exceeds 17,820 pounds.



Sec. 98.302  GHGs to report.

    You must report total SF6 and PFC emissions from your 
facility (including emissions from fugitive equipment leaks, 
installation, servicing, equipment decommissioning and disposal, and 
from storage cylinders) resulting from the transmission and distribution 
servicing inventory and equipment listed in Sec. 98.300(a). For 
acquisitions of equipment containing or insulated with SF6 or 
PFCs, you must report emissions from the equipment after the title to 
the equipment is transferred to the electric power transmission or 
distribution entity.



Sec. 98.303  Calculating GHG emissions.

    (a) Calculate the annual SF6 and PFC emissions using the 
mass-balance approach in Equation DD-1 of this section:

[[Page 959]]

[GRAPHIC] [TIFF OMITTED] TR01DE10.053


where:

Decrease in SF6 Inventory = (pounds of SF6 stored 
          in containers, but not in energized equipment, at the 
          beginning of the year) - (pounds of SF6 stored in 
          containers, but not in energized equipment, at the end of the 
          year).
Acquisitions of SF6 = (pounds of SF6 purchased 
          from chemical producers or distributors in bulk) + (pounds of 
          SF6 purchased from equipment manufacturers or 
          distributors with or inside equipment, including hermetically 
          sealed-pressure switchgear) + (pounds of SF6 
          returned to facility after off-site recycling).
Disbursements of SF6 = (pounds of SF6 in bulk and 
          contained in equipment that is sold to other entities) + 
          (pounds of SF6 returned to suppliers) + (pounds of 
          SF6 sent off site for recycling) + (pounds of 
          SF6 sent off-site for destruction).
Net Increase in Total Nameplate Capacity of Equipment Operated = (The 
          Nameplate Capacity of new equipment in pounds, including 
          hermetically sealed-pressure switchgear) - (Nameplate Capacity 
          of retiring equipment in pounds, including hermetically 
          sealed-pressure switchgear). (Note that Nameplate Capacity 
          refers to the full and proper charge of equipment rather than 
          to the actual charge, which may reflect leakage).

    (b) Use Equation DD-1 of this section to estimate emissions of PFCs 
from power transformers, substituting the relevant PFC(s) for 
SF6 in the equation.



Sec. 98.304  Monitoring and QA/QC requirements.

    (a) For calendar year 2011 monitoring, you may follow the provisions 
of Sec. 98.3(d)(1) through (d)(2) for best available monitoring methods 
rather than follow the monitoring requirements of this section. For 
purposes of this subpart, any reference in Sec. 98.3(d)(1) through 
(d)(2) to 2010 means 2011, to March 31 means June 30, and to April 1 
means July 1. Any reference to the effective date in Sec. 98.3(d)(1) 
through (d)(2) means February 28, 2011.
    (b) You must adhere to the following QA/QC methods for reviewing the 
completeness and accuracy of reporting:
    (1) Review inputs to Equation DD-1 of this section to ensure inputs 
and outputs to the company's system are included.
    (2) Do not enter negative inputs and confirm that negative emissions 
are not calculated. However, the Decrease in SF6 Inventory 
and the Net Increase in Total Nameplate Capacity may be calculated as 
negative numbers.
    (3) Ensure that beginning-of-year inventory matches end-of-year 
inventory from the previous year.
    (4) Ensure that in addition to SF6 purchased from bulk 
gas distributors, SF6 purchased from Original Equipment 
Manufacturers (OEM) and SF6 returned to the facility from 
off-site recycling are also accounted for among the total additions.
    (c) Ensure the following QA/QC methods are employed throughout the 
year:
    (1) Ensure that cylinders returned to the gas supplier are 
consistently weighed on a scale that is certified to be accurate and 
precise to within 2 pounds of true weight and is periodically 
recalibrated per the manufacturer's specifications. Either measure 
residual gas (the amount of gas remaining in returned cylinders) or have 
the gas supplier measure it. If the gas supplier weighs the residual 
gas, obtain from the gas supplier a detailed monthly accounting, within 
 2 pounds, of residual gas amounts in the 
cylinders returned to the gas supplier.
    (2) Ensure that cylinders weighed for the beginning and end of year 
inventory measurements are weighed on a scale that is certified to be 
accurate and precise to within 2 pounds of true weight and is 
periodically recalibrated per the manufacturer's specifications. All 
scales used to measure quantities that are to be reported under Sec. 
98.306 must be calibrated using calibration

[[Page 960]]

procedures specified by the scale manufacturer. Calibration must be 
performed prior to the first reporting year. After the initial 
calibration, recalibration must be performed at the minimum frequency 
specified by the manufacturer.
    (3) Ensure all substations have provided information to the manager 
compiling the emissions report (if it is not already handled through an 
electronic inventory system).
    (d) GHG Monitoring Plans, as described in Sec. 98.3(g)(5), must be 
completed by April 1, 2011.

[74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71966, Nov. 29, 2013]



Sec. 98.305  Procedures for estimating missing data.

    A complete record of all measured parameters used in the GHG 
emissions calculations is required. Replace missing data, if needed, 
based on data from equipment with a similar nameplate capacity for 
SF6 and PFC, and from similar equipment repair, replacement, 
and maintenance operations.



Sec. 98.306  Data reporting requirements.

    In addition to the information required by Sec. 98.3(c), each 
annual report must contain the following information for each electric 
power system, by chemical:
    (a) Nameplate capacity of equipment (pounds) containing 
SF6 and nameplate capacity of equipment (pounds) containing 
each PFC:
    (1) Existing at the beginning of the year (excluding hermetically 
sealed-pressure switchgear).
    (2) New during the year (all SF6-insulated equipment, 
including hermetically sealed-pressure switchgear).
    (3) Retired during the year (all SF6-insulated equipment, 
including hermetically sealed-pressure switchgear).
    (b) Transmission miles (length of lines carrying voltages above 35 
kilovolt).
    (c) Distribution miles (length of lines carrying voltages at or 
below 35 kilovolt).
    (d) Pounds of SF6 and PFC stored in containers, but not 
in energized equipment, at the beginning of the year.
    (e) Pounds of SF6 and PFC stored in containers, but not in energized 
equipment, at the end of the year.
    (f) Pounds of SF6 and PFC purchased in bulk from chemical 
producers or distributors.
    (g) Pounds of SF6 and PFC purchased from equipment 
manufacturers or distributors with or inside equipment, including 
hermetically sealed-pressure switchgear.
    (h) Pounds of SF6 and PFC returned to facility after off-
site recycling.
    (i) Pounds of SF6 and PFC in bulk and contained in 
equipment sold to other entities.
    (j) Pounds of SF6 and PFC returned to suppliers.
    (k) Pounds of SF6 and PFC sent off-site for recycling.
    (l) Pounds of SF6 and PFC sent off-site for destruction.



Sec. 98.307  Records that must be retained.

    In addition to the information required by Sec. 98.3(g), you must 
retain records of the information reported and listed in Sec. 98.306.



Sec. 98.308  Definitions.

    Except as specified in this section, all terms used in this subpart 
have the same meaning given in the Clean Air Act and subpart A of this 
part.
    Facility, with respect to an electric power system, means the 
electric power system as defined in this paragraph. An electric power 
system is comprised of all electric transmission and distribution 
equipment insulated with or containing SF6 or PFCs that is 
linked through electric power transmission or distribution lines and 
functions as an integrated unit, that is owned, serviced, or maintained 
by a single electric power transmission or distribution entity (or 
multiple entities with a common owner), and that is located between: (1) 
The point(s) at which electric energy is obtained from an electricity 
generating unit or a different electric power transmission or 
distribution entity that does not have a common owner, and (2) the 
point(s) at which any customer or another electric power transmission or 
distribution entity that does not have a common owner receives the 
electric energy. The

[[Page 961]]

facility also includes servicing inventory for such equipment that 
contains SF6 or PFCs.
    Electric power transmission or distribution entity means any entity 
that transmits, distributes, or supplies electricity to a consumer or 
other user, including any company, electric cooperative, public electric 
supply corporation, a similar Federal department (including the Bureau 
of Reclamation or the Corps of Engineers), a municipally owned electric 
department offering service to the public, an electric public utility 
district, or a jointly owned electric supply project.
    Operator, for the purposes of this subpart, means any person who 
operates or supervises a facility, excluding a person whose sole 
responsibility is to ensure reliability, balance load or otherwise 
address electricity flow.



                 Subpart EE_Titanium Dioxide Production



Sec. 98.310  Definition of the source category.

    The titanium dioxide production source category consists of 
facilities that use the chloride process to produce titanium dioxide.



Sec. 98.311  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains a titanium dioxide production process and the facility meets 
the requirements of either Sec. 98.2(a)(1) or (a)(2).



Sec. 98.312  GHGs to report.

    (a) You must report CO2 process emissions from each 
chloride process line as required in this subpart.
    (b) You must report CO2, CH4, and 
N2O emissions from each stationary combustion unit under 
subpart C of this part (General Stationary Fuel Combustion Sources) by 
following the requirements of subpart C.



Sec. 98.313  Calculating GHG emissions.

    You must calculate and report the annual process CO2 
emissions for each chloride process line using the procedures in either 
paragraph (a) or (b) of this section.
    (a) Calculate and report under this subpart the process 
CO2 emissions by operating and maintaining a CEMS according 
to the Tier 4 Calculation Methodology specified in Sec. 98.33(a)(4) and 
all associated requirements for Tier 4 in subpart C of this part 
(General Stationary Fuel Combustion Sources).
    (b) Calculate and report under this subpart the annual process 
CO2 emissions for each chloride process line by determining 
the mass of calcined petroleum coke consumed in each line as specified 
in paragraphs (b)(1) through (b)(3) of this section. Use Equation EE-1 
of this section to calulate annual combined process CO2 
emissions from all process lines and use Equation EE-2 of this section 
to calculate annual process CO2 emissions for each process 
line. If your facility generates carbon-containing waste, use Equation 
EE-3 of this section to estimate the annual quantity of carbon-
containing waste generated and its carbon contents according to Sec. 
98.314(e) and (f):
    (1) You must calculate the annual CO2 process emissions 
from all process lines at the facility using Equation EE-1 of this 
section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.123

Where:

CO2 = Annual CO2 emissions from titanium dioxide 
          production facility (metric tons/year).
Ep = Annual CO2 emissions from chloride process 
          line p (metric tons), determined using Equation EE-2 of this 
          section.
p = Process line.
m = Number of separate chloride process lines located at the facility.

    (2) You must calculate the annual CO2 process emissions 
from each process lines at the facility using Equation EE-2 of this 
section:

[[Page 962]]

[GRAPHIC] [TIFF OMITTED] TR30OC09.124

Where:

Ep = Annual CO2 mass emissions from chloride 
          process line p (metric tons).
Cp,n = Calcined petroleum coke consumption for process line p 
          in month n (tons).
44/12 = Ratio of molecular weights, CO2 to carbon.
2000/2205 = Conversion of tons to metric tons.
CCFn = Carbon content factor for petroleum coke consumed in 
          month n from the supplier or as measured by the applicable 
          method incorporated by reference in Sec. 98.7 according to 
          Sec. 98.314(c) (percent by weight expressed as a decimal 
          fraction).
n = Number of month.

    (3) If facility generates carbon-containing waste, you must 
calculate the total annual quantity of carbon-containing waste produced 
from all process lines using Equation EE-3 of this section and its 
carbon contents according to Sec. 98.314(e) and (f):
[GRAPHIC] [TIFF OMITTED] TR30OC09.125

Where:

TWC = Annual production of carbon-containing waste from titanium dioxide 
          production facility (tons).
WCp,n = Production of carbon-containing waste in month n from 
          chloride process line p (tons).
p = Process line.
m = Total number of process lines.
n = Number of month.

    (c) If GHG emissions from a chloride process line are vented through 
the same stack as any combustion unit or process equipment that reports 
CO2 emissions using a CEMS that complies with the Tier 4 
Calculation Methodology in subpart C of this part (General Stationary 
Fuel Combustion Sources), then the calculation methodology in paragraph 
(b) of this section shall not be used to calculate process 
CO2 emissions. The owner or operator shall report under this 
subpart the combined stack emissions according to the Tier 4 Calculation 
Methodology in Sec. 98.33(a)(4) and all associated requirements for 
Tier 4 in subpart C of this part.



Sec. 98.314  Monitoring and QA/QC requirements.

    (a) You must measure your consumption of calcined petroleum coke 
using plant instruments used for accounting purposes including direct 
measurement weighing the petroleum coke fed into your process (by belt 
scales or a similar device) or through the use of purchase records.
    (b) You must document the procedures used to ensure the accuracy of 
monthly calcined petroleum coke consumption measurements.
    (c) You must determine the carbon content of the calcined petroleum 
coke each month based on reports from the supplier. Alternatively, 
facilities can measure monthly carbon contents of the petroleum coke 
using ASTM D3176-89 (Reapproved 2002) Standard Practice for Ultimate 
Analysis of Coal and Coke (incorporated by reference, see Sec. 98.7) 
and ASTM D5373-08 Standard Test Methods for Instrumental Determination 
of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal 
(incorporated by reference, see Sec. 98.7).
    (d) For quality assurance and quality control of the supplier data, 
you must conduct an annual measurement of the carbon content from a 
representative sample of the petroleum coke consumed using ASTM D3176-89 
and ASTM D5373-08.
    (e) You must determine the quantity of carbon-containing waste 
generated from each titanium dioxide production line on a monthly basis 
using plant instruments used for accounting purposes including direct 
measurement weighing the carbon-containing waste not used during the 
process (by belt scales or a similar device) or through the use of sales 
records.
    (f) You must determine the carbon contents of the carbon-containing 
waste from each titanium production line on an annual basis by 
collecting and analyzing a representative sample

[[Page 963]]

of the material using ASTM D3176-89 and ASTM D5373-08.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66469, Oct. 28, 2010]



Sec. 98.315  Procedures for estimating missing data.

    For the petroleum coke input procedure in Sec. 98.313(b), a 
complete record of all measured parameters used in the GHG emissions 
calculations is required (e.g., carbon content values, etc.). Therefore, 
whenever the monitoring and quality assurance procedures in Sec. 98.315 
cannot be followed, a substitute data value for the missing parameter 
shall be used in the calculations as specified in the paragraphs (a) 
through (c) of this section. You must document and keep records of the 
procedures used for all such estimates.
    (a) For each missing value of the monthly carbon content of calcined 
petroleum coke the substitute data value shall be the arithmetic average 
of the quality-assured values of carbon contents for the month 
immediately preceding and the month immediately following the missing 
data incident. If no quality-assured data on carbon contents are 
available prior to the missing data incident, the substitute data value 
shall be the first quality-assured value for carbon contents obtained 
after the missing data period.
    (b) For each missing value of the monthly calcined petroleum coke 
consumption and/or carbon-containing waste, the substitute data value 
shall be the best available estimate of the monthly petroleum coke 
consumption based on all available process data or information used for 
accounting purposes (such as purchase records).
    (c) For each missing value of the carbon content of carbon-
containing waste, you must conduct a new analysis following the 
procedures in Sec. 98.314(f).



Sec. 98.316  Data reporting requirements.

    In addition to the information required by Sec. 98.3(c), each 
annual report must contain the information specified in paragraphs (a) 
or (b) of this section, as applicable for each titanium dioxide 
production line.
    (a) If a CEMS is used to measure CO2 emissions, then you 
must report the relevant information required under Sec. 
98.36(e)(2)(vi) for the Tier 4 Calculation Methodology and the following 
information in this paragraph (a).
    (1) Identification number of each process line.
    (2) Annual consumption of calcined petroleum coke (tons).
    (3) Annual production of titanium dioxide (tons).
    (4) Annual production capacity of titanium dioxide (tons).
    (5) Annual production of carbon-containing waste (tons), if 
applicable.
    (b) If a CEMS is not used to measure CO2 emissions, then 
you must report the information listed in this paragraph (b):
    (1) Identification number of each process line.
    (2) Annual CO2 emissions from each chloride process line 
(metric tons/year).
    (3) Annual consumption of calcined petroleum coke for each process 
line (tons).
    (4) Annual production of titanium dioxide for each process line 
(tons).
    (5) Annual production capacity of titanium dioxide for each process 
line (tons).
    (6) [Reserved]
    (7) Annual production of carbon-containing waste for each process 
line (tons), if applicable.
    (8) Monthly production of titanium dioxide for each process line 
(tons).
    (9) [Reserved]
    (10) Whether monthly carbon content of the petroleum coke is based 
on reports from the supplier or through self measurement using 
applicable ASTM standard methods.
    (11) Carbon content for carbon-containing waste for each process 
line (percent by weight expressed as a decimal fraction).
    (12) If carbon content of petroleum coke is based on self 
measurement, the ASTM standard methods used.
    (13) Sampling analysis results of carbon content of petroleum coke 
as determined for QA/QC of supplier data under Sec. 98.314(d) (percent 
by weight expressed as a decimal fraction).
    (14) Number of separate chloride process lines located at the 
facility.

[[Page 964]]

    (15) The number of times in the reporting year that missing data 
procedures were followed to measure the carbon contents of petroleum 
coke (number of months); petroleum coke consumption (number of months); 
carbon-containing waste generated (number of months); and carbon 
contents of the carbon-containing waste (number of times during year).

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66469, Oct. 28, 2010; 
79 FR 63799, Oct. 24, 2014]



Sec. 98.317  Records that must be retained.

    In addition to the records required by Sec. 98.3(g), you must 
retain the records specified in paragraphs (a) through (c) of this 
section for each titanium dioxide production facility.
    (a) If a CEMS is used to measure CO2 emissions, then you 
must retain under this subpart required for the Tier 4 Calculation 
Methodology in Sec. 98.37 and the information listed in this paragraph 
(a):
    (1) Records of all calcined petroleum coke purchases.
    (2) Annual operating hours for each titanium dioxide process line.
    (b) If a CEMS is not used to measure CO2 emissions, then 
you must retain records for the information listed in this paraghraph:
    (1) Records of all calcined petroleum coke purchases (tons).
    (2) Records of all analyses and calculations conducted for all 
reported data as listed in Sec. 98.316(b).
    (3) Sampling analysis results for carbon content of consumed 
calcined petroleum coke (percent by weight expressed as a decimal 
fraction).
    (4) Sampling analysis results for the carbon content of carbon 
containing waste (percent by weight expressed as a decimal fraction), if 
applicable.
    (5) Monthly production of carbon-containing waste (tons).
    (6) You must document the procedures used to ensure the accuracy of 
the monthly petroleum coke consumption and quantity of carbon-containing 
waste measurement including, but not limited to, calibration of weighing 
equipment and other measurement devices. The estimated accuracy of 
measurements made with these devices must also be recorded, and the 
technical basis for these estimates must be provided.
    (7) Annual operating hours for each titanium dioxide process line 
(hours).
    (c) Verification software records. You must keep a record of the 
file generated by the verification software specified in Sec. 98.5(b) 
for the applicable data specified in paragraphs (c)(1) and (2) of this 
section. Retention of this file satisfies the recordkeeping requirement 
for the data in paragraphs (c)(1) and (2) of this section.
    (1) Carbon content factor for petroleum coke consumed in month from 
the supplier or as measured by the applicable method incorporated by 
reference in Sec. 98.7 according to Sec. 98.314(c) (percent by weight, 
expressed as a decimal fraction) (Equation EE-2 of Sec. 98.313).
    (2) Calcined petroleum coke consumption for process line in month 
(tons) (Equation EE-2).

[74 FR 56374, Oct. 30, 2009, as amended at 79 FR 63799, Oct. 24, 2014]



Sec. 98.318  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.



                    Subpart FF_Underground Coal Mines

    Source: 75 FR 39763, July 12, 2010, unless otherwise noted.



Sec. 98.320  Definition of the source category.

    (a) This source category consists of active underground coal mines, 
and any underground mines under development that have operational pre-
mining degasification systems. An underground coal mine is a mine at 
which coal is produced by tunneling into the earth to the coalbed, which 
is then mined with underground mining equipment such as cutting machines 
and continuous, longwall, and shortwall mining machines, and transported 
to the surface. Underground coal mines are categorized as active if any 
one of the following five conditions apply:
    (1) Mine development is underway.

[[Page 965]]

    (2) Coal has been produced within the last 90 days.
    (3) Mine personnel are present in the mine workings.
    (4) Mine ventilation fans are operative.
    (5) The mine is designated as an ''intermittent'' mine by the Mine 
Safety and Health Administration (MSHA).
    (b) This source category includes the following:
    (1) Each ventilation system shaft or vent hole, including both those 
points where mine ventilation air is emitted and those where it is sold, 
used onsite, or otherwise destroyed (including by ventilation air 
methane (VAM) oxidizers).
    (2) Each degasification system well or gob gas vent hole, including 
degasification systems deployed before, during, or after mining 
operations are conducted in a mine area. This includes both those wells 
and vent holes where coal bed gas is emitted, and those where the gas is 
sold, used onsite, or otherwise destroyed (including by flaring).
    (c) This source category does not include abandoned or closed mines, 
surface coal mines, or post-coal mining activities (e.g., storage or 
transportation of coal).

[74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71966, Nov. 29, 2013]



Sec. 98.321  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains an active underground coal mine and the facility meets the 
requirements of Sec. 98.2(a)(1).



Sec. 98.322  GHGs to report.

    (a) You must report CH4 liberated from ventilation and 
degasification systems.
    (b) You must report CH4 destruction from systems where 
gas is sold, used onsite, or otherwise destroyed (including by VAM 
oxidation and by flaring).
    (c) You must report net CH4 emissions from ventilation 
and degasification systems.
    (d) You must report under this subpart the CO2 emissions 
from coal mine gas CH4 destruction occurring at the facility, 
where the gas is not a fuel input for energy generation or use (e.g., 
flaring and VAM oxidation).
    (e) You must report under subpart C of this part (General Stationary 
Fuel Combustion Sources) the CO2, CH4, and 
N2O emissions from each stationary fuel combustion unit by 
following the requirements of subpart C. Report emissions from both the 
combustion of collected coal mine CH4 and any other fuels.
    (f) An underground coal mine that is subject to this part because 
emissions from source categories described in Tables A-3, A-4 or A-5 of 
subpart A of this part, or from stationary combustion (subpart C of this 
part), is not required to report emissions under this subpart unless the 
coal mine liberates 36,500,000 actual cubic feet (acf) or more of 
methane per year from its ventilation system.

[75 FR 39763, July 12, 2010, as amended at 76 FR 73901, Nov. 29, 2011; 
78 FR 71966, Nov. 29, 2013]



Sec. 98.323  Calculating GHG emissions.

    (a) For each ventilation shaft, vent hole, or centralized point into 
which CH4 from multiple shafts and/or vent holes are 
collected, you must calculate the quarterly CH4 liberated 
from the ventilation system using Equation FF-1 of this section. You 
must measure CH4 content, flow rate, temperature, pressure, 
and moisture content of the gas using the procedures outlined in Sec. 
98.324.
[GRAPHIC] [TIFF OMITTED] TR12JY10.004

Where:

CH4V = Quarterly CH4 liberated from a ventilation 
          monitoring point (metric tons CH4).

[[Page 966]]

V = Volumetric flow rate for the quarter (acfm) based on sampling or a 
          flow rate meter. If a flow rate meter is used and the meter 
          automatically corrects to standard temperature and pressure, 
          then use scfm and replace ``520 deg.R/T x P/1 atm'' with 
          ``1''.
MCF = Moisture correction factor for the measurement period, volumetric 
          basis.
    = 1 when V and C are measured on a dry basis or if both are measured 
on a wet basis.
    = 1-(fH2O) when V is measured on a wet basis and C is 
measured on a dry basis.
    = 1/[1-(fH2O)] when V is measured on a dry basis and C is 
measured on a wet basis.
(fH2O) = Moisture content of the CH4 emitted 
          during the measurement period, volumetric basis (cubic feet 
          water per cubic feet emitted gas).
C = CH4 concentration of ventilation gas for the quarter (%).
n = The number of days in the quarter where active ventilation of mining 
          operations is taking place at the monitoring point.
0.0423 = Density of CH4 at 520  deg.R (60  deg.F) and 1 atm 
          (lb/scf).
520  deg.R = 520 degrees Rankine.
T = Temperature at which flow is measured ( deg.R) for the quarter.
P = Absolute pressure at which flow is measured (atm) for the quarter. 
          The annual average barometric pressure from the nearest NOAA 
          weather service station may be used as a default.
1,440 = Conversion factor (min/day).
0.454/1,000 = Conversion factor (metric ton/lb).

    (1) Consistent with MSHA inspections, the quarterly periods are:
    (i) January 1-March 31.
    (ii) April 1-June 30.
    (iii) July 1-September 30.
    (iv) October 1-December 31.
    (2) Values of V, C, T, P, and (fH2O), if applicable, must 
be based on measurements taken at least once each quarter with no fewer 
than 6 weeks between measurements. If measurements are taken more 
frequently than once per quarter, then use the average value for all 
measurements taken. If continuous measurements are taken, then use the 
average value over the time period of continuous monitoring.
    (3) If a facility has more than one monitoring point, the facility 
must calculate total CH4 liberated from ventilation systems 
(CH4VTotal) as the sum of the CH4 from all 
ventilation monitoring points in the mine, as follows:
[GRAPHIC] [TIFF OMITTED] TR12JY10.005

Where:

CH4VTotal = Total quarterly CH4 liberated from 
          ventilation systems (metric tons CH4).
CH4V = Quarterly CH4 liberated from each 
          ventilation monitoring point (metric tons CH4).
m = Number of ventilation monitoring points.

    (b) For each monitoring point in the degasification system (this 
could be at each degasification well and/or vent hole, or at more 
centralized points into which CH4 from multiple wells and/or 
vent holes are collected), you must calculate the weekly CH4 
liberated from the mine using CH4 measured weekly or more 
frequently (including by CEMS) according to 98.234(c), CH4 
content, flow rate, temperature, pressure, and moisture content, and 
Equation FF-3 of this section.
[GRAPHIC] [TIFF OMITTED] TR29NO13.018

Where:
CH4D = Weekly CH4 liberated from at the monitoring 
          point (metric tons CH4).
Vi = Measured volumetric flow rate for the days in the week 
          when the degasification system is in operation at that 
          monitoring point, based on sampling or a flow rate meter 
          (acfm). If a flow rate meter is used and the meter 
          automatically corrects to standard temperature and pressure, 
          then use scfm and replace ``520 deg.R/Ti x 
          Pi/1 atm'' with ``1''.
MCFi = Moisture correction factor for the measurement period, 
          volumetric basis.
    = 1 when Vi and Ci are measured on a dry basis 
or if both are measured on a wet basis.
    = 1-(fH2O)I when Vi is measured on 
a wet basis and Ci is measured on a dry basis.
    = 1/[1-(fH2O)i] when Vi is measured 
on a dry basis and Ci is measured on a wet basis.

[[Page 967]]

(fH2O) = Moisture content of the CH4 emitted 
          during the measurement period, volumetric basis (cubic feet 
          water per cubic feet emitted gas).
Ci = CH4 concentration of gas for the days in the 
          week when the degasification system is in operation at that 
          monitoring point (%).
n = The number of days in the week that the system is operational at 
          that measurement point.
0.0423 = Density of CH4 at 520  deg.R (60  deg.F) and 1 atm 
          (lb/scf).
520  deg.R = 520 degrees Rankine.
Ti = Temperature at which flow is measured ( deg.R).
Pi = Absolute pressure at which flow is measured (atm).
1,440 = Conversion factor (minutes/day).
0.454/1,000 = Conversion factor (metric ton/lb).

    (1) Values for V, C, T, P, and (fH2O), if applicable, 
must be based on measurements taken at least once each calendar week 
with at least 3 days between measurements. If measurements are taken 
more frequently than once per week, then use the average value for all 
measurements taken that week. If continuous measurements are taken, then 
use the average values over the time period of continuous monitoring 
when the continuous monitoring equipment is properly functioning.
    (2) Quarterly total CH4 liberated from degasification 
systems for the mine should be determined as the sum of CH4 
liberated determined at each of the monitoring points in the mine, 
summed over the number of weeks in the quarter, as follows:
[GRAPHIC] [TIFF OMITTED] TR12JY10.007

Where:
CH4DTotal = Quarterly CH4 liberated from all 
          degasification monitoring points (metric tons CH4).
(CH4D)i,j = Weekly CH4 liberated from a 
          degasification monitoring point (metric tons CH4).
m = Number of monitoring points.
w = Number of weeks in the quarter during which the degasification 
          system is operated.
    (c) If gas from a degasification system or ventilation system is 
sold, used onsite, or otherwise destroyed (including by flaring or VAM 
oxidation), you must calculate the quarterly CH4 destroyed 
for each destruction device and each point of offsite transport to a 
destruction device, using Equation FF-5 of this section. You must 
measure CH4 content and flow rate according to the provisions 
in Sec. 98.324, and calculate the methane routed to the destruction 
device (CH4) using either Equation FF-1 or Equation FF-4 of 
this section, as applicable.
[GRAPHIC] [TIFF OMITTED] TR12JY10.008

Where:
CH4Destroyed = Quarterly CH4 destroyed (metric 
          tons).
CH4 = Quarterly CH4 routed to the destruction 
          device or offsite transfer point (metric tons).
DE = Destruction efficiency (lesser of manufacturer's specified 
          destruction efficiency and 0.99). If the gas is transported 
          off-site for destruction, use DE = 1.

    (1) Calculate total CH4 destroyed as the sum of the 
methane destroyed at all destruction devices (onsite and offsite), using 
Equation FF-6 of this section.
[GRAPHIC] [TIFF OMITTED] TR29NO13.019

Where:
CH4DestroyedTotal = Quarterly total CH4 destroyed 
          at the mine (metric tons CH4).

[[Page 968]]

CH4Destroyed = Quarterly CH4 destroyed from each 
          destruction device or offsite transfer point.
d = Number of onsite destruction devices and points of offsite 
          transport.

    (2) [Reserved]
    (d) You must calculate the quarterly measured net CH4 
emissions to the atmosphere using Equation FF-7 of this section.
[GRAPHIC] [TIFF OMITTED] TR12JY10.010

Where:
CH4 emitted (net)= Quarterly CH4 emissions from 
          the mine (metric tons).
CH4VTotal = Quarterly sum of the CH4 liberated 
          from all mine ventilation monitoring points (CH4V), 
          calculated using Equation FF-2 of this section (metric tons).
CH4DTotal = Quarterly sum of the CH4 liberated 
          from all mine degasification monitoring points 
          (CH4D), calculated using Equation FF-4 of this 
          section (metric tons).
CH4DestroyedTotal = Quarterly sum of the measured 
          CH4 destroyed from all mine ventilation and 
          degasification systems, calculated using Equation FF-6 of this 
          section (metric tons).

    (e) For the methane collected from degasification and/or ventilation 
systems that is destroyed on site and is not a fuel input for energy 
generation or use (those emissions are monitored and reported under 
Subpart C of this part), you must estimate the CO2 emissions 
using Equation FF-8 of this section.
[GRAPHIC] [TIFF OMITTED] TR12JY10.011

Where:
CO2 = Total quarterly CO2 emissions from 
          CH4 destruction (metric tons).
CH4Destroyedonsite = Quarterly sum of the CH4 
          destroyed, calculated as the sum of CH4 destroyed 
          for each onsite, non-energy use, as calculated individually in 
          Equation FF-5 of this section (metric tons).
44/16 = Ratio of molecular weights of CO2 to CH4.

[75 FR 39763, July 12, 2010, as amended at 76 FR 73901, Nov. 29, 2011; 
78 FR 71967, Nov. 29, 2013]



Sec. 98.324  Monitoring and QA/QC requirements.

    (a) For calendar year 2011 monitoring, the facility may submit a 
request to the Administrator to use one or more best available 
monitoring methods as listed in Sec. 98.3(d)(1)(i) through (iv). The 
request must be submitted no later than October 12, 2010 and must 
contain the information in Sec. 98.3(d)(2)(ii). To obtain approval, the 
request must demonstrate to the Administrator's satisfaction that it is 
not reasonably feasible to acquire, install, and operate a required 
piece of monitoring equipment by January 1, 2011. The use of best 
available monitoring methods will not be approved beyond December 31, 
2011.
    (b) For CH4 liberated from ventilation systems, determine 
whether CH4 will be monitored from each ventilation shaft and 
vent hole, from a centralized monitoring point, or from a combination of 
the two options. Operators are allowed flexibility for aggregating 
emissions from more than one ventilation point, as long as emissions 
from all are addressed, and the methodology for calculating total 
emissions documented. Monitor by one of the following options:
    (1) Collect quarterly or more frequent grab samples (with no fewer 
than 6 weeks between measurements) for methane concentration and make 
quarterly measurements of flow rate, temperature, pressure, and moisture 
content, if applicable. The sampling and measurements must be made at 
the same locations as Mine Safety and Health Administration (MSHA) 
inspection samples are taken, and should be taken when the mine is 
operating

[[Page 969]]

under normal conditions. You must follow MSHA sampling procedures as set 
forth in the MSHA Handbook entitled, General Coal Mine Inspection 
Procedures and Inspection Tracking System Handbook Number: PH-08-V-1, 
January 1, 2008 (incorporated by reference, see Sec. 98.7). You must 
record the date of sampling, flow, temperature, pressure, and moisture 
measurements, the methane concentration (percent), the bottle number of 
samples collected, and the location of the measurement or collection.
    (2) Obtain results of the quarterly (or more frequent) testing 
performed by MSHA for the methane flowrate. At the same location and 
within seven days of the MSHA sampling, make measurements of temperature 
and pressure using the same procedures specified in paragraph (b)(1) of 
this section. The annual average barometric pressure from the nearest 
National Oceanic and Atmospheric Administration (NOAA) weather service 
station may be used as a default for pressure. If the MSHA data for 
methane flow is provided in the units of actual cubic feet of methane 
per day, the methane flow data is inserted into Equation FF-1 of this 
section in place of the value for V and the variables MCF, C/100%, and 
1440 are removed from the equation.
    (3) Monitor emissions through the use of one or more continuous 
emission monitoring systems (CEMS). If operators use CEMS as the basis 
for emissions reporting, they must provide documentation on the process 
for using data obtained from their CEMS to estimate emissions from their 
mine ventilation systems.
    (c) For CH4 liberated at degasification systems, 
determine whether CH4 will be monitored from each well and 
gob gas vent hole, from a centralized monitoring point, or from a 
combination of the two options. Operators are allowed flexibility for 
aggregating emissions from more than one well or gob gas vent hole, as 
long as emissions from all are addressed, and the methodology for 
calculating total emissions is documented. Monitor both gas volume and 
methane concentration by one of the following two options:
    (1) Monitor emissions through the use of one or more continuous 
emissions monitoring systems (CEMS). If operators use CEMS as the basis 
for emissions reporting, they must provide documentation on the process 
for using data obtained from their CEMS to estimate emissions from their 
mine ventilation systems.
    (2) Collect weekly (once each calendar week, with at least three 
days between measurements) or more frequent samples, for all 
degasification wells and gob gas vent holes. Determine weekly or more 
frequent flow rates, methane concentration, temperature, and pressure 
from these degasification wells and gob gas vent holes. Methane 
composition should be determined either by submitting samples to a lab 
for analysis, or from the use of methanometers at the degasification 
monitoring site. Follow the sampling protocols for sampling of methane 
emissions from ventilation shafts, as described in Sec. 98.324(b)(1). 
You must record the date of sampling, flow, temperature, pressure, and 
moisture measurements, the methane concentration (percent), the bottle 
number of samples collected, and the location of the measurement or 
collection.
    (3) If the CH4 concentration is determined on a dry basis 
and flow is determined on a wet basis or CH4 concentration is 
determined on a wet basis and flow is determined on a dry basis, and the 
flow meter does not automatically correct for moisture content, 
determine the moisture content in the gas in a location near or 
representative of the location of:
    (i) The gas flow meter at least once each calendar week; if 
measuring with CEMS. If only one measurement is made each calendar week, 
there must be at least three days between measurements; and
    (ii) The grab sample, if using grab samples, at the time of the 
sample.
    (d) Monitoring must adhere to one of the methods specified in 
paragraphs (d)(1) through (d)(2) of this section.
    (1) ASTM D1945-03, Standard Test Method for Analysis of Natural Gas 
by Gas Chromatography; ASTM D1946-90 (Reapproved 2006), Standard 
Practice for Analysis of Reformed Gas by Gas

[[Page 970]]

Chromatography; ASTM D4891-89 (Reapproved 2006), Standard Test Method 
for Heating Value of Gases in Natural Gas Range by Stoichiometric 
Combustion; or ASTM UOP539-97 Refinery Gas Analysis by Gas 
Chromatography (incorporated by reference, see Sec. 98.7).
    (2) As an alternative to the gas chromatography methods provided in 
paragraph (d)(1) of this section, you may use gaseous organic 
concentration analyzers and a correction factor to calculate the 
CH4 concentration following the requirements in paragraphs 
(d)(2)(i) through (d)(2)(iii) of this section.
    (i) Use Method 25A or 25B at 40 CFR part 60, appendix A-7 to 
determine gaseous organic concentration as required in Sec. 98.323 and 
in paragraphs (b) and (c) of this section. You must calibrate the 
instrument with CH4 and determine the total gaseous organic 
concentration as carbon (or as CH4; K = 1 in Equation 25A-1 
of Method 25A at 40 CFR part 60, appendix A-7).
    (ii) Determine a correction factor that will be used with the 
gaseous organic concentrations measured in paragraph (i) of this 
section. The correction factor must be determined at the routine 
sampling location no less frequently than once a reporting year 
following the requirements in paragraphs (d)(2)(ii)(A) through 
(d)(2)(ii)(C) of this section.
    (A) Take a minimum of three grab samples of the gas with a minimum 
of 20 minutes between samples and determine the methane composition of 
the gas using one of the methods specified in paragraph (d)(1) of this 
section.
    (B) As soon as practical after each grab sample is collected and 
prior to the collection of a subsequent grab sample, determine the 
gaseous organic concentration of the gas using either Method 25A or 25B 
at 40 CFR part 60, appendix A-7 as specified in paragraph (d)(2)(i) of 
this section.
    (C) Determine the arithmetic average methane concentration and the 
arithmetic average gaseous organic concentration of the samples analyzed 
according to paragraphs (d)(2)(ii)(A) and (d)(2)(ii)(B) of this section, 
respectively, and calculate the non-methane organic carbon correction 
factor as the ratio of the average methane concentration to the average 
total gaseous organic concentration. If the ratio exceeds 1, use 1 for 
the correction factor.
    (iii) Calculate the CH4 concentration as specified in 
Equation FF-9 of this section:
[GRAPHIC] [TIFF OMITTED] TR29NO11.000


Where:

CCH4 = Methane (CH4) concentration in the gas 
          (volume %) for use in Equations FF-1 and FF-3 of this subpart.
fNMOC = Correction factor from the most recent determination 
          of the correction factor as specified in paragraph (d)(2)(ii) 
          of this section (unitless).
CTGOC = Gaseous organic carbon concentration measured using 
          Method 25A or 25B at 40 CFR part 60, appendix A-7 during 
          routine monitoring of the gas (volume %).

    (e) All flow meters and gas composition monitors that are used to 
provide data for the GHG emissions calculations shall be calibrated 
prior to the first reporting year, using the applicable methods 
specified in paragraphs (d), and (e)(1) through (e)(7) of this section. 
Alternatively, calibration procedures specified by the flow meter 
manufacturer may be used. Flow meters and gas composition monitors shall 
be recalibrated either at the minimum frequency specified by the 
manufacturer or annually. The operator shall operate, maintain, and 
calibrate a gas composition monitor capable of measuring the 
concentration of CH4 in the gas using one of the methods 
specified in paragraph (d) of this section. The operator shall operate, 
maintain, and calibrate the flow meter using any of the following test 
methods or follow the procedures specified by the flow meter 
manufacturer. Flow meters must meet the accuracy requirements in Sec. 
98.3(i).
    (1) ASME MFC-3M-2004, Measurement of Fluid Flow in Pipes Using 
Orifice, Nozzle, and Venturi (incorporated by reference, see Sec. 
98.7).

[[Page 971]]

    (2) ASME MFC-4M-1986 (Reaffirmed 1997), Measurement of Gas Flow by 
Turbine Meters (incorporated by reference, see Sec. 98.7).
    (3) ASME MFC-6M-1998, Measurement of Fluid Flow in Pipes Using 
Vortex Flowmeters (incorporated by reference, see Sec. 98.7).
    (4) ASME MFC-7M-1987 (Reaffirmed 1992), Measurement of Gas Flow by 
Means of Critical Flow Venturi Nozzles (incorporated by reference, see 
Sec. 98.7).
    (5) ASME MFC-11M-2006 Measurement of Fluid Flow by Means of Coriolis 
Mass Flowmeters (incorporated by reference, see Sec. 98.7).
    (6) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore 
Precision Orifice Meters (incorporated by reference, see Sec. 98.7).
    (7) ASME MFC-18M-2001 Measurement of Fluid Flow using Variable Area 
Meters (incorporated by reference, see Sec. 98.7).
    (f) For CH4 destruction, CH4 must be monitored 
at each onsite destruction device and each point of offsite transport 
for combustion using continuous monitors of gas routed to the device or 
point of offsite transport.
    (g) All temperature, pressure, and moisture content monitors must be 
operated and calibrated using the procedures and frequencies specified 
by the manufacturer.
    (h) If applicable, the owner or operator shall document the 
procedures used to ensure the accuracy of gas flow rate, gas 
composition, temperature, pressure, and moisture content measurements. 
These procedures include, but are not limited to, calibration of flow 
meters, and other measurement devices. The estimated accuracy of 
measurements, and the technical basis for the estimated accuracy shall 
be recorded.

[75 FR 39763, July 12, 2010, as amended at 76 FR 73901, Nov. 29, 2011; 
78 FR 71967, Nov. 29, 2013]



Sec. 98.325  Procedures for estimating missing data.

    (a) A complete record of all measured parameters used in the GHG 
emissions calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable (e.g., if a meter 
malfunctions during unit operation or if a required fuel sample is not 
taken), a substitute data value for the missing parameter shall be used 
in the calculations, in accordance with paragraph (b) of this section.
    (b) For each missing value of CH4 concentration, flow 
rate, temperature, pressure, and moisture content for ventilation and 
degasification systems, the substitute data value shall be the 
arithmetic average of the quality-assured values of that parameter 
immediately preceding and immediately following the missing data 
incident. If, for a particular parameter, no quality-assured data are 
available prior to the missing data incident, the substitute data value 
shall be the first quality-assured value obtained after the missing data 
period.

[75 FR 39763, July 12, 2010, as amended at 76 FR 73903, Nov. 29, 2011]



Sec. 98.326  Data reporting requirements.

    In addition to the information required by Sec. 98.3(c), each 
annual report must contain the following information for each mine:
    (a) Quarterly CH4 liberated from each ventilation 
monitoring point, (metric tons CH4).
    (b) Weekly CH4 liberated from each degasification system 
monitoring point (metric tons CH4).
    (c) Quarterly CH4 destruction at each ventilation and 
degasification system destruction device or point of offsite transport 
(metric tons CH4).
    (d) Quarterly CH4 emissions (net) from all ventilation 
and degasification systems (metric tons CH4).
    (e) Quarterly CO2 emissions from on-site destruction of 
coal mine gas CH4, where the gas is not a fuel input for 
energy generation or use (e.g., flaring) (metric tons CO2).
    (f) Quarterly volumetric flow rate for each ventilation monitoring 
point and units of measure (scfm or acfm), date and location of each 
measurement, and method of measurement (quarterly sampling or continuous 
monitoring), used in Equation FF-1 of this subpart.
    (g) Quarterly CH4 concentration for each ventilation 
monitoring point, dates and locations of each measurement and method of 
measurement (sampling or continuous monitoring).

[[Page 972]]

    (h) Weekly volumetric flow rate used to calculate CH4 
liberated from degasification systems and units of measure (acfm or 
scfm), and method of measurement (sampling or continuous monitoring), 
used in Equation FF-3 of this subpart.
    (i) Quarterly CH4 concentration (%) used to calculate 
CH4 liberated from degasification systems and if the data is 
based on CEMS or weekly sampling.
    (j) Weekly volumetric flow rate used to calculate CH4 
destruction for each destruction device and each point of offsite 
transport, and units of measure (acfm or scfm).
    (k) Weekly CH4 concentration (%) used to calculate 
CH4 flow to each destruction device and each point of offsite 
transport (C).
    (l) Dates in quarterly reporting period where active ventilation of 
mining operations is taking place.
    (m) Dates in quarterly reporting period where degasification of 
mining operations is taking place.
    (n) Dates in quarterly reporting period when continuous monitoring 
equipment is not properly functioning, if applicable.
    (o) Temperatures ( deg.R), pressure (atm), moisture content, and the 
moisture correction factor (if applicable) used in Equation FF-1 and FF-
3 of this subpart; and the gaseous organic concentration correction 
factor, if Equation FF-9 was required.
    (p) For each destruction device, a description of the device, 
including an indication of whether destruction occurs at the coal mine 
or off-site. If destruction occurs at the mine, also report an 
indication of whether a back-up destruction device is present at the 
mine, the annual operating hours for the primary destruction device, the 
annual operating hours for the back-up destruction device (if present), 
and the destruction efficiencies assumed (percent).
    (q) A description of the gas collection system (manufacturer, 
capacity, and number of wells) the surface area of the gas collection 
system (square meters), and the annual operating hours of the gas 
collection system.
    (r) Identification information and description for each well, shaft, 
and vent hole, including paragraphs (r)(1) through (r)(3) of this 
section:
    (1) Indication of whether the well, shaft, or vent hole is monitored 
individually, or as part of a centralized monitoring point. Note which 
method (sampling or continuous monitoring) was used.
    (2) Start date and close date of each well, shaft, and vent hole.
    (3) Number of days the well, shaft, or vent hole was in operation 
during the reporting year.
    (s) For each centralized monitoring point, identification of the 
wells and shafts included in the point. Note which method (sampling or 
continuous monitoring) was used.
    (t) Mine Safety and Health Administration (MSHA) identification for 
this coal mine.

[75 FR 39763, July 12, 2010, as amended at 76 FR 73903, Nov. 29, 2011; 
78 FR 71967, Nov. 29, 2013]



Sec. 98.327  Records that must be retained.

    In addition to the information required by Sec. 98.3(g), you must 
retain the following records:
    (a) Calibration records for all monitoring equipment, including the 
method or manufacturer's specification used for calibration.
    (b) Records of gas sales.
    (c) Logbooks of parameter measurements.
    (d) Laboratory analyses of samples.



Sec. 98.328  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.



                       Subpart GG_Zinc Production



Sec. 98.330  Definition of the source category.

    The zinc production source category consists of zinc smelters and 
secondary zinc recycling facilities.



Sec. 98.331  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains a zinc production process and the facility meets the 
requirements of either Sec. 98.2(a)(1) or (2).

[[Page 973]]



Sec. 98.332  GHGs to report.

    You must report:
    (a) CO2 process emissions from each Waelz kiln and 
electrothermic furnace used for zinc production.
    (b) CO2, CH4, and N2O combustion 
emissions from each Waelz kiln. You must calculate and report these 
emissions under subpart C of this part (General Stationary Fuel 
Combustion Sources) by following the requirements of subpart C.
    (c) CO2, CH4, and N2O emissions 
from each stationary combustion unit other than Waelz kilns. You must 
report these emissions under subpart C of this part (General Stationary 
Fuel Combustion Sources) by following the requirements of subpart C.



Sec. 98.333  Calculating GHG emissions.

    You must calculate and report the annual process CO2 
emissions using the procedures specified in either paragraph (a) or (b) 
of this section.
    (a) Calculate and report under this subpart the process or combined 
process and combustion CO2 emissions by operating and 
maintaining a CEMS according to the Tier 4 Calculation Methodology in 
Sec. 98.33(a)(4) and all associated requirements for Tier 4 in subpart 
C of this part (General Stationary Fuel Combustion Sources).
    (b) Calculate and report under this subpart the process 
CO2 emissions by following paragraphs (b)(1) and (b)(2) of 
this section.
    (1) For each Waelz kiln or electrothermic furnace at your facility 
used for zinc production, you must determine the mass of carbon in each 
carbon-containing material, other than fuel, that is fed, charged, or 
otherwise introduced into each Waelz kiln and electrothermic furnace at 
your facility for each year and calculate annual CO2 process 
emissions from each affected unit at your facility using Equation GG-1 
of this section. For electrothermic furnaces, carbon containing input 
materials include carbon eletrodes and carbonaceous reducing agents. For 
Waelz kilns, carbon containing input materials include carbonaceous 
reducing agents. If you document that a specific material contributes 
less than 1 percent of the total carbon into the process, you do not 
have to include the material in your calculation using Equation R-1 of 
Sec. 98.183.
[GRAPHIC] [TIFF OMITTED] TR30OC09.126

Where:

ECO2k = Annual CO2 process emissions from 
          individual Waelz kiln or electrothermic furnace ``k'' (metric 
          tons).
44/12 = Ratio of molecular weights, CO2 to carbon.
2000/2205 = Conversion factor to convert tons to metric tons.
(Zinc)k = Annual mass of zinc bearing material charged to 
          kiln or furnace ''k'' (tons).
(CZinc)k = Carbon content of the zinc bearing 
          material, from the annual carbon analysis for kiln or furnace 
          ``k'' (percent by weight, expressed as a decimal fraction).
(Flux)k = Annual mass of flux materials (e.g., limestone, 
          dolomite) charged to kiln or furnace ``k'' (tons).
(CFlux)k = Carbon content of the flux materials 
          charged to kiln or furnace ``k'', from the annual carbon 
          analysis (percent by weight, expressed as a decimal fraction).
(Electrode)k = Annual mass of carbon electrode consumed in 
          furnace ``k'' (tons).
(CElectrode)k = Carbon content of the carbon 
          electrode consumed in furnace ``k'', from the annual carbon 
          analysis (percent by weight, expressed as a decimal fraction).
(Carbon)k = Annual mass of carbonaceous materials (e.g., 
          coal, coke) charged to the kiln or furnace ``k''(tons).
(CCarbon)k Carbon content of the carbonaceous 
          materials charged to kiln or furnace, ``k'', from the annual 
          carbon analysis (percent by weight, expressed as a decimal 
          fraction).

    (2) You must determine the CO2 emissions from all of the 
Waelz kilns or electrothermic furnaces at your facility using Equation 
GG-2 of this section.

[[Page 974]]

[GRAPHIC] [TIFF OMITTED] TR30OC09.127

Where:

CO2 = Annual combined CO2 emissions from all Waelz 
          kilns or electrothermic furnaces (tons).
ECO2k = Annual CO2 emissions from each Waelz kiln 
          or electrothermic furnace k calculated using Equation GG-1 of 
          this section (tons).
n = Total number of Waelz kilns or electrothermic furnaces at facility 
          used for the zinc production.

    (c) If GHG emissions from a Waelz kiln or electrothermic furnace are 
vented through the same stack as any combustion unit or process 
equipment that reports CO2 emissions using a CEMS that 
complies with the Tier 4 Calculation Methodology in subpart C of this 
part (General Stationary Fuel Combustion Sources), then the calculation 
methodology in paragraph (b) of this section shall not be used to 
calculate process emissions. The owner or operator shall report under 
this subpart the combined stack emissions according to the Tier 4 
Calculation Methodology in Sec. 98.33(a)(4) and all associated 
requirements for Tier 4 in subpart C of this part.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66470, Oct. 28, 2010]



Sec. 98.334  Monitoring and QA/QC requirements.

    If you determine CO2 emissions using the carbon input 
procedure in Sec. 98.333(b)(1) and (b)(2), you must meet the 
requirements specified in paragraphs (a) and (b) of this section.
    (a) Determine the mass of each solid carbon-containing input 
material consumed using facility instruments, procedures, or records 
used for accounting purposes including direct measurement weighing or 
through the use of purchase records same plant instruments or procedures 
that are used for accounting purposes (such as weigh hoppers, belt weigh 
feeders, weighed purchased quantities in shipments or containers, 
combination of bulk density and volume measurements, etc.). Record the 
total mass for the materials consumed each calendar month and sum the 
monthly mass to determine the annual mass for each input material.
    (b) For each input material identified in paragraph (a) of this 
section, you must determine the average carbon content of the material 
consumed or used in the calendar year using the methods specified in 
either paragraph (b)(1) or (b)(2) of this section.
    (1) Information provided by your material supplier.
    (2) Collecting and analyzing at least three representative samples 
of the material using the appropriate testing method. For each carbon-
containing input material identified for which the carbon content is not 
provided by your material supplier, the carbon content of the material 
must be analyzed at least annually using the appropriate standard 
methods (and their QA/QC procedures), which are identified in paragraphs 
(b)(2)(i) through (b)(2)(iii) of this section, as applicable. If you 
document that a specific process input or output contributes less than 
one percent of the total mass of carbon into or out of the process, you 
do not have to determine the monthly mass or annual carbon content of 
that input or output.
    (i) Using ASTM E1941-04 Standard Test Method for Determination of 
Carbon in Refractory and Reactive Metals and Their Alloys (incorporated 
by reference, see Sec. 98.7), analyze zinc bearing materials.
    (ii) Using ASTM D5373-08 Standard Test Methods for Instrumental 
Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of 
Coal (incorporated by reference, see Sec. 98.7), analyze carbonaceous 
reducing agents and carbon electrodes.
    (iii) Using ASTM C25-06 Standard Test Methods for Chemical Analysis 
of Limestone, Quicklime, and Hydrated Lime (incorporated by reference, 
see Sec. 98.7), analyze flux materials such as limestone or dolomite.



Sec. 98.335  Procedures for estimating missing data.

    For the carbon input procedure in Sec. 98.333(b), a complete record 
of all measured parameters used in the GHG emissions calculations is 
required (e.g., raw materials carbon content values, etc.). Therefore, 
whenever a quality-assured value of a required parameter is

[[Page 975]]

unavailable, a substitute data value for the missing parameter shall be 
used in the calculations as specified in paragraphs (a) and (b) of this 
section. You must document and keep records of the procedures used for 
all such estimates.
    (a) For missing records of the carbon content of inputs for 
facilities that estimate emissions using the carbon input procedure in 
Sec. 98.333(b); 100 percent data availability is required. You must 
repeat the test for average carbon contents of inputs according to the 
procedures in Sec. 98.335(b) if data are missing.
    (b) For missing records of the annual mass of carbon-containing 
inputs using the carbon input procedure in Sec. 98.333(b), the 
substitute data value must be based on the best available estimate of 
the mass of the input material from all available process data or 
information used for accounting purposes, such as purchase records.



Sec. 98.336  Data reporting requirements.

    In addition to the information required by Sec. 98.3(c), each 
annual report must contain the information specified in paragraphs (a) 
or (b) of this section, as applicable, for each Waelz kiln or 
electrothermic furnace.
    (a) If a CEMS is used to measure CO2 emissions, then you 
must report under this subpart the relevant information required for the 
Tier 4 Calculation Methodology in Sec. 98.36 and the information listed 
in this paragraph (a):
    (1) Annual zinc product production capacity (tons).
    (2) Annual production quantity for each zinc product (tons).
    (3) Annual facility production quantity for each zinc product 
(tons).
    (4) Number of Waelz kilns at each facility used for zinc production.
    (5) Number of electrothermic furnaces at each facility used for zinc 
production.
    (b) If a CEMS is not used to measure CO2 emissions, then 
you must report the information listed in this paragraph (b):
    (1) Identification number and annual process CO2 
emissions from each individual Waelz kiln or electrothermic furnace 
(metric tons).
    (2) Annual zinc product production capacity (tons).
    (3) Annual production quantity for each zinc product (tons).
    (4) Number of Waelz kilns at each facility used for zinc production.
    (5) Number of electrothermic furnaces at each facility used for zinc 
production.
    (6) [Reserved]
    (7) [Reserved]
    (8) Whether carbon content of each carbon-containing input material 
charged to each kiln or furnace is based on reports from the supplier or 
through self measurement using applicable ASTM standard method.
    (9) If carbon content of each carbon-containing input material 
charged to each kiln or furnace is based on self measurement, the ASTM 
Standard Test Method used.
    (10) [Reserved]
    (11) Whether carbon content of the carbon electrode used in each 
furnace is based on reports from the supplier or through self 
measurement using applicable ASTM standard method.
    (12) If carbon content of carbon electrode used in each furnace is 
based on self measurement, the ASTM standard method used.
    (13) If you use the missing data procedures in Sec. 98.335(b), you 
must report how the monthly mass of carbon-containing materials with 
missing data was determined and the number of months the missing data 
procedures were used.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66470, Oct. 28, 2010; 
79 FR 63799, Oct. 24, 2014]



Sec. 98.337  Records that must be retained.

    In addition to the records required by Sec. 98.3(g), you must 
retain the records specified in paragraphs (a) through (c) of this 
section for each zinc production facility.
    (a) If a CEMS is used to measure emissions, then you must retain 
under this subpart the records required for the Tier 4 Calculation 
Methodology in Sec. 98.37 and the information listed in this paragraph 
(a):
    (1) Monthly facility production quantity for each zinc product 
(tons).
    (2) Annual operating hours for all Waelz kilns and electrothermic 
furnaces used in zinc production.

[[Page 976]]

    (b) If a CEMS is not used to measure emissions, you must also retain 
the records specified in paragraphs (b)(1) through (b)(7) of this 
section.
    (1) Records of all analyses and calculations conducted for data 
reported as listed in Sec. 98.336(b).
    (2) Annual operating hours for Waelz kilns and electrothermic 
furnaces used in zinc production.
    (3) Monthly production quantity for each zinc product (tons).
    (4) Monthly mass of zinc bearing materials, flux materials (e.g., 
limestone, dolomite), and carbonaceous materials (e.g., coal, coke) 
charged to the kiln or furnace (tons).
    (5) Sampling and analysis records for carbon content of zinc bearing 
materials, flux materials (e.g., limestone, dolomite), carbonaceous 
materials (e.g., coal, coke), charged to the kiln or furnace (percent by 
weight, expressed as a decimal fraction).
    (6) Monthly mass of carbon electrode consumed in for each 
electrothermic furnace (tons).
    (7) Sampling and analysis records for carbon content of electrode 
materials.
    (8) You must keep records that include a detailed explanation of how 
company records of measurements are used to estimate the carbon input to 
each Waelz kiln or electrothermic furnace, as applicable to your 
facility, including documentation of any materials excluded from 
Equation GG-1 of this subpart that contribute less than 1 percent of the 
total carbon inputs to the process. You also must document the 
procedures used to ensure the accuracy of the measurements of materials 
fed, charged, or placed in an affected unit including, but not limited 
to, calibration of weighing equipment and other measurement devices. The 
estimated accuracy of measurements made with these devices must also be 
recorded, and the technical basis for these estimates must be provided.
    (c) Verification software records. You must keep a record of the 
file generated by the verification software specified in Sec. 98.5(b) 
for the applicable data specified in paragraphs (c)(1) through (9) of 
this section. Retention of this file satisfies the recordkeeping 
requirement for the data in paragraphs (c)(1) through (9) of this 
section.
    (1) Annual mass of zinc bearing material charged to kiln or furnace 
(tons) (Equation GG-1 of Sec. 98.333).
    (2) Carbon content of the zinc bearing material, from the annual 
carbon analysis for kiln or furnace (percent by weight, expressed as a 
decimal fraction) (Equation GG-1).
    (3) Annual mass of flux materials (e.g., limestone, dolomite) 
charged to each kiln or furnace (tons) (Equation GG-1).
    (4) Carbon content of the flux materials charged to each kiln or 
furnace, from the annual carbon analysis (percent by weight, expressed 
as a decimal fraction) (Equation GG-1).
    (5) Annual mass of carbon electrode consumed in each furnace (tons) 
(Equation GG-1).
    (6) Carbon content of the carbon electrode consumed in each furnace, 
from the annual carbon analysis (percent by weight, expressed as a 
decimal fraction) (Equation GG-1).
    (7) Annual mass of carbonaceous materials (e.g., coal, coke) charged 
to each kiln or furnace (tons) (Equation GG-1).
    (8) Carbon content of the carbonaceous materials charged to each 
kiln or furnace, from the annual carbon analysis (percent by weight, 
expressed as a decimal fraction) (Equation GG-1).
    (9) Identify whether each unit is a Waelz kiln or an electrothermic 
furnace.

[74 FR 56374, Oct. 30, 2009, as amended at 79 FR 63799, Oct. 24, 2014]



Sec. 98.338  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.



               Subpart HH_Municipal Solid Waste Landfills



Sec. 98.340  Definition of the source category.

    (a) This source category applies to municipal solid waste (MSW) 
landfills that accepted waste on or after January 1, 1980, unless all 
three of the following conditions apply.
    (1) The MSW landfill did not receive waste on or after January 1, 
2013.
    (2) The MSW landfill had CH4 generation as determined 
using Equation HH-

[[Page 977]]

5 and, if applicable, Equation HH-7 of this subpart of less than 1,190 
metric tons of CH4 in the 2013 reporting year.
    (3) The owner or operator of the MSW landfill was not required to 
submit an annual report under any requirement of this part in any 
reporting year prior to 2013.
    (b) This source category does not include Resource Conservation and 
Recovery Act (RCRA) Subtitle C or Toxic Substances Control Act (TSCA) 
hazardous waste landfills, construction and demolition waste landfills, 
or industrial waste landfills.
    (c) This source category consists of the following sources at 
municipal solid waste (MSW) landfills: Landfills, landfill gas 
collection systems, and landfill gas destruction devices (including 
flares).

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66470, Oct. 28, 2010; 
78 FR 71968, Nov. 29, 2013]



Sec. 98.341  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains a MSW landfill and the facility meets the requirements of Sec. 
98.2(a)(1).



Sec. 98.342  GHGs to report.

    (a) You must report CH4 generation and CH4 
emissions from landfills.
    (b) You must report CH4 destruction resulting from 
landfill gas collection and combustion systems.
    (c) You must report under subpart C of this part (General Stationary 
Fuel Combustion Sources) the emissions of CO2, 
CH4, and N2O from each stationary combustion unit 
following the requirements of subpart C.



Sec. 98.343  Calculating GHG emissions.

    (a) For all landfills subject to the reporting requirements of this 
subpart, calculate annual modeled CH4 generation according to 
the applicable requirements in paragraphs (a)(1) through (a)(3) of this 
section.
    (1) Calculate annual modeled CH4 generation using 
Equation HH-1 of this section.
[GRAPHIC] [TIFF OMITTED] TR28OC10.033

Where:

GCH4 = Modeled methane generation rate in reporting year T 
          (metric tons CH4).
x = Year in which waste was disposed.
S = Start year of calculation. Use the year 1960 or the opening year of 
          the landfill, whichever is more recent.
T = Reporting year for which emissions are calculated.
WX = Quantity of waste disposed in the landfill in year x 
          from measurement data, tipping fee receipts, or other company 
          records (metric tons, as received (wet weight)).
MCF = Methane correction factor (fraction). Use the default value of 1 
          unless there is active aeration of waste within the landfill 
          during the reporting year. If there is active aeration of 
          waste within the landfill during the reporting year, use 
          either the default value of 1 or select an alternative value 
          no less than 0.5 based on site-specific aeration parameters.
DOC = Degradable organic carbon from Table HH-1 of this subpart 
          [fraction (metric tons C/metric ton waste)].
DOCF = Fraction of DOC dissimilated (fraction). Use the 
          default value of 0.5.
F = Fraction by volume of CH4 in landfill gas from 
          measurement data for the current reporting year, if available 
          (fraction, dry basis, corrected to 0% oxygen); otherwise, use 
          the default of 0.5.
k = Rate constant from Table HH-1 to this subpart (yr-1). 
          Select the most applicable k value for the majority of the 
          past 10 years (or operating life, whichever is shorter).

    (2) For years when material-specific waste quantity data are 
available, apply Equation HH-1 of this section for each waste quantity 
type and sum the CH4 generation rates for all waste types to 
calculate the total modeled CH4 generation rate for the 
landfill. Use the appropriate parameter values for k, DOC, MCF, 
DOCF, and F shown in Table HH-1 of this subpart. The annual 
quantity of each type of waste disposed must be calculated as the sum of 
the

[[Page 978]]

daily quantities of waste (of that type) disposed. You may use the bulk 
waste parameters for a portion of your waste materials when using the 
material-specific modeling approach for mixed waste streams that cannot 
be designated to a specific material type. For years when waste 
composition data are not available, use the bulk waste parameter values 
for k and DOC in Table HH-1 to this subpart for the total quantity of 
waste disposed in those years.
    (3) Beginning in the first emissions reporting year and for each 
year thereafter, if scales are in place, you must determine the annual 
quantity of waste (in metric tons as received, i.e., wet weight) 
disposed of in the landfill using paragraph (a)(3)(i) of this section 
for all containers and for all vehicles used to haul waste to the 
landfill, except for passenger cars, light duty pickup trucks, or waste 
loads that cannot be measured using the scales due to physical 
limitations (load cannot physically access or fit on the scale) and/or 
operational limitations of the scale (load exceeding the limits or 
sensitivity range of the scale). If scales are not in place, you must 
use paragraph (a)(3)(ii) of this section to determine the annual 
quantity of waste disposed. For waste hauled to the landfill in 
passenger cars or light duty pickup trucks, you may use either paragraph 
(a)(3)(i) or paragraph (a)(3)(ii) of this section to determine the 
annual quantity of waste disposed. For loads that cannot be measured 
using the scales due to physical and/or operational limitations of the 
scale, you must use paragraph (a)(3)(ii) of this section or similar 
engineering calculations to determine the annual quantity of waste 
disposed. The approach used to determine the annual quantity of waste 
disposed of must be documented in the monitoring plan.
    (i) Use direct mass measurements of each individual load received at 
the landfill using either of the following methods:
    (A) Weigh using mass scales each vehicle or container used to haul 
waste as it enters the landfill or disposal area; weigh using mass 
scales each vehicle or container after it has off-loaded the waste; 
determine the quantity of waste received from the individual load as the 
difference in the two mass measurements; and determine the annual 
quantity of waste received as the sum of all waste loads received during 
the year. Alternatively, you may determine annual quantity of waste by 
summing the weights of all vehicles and containers entering the landfill 
and subtracting from it the sum of all the weights of vehicles and 
containers after they have off-loaded the waste in the landfill.
    (B) Weigh using mass scales each vehicle or container used to haul 
waste as it enters the landfill or disposal area; determine a 
representative tare weight by vehicle or container type by weighing no 
less than 5 of each type of vehicle or container after it has off-loaded 
the waste; determine the quantity of waste received from the individual 
load as the difference between the measured weight in and the tare 
weight determined for that container/vehicle type; and determine the 
annual quantity of waste received as the sum of all waste loads received 
during the year.
    (ii) Determine the working capacity in units of mass for each type 
of container or vehicle used to haul waste to the landfill (e.g., using 
volumetric capacity and waste density measurements; direct measurement 
of a selected number of passenger vehicles and light duty pick-up 
trucks; or similar methods); record the number of loads received at the 
landfill by vehicle/container type; calculate the annual mass per 
vehicle/container type as the mass product of the number of loads of 
that vehicle/container multiplied by its working capacity; and calculate 
the annual quantity of waste received as the sum of the annual mass per 
vehicle/container type across all of the vehicle/container types used to 
haul waste to the landfill.
    (4) For years prior to the first emissions reporting year, use 
methods in paragraph (a)(3) of this section when waste disposal quantity 
data are readily available. When waste disposal quantity data are not 
readily available, WX shall be estimated using one of the 
applicable methods in paragraphs (a)(4)(i) through (a)(4)(iii) of this 
section. You must determine which method is most applicable to the 
conditions

[[Page 979]]

and disposal history of your facility. Historical waste disposal 
quantities should only be determined once, as part of the first annual 
report, and the same values should be used for all subsequent annual 
reports, supplemented by the next year's data on new waste disposal.
    (i) Assume all prior years waste disposal quantities are the same as 
the waste quantity in the first year for which waste quantities are 
available.
    (ii) Use the estimated population served by the landfill in each 
year, the values for national average per capita waste disposal rates 
found in Table HH-2 to this subpart, and calculate the waste quantity 
landfilled using Equation HH-2 of this section.
[GRAPHIC] [TIFF OMITTED] TR28OC10.034

where:

WX = Quantity of waste placed in the landfill in year x 
          (metric tons, wet basis).
POPX = Population served by the landfill in year x from city 
          population, census data, or other estimates (capita).
WDRX = Average per capita waste disposal rate for year x from 
          Table HH-2 to this subpart (metric tons per capita per year, 
          wet basis; tons/cap/yr).

    (iii) Use a constant average waste disposal quantity calculated 
using Equation HH-3 of this section for each year the landfill was in 
operation (i.e., from the first year accepting waste until the last year 
for which waste disposal data is unavailable, inclusive).
[GRAPHIC] [TIFF OMITTED] TR28OC10.035

where:

WX = Quantity of waste placed in the landfill in year x 
          (metric tons, wet basis).
LFC = Landfill capacity or, for operating landfills, capacity of the 
          landfill used (or the total quantity of waste-in-place) at the 
          end of the year prior to the year when waste disposal data are 
          available from design drawings or engineering estimates 
          (metric tons).
YrData = Year in which the landfill last received waste or, for 
          operating landfills, the year prior to the first reporting 
          year when waste disposal data is first available from company 
          records, or best available data.
YrOpen = Year in which the landfill first received waste from company 
          records or best available data. If no data are available for 
          estimating YrOpen for a closed landfill, use 30 years as the 
          default operating life of the landfill.

    (b) For landfills with gas collection systems, calculate the 
quantity of CH4 destroyed according to the requirements in 
paragraphs (b)(1) and (b)(2) of this section.
    (1) If you continuously monitor the flow rate, CH4 
concentration, temperature, pressure, and, if necessary, moisture 
content of the landfill gas that is collected and routed to a 
destruction device (before any treatment equipment) using a monitoring 
meter specifically for CH4 gas, as specified in Sec. 98.344, 
you must use this monitoring system and calculate the quantity of 
CH4 recovered for destruction using Equation HH-4 of this 
section. A fully integrated system that directly reports CH4 
content requires no other calculation than summing the results of all 
monitoring periods for a given year.
[GRAPHIC] [TIFF OMITTED] TR29NO13.020

where:

R = Annual quantity of recovered CH4 (metric tons 
          CH4).
N = Total number of measurement periods in a year. Use daily averaging 
          periods for a continuous monitoring system and N = 365 (or N = 
          366 for leap years). For monthly sampling, as provided in 
          paragraph (b)(2) of this section, use N = 12.
n = Index for measurement period.
(V)n = Cumulative volumetric flow for the measurement period 
          in actual cubic feet (acf). If the flow rate meter 
          automatically corrects for temperature and pressure, replace 
          ``520 deg.R/(T)n x (P)n/1 atm'' with 
          ``1''.
(KMC)n = Moisture correction term for the 
          measurement period, volumetric basis, as follows: 
          (KMC)n = 1 when (V)n and 
          (C)n are both measured on a dry basis or if both 
          are measured on a wet basis; (KMC)n = 
          [1-

[[Page 980]]

          (fH2O)n] when (V)n 
          is measured on a wet basis and (C)n is measured on 
          a dry basis; and (KMC)n = 1/[1-
          (fH2O)n] when (V)n is 
          measured on a dry basis and (C)n is measured on a 
          wet basis.
(fH2O)n = Average moisture content of 
          landfill gas during the measurement period, volumetric basis 
          (cubic feet water per cubic feet landfill gas)
(CCH4)n = Average CH4 concentration of 
          landfill gas for the measurement period (volume %).
0.0423 = Density of CH4 lb/cf at 520 deg.R or 60 degrees 
          Fahrenheit and 1 atm.
(T)n = Average temperature at which flow is measured for the 
          measurement period ( deg.R).
(P)n = Average pressure at which flow is measured for the 
          measurement period (atm).
0.454/1,000 = Conversion factor (metric ton/lb).

    (2) If you do not continuously monitor according to paragraph (b)(1) 
of this section, you must determine the flow rate, CH4 
concentration, temperature, pressure, and moisture content of the 
landfill gas that is collected and routed to a destruction device 
(before any treatment equipment) according to the requirements in 
paragraphs (b)(2)(i) through (b)(2)(iii) of this section and calculate 
the quantity of CH4 recovered for destruction using Equation 
HH-4 of this section.
    (i) Continuously monitor gas flow rate and determine the cumulative 
volume of landfill gas each month and the cumulative volume of landfill 
gas each year that is collected and routed to a destruction device 
(before any treatment equipment). Under this option, the gas flow meter 
is not required to automatically correct for temperature, pressure, or, 
if necessary, moisture content. If the gas flow meter is not equipped 
with automatic correction for temperature, pressure, or, if necessary, 
moisture content, you must determine these parameters as specified in 
paragraph (b)(2)(iii) of this section.
    (ii) Determine the CH4 concentration in the landfill gas 
that is collected and routed to a destruction device (before any 
treatment equipment) in a location near or representative of the 
location of the gas flow meter at least once each calendar month; if 
only one measurement is made each calendar month, there must be at least 
fourteen days between measurements.
    (iii) If the gas flow meter is not equipped with automatic 
correction for temperature, pressure, or, if necessary, moisture 
content:
    (A) Determine the temperature and pressure in the landfill gas that 
is collected and routed to a destruction device (before any treatment 
equipment) in a location near or representative of the location of the 
gas flow meter at least once each calendar month; if only one 
measurement is made each calendar month, there must be at least fourteen 
days between measurements.
    (B) If the CH4 concentration is determined on a dry basis 
and flow is determined on a wet basis or CH4 concentration is 
determined on a wet basis and flow is determined on a dry basis, and the 
flow meter does not automatically correct for moisture content, 
determine the moisture content in the landfill gas that is collected and 
routed to a destruction device (before any treatment equipment) in a 
location near or representative of the location of the gas flow meter at 
least once each calendar month; if only one measurement is made each 
calendar month, there must be at least fourteen days between 
measurements.
    (c) For all landfills, calculate CH4 generation (adjusted 
for oxidation in cover materials) and actual CH4 emissions 
(taking into account any CH4 recovery, and oxidation in cover 
materials) according to the applicable methods in paragraphs (c)(1) 
through (c)(3) of this section.
    (1) Calculate CH4 generation, adjusted for oxidation, 
from the modeled CH4 (GCH4 from Equation HH-1 of 
this section) using Equation HH-5 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.132

Where:

MG = Methane generation, adjusted for oxidation, from the landfill in 
          the reporting year (metric tons CH4).
GCH4 = Modeled methane generation rate in reporting year from 
          Equation HH-1 of this section (metric tons CH4).
OX = Oxidation fraction. Use the appropriate oxidation fraction default 
          value from Table HH-4 of this subpart.

    (2) For landfills that do not have landfill gas collection systems, 
the CH4

[[Page 981]]

emissions are equal to the CH4 generation (MG) calculated in 
Equation HH-5 of this section.
    (3) For landfills with landfill gas collection systems, calculate 
CH4 emissions using the methodologies specified in paragraphs 
(c)(3)(i) and (c)(3)(ii) of this section.
    (i) Calculate CH4 emissions from the modeled 
CH4 generation and measured CH4 recovery using 
Equation HH-6 of this section.
[GRAPHIC] [TIFF OMITTED] TR29NO13.021

Where:

Emissions = Methane emissions from the landfill in the reporting year 
          (metric tons CH4).
GCH4 = Modeled methane generation rate in reporting year from 
          Equation HH-1 of this section or the quantity of recovered 
          CH4 from Equation HH-4 of this section, whichever 
          is greater (metric tons CH4).
N = Number of landfill gas measurement locations (associated with a 
          destruction device or gas sent off-site). If a single 
          monitoring location is used to monitor volumetric flow and 
          CH4 concentration of the recovered gas sent to one 
          or multiple destruction devices, then N = 1.
Rn = Quantity of recovered CH4 from Equation HH-4 
          of this section for the nth measurement location 
          (metric tons).
OX = Oxidation fraction. Use the appropriate oxidation fraction default 
          value from Table HH-4 of this subpart.
DEn = Destruction efficiency (lesser of manufacturer's 
          specified destruction efficiency and 0.99) for the 
          nth measurement location. If the gas is transported 
          off-site for destruction, use DE = 1. If the volumetric flow 
          and CH4 concentration of the recovered gas is 
          measured at a single location providing landfill gas to 
          multiple destruction devices (including some gas destroyed on-
          site and some gas sent off-site for destruction), calculate 
          DEn as the arithmetic average of the DE values 
          determined for each destruction device associated with that 
          measurement location.
fDest,n = Fraction of hours the destruction device associated 
          with the nth measurement location was operating 
          during active gas flow calculated as the annual operating 
          hours for the destruction device divided by the annual hours 
          flow was sent to the destruction device as measured at the 
          nth measurement location. If the gas is transported 
          off-site for destruction, use fDest,n= 1. If the 
          volumetric flow and CH4 concentration of the 
          recovered gas is measured at a single location providing 
          landfill gas to multiple destruction devices (including some 
          gas destroyed on-site and some gas sent off-site for 
          destruction), calculate fDest,n as the arithmetic 
          average of the fDest values determined for each 
          destruction device associated with that measurement location.

    (ii) Calculate CH4 generation and CH4 
emissions using measured CH4 recovery and estimated gas 
collection efficiency and Equations HH-7 and HH-8 of this section.
[GRAPHIC] [TIFF OMITTED] TR29NO13.022

Where:

MG = Methane generation, adjusted for oxidation, from the landfill in 
          the reporting year (metric tons CH4).
Emissions = Methane emissions from the landfill in the reporting year 
          (metric tons CH4).

[[Page 982]]

N = Number of landfill gas measurement locations (associated with a 
          destruction device or gas sent off-site). If a single 
          monitoring location is used to monitor volumetric flow and 
          CH4 concentration of the recovered gas sent to one 
          or multiple destruction devices, then N = 1.
Rn = Quantity of recovered CH4 from Equation HH-4 
          of this section for the nth measurement location 
          (metric tons CH4).
CE = Collection efficiency estimated at landfill, taking into account 
          system coverage, operation, and cover system materials from 
          Table HH-3 of this subpart. If area by soil cover type 
          information is not available, use default value of 0.75 (CE4 
          in table HH-3 of this subpart) for all areas under active 
          influence of the collection system.
fRec,n = Fraction of hours the recovery system associated 
          with the nth measurement location was operating 
          (annual operating hours/8760 hours per year or annual 
          operating hours/8784 hours per year for a leap year).
OX = Oxidation fraction. Use appropriate oxidation fraction default 
          value from Table HH-4 of this subpart.
DEn = Destruction efficiency, (lesser of manufacturer's 
          specified destruction efficiency and 0.99) for the 
          nth measurement location. If the gas is transported 
          off-site for destruction, use DE = 1. If the volumetric flow 
          and CH4 concentration of the recovered gas is 
          measured at a single location providing landfill gas to 
          multiple destruction devices (including some gas destroyed on-
          site and some gas sent off-site for destruction), calculate 
          DEn as the arithmetic average of the DE values 
          determined for each destruction device associated with that 
          measurement location.
fDest,n = Fraction of hours the destruction device associated 
          with the nth measurement location was operating 
          during active gas flow calculated as the annual operating 
          hours for the destruction device divided by the annual hours 
          flow was sent to the destruction device as measured at the 
          nth measurement location. If the gas is transported 
          off-site for destruction, use fDest,n= 1. If the 
          volumetric flow and CH4 concentration of the 
          recovered gas is measured at a single location providing 
          landfill gas to multiple destruction devices (including some 
          gas destroyed on-site and some gas sent off-site for 
          destruction), calculate fDest,n as the arithmetic 
          average of the fDest values determined for each 
          destruction device associated with that measurement location.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66470, Oct. 28, 2010; 
78 FR 71968, Nov. 29, 2013]



Sec. 98.344  Monitoring and QA/QC requirements.

    (a) Mass measurement equipment used to determine the quantity of 
waste landfilled on or after January 1, 2010 must meet the requirements 
for weighing equipment as described in ``Specifications, Tolerances, and 
Other Technical Requirements For Weighing and Measuring Devices'' NIST 
Handbook 44 (2009) (incorporated by reference, see Sec. 98.7).
    (b) For landfills with gas collection systems, operate, maintain, 
and calibrate a gas composition monitor capable of measuring the 
concentration of CH4 in the recovered landfill gas using one 
of the methods specified in paragraphs (b)(1) through (b)(6) of this 
section or as specified by the manufacturer. Gas composition monitors 
shall be calibrated prior to the first reporting year and recalibrated 
either annually or at the minimum frequency specified by the 
manufacturer, whichever is more frequent, or whenever the error in the 
midrange calibration check exceeds 10 percent.
    (1) Method 18 at 40 CFR part 60, appendix A-6.
    (2) ASTM D1945-03, Standard Test Method for Analysis of Natural Gas 
by Gas Chromatography (incorporated by reference, see Sec. 98.7).
    (3) ASTM D1946-90 (Reapproved 2006), Standard Practice for Analysis 
of Reformed Gas by Gas Chromatography (incorporated by reference, see 
Sec. 98.7).
    (4) GPA Standard 2261-00, Analysis for Natural Gas and Similar 
Gaseous Mixtures by Gas Chromatography.
    (5) UOP539-97 Refinery Gas Analysis by Gas Chromatography 
(incorporated by reference, see Sec. 98.7).
    (6) As an alternative to the gas chromatography methods provided in 
paragraphs (b)(1) through (b)(5) of this section, you may use total 
gaseous organic concentration analyzers and calculate the methane 
concentration following the requirements in paragraphs (b)(6)(i) through 
(b)(6)(iii) of this section.
    (i) Use Method 25A or 25B at 40 CFR part 60, appendix A-7 to 
determine total gaseous organic concentration. You must calibrate the 
instrument with methane and determine the total

[[Page 983]]

gaseous organic concentration as carbon (or as methane; K = 1 in 
Equation 25A-1 of Method 25A at 40 CFR part 60, appendix A-7).
    (ii) Determine a non-methane organic carbon correction factor at the 
routine sampling location no less frequently than once a reporting year 
following the requirements in paragraphs (b)(6)(ii)(A) through 
(b)(6)(ii)(C) of this section.
    (A) Take a minimum of three grab samples of the landfill gas with a 
minimum of 20 minutes between samples and determine the methane 
composition of the landfill gas using one of the methods specified in 
paragraphs (b)(1) through (b)(5) of this section.
    (B) As soon as practical after each grab sample is collected and 
prior to the collection of a subsequent grab sample, determine the total 
gaseous organic concentration of the landfill gas using either Method 
25A or 25B at 40 CFR part 60, appendix A-7 as specified in paragraph 
(b)(6)(i) of this section.
    (C) Determine the arithmetic average methane concentration and the 
arithmetic average total gaseous organic concentration of the samples 
analyzed according to paragraphs (b)(6)(ii)(A) and (b)(6)(ii)(B) of this 
section, respectively, and calculate the non-methane organic carbon 
correction factor as the ratio of the average methane concentration to 
the average total gaseous organic concentration. If the ratio exceeds 1, 
use 1 for the non-methane organic carbon correction factor.
    (iii) Calculate the methane concentration as specified in Equation 
HH-9 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.136

Where:

CCH4 = Methane concentration in the landfill gas (volume %) 
          for use in Equation HH-4 of this subpart.
fNMOC = Non-methane organic carbon correction factor from the 
          most recent determination of the non-methane organic carbon 
          correction factor as specified in paragraph (b)(6)(ii) of this 
          section (unitless).
CTGOC = Total gaseous organic carbon concentration measured 
          using Method 25A or 25B at 40 CFR part 60, appendix A-7 during 
          routine monitoring of the landfill gas (volume %).

    (c) For landfills with gas collection systems, install, operate, 
maintain, and calibrate a gas flow meter capable of measuring the 
volumetric flow rate of the recovered landfill gas using one of the 
methods specified in paragraphs (c)(1) through (c)(8) of this section or 
as specified by the manufacturer. Each gas flow meter shall be 
recalibrated either biennially (every 2 years) or at the minimum 
frequency specified by the manufacturer. Except as provided in Sec. 
98.343(b)(2)(i), each gas flow meter must be capable of correcting for 
the temperature and pressure and, if necessary, moisture content.
    (1) ASME MFC-3M-2004, Measurement of Fluid Flow in Pipes Using 
Orifice, Nozzle, and Venturi (incorporated by reference, see Sec. 
98.7).
    (2) ASME MFC-4M-1986 (Reaffirmed 1997), Measurement of Gas Flow by 
Turbine Meters (incorporated by reference, see Sec. 98.7).
    (3) ASME MFC-6M-1998, Measurement of Fluid Flow in Pipes Using 
Vortex Flowmeters (incorporated by reference, see Sec. 98.7).
    (4) ASME MFC-7M-1987 (Reaffirmed 1992), Measurement of Gas Flow by 
Means of Critical Flow Venturi Nozzles (incorporated by reference, see 
Sec. 98.7).
    (5) ASME MFC-11M-2006 Measurement of Fluid Flow by Means of Coriolis 
Mass Flowmeters (incorporated by reference, see Sec. 98.7). The mass 
flow must be corrected to volumetric flow based on the measured 
temperature, pressure, and gas composition.
    (6) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore 
Precision Orifice Meters (incorporated by reference, see Sec. 98.7).
    (7) ASME MFC-18M-2001 Measurement of Fluid Flow using Variable Area 
Meters (incorporated by reference, see Sec. 98.7).
    (8) Method 2A or 2D at 40 CFR part 60, appendix A-1.
    (d) All temperature, pressure, and if necessary, moisture content 
monitors must be calibrated using the procedures and frequencies 
specified by the manufacturer.
    (e) For landfills electing to measure the fraction by volume of 
CH4 in landfill gas (F), follow the requirements in 
paragraphs (e)(1) and (2) of this section.

[[Page 984]]

(1) Use a gas composition monitor capable of measuring the concentration 
of CH4 on a dry basis that is properly operated, calibrated, 
and maintained according to the requirements specified in paragraph (b) 
of this section. You must either use a gas composition monitor that is 
also capable of measuring the O2 concentration correcting for 
excess (infiltration) air or you must operate, maintain, and calibrate a 
second monitor capable of measuring the O2 concentration on a 
dry basis according to the manufacturer's specifications.
    (2) Use Equation HH-10 of this section to correct the measured 
CH4 concentration to 0% oxygen. If multiple CH4 
concentration measurements are made during the reporting year, determine 
F separately for each measurement made during the reporting year, and 
use the results to determine the arithmetic average value of F for use 
in Equation HH-1 of this part.
[GRAPHIC] [TIFF OMITTED] TR29NO13.023

Where:

F = Fraction by volume of CH4 in landfill gas (fraction, dry 
          basis, corrected to 0% oxygen).
CCH4 = Measured CH4 concentration in landfill gas 
          (volume %, dry basis).
20.9c = Defined O2 correction basis, (volume %, 
          dry basis).
20.9 = O2 concentration in air (volume %, dry basis).
%O2 = Measured O2 concentration in landfill gas 
          (volume %, dry basis).

    (f) The owner or operator shall document the procedures used to 
ensure the accuracy of the estimates of disposal quantities and, if 
applicable, gas flow rate, gas composition, temperature, pressure, and 
moisture content measurements. These procedures include, but are not 
limited to, calibration of weighing equipment, fuel flow meters, and 
other measurement devices. The estimated accuracy of measurements made 
with these devices, and the technical basis for these estimates shall be 
recorded.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66472, Oct. 28, 2010; 
78 FR 71969, Nov. 29, 2013]



Sec. 98.345  Procedures for estimating missing data.

    A complete record of all measured parameters used in the GHG 
emissions calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable (e.g., if a meter 
malfunctions during unit operation or if a required fuel sample is not 
taken), a substitute data value for the missing parameter shall be used 
in the calculations, according to the requirements in paragraphs (a) 
through (c) of this section.
    (a) For each missing value of the CH4 content, the 
substitute data value shall be the arithmetic average of the quality-
assured values of that parameter immediately preceding and immediately 
following the missing data incident. If the ``after'' value is not 
obtained by the end of the reporting year, you may use the ``before'' 
value for the missing data substitution. If, for a particular parameter, 
no quality-assured data are available prior to the missing data 
incident, the substitute data value shall be the first quality-assured 
value obtained after the missing data period.
    (b) For missing gas flow rates, the substitute data value shall be 
the arithmetic average of the quality-assured values of that parameter 
immediately preceding and immediately following the missing data 
incident. If the ``after'' value is not obtained by the end of the 
reporting year, you may use the ``before'' value for the missing data 
substitution. If, for a particular parameter, no quality-assured data 
are available prior to the missing data incident, the substitute data 
value shall be the first quality-assured value obtained after the 
missing data period.

[[Page 985]]

    (c) For missing daily waste disposal quantity data for disposal in 
the reporting year, the substitute value shall be the average daily 
waste disposal quantity for that day of the week as measured on the week 
before and week after the missing daily data.

[74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71970, Nov. 29, 2013]



Sec. 98.346  Data reporting requirements.

    In addition to the information required by Sec. 98.3(c), each 
annual report must contain the following information for each landfill.
    (a) A classification of the landfill as ``open'' (actively received 
waste in the reporting year) or ``closed'' (no longer receiving waste), 
the year in which the landfill first started accepting waste for 
disposal, the last year the landfill accepted waste (for open landfills, 
enter the estimated year of landfill closure), the capacity (in metric 
tons) of the landfill, an indication of whether leachate recirculation 
is used during the reporting year and its typical frequency of use over 
the past 10 years (e.g., used several times a year for the past 10 
years, used at least once a year for the past 10 years, used 
occasionally but not every year over the past 10 years, not used), an 
indication as to whether scales are present at the landfill, and the 
waste disposal quantity for each year of landfilling required to be 
included when using Equation HH-1 of this subpart (in metric tons, wet 
weight).
    (b) Method for estimating reporting year and historical waste 
disposal quantities, reason for its selection, and the range of years it 
is applied. For years when waste quantity data are determined using the 
methods in Sec. 98.343(a)(3), report separately the quantity of waste 
determined using the methods in Sec. 98.343(a)(3)(i) and the quantity 
of waste determined using the methods in Sec. 98.343(a)(3)(ii). For 
historical waste disposal quantities that were not determined using the 
methods in Sec. 98.343(a)(3), provide the population served by the 
landfill for each year the Equation HH-2 of this subpart is applied, if 
applicable, or, for open landfills using Equation HH-3 of this subpart, 
provide the value of landfill capacity (LFC) used in the calculation.
    (c) Waste composition for each year required for Equation HH-1 of 
this subpart, in percentage by weight, for each waste category listed in 
Table HH-1 to this subpart that is used in Equation HH-1 of this subpart 
to calculate the annual modeled CH4 generation.
    (d) For each waste type used to calculate CH4 generation 
using Equation HH-1 of this subpart, you must report:
    (1) Degradable organic carbon (DOC) and fraction of DOC dissimilated 
(DOCF) values used in the calculations.
    (2) Decay rate (k) value used in the calculations.
    (e) Fraction of CH4 in landfill gas (F), an indication of 
whether the fraction of CH4 was determined based on measured 
values or the default value, and the methane correction factor (MCF) 
used in the calculations. If an MCF other than the default of 1 is used, 
provide an indication of whether active aeration of the waste in the 
landfill was conducted during the reporting year, a description of the 
aeration system, including aeration blower capacity, the fraction of the 
landfill containing waste affected by aeration, the total number of 
hours during the year the aeration blower was operated, and other 
factors used as a basis for the selected MCF value.
    (f) The surface area of the landfill containing waste (in square 
meters), identification of the type of cover material used (as either 
organic cover, clay cover, sand cover, or other soil mixtures). If 
multiple cover types are used, the surface area associated with each 
cover type.
    (g) The modeled annual methane generation rate for the reporting 
year (metric tons CH4) calculated using Equation HH-1 of this 
subpart.
    (h) For landfills without gas collection systems, the annual methane 
emissions (i.e., the methane generation, adjusted for oxidation, 
calculated using Equation HH-5 of this subpart), reported in metric tons 
CH4, the oxidation fraction used in the calculation, and an 
indication of whether passive vents and/or passive flares (vents or 
flares that are not considered part of the gas collection system as 
defined in Sec. 98.6) are present at this landfill.
    (i) For landfills with gas collection systems, you must report:

[[Page 986]]

    (1) Total volumetric flow of landfill gas collected for destruction 
for the reporting year (cubic feet at 520  deg.R or 60 degrees 
Fahrenheit and 1 atm).
    (2) Annual average CH4 concentration of landfill gas 
collected for destruction (percent by volume).
    (3) Monthly average temperature and pressure for each month at which 
flow is measured for landfill gas collected for destruction, or 
statement that temperature and/or pressure is incorporated into internal 
calculations run by the monitoring equipment.
    (4) An indication as to whether flow was measured on a wet or dry 
basis, an indication as to whether CH4 concentration was 
measured on a wet or dry basis, and if required for Equation HH-4 of 
this subpart, monthly average moisture content for each month at which 
flow is measured for landfill gas collected for destruction.
    (5) An indication of whether destruction occurs at the landfill 
facility, off-site, or both. If destruction occurs at the landfill 
facility, also report for each measurement location the number of 
destruction devices associated with that measurement location and the 
annual operating hours and the destruction efficiency (percent) for each 
destruction device associated with that measurement location.
    (6) Annual quantity of recovered CH4 (metric tons 
CH4) calculated using Equation HH-4 of this subpart for each 
measurement location.
    (7) A description of the gas collection system (manufacturer, 
capacity, and number of wells), the surface area (square meters) and 
estimated waste depth (meters) for each area specified in Table HH-3 to 
this subpart, the estimated gas collection system efficiency for 
landfills with this gas collection system, the annual operating hours of 
the gas collection system for each measurement location, and an 
indication of whether passive vents and/or passive flares (vents or 
flares that are not considered part of the gas collection system as 
defined in Sec. 98.6) are present at the landfill.
    (8) Methane generation corrected for oxidation calculated using 
Equation HH-5 of this subpart, reported in metric tons CH4, 
and the oxidation fraction used in the calculation.
    (9) Methane generation (GCH4) value used as an input to 
Equation HH-6 of this subpart. Specify whether the value is modeled 
(GCH4 from HH-1 of this subpart) or measured (R from Equation 
HH-4 of this subpart).
    (10) Methane generation corrected for oxidation calculated using 
Equation HH-7 of this subpart, reported in metric tons CH4, 
and the oxidation fraction used in the calculation.
    (11) Methane emissions calculated using Equation HH-6 of this 
subpart, reported in metric tons CH4, and the oxidation 
fraction used in the calculation.
    (12) Methane emissions calculated using Equation HH-8 of this 
subpart, reported in metric tons CH4, and the oxidation 
fraction used in the calculation.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66472, Oct. 28, 2010; 
78 FR 71970, Nov. 29, 2013]



Sec. 98.347  Records that must be retained.

    In addition to the information required by Sec. 98.3(g), you must 
retain the calibration records for all monitoring equipment, including 
the method or manufacturer's specification used for calibration. You 
must retain records of all measurements made to determine tare weights 
and working capacities by vehicle/container type if these are used to 
determine the annual waste quantities.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66473, Oct. 28, 2010]



Sec. 98.348  Definitions.

    Except as specified in this section, all terms used in this subpart 
have the same meaning given in the Clean Air Act and subpart A of this 
part.
    Construction and demolition (C&D) waste landfill means a solid waste 
disposal facility subject to the requirements of part 257, subparts A or 
B of this chapter that receives construction and demolition waste and 
does not receive hazardous waste (defined in Sec. 261.3 of this 
chapter) or industrial solid waste (defined in Sec. 258.2 of this 
chapter) or municipal solid waste (as defined in Sec. 98.6) other than 
residential lead-based paint waste. A C&D waste landfill typically 
receives any one or more of the

[[Page 987]]

following types of solid wastes: Roadwork material, excavated material, 
demolition waste, construction/renovation waste, and site clearance 
waste.
    Destruction device means a flare, thermal oxidizer, boiler, turbine, 
internal combustion engine, or any other combustion unit used to destroy 
or oxidize methane contained in landfill gas.
    Industrial waste landfill means any landfill other than a municipal 
solid waste landfill, a RCRA Subtitle C hazardous waste landfill, or a 
TSCA hazardous waste landfill, in which industrial solid waste, such a 
RCRA Subtitle D wastes (nonhazardous industrial solid waste, defined in 
Sec. 257.2 of this chapter), commercial solid wastes, or conditionally 
exempt small quantity generator wastes, is placed. An industrial waste 
landfill includes all disposal areas at the facility.
    Landfill capacity means the maximum amount of solid waste a landfill 
can accept. For the purposes of this subpart, for landfills that have a 
permit, the landfill capacity can be determined in terms of volume or 
mass in the most recent permit issued by the state, local, or Tribal 
agency responsible for regulating the landfill, plus any in-place waste 
not accounted for in the most recent permit. If the owner or operator 
chooses to convert from volume to mass to determine its capacity, the 
calculation must include a site-specific density.
    Leachate recirculation means the practice of taking the leachate 
collected from the landfill and reapplying it to the landfill by any of 
one of a variety of methods, including pre-wetting of the waste, direct 
discharge into the working face, spraying, infiltration ponds, vertical 
injection wells, horizontal gravity distribution systems, and pressure 
distribution systems.
    Solid waste has the meaning established by the Administrator 
pursuant to the Solid Waste Disposal Act (42 U.S.C.A. 6901 et seq.).
    Working capacity means the maximum volume or mass of waste that is 
actually placed in the landfill from an individual or representative 
type of container (such as a tank, truck, or roll-off bin) used to 
convey wastes to the landfill, taking into account that the container 
may not be able to be 100 percent filled and/or 100 percent emptied for 
each load.

[75 FR 66473, Oct. 28, 2010, as amended at 78 FR 71970, Nov. 29, 2013]



 Sec. Table HH-1 to Subpart HH of Part 98--Emissions Factors, Oxidation 
                           Factors and Methods

----------------------------------------------------------------------------------------------------------------
                  Factor                           Default value                           Units
----------------------------------------------------------------------------------------------------------------
                                       DOC and k values--Bulk waste option
----------------------------------------------------------------------------------------------------------------
DOC (bulk waste).........................  0.20.........................  Weight fraction, wet basis.
k (precipitation plus recirculated         0.02.........................  yr -1
 leachate \a\ <20 inches/year).
k (precipitation plus recirculated         0.038........................  yr -1
 leachate \a\ 20-40 inches/year).
k (precipitation plus recirculated         0.057........................  yr -1
 leachate \a\ 40 inches/year).
----------------------------------------------------------------------------------------------------------------
                                   DOC and k values--Modified bulk MSW option
----------------------------------------------------------------------------------------------------------------
DOC (bulk MSW, excluding inerts and C&D    0.31.........................  Weight fraction, wet basis.
 waste).
DOC (inerts, e.g., glass, plastics,        0.00.........................  Weight fraction, wet basis.
 metal, concrete).
DOC (C&D waste)..........................  0.08.........................  Weight fraction, wet basis.
k (bulk MSW, excluding inerts and C&D      0.02 to 0.057 \b\............  yr -1
 waste).
k (inerts, e.g., glass, plastics, metal,   0.00.........................  yr -1
 concrete).
k (C&D waste)............................  0.02 to 0.04 \b\.............  yr -1
----------------------------------------------------------------------------------------------------------------
                                   DOC and k values--Waste composition option
----------------------------------------------------------------------------------------------------------------
DOC (food waste).........................  0.15.........................  Weight fraction, wet basis.
DOC (garden).............................  0.2..........................  Weight fraction, wet basis.
DOC (paper)..............................  0.4..........................  Weight fraction, wet basis.
DOC (wood and straw).....................  0.43.........................  Weight fraction, wet basis.
DOC (textiles)...........................  0.24.........................  Weight fraction, wet basis.
DOC (diapers)............................  0.24.........................  Weight fraction, wet basis.
DOC (sewage sludge)......................  0.05.........................  Weight fraction, wet basis.
DOC (inerts, e.g., glass, plastics,        0.00.........................  Weight fraction, wet basis.
 metal, cement).
k (food waste)...........................  0.06 to 0.185 \c\............  yr -1
k (garden)...............................  0.05 to 0.10 \c\.............  yr -1

[[Page 988]]

 
k (paper)................................  0.04 to 0.06 \c\.............  yr -1
k (wood and straw).......................  0.02 to 0.03 \c\.............  yr -1
k (textiles).............................  0.04 to 0.06 \c\.............  yr -1
k (diapers)..............................  0.05 to 0.10 \c\.............  yr -1
k (sewage sludge)........................  0.06 to 0.185 \c\............  yr -1
k (inerts e.g., glass, plastics, metal,    0.00.........................  yr -1
 concrete).
----------------------------------------------------------------------------------------------------------------
                                       Other parameters--All MSW landfills
----------------------------------------------------------------------------------------------------------------
MCF......................................  1.
DOCF.....................................  0.5..........................
F........................................  0.5..........................
OX.......................................  See Table HH-4 of this
                                            subpart.
DE.......................................  0.99.........................
----------------------------------------------------------------------------------------------------------------
\a\ Recirculated leachate (in inches/year) is the total volume of leachate recirculated from company records or
  engineering estimates divided by the area of the portion of the landfill containing waste with appropriate
  unit conversions. Alternatively, landfills that use leachate recirculation can elect to use the k value of
  0.057 rather than calculating the recirculated leachate rate.
\b\ Use the lesser value when precipitation plus recirculated leachate is less than 20 inches/year. Use the
  greater value when precipitation plus recirculated leachate is greater than 40 inches/year. Use the average of
  the range of values when precipitation plus recirculated leachate is 20 to 40 inches/year (inclusive).
  Alternatively, landfills that use leachate recirculation can elect to use the greater value rather than
  calculating the recirculated leachate rate.
\c\ Use the lesser value when the potential evapotranspiration rate exceeds the mean annual precipitation rate
  plus recirculated leachate. Use the greater value when the potential evapotranspiration rate does not exceed
  the mean annual precipitation rate plus recirculated leachate. Alternatively, landfills that use leachate
  recirculation can elect to use the greater value rather than assessing the potential evapotranspiration rate
  or recirculated leachate rate.


[75 FR 66473, Oct. 28, 2010, as amended at 78 FR 71970, Nov. 29, 2013]



Sec. Table HH-2 to Subpart HH of Part 98--U.S. Per Capita Waste Disposal 
                                  Rates

------------------------------------------------------------------------
                                                    Waste per capita ton/
                       Year                                cap/yr
------------------------------------------------------------------------
1950..............................................                  0.63
1951..............................................                  0.63
1952..............................................                  0.63
1953..............................................                  0.63
1954..............................................                  0.63
1955..............................................                  0.63
1956..............................................                  0.63
1957..............................................                  0.63
1958..............................................                  0.63
1959..............................................                  0.63
1960..............................................                  0.63
1961..............................................                  0.64
1962..............................................                  0.64
1963..............................................                  0.65
1964..............................................                  0.65
1965..............................................                  0.66
1966..............................................                  0.66
1967..............................................                  0.67
1968..............................................                  0.68
1969..............................................                  0.68
1970..............................................                  0.69
1971..............................................                  0.69
1972..............................................                  0.70
1973..............................................                  0.71
1974..............................................                  0.71
1975..............................................                  0.72
1976..............................................                  0.73
1977..............................................                  0.73
1978..............................................                  0.74
1979..............................................                  0.75
1980..............................................                  0.75
1981..............................................                  0.76
1982..............................................                  0.77
1983..............................................                  0.77
1984..............................................                  0.78
1985..............................................                  0.79
1986..............................................                  0.79
1987..............................................                  0.80
1988..............................................                  0.80
1989..............................................                  0.83
1990..............................................                  0.82
1991..............................................                  0.76
1992..............................................                  0.74
1993..............................................                  0.76
1994..............................................                  0.75
1995..............................................                  0.70
1996..............................................                  0.68
1997..............................................                  0.69
1998..............................................                  0.75
1999..............................................                  0.75
2000..............................................                  0.80
2001..............................................                  0.91
2002..............................................                  1.02
2003..............................................                  1.02
2004..............................................                  1.01
2005..............................................                  0.98
2006..............................................                  0.95
2007..............................................                  0.95
2008..............................................                  0.95
2009 and all later years..........................                  0.95
------------------------------------------------------------------------


[78 FR 71971, Nov. 29, 2013]

[[Page 989]]



   Sec. Table HH-3 to Subpart HH of Part 98--Landfill Gas Collection 
                              Efficiencies

------------------------------------------------------------------------
                                             Landfill Gas Collection
              Description                           Efficiency
------------------------------------------------------------------------
A1: Area with no waste in-place........  Not applicable; do not use this
                                          area in the calculation.
A2: Area without active gas collection,  CE2: 0%.
 regardless of cover type.
A3: Area with daily soil cover and       CE3: 60%.
 active gas collection.
A4: Area with an intermediate soil       CE4: 75%.
 cover, or a final soil cover not
 meeting the criteria for A5 below, and
 active gas collection.
A5: Area with a final soil cover of 3    CE5: 95%.
 feet or thicker of clay and/or
 geomembrane cover system and active
 gas collection.
Area weighted average collection         CEave1 = (A2*CE2 + A3*CE3 +
 efficiency for landfills.                A4*CE4 + A5*CE5) / (A2 + A3 +
                                          A4 + A5).
------------------------------------------------------------------------


[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66474, Oct. 28, 2010]



  Sec. Table HH-4 to Subpart HH of Part 98--Landfill Methane Oxidation 
                                Fractions

------------------------------------------------------------------------
                                                             Use this
                                                             landfill
                 Under these conditions:                      methane
                                                             oxidation
                                                             fraction:
------------------------------------------------------------------------
       I. For all reporting years prior to the 2013 reporting year
------------------------------------------------------------------------
C1: For all landfills regardless of cover type or                   0.10
 methane flux...........................................
------------------------------------------------------------------------
        II. For the 2013 reporting year and all subsequent years
------------------------------------------------------------------------
C2: For landfills that have a geomembrane (synthetic)                0.0
 cover with less than 12 inches of cover soil for the
 majority of the landfill area containing waste.........
C3: For landfills that do not meet the conditions in C2             0.10
 above, and for which you elect not to determine methane
 flux...................................................
C4: For landfills that do not meet the conditions in C2             0.10
 above and that do not have a soil cover of at least 24
 inches for a majority of the landfill area containing
 waste..................................................
C5: For landfills that have a soil cover of at least 24             0.35
 inches for a majority of the landfill area containing
 waste and for which the methane flux rate is less than
 10 grams per square meter per day (g/m\2\/d)...........
C6: For landfills that have a soil cover of at least 24             0.25
 inches for a majority of the landfill area containing
 waste and for which the methane flux rate is 10 to 70 g/
 m\2\/d.................................................
C7: For landfills that have a soil cover of at least 24             0.10
 inches for a majority of the landfill area containing
 waste and for which the methane flux rate is greater
 than 70 g/m\2\/d.......................................
------------------------------------------------------------------------
\a\ Methane flux rate (in grams per square meter per day; g/m\2\/d) is
  the mass flow rate of methane per unit area at the bottom of the
  surface soil prior to any oxidation and is calculated as follows:


[[Page 990]]

[GRAPHIC] [TIFF OMITTED] TR29NO13.024

Where:

MF = Methane flux rate from the landfill in the reporting year (grams 
          per square meter per day, g/m\2\/d).
K = unit conversion factor = 10\6\/365 (g/metric ton per days/year) or 
          10\6\/366 for a leap year.
SArea = The surface area of the landfill containing waste at the 
          beginning of the reporting year (square meters, m\2\).
GCH4 = Modeled methane generation rate in reporting year from 
          Equation HH-1 of this subpart or Equation TT-1 of subpart TT 
          of this part, as applicable, except for application with 
          Equation HH-6 of this subpart (metric tons CH4). 
          For application with Equation HH-6 of this subpart, the 
          greater of the modeled methane generation rate in reporting 
          year from Equation HH-1 of this subpart or Equation TT-1 of 
          this part, as applicable, and the quantity of recovered 
          CH4 from Equation HH-4 of this subpart (metric tons 
          CH4).
CE = Collection efficiency estimated at landfill, taking into account 
          system coverage, operation, and cover system materials from 
          Table HH-3 of this subpart. If area by soil cover type 
          information is not available, use default value of 0.75 (CE4 
          in table HH-3 of this subpart) for all areas under active 
          influence of the collection system.
N = Number of landfill gas measurement locations (associated with a 
          destruction device or gas sent off-site). If a single 
          monitoring location is used to monitor volumetric flow and 
          CH4 concentration of the recovered gas sent to one 
          or multiple destruction devices, then N = 1.
Rn = Quantity of recovered CH4 from Equation HH-4 
          of this subpart for the nth measurement location (metric 
          tons).
fRec,n = Fraction of hours the recovery system associated 
          with the nth measurement location was operating (annual 
          operating hours/8760 hours per year or annual operating hours/
          8784 hours per year for a leap year).

[78 FR 71971, Nov. 29, 2013]



               Subpart II_Industrial Wastewater Treatment

    Source: 75 FR 39767, July 12, 2010, unless otherwise noted.



Sec. 98.350  Definition of source category.

    (a) This source category consists of anaerobic processes used to 
treat industrial wastewater and industrial

[[Page 991]]

wastewater treatment sludge at facilities that perform the operations 
listed in this paragraph.
    (1) Pulp and paper manufacturing.
    (2) Food processing.
    (3) Ethanol production.
    (4) Petroleum refining.
    (b) An anaerobic process is a procedure in which organic matter in 
wastewater, wastewater treatment sludge, or other material is degraded 
by micro-organisms in the absence of oxygen, resulting in the generation 
of CO2 and CH4. This source category consists of 
the following: anaerobic reactors, anaerobic lagoons, anaerobic sludge 
digesters, and biogas destruction devices (for example, burners, 
boilers, turbines, flares, or other devices).
    (1) An anaerobic reactor is an enclosed vessel used for anaerobic 
wastewater treatment (e.g., upflow anaerobic sludge blanket, fixed 
film).
    (2) Ananaerobic sludge digester is an enclosed vessel in which 
wastewater treatment sludge is degraded anaerobically.
    (3) Ananaerobic lagoon is a lined or unlined earthen basin used for 
wastewater treatment, in which oxygen is absent throughout the depth of 
the basin, except for a shallow surface zone. Anaerobic lagoons are not 
equipped with surface aerators. Anaerobic lagoons are classified as deep 
(depth more than 2 meters) or shallow (depth less than 2 meters).
    (c) This source category does not include municipal wastewater 
treatment plants or separate treatment of sanitary wastewater at 
industrial sites.

[75 FR 39767, July 12, 2010, as amended at 76 FR 73903, Nov. 29, 2011]



Sec. 98.351  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
meets all of the conditions under paragraphs (a) or (b) of this section:
    (a) Petroleum refineries and pulp and paper manufacturing. (1) The 
facility is subject to reporting under subpart Y of this part (Petroleum 
Refineries) or subpart AA of this part (Pulp and Paper Manufacturing).
    (2) The facility meets the requirements of either Sec. 98.2(a)(1) 
or (2).
    (3) The facility operates an anaerobic process to treat industrial 
wastewater and/or industrial wastewater treatment sludge.
    (b) Ethanol production and food processing facilities. (1) The 
facility performs an ethanol production or food processing operation, as 
defined in Sec. 98.358 of this subpart.
    (2) The facility meets the requirements of Sec. 98.2(a)(2).
    (3) The facility operates an anaerobic process to treat industrial 
wastewater and/or industrial wastewater treatment sludge.



Sec. 98.352  GHGs to report.

    (a) You must report CH4 generation, CH4 
emissions, and CH4 recovered from treatment of industrial 
wastewater at each anaerobic lagoon and anaerobic reactor.
    (b) You must report CH4 emissions and CH4 
recovered from each anaerobic sludge digester.
    (c) You must report CH4 emissions and CH4 
destruction resulting from each biogas collection and biogas destruction 
device.
    (d) You must report under subpart C of this part (General Stationary 
Fuel Combustion Sources) the emissions of CO2, 
CH4, and N2O from each stationary combustion unit 
associated with the biogas destruction device, if present, by following 
the requirements of subpart C of this part.

[75 FR 39767, July 12, 2010, as amended at 76 FR 73903, Nov. 29, 2011]



Sec. 98.353  Calculating GHG emissions.

    (a) For each anaerobic reactor and anaerobic lagoon, estimate the 
annual mass of CH4 generated according to the applicable 
requirements in paragraphs (a)(1) through (a)(2) of this section.
    (1) If you measure the concentration of organic material entering 
the anaerobic reactors or anaerobic lagoon using methods for the 
determination of chemical oxygen demand (COD), then estimate annual mass 
of CH4 generated using Equation II-1 of this section.

[[Page 992]]

[GRAPHIC] [TIFF OMITTED] TR12JY10.012

Where:

CH4Gn = Annual mass CH4 generated from 
          the nth anaerobic wastewater treatment process (metric tons).
n = Index for processes at the facility, used in Equation II-7.
w = Index for weekly measurement period.
Floww = Volume of wastewater sent to an anaerobic wastewater 
          treatment process in week w (m\3\/week), measured as specified 
          in Sec. 98.354(d).
CODw = Average weekly concentration of chemical oxygen demand 
          of wastewater entering an anaerobic wastewater treatment 
          process (for week w)(kg/m\3\), measured as specified in Sec. 
          98.354(b) and (c).
B0 = Maximum CH4 producing potential of wastewater 
          (kg CH4/kg COD), use the value 0.25.
MCF = CH4 conversion factor, based on relevant values in 
          Table II-1 of this subpart.
0.001 = Conversion factor from kg to metric tons.

    (2) If you measure the concentration of organic material entering an 
anaerobic reactor or anaerobic lagoon using methods for the 
determination of 5-day biochemical oxygen demand (BOD5), then 
estimate annual mass of CH4 generated using Equation II-2 of 
this section.
[GRAPHIC] [TIFF OMITTED] TR29NO11.001

Where:

CH4Gn = Annual mass of CH4 generated 
          from the anaerobic wastewater treatment process (metric tons).
n = Index for processes at the facility, used in Equation II-7.
w = Index for weekly measurement period.
Floww = Volume of wastewater sent to an anaerobic wastewater 
          treatment process in week w(m\3\/week), measured as specified 
          in Sec. 98.354(d).
BOD5,w = Average weekly concentration of 5-day biochemical 
          oxygen demand of wastewater entering an anaerobic wastewater 
          treatment process for week w(kg/m\3\), measured as specified 
          in Sec. 98.354(b) and (c).
B0 = Maximum CH4 producing potential of wastewater 
          (kg CH4/kg BOD5), use the value 0.6.
MCF = CH4 conversion factor, based on relevant values in 
          Table II-1 to this subpart.
0.001 = Conversion factor from kg to metric tons.

    (b) For each anaerobic reactor and anaerobic lagoon from which 
biogas is not recovered, estimate annual CH4 emissions using 
Equation II-3 of this section.
[GRAPHIC] [TIFF OMITTED] TR12JY10.014

Where:

CH4En = Annual mass of CH4 emissions 
          from the wastewater treatment process n from which biogas is 
          not recovered (metric tons).
CH4Gn = Annual mass of CH4 generated 
          from the wastewater treatment process n, as calculated in 
          Equation II-1 or II-2 of this section (metric tons).

    (c) For each anaerobic sludge digester, anaerobic reactor, or 
anaerobic lagoon from which some biogas is recovered, estimate the 
annual mass of CH4 recovered according to the requirements in 
paragraphs (c)(1) and (c)(2) of this section. To estimate the annual 
mass of CH4 recovered, you must continuously monitor biogas 
flow rate and determine the volume of biogas each week and the 
cumulative volume of biogas each year that is collected and routed to a 
destruction device as specified in Sec. 98.354(h). If the gas flow 
meter is not equipped with automatic correction for temperature, 
pressure, or, if necessary, moisture content, you must determine these 
parameters as specified in paragraph (c)(2)(ii) of this section.

[[Page 993]]

    (1) If you continuously monitor CH4 concentration (and if 
necessary, temperature, pressure, and moisture content required as 
specified in Sec. 98.354(f)) of the biogas that is collected and routed 
to a destruction device using a monitoring meter specifically for 
CH4 gas, as specified in Sec. 98.354(g), you must use this 
monitoring system and calculate the quantity of CH4 recovered 
for destruction using Equation II-4 of this section. A fully integrated 
system that directly reports CH4 quantity requires only the 
summing of results of all monitoring periods for a given year.
[GRAPHIC] [TIFF OMITTED] TR12JY10.015

Where:

Rn = Annual quantity of CH4 recovered from the nth 
          anaerobic reactor, sludge digester, or lagoon (metric tons 
          CH4/yr)
n = Index for processes at the facility, used in Equation II-7.
M = Total number of measurement periods in a year. Use M = 365 (M = 366 
          for leap years) for daily averaging of continuous monitoring, 
          as provided in paragraph (c)(1)of this section. Use M = 52 for 
          weekly sampling, as provided in paragraph (c)(2)of this 
          section.
m = Index for measurement period.
Vm = Cumulative volumetric flow for the measurement period in 
          actual cubic feet (acf). If no biogas was recovered during a 
          monitoring period, use zero.
(KMC)m = Moisture correction term for the 
          measurement period, volumetric basis.
    = 1 when (V)m and (CCH4)m are 
measured on a dry basis or if both are measured on a wet basis.
    = 1-(fH2O)m when (V)m is measured 
on a wet basis and (CCH4)m is measured on a dry 
basis.
    = 1/[1-(fH2O)m] when (V)m is 
measured on a dry basis and (CCH4)m is measured on 
a wet basis.
(fH2O)m = Average moisture content of biogas 
          during the measurment period, volumetric basis, (cubic feet 
          water per cubic feet biogas).
(CCH4)m = Average CH4 concentration of 
          biogas during the measurement period, (volume %).
0.0423 = Density of CH4 lb/cf at 520  deg.R or 60  deg.F and 
          1 atm.
520  deg.R = 520 degrees Rankine.
Tm = Average temperature at which flow is measured for the 
          measurement period ( deg.R). If the flow rate meter 
          automatically corrects for temperature to 520 deg. R, replace 
          ``520 deg. R/Tm'' with ``1''.
Pm = Average pressure at which flow is measured for the 
          measurement period (atm). If the flow rate meter automatically 
          corrects for pressure to 1 atm, replace ``Pm/1'' 
          with ``1''.
0.454/1,000 = Conversion factor (metric ton/lb).

    (2) If you do not continuously monitor CH4 concentration 
according to paragraph (c)(1) of this section, you must determine the 
CH4 concentration, temperature, pressure, and, if necessary, 
moisture content of the biogas that is collected and routed to a 
destruction device according to the requirements in paragraphs (c)(2)(i) 
through (c)(2)(ii) of this section and calculate the quantity of 
CH4 recovered for destruction using Equation II-4 of this 
section.
    (i) Determine the CH4 concentration in the biogas that is 
collected and routed to a destruction device in a location near or 
representative of the location of the gas flow meter at least once each 
calendar week; if only one measurement is made each calendar week, there 
must be least three days between measurements. For a given calendar 
week, you are not required to determine CH4 concentration if 
the cumulative volume of biogas for that calendar week, determined as 
specified in paragraph (c) of this section, is zero.
    (ii) If the gas flow meter is not equipped with automatic correction 
for temperature, pressure, or, if necessary, moisture content:
    (A) Determine the temperature and pressure in the biogas that is 
collected and routed to a destruction device in a location near or 
representative of the location of the gas flow meter at least once each 
calendar week; if only one measurement is made each calendar

[[Page 994]]

week, there must be at least three days between measurements.
    (B) If the CH4 concentration is determined on a dry basis 
and biogas flow is determined on a wet basis, or CH4 
concentration is determined on a wet basis and biogas flow is determined 
on a dry basis, and the flow meter does not automatically correct for 
moisture content, determine the moisture content in the biogas that is 
collected and routed to a destruction device in a location near or 
representative of the location of the gas flow meter at least once each 
calendar week that the cumulative biogas flow measured as specified in 
Sec. 98.354(h) is greater than zero; if only one measurement is made 
each calendar week, there must be at least three days between 
measurements.
    (d) For each anaerobic sludge digester, anaerobic reactor, or 
anaerobic lagoon from which some quantity of biogas is recovered, you 
must estimate both the annual mass of CH4 that is generated, 
but not recovered, according to paragraph (d)(1) of this section and the 
annual mass of CH4 emitted according to paragraph (d)(2) of 
this section.
    (1) Estimate the annual mass of CH4 that is generated, 
but not recovered, using Equation II-5 of this section.
[GRAPHIC] [TIFF OMITTED] TR12JY10.016

Where:

CH4Ln = Leakage at the anaerobic process n (metric 
          tons CH4).
n = Index for processes at the facility, used in Equation II-7.
Rn = Annual quantity of CH4 recovered from the nth 
          anaerobic reactor, anaerobic lagoon, or anaerobic sludge 
          digester, as calculated in Equation II-4 of this section 
          (metric tons CH4).
CE = CH4 collection efficiency of anaerobic process n, as 
          specified in Table II-2 of this subpart (decimal).

    (2) For each anaerobic sludge digester, anaerobic reactor, or 
anaerobic lagoon from which some quantity of biogas is recovered, 
estimate the annual mass of CH4 emitted using Equation II-6 
of this section.
[GRAPHIC] [TIFF OMITTED] TR29NO11.002

Where:

CH4En = Annual quantity of CH4 emitted 
          from the process n from which biogas is recovered (metric 
          tons).
n = Index for processes at the facility, used in Equation II-7.
CH4Ln = Leakage at the anaerobic process n, as 
          calculated in Equation II-5 of this section (metric tons 
          CH4).
Rn = Annual quantity of CH4 recovered from the nth 
          anaerobic reactor or anaerobic sludge digester, as calculated 
          in Equation II-4 of this section (metric tons CH4).
DE1 = Primary destruction device CH4 destruction 
          efficiency (lesser of manufacturer's specified destruction 
          efficiency and 0.99). If the biogas is transported off-site 
          for destruction, use DE = 1.
fDest--1 = Fraction of hours the primary destruction device 
          was operating calculated as the annual hours when the 
          destruction device was operating divided by the annual 
          operating hours of the biogas recovery system. If the biogas 
          is transported off-site for destruction, use fDest 
          = 1.
DE2 = Back-up destruction device CH4 destruction 
          efficiency (lesser of manufacturer's specified destruction 
          efficiency and 0.99).
fDest--2 = Fraction of hours the back-up destruction device 
          was operating calculated as the annual hours when the 
          destruction device was operating divided by the annual 
          operating hours of the biogas recovery system.

    (e) Estimate the total mass of CH4 emitted from all 
anaerobic processes from which biogas is not recovered (calculated in 
Eq. II-3) and all anaerobic processes from which some biogas is 
recovered (calculated in Equation II-6) using Equation II-7 of this 
section.
[GRAPHIC] [TIFF OMITTED] TR12JY10.018

Where:

CH4ET = Annual mass CH4 emitted from 
          all anaerobic processes at the facility (metric tons).
n = Index for processes at the facility.
CH4En = Annual mass of CH4 emissions 
          from process n (metric tons).

[[Page 995]]

j = Total number of processes from which methane is emitted.

[75 FR 39767, July 12, 2010, as amended at 76 FR 73903, Nov. 29, 2011; 
78 FR 71972, Nov. 29, 2013]



Sec. 98.354  Monitoring and QA/QC requirements.

    (a) For calendar year 2011 monitoring, the facility may submit a 
request to the Administrator to use one or more best available 
monitoring methods as listed in Sec. 98.3(d)(1)(i) through (iv). The 
request must be submitted no later than October 12, 2010 and must 
contain the information in Sec. 98.3(d)(2)(ii). To obtain approval, the 
request must demonstrate to the Administrator's satisfaction that it is 
not reasonably feasible to acquire, install, and operate a required 
piece of monitoring equipment by January 1, 2011. The use of best 
available monitoring methods will not be approved beyond December 31, 
2011.
    (b) You must determine the concentration of organic material in 
wastewater treated anaerobically using analytical methods for COD or 
BOD5 specified in 40 CFR 136.3 Table 1B. For the purpose of 
determining concentrations of wastewater influent to the anaerobic 
wastewater treatment process, samples may be diluted to the 
concentration range of the approved method, but the calculated 
concentration of the undiluted wastewater must be used for calculations 
and reporting required by this subpart.
    (c) You must collect samples representing wastewater influent to the 
anaerobic wastewater treatment process, following all preliminary and 
primary treatment steps (e.g., after grit removal, primary 
clarification, oil-water separation, dissolved air flotation, or similar 
solids and oil separation processes). You must collect and analyze 
samples for COD or BOD5 concentration at least once each 
calendar week that the anaerobic wastewater treatment process is 
operating; if only one measurement is made each calendar week, there 
must be at least three days between measurements. You must collect a 
sample that represents the average COD or BOD5 concentration 
of the waste stream over a 24-hour sampling period. You must collect a 
minimum of four sample aliquots per 24-hour period and composite the 
aliquots for analysis. Collect a flow-proportional composite sample 
(either constant time interval between samples with sample volume 
proportional to stream flow, or constant sample volume with time 
interval between samples proportional to stream flow). Follow sampling 
procedures and techniques presented in Chapter 5, Sampling, of the 
``NPDES Compliance Inspection Manual,'' (incorporated by reference, see 
Sec. 98.7) or Section 7.1.3, Sample Collection Methods, of the ``U.S. 
EPA NPDES Permit Writers' Manual,'' (incorporated by reference, see 
Sec. 98.7).
    (d) You must measure the flowrate of wastewater entering anaerobic 
wastewater treatment process at least once each calendar week that the 
process is operating; if only one measurement is made each calendar 
week, there must be at least three days between measurements. You must 
measure the flowrate for the 24-hour period for which you collect 
samples analyzed for COD or BOD5 concentration. The flow 
measurement location must correspond to the location used to collect 
samples analyzed for COD or BOD5 concentration. You must 
measure the flowrate using one of the methods specified in paragraphs 
(d)(1) through (d)(5) of this section or as specified by the 
manufacturer.
    (1) ASME MFC-3M-2004 Measurement of Fluid Flow in Pipes Using 
Orifice, Nozzle, and Venturi (incorporated by reference, see Sec. 
98.7).
    (2) ASME MFC-5M-1985 (Reaffirmed 1994) Measurement of Liquid Flow in 
Closed Conduits Using Transit-Time Ultrasonic Flowmeters (incorporated 
by reference, see Sec. 98.7).
    (3) ASME MFC-16-2007 Measurement of Liquid Flow in Closed Conduits 
with Electromagnetic Flowmeters (incorporated by reference, see Sec. 
98.7).
    (4) ASTM D1941-91 (Reapproved 2007) Standard Test Method for Open 
Channel Flow Measurement of Water with the Parshall Flume, approved June 
15, 2007, (incorporated by reference, see Sec. 98.7).
    (5) ASTM D5614-94 (Reapproved 2008) Standard Test Method for Open 
Channel Flow Measurement of Water with Broad-Crested Weirs, approved 
October

[[Page 996]]

1, 2008, (incorporated by reference, see Sec. 98.7).
    (e) All wastewater flow measurement devices must be calibrated prior 
to the first year of reporting and recalibrated either biennially (every 
2 years) or at the minimum frequency specified by the manufacturer. 
Wastewater flow measurement devices must be calibrated using the 
procedures specified by the device manufacturer.
    (f) For each anaerobic process (such as anaerobic reactor, sludge 
digester, or lagoon) from which biogas is recovered, you must make the 
measurements or determinations specified in paragraphs (f)(1) through 
(f)(3) of this section.
    (1) You must continuously measure the biogas flow rate as specified 
in paragraph (h) of this section and determine the cumulative volume of 
biogas recovered.
    (2) You must determine the CH4 concentration of the 
recovered biogas as specified in paragraph (g) of this section at a 
location near or representative of the location of the gas flow meter. 
You must determine CH4 concentration either continuously or 
intermittently. If you determine the concentration intermittently, you 
must determine the concentration at least once each calendar week that 
the cumulative biogas flow measured as specified in paragraph (h) of 
this section is greater than zero, with at least three days between 
measurements.
    (3) As specified in Sec. 98.353(c) and paragraph (h) of this 
section, you must determine temperature, pressure, and moisture content 
as necessary to accurately determine the biogas flow rate and 
CH4 concentration. You must determine temperature and 
pressure if the gas flow meter or gas composition monitor do not 
automatically correct for temperature or pressure. You must measure 
moisture content of the recovered biogas if the biogas flow rate is 
measured on a wet basis and the CH4 concentration is measured 
on a dry basis. You must also measure the moisture content of the 
recovered biogas if the biogas flow rate is measured on a dry basis and 
the CH4 concentration is measured on a wet basis.
    (g) For each anaerobic process (such as an anaerobic reactor, sludge 
digester, or lagoon) from which biogas is recovered, operate, maintain, 
and calibrate a gas composition monitor capable of measuring the 
concentration of CH4 in the recovered biogas using one of the 
methods specified in paragraphs (g)(1) through (g)(6) of this section or 
as specified by the manufacturer.
    (1) Method 18 at 40 CFR part 60, appendix A-6.
    (2) ASTM D1945-03, Standard Test Method for Analysis of Natural Gas 
by Gas Chromatography (incorporated by reference, see Sec. 98.7).
    (3) ASTM D1946-90 (Reapproved 2006), Standard Practice for Analysis 
of Reformed Gas by Gas Chromatography (incorporated by reference, see 
Sec. 98.7).
    (4) GPA Standard 2261-00, Analysis for Natural Gas and Similar 
Gaseous Mixtures by Gas Chromatography (incorporated by reference, see 
Sec. 98.7).
    (5) ASTM UOP539-97 Refinery Gas Analysis by Gas Chromatography 
(incorporated by reference, see Sec. 98.7).
    (6) As an alternative to the gas chromatography methods provided in 
paragraphs (g)(1) through (g)(5) of this section, you may use total 
gaseous organic concentration analyzers and calculate the CH4 
concentration following the requirements in paragraphs (g)(6)(i) through 
(g)(6)(iii) of this section.
    (i) Use Method 25A or 25B at 40 CFR part 60, appendix A-7 to 
determine total gaseous organic concentration. You must calibrate the 
instrument with CH4 and determine the total gaseous organic 
concentration as carbon (or as CH4; K = 1 in Equation 25A-1 
of Method 25A at 40 CFR part 60, appendix A-7).
    (ii) Determine a non-methane organic carbon correction factor at the 
routine sampling location no less frequently than once a reporting year 
following the requirements in paragraphs (g)(6)(ii)(A) through 
(g)(6)(ii)(C) of this section.
    (A) Take a minimum of three grab samples of the biogas with a 
minimum of 20 minutes between samples and determine the methane 
composition of the biogas using one of the methods specified in 
paragraphs (g)(1) through (g)(5) of this section.
    (B) As soon as practical after each grab sample is collected and 
prior to the collection of a subsequent grab

[[Page 997]]

sample, determine the total gaseous organic concentration of the biogas 
using either Method 25A or 25B at 40 CFR part 60, appendix A-7 as 
specified in paragraph (g)(6)(i) of this section.
    (C) Determine the arithmetic average methane concentration and the 
arithmetic average total gaseous organic concentration of the samples 
analyzed according to paragraphs (g)(6)(ii)(A) and (g)(6)(ii)(B) of this 
section, respectively, and calculate the non-methane organic carbon 
correction factor as the ratio of the average methane concentration to 
the average total gaseous organic concentration. If the ratio exceeds 1, 
use 1 for the non-methane organic carbon correction factor.
    (iii) Calculate the CH4 concentration as specified in 
Equation II-8 of this section.
[GRAPHIC] [TIFF OMITTED] TR12JY10.019

Where:

CCH4 = Methane (CH4) concentration in the biogas 
          (volume %) for use in Equation II-4 of this subpart.
fNMOC = Non-methane organic carbon correction factor from the 
          most recent determination of the non-methane organic carbon 
          correction factor as specified in paragraph (g)(6)(ii) of this 
          section (unitless).
CTGOC = Total gaseous organic carbon concentration measured 
          using Method 25A or 25B at 40 CFR part 60, appendix A-7 during 
          routine monitoring of the biogas (volume %).

    (h) For each anaerobic process (such as an anaerobic reactor, sludge 
digester, or lagoon) from which biogas is recovered, install, operate, 
maintain, and calibrate a gas flow meter capable of continuously 
measuring the volumetric flow rate of the recovered biogas using one of 
the methods specified in paragraphs (h)(1) through (h)(8) of this 
section or as specified by the manufacturer. Recalibrate each gas flow 
meter either biennially (every 2 years) or at the minimum frequency 
specified by the manufacturer. Except as provided in Sec. 
98.353(c)(2)(iii), each gas flow meter must be capable of correcting for 
the temperature and pressure and, if necessary, moisture content.
    (1) ASME MFC-3M-2004, Measurement of Fluid Flow in Pipes Using 
Orifice, Nozzle, and Venturi (incorporated by reference, see Sec. 
98.7).
    (2) ASME MFC-4M-1986 (Reaffirmed 1997), Measurement of Gas Flow by 
Turbine Meters (incorporated by reference, see Sec. 98.7).
    (3) ASME MFC-6M-1998, Measurement of Fluid Flow in Pipes Using 
Vortex Flowmeters (incorporated by reference, see Sec. 98.7).
    (4) ASME MFC-7M-1987 (Reaffirmed 1992), Measurement of Gas Flow by 
Means of Critical Flow Venturi Nozzles (incorporated by reference, see 
Sec. 98.7).
    (5) ASME MFC-11M-2006 Measurement of Fluid Flow by Means of Coriolis 
Mass Flowmeters (incorporated by reference, see Sec. 98.7). The mass 
flow must be corrected to volumetric flow based on the measured 
temperature, pressure, and biogas composition.
    (6) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore 
Precision Orifice Meters (incorporated by reference, see Sec. 98.7).
    (7) ASME MFC-18M-2001 Measurement of Fluid Flow using Variable Area 
Meters (incorporated by reference, see Sec. 98.7).
    (8) Method 2A or 2D at 40 CFR part 60, appendix A-1.
    (i) All temperature, pressure, and, moisture content monitors 
required as specified in paragraph (f) of this section must be 
calibrated using the procedures and frequencies where specified by the 
device manufacturer, if not specified use an industry accepted or 
industry standard practice.
    (j) All equipment (temperature, pressure, and moisture content 
monitors and gas flow meters and gas composition monitors) must be 
maintained as specified by the manufacturer.
    (k) If applicable, the owner or operator must document the 
procedures used to ensure the accuracy of measurements of COD or 
BOD5 concentration, wastewater flow rate, biogas flow rate, 
biogas composition, temperature, pressure, and moisture content. These 
procedures include, but are not limited to, calibration of gas flow 
meters, and other measurement devices. The estimated accuracy of 
measurements made

[[Page 998]]

with these devices must also be recorded, and the technical basis for 
these estimates must be documented.

[75 FR 39767, July 12, 2010, as amended at 76 FR 73904, Nov. 29, 2011]



Sec. 98.355  Procedures for estimating missing data.

    A complete record of all measured parameters used in the GHG 
emissions calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable (e.g., if a meter 
malfunctions during unit operation or if a required sample is not 
taken), a substitute data value for the missing parameter must be used 
in the calculations, according to the following requirements in 
paragraphs (a) through (c) of this section:
    (a) For each missing weekly value of COD or BOD5 or 
wastewater flow entering an anaerobic wastewater treatment process, the 
substitute data value must be the arithmetic average of the quality-
assured values of those parameters for the week immediately preceding 
and the week immediately following the missing data incident.
    (b) For each missing value of the CH4 content or biogas 
flow rates, the substitute data value must be the arithmetic average of 
the quality-assured values of that parameter immediately preceding and 
immediately following the missing data incident.
    (c) If, for a particular parameter, no quality-assured data are 
available prior to the missing data incident, the substitute data value 
must be the first quality-assured value obtained after the missing data 
period. If, for a particular parameter, the ``after'' value is not 
obtained by the end of the reporting year, you may use the last quality-
assured value obtained ``before'' the missing data period for the 
missing data substitution. You must document and keep records of the 
procedures you use for all such estimates.

[75 FR 39767, July 12, 2010, as amended at 76 FR 73905, Nov. 29, 2011]



Sec. 98.356  Data reporting requirements.

    In addition to the information required by Sec. 98.3(c), each 
annual report must contain the following information for each wastewater 
treatment system.
    (a) A description or diagram of the industrial wastewater treatment 
system, identifying the processes used to treat industrial wastewater 
and industrial wastewater treatment sludge. Indicate how the processes 
are related to each other and identify the anaerobic processes. Provide 
a unique identifier for each anaerobic process, indicate the average 
depth in meters of each anaerobic lagoon, and indicate whether biogas 
generated by each anaerobic process is recovered. The anaerobic 
processes must be identified as:
    (1) Anaerobic reactor.
    (2) Anaerobic deep lagoon (depth more than 2 meters).
    (3) Anaerobic shallow lagoon (depth less than 2 meters).
    (4) Anaerobic sludge digester.
    (b) For each anaerobic wastewater treatment process (reactor, deep 
lagoon, or shallow lagoon) you must report:
    (1) Weekly average COD or BOD5 concentration of 
wastewater entering each anaerobic wastewater treatment process, for 
each week the anaerobic process was operated.
    (2) Volume of wastewater entering each anaerobic wastewater 
treatment process for each week the anaerobic process was operated.
    (3) Maximum CH4 production potential (B0) used 
as an input to Equation II-1 or II-2 of this subpart, from Table II-1 to 
this subpart.
    (4) Methane conversion factor (MCF) used as an input to Equation II-
1 or II-2 of this subpart, from Table II-1 to this subpart.
    (5) Annual mass of CH4 generated by each anaerobic 
wastewater treatment process, calculated using Equation II-1 or II-2 of 
this subpart.
    (c) For each anaerobic wastewater treatment process from which 
biogas is not recovered, you must report the annual CH4 
emissions, calculated using Equation II-3 of this subpart.
    (d) For each anaerobic wastewater treatment process and anaerobic 
sludge digester from which some biogas is recovered, you must report:
    (1) Annual quantity of CH4 recovered from the anaerobic 
process calculated using Equation II-4 of this subpart.

[[Page 999]]

    (2) Total weekly volumetric biogas flow for each week (up to 52 
weeks/year) that biogas is collected for destruction.
    (3) Weekly average CH4 concentration for each week that 
biogas is collected for destruction.
    (4) Weekly average biogas temperature for each week at which flow is 
measured for biogas collected for destruction, or statement that 
temperature is incorporated into monitoring equipment internal 
calculations.
    (5) Whether flow was measured on a wet or dry basis, whether 
CH4 concentration was measured on a wet or dry basis, and if 
required for Equation II-4 of this subpart, weekly average moisture 
content for each week at which flow is measured for biogas collected for 
destruction, or statement that moisture content is incorporated into 
monitoring equipment internal calculations.
    (6) Weekly average biogas pressure for each week at which flow is 
measured for biogas collected for destruction, or statement that 
pressure is incorporated into monitoring equipment internal 
calculations.
    (7) CH4 collection efficiency (CE) used in Equation II-5 
of this subpart.
    (8) Whether destruction occurs at the facility or off-site. If 
destruction occurs at the facility, also report whether a back-up 
destruction device is present at the facility, the annual operating 
hours for the primary destruction device, the annual operating hours for 
the back-up destruction device (if present), the destruction efficiency 
for the primary destruction device, and the destruction efficiency for 
the back-up destruction device (if present).
    (9) For each anaerobic process from which some biogas is recovered, 
you must report the annual CH4 emissions, as calculated by 
Equation II-6 of this subpart.
    (e) The total mass of CH4 emitted from all anaerobic 
processes from which biogas is not recovered (calculated in Equation II-
3 of this subpart) and from all anaerobic processes from which some 
biogas is recovered (calculated in Equation II-6 of this subpart) using 
Equation II-7 of this subpart.

[75 FR 39767, July 12, 2010, as amended at 76 FR 73905, Nov. 29, 2011]



Sec. 98.357  Records that must be retained.

    In addition to the information required by Sec. 98.3(g), you must 
retain the calibration records for all monitoring equipment, including 
the method or manufacturer's specification used for calibration.



Sec. 98.358  Definitions.

    Except as provided below, all terms used in this subpart have the 
same meaning given in the CAA and subpart A of this part.
    Biogas means the combination of CO2, CH4, and 
other gases produced by the biological breakdown of organic matter in 
the absence of oxygen.
    Ethanol production means an operation that produces ethanol from the 
fermentation of sugar, starch, grain, or cellulosic biomass feedstocks, 
or the production of ethanol synthetically from petrochemical 
feedstocks, such as ethylene or other chemicals.
    Food processing means an operation used to manufacture or process 
meat, poultry, fruits, and/or vegetables as defined under NAICS 3116 
(Meat Product Manufacturing) or NAICS 3114 (Fruit and Vegetable 
Preserving and Specialty Food Manufacturing). For information on NAICS 
codes, see http://www.census.gov/eos/www/naics/.
    Industrial wastewater means water containing wastes from an 
industrial process. Industrial wastewater includes water which comes 
into direct contact with or results from the storage, production, or use 
of any raw material, intermediate product, finished product, by-product, 
or waste product. Examples of industrial wastewater include, but are not 
limited to, paper mill white water, wastewater from equipment cleaning, 
wastewater from air pollution control devices, rinse water, contaminated 
stormwater, and contaminated cooling water.
    Industrial wastewater treatment sludge means solid or semi-solid 
material resulting from the treatment of industrial wastewater, 
including but not

[[Page 1000]]

limited to biosolids, screenings, grit, scum, and settled solids.
    Wastewater treatment system means the collection of all processes 
that treat or remove pollutants and contaminants, such as soluble 
organic matter, suspended solids, pathogenic organisms, and chemicals 
from wastewater prior to its reuse or discharge from the facility.



       Sec. Table II-1 to Subpart II of Part 98--Emission Factors

------------------------------------------------------------------------
            Factors                Default value           Units
------------------------------------------------------------------------
B0--for facilities monitoring                0.25  Kg CH4/kg COD
 COD.
B0--for facilities monitoring                0.60  Kg CH4/kg BOD5
 BOD5.
MCF--anaerobic reactor.........               0.8  Fraction.
MCF--anaerobic deep lagoon                    0.8  Fraction.
 (depth more than 2 m).
MCF--anaerobic shallow lagoon                 0.2  Fraction.
 (depth less than 2 m).
------------------------------------------------------------------------



  Sec. Table II-2 to Subpart II--Collection Efficiencies of Anaerobic 
                                Processes

------------------------------------------------------------------------
                                                              Methane
      Anaerobic process type             Cover type         collection
                                                            efficiency
------------------------------------------------------------------------
Covered anaerobic lagoon (biogas    Bank to bank,                  0.975
 capture).                           impermeable.
                                    Modular, impermeable            0.70
Anaerobic sludge digester;          Enclosed Vessel.....            0.99
 anaerobic reactor.
------------------------------------------------------------------------



                      Subpart JJ_Manure Management



Sec. 98.360  Definition of the source category.

    (a) This source category consists of livestock facilities with 
manure management systems that emit 25,000 metric tons CO2e 
or more per year.
    (1) Table JJ-1 presents the minimum average annual animal population 
by animal group that is estimated to emit 25,000 metric tons 
CO2e or more per year. Facilities with an average annual 
animal population, as described in Sec. 98.363(a)(1) and (2), below 
those listed in Table JJ-1 do not need to report under this rule. A 
facility with an annual animal population that exceeds those listed in 
Table JJ-1 should conduct a more thorough analysis to determine 
applicability.
    (2) (i) If a facility has more than one animal group present (e.g., 
swine and poultry), the facility must determine if they are required to 
report by calculating the combined animal group factor (CAGF) using 
equation JJ-1:
[GRAPHIC] [TIFF OMITTED] TR30OC09.137

Where:

CAGF = Combined Animal Group Factor
AAAPAG,Facility = Average annual animal population at the 
          facility, by animal group
APTL AG = Animal population threshold level, as specified in 
          Table JJ-1 of this section

    (ii) If the calculated CAGF for a facility is less than 1, the 
facility is not required to report under this rule. If the CAGF is equal 
to or greater than 1, the facility must use more detailed applicability 
tables and tools to determine if they are required to report under this 
rule.
    (b) A manure management system (MMS) is a system that stabilizes 
and/or stores livestock manure, litter, or manure wastewater in one or 
more of the following system components: Uncovered anaerobic lagoons, 
liquid/slurry systems with and without crust covers (including but not 
limited to ponds and tanks), storage pits, digesters,

[[Page 1001]]

solid manure storage, dry lots (including feedlots), high-rise houses 
for poultry production (poultry without litter), poultry production with 
litter, deep bedding systems for cattle and swine, manure composting, 
and aerobic treatment.
    (c) This source category does not include system components at a 
livestock facility that are unrelated to the stabilization and/or 
storage of manure such as daily spread or pasture/range/paddock systems 
or land application activities or any method of manure utilization that 
is not listed in Sec. 98.360(b).
    (d) This source category does not include manure management 
activities located off site from a livestock facility or off-site manure 
composting operations.



Sec. 98.361  Reporting threshold.

    Livestock facilities must report GHG emissions under this subpart if 
the facility meets the reporting threshold as defined in 98.360(a) 
above, contains a manure management system as defined in 98.360(b) 
above, and meets the requirements of Sec. 98.2(a)(1).



Sec. 98.362  GHGs to report.

    (a) Livestock facilities must report annual aggregate CH4 
and N2O emissions for the following MMS components at the 
facility:
    (1) Uncovered anaerobic lagoons.
    (2) Liquid/slurry systems (with and without crust covers, and 
including but not limited to ponds and tanks).
    (3) Storage pits.
    (4) Digesters, including covered anaerobic lagoons.
    (5) Solid manure storage.
    (6) Dry lots, including feedlots.
    (7) High-rise houses for poultry production (poultry without litter)
    (8) Poultry production with litter.
    (9) Deep bedding systems for cattle and swine.
    (10) Manure composting.
    (11) Aerobic treatment.
    (b) A livestock facility that is subject to this rule only because 
of emissions from manure management system components is not required to 
report emissions from subparts C through PP (other than subpart JJ) of 
this part.
    (c) A livestock facility that is subject to this part because of 
emissions from source categories described in subparts C through PP of 
this part is not required to report emissions under subpart JJ of this 
part unless emissions from manure management systems are 25,000 metric 
tons CO2e per year or more.



Sec. 98.363  Calculating GHG emissions.

    (a) For all manure management system components listed in 98.360(b) 
except digesters, estimate the annual CH4 emissions and sum 
for all the components to obtain total emissions from the manure 
management system for all animal types using Equation JJ-1.
[GRAPHIC] [TIFF OMITTED] TR30OC09.138

Where:

MMSC = Manure management systems component.
TVSAT = Total volatile solids excreted by animal type, 
          calculated using Equation JJ-3 of this section (kg/day).
VSMMSC = Fraction of the total manure for each animal type 
          that is managed in MMS component MMSC, assumed to be 
          equivalent to the fraction of VS in each MMS component.
VSss = Volatile solids removal through solid separation; if 
          solid separation occurs prior to the MMS component, use a 
          default value from Table JJ-4 of this section; if no solid 
          separation occurs, this value is set to 0.
(B0)AT = Maximum CH4-producing capacity 
          for each animal type, as specified in Table JJ-2 of this 
          section (m\3\ CH4/kg VS).
MCFMMSC = CH4 conversion factor for the MMS 
          component, as specified in Table JJ-5 of this section 
          (decimal).

[[Page 1002]]

[GRAPHIC] [TIFF OMITTED] TR30OC09.139

Where:

TVSAT = Daily total volatile solids excreted per animal type 
          (kg/day).
PopulationAT = Average annual animal population contributing 
          manure to the manure management system by animal type (head) 
          (see description in Sec. 98.363(a)(i) and (ii) below).
TAMAT = Typical animal mass for each animal type, using 
          either default values in Table JJ-2 of this section or farm-
          specific data (kg/head).
VSAT = Volatile solids excretion rate for each animal type, 
          using default values in Table JJ-2 or JJ-3 of this section (kg 
          VS/day/1000 kg animal mass).

    (1) Average annual animal populations for static populations (e.g., 
dairy cows, breeding swine, layers) must be estimated by performing an 
animal inventory or review of facility records once each reporting year.
    (2) Average annual animal populations for growing populations (meat 
animals such as beef and veal cattle, market swine, broilers, and 
turkeys) must be estimated each year using the average number of days 
each animal is kept at the facility and the number of animals produced 
annually, and an equation similar or equal to Equation JJ-4 below, 
adapted from Equation 10.1 in 2006 IPCC Guidelines for National 
Greenhouse Gas Inventories, Volume 4, Chapter 10.
[GRAPHIC] [TIFF OMITTED] TR30OC09.140

Where:

PopulationAT = Average annual animal population (by animal 
          type).
Days onsiteAT = Average number of days the animal is kept at 
          the facility, by animal type.
NAPAAT = Number of animals produced annually, by animal type.

    (b) For each digester, calculate the total amount of CH4 
emissions, and then sum the emissions from all digesters, as shown in 
Equation JJ-5 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.141

Where:

CH4 EmissionsAD = CH4 emissions from 
          anaerobic digestion (metric tons/yr).
AD = Number of anaerobic digesters at the manure management facility.
CH4C = CH4 flow to digester combustion device, 
          calculated using Equation JJ-6 of this section (metric tons 
          CH4/yr).
CH4D = CH4 destruction at digesters, calculated 
          using Equation JJ-11 of this section (metric tons 
          CH4/yr)
CH4L = Leakage at digesters calculated using Equation JJ-12 
          of this section (metric tons CH4/yr).

    (1) For each digester, calculate the annual CH4 flow to 
the combustion device (CH4C) using Equation JJ-6 of this 
section. A fully integrated system that directly reports the quantity of 
CH4 flow to the digester combustion device requires only 
summing the results of all monitoring periods for a given year to obtain 
CH4C.

[[Page 1003]]

[GRAPHIC] [TIFF OMITTED] TR30OC09.142

Where:

CH4C = CH4 flow to digester combustion device 
          (metric tons CH4/yr).
V = Average annual volumetric flow rate, calculated in Equation JJ-7 of 
          this subsection (cubic feet CH4/yr).
C = Average annual CH4 concentration of digester gas, 
          calculated in Equation JJ-8 of this section (%, wet basis).
0.0423 = Density of CH4 lb/scf (at 520  deg.R or 60  deg.F 
          and 1 atm).
T = Average annual temperature at which flow is measured, calculated in 
          Equation JJ-9 of this section ( deg.R).
P = Average annual pressure at which flow is measured, calculated in 
          Equation JJ-10 of this section (atm).

    (2) For each digester, calculate the average annual volumetric flow 
rate, CH4 concentration of digester gas, temperature, and 
pressure at which flow are measured using Equations JJ-7 through JJ-10 
of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.143

Where:

V = Average annual volumetric flow rate (cubic feet CH4/yr).
OD = Operating days, number of days per year that that the digester was 
          operating (days/yr).
Vn = Daily average volumetric flow rate for day n, as 
          determined from daily monitoring as specified in Sec. 98.364 
          (acfm).
          [GRAPHIC] [TIFF OMITTED] TR30OC09.144
          
Where:

C = Average annual CH4 concentration of digester gas (%, wet 
          basis).
OD = Operating days, number of days per year that the digester was 
          operating (days/yr).
Cn = Average daily CH4 concentration of digester 
          gas for day n, as determined from daily monitoring as 
          specified in Sec. 98.364 (%, wet basis).
          [GRAPHIC] [TIFF OMITTED] TR30OC09.145
          
Where:

T = Average annual temperature at which flow is measured ( deg.R).
OD = Operating days, number of days per year that the digester was 
          operating (days/yr).
Tn = Temperature at which flow is measured for day n( deg.R).
[GRAPHIC] [TIFF OMITTED] TR30OC09.146

Where:

P = Average annual pressure at which flow is measured (atm).
OD = Operating days, number of days per year that the digester was 
          operating (days/yr).
Pn = Pressure at which flow is measured for day n (atm).

    (3) For each digester, calculate the CH4 destruction at 
the digester combustion device using Equation JJ-11 of this section.

[[Page 1004]]

[GRAPHIC] [TIFF OMITTED] TR30OC09.147

Where:

CH4D = CH4 destruction at digester combustion 
          device (metric tons/yr).
CH4C = Annual quantity of CH4 flow to digester 
          combustion device, as calculated in Equation JJ-6 of this 
          section (metric tons CH4).
DE = CH4 destruction efficiency from flaring or burning in 
          engine (lesser of manufacturer's specified destruction 
          efficiency and 0.99). If the gas is transported off-site for 
          destruction, use DE = 1.
OH = Number of hours combustion device is functioning in reporting year.
Hours = Hours in reporting year.

    (4) For each digester, calculate the CH4 leakage using 
Equation JJ-12 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.148

Where:

CH4L = Leakage at digesters (metric tons/yr).
CH4C = Annual quantity of CH4 flow to digester 
          combustion device, as calculated in Equation JJ-6 of this 
          section (metric tons CH4).
CE = CH4 collection efficiency of anaerobic digester, as 
          specified in Table JJ-6 of this section (decimal).

    (c) For each MMS component, estimate the annual N2O 
emissions and sum for all MMS components to obtain total emissions from 
the manure management system for all animal types using Equation JJ-13 
of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.149

Where:

Nex AT = Daily total nitrogen excreted per animal type, 
          calculated using Equation JJ-14 of this section (kg N/day).
Nex,MMSC = Fraction of the total manure for each animal type 
          that is managed in MMS component MMSC, assumed to be 
          equivalent to the fraction of Nex in each MMS 
          component.
Nss = Nitrogen removal through solid separation; if solid 
          separation occurs prior to the MMS component, use a default 
          value from Table JJ-4 of this section; if no solid separation 
          occurs, this value is set to 0.
EFMMSC = Emission factor for MMS component, as specified in 
          Table JJ-7 of this section (kg N2O-N/kg N).
          [GRAPHIC] [TIFF OMITTED] TR30OC09.150
          
Where:

Nex AT = Total nitrogen excreted per animal type (kg/day).
PopulationAT = Average annual animal population contributing 
          manure to the manure management system by animal type (head) 
          (see description in Sec. 98.363(a)(i) and (ii)).
TAMAT = Typical animal mass by animal type, using either 
          default values in Table JJ-2 of this section or farm-specific 
          data (kg/head).

[[Page 1005]]

NAT = Nitrogen excretion rate by animal type, using default 
          values in Tables JJ-2 or JJ-3 of this section (kg N/day/1000 
          kg animal mass).

    (d) Estimate the annual total facility emissions using Equation JJ-
15 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.151

Where:

CH4 emissionsMMS = From Equation JJ-2 of this 
          section.
CH4 emissionsAD = From Equation JJ-5 of this 
          section.
21 = Global Warming Potential of CH4.
Direct N2O emissions = From Equation JJ-13 of this section.
310 = Global Warming Potential of N2O.



Sec. 98.364  Monitoring and QA/QC requirements.

    (a) Perform an annual animal inventory or review of facility records 
(for static populations) or population calculation (for growing 
populations) to determine the average annual animal population for each 
animal type (see description in Sec. 98.363(a)(1) and (2)).
    (b) Perform an analysis on your operation to determine the fraction 
of total manure by weight for each animal type that is managed in each 
on-site manure management system component. If your system changes from 
previous reporting periods, you must reevaluate the fraction of total 
manure managed in each system component.
    (c) The CH4 concentration of gas from digesters must be 
determined using ASTM D1946-90 (Reapproved 2006) Standard Practice for 
Analysis of Reformed Gas by Gas Chromatography (incorporated by 
reference see Sec. 98.7). All gas composition monitors shall be 
calibrated prior to the first reporting year for biogas methane and 
carbon dioxide content using ASTM D1946-90 (Reapproved 2006) Standard 
Practice for Analysis of Reformed Gas by Gas Chromatography 
(incorporated by reference see Sec. 98.7)and recalibrated either 
annually or at the minimum frequency specified by the manufacturer, 
whichever is more frequent, or whenever the error in the midrange 
calibration check exceeds 10 percent. All monitors 
shall be maintained as specified by the manufacturer.
    (d) All temperature and pressure monitors must be calibrated using 
the procedures and frequencies specified by the manufacturer. All 
equipment (temperature and pressure monitors) shall be maintained as 
specified by the manufacturer.
    (e) For digesters with gas collection systems, install, operate, 
maintain, and calibrate a gas flow meter capable of measuring the 
volumetric flow rate to provide data for the GHG emissions calculations, 
using the applicable methods specified in paragraphs (e)(1) through 
(e)(6) of this section or as specified by the manufacturer.
    (1) ASME MFC-3M-2004 Measurement of Fluid Flow in Pipes Using 
Orifice, Nozzle, and Venturi (incorporated by reference, see Sec. 
98.7).
    (2) ASME MFC-4M-1986 (Reaffirmed 1997) Measurement of Gas Flow by 
Turbine Meters (incorporated by reference, see Sec. 98.7).
    (3) ASME MFC-6M-1998 Measurement of Fluid Flow in Pipes Using Vortex 
Flowmeters (incorporated by reference, see Sec. 98.7).
    (4) ASME MFC-7M-1987 (Reaffirmed 1992) Measurement of Gas Flow by 
Means of Critical Flow Venturi Nozzles (incorporated by reference, see 
Sec. 98.7).
    (5) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore 
Precision Orifice Meters (incorporated by reference, see Sec. 98.7).
    (6) ASME MFC-18M-2001 Measurement of Fluid Flow using Variable Area 
Meters (incorporated by reference, see Sec. 98.7).
    (f) If applicable, the owner or operator shall document the 
procedures used to ensure the accuracy of gas flow rate, gas 
composition, temperature, and pressure measurements. These procedures 
include, but are not limited to, calibration of fuel flow meters and 
other measurement devices. The estimated accuracy of measurements made 
with these devices shall also be recorded, and the technical basis for 
these estimates shall be provided.

[[Page 1006]]

    (g) Each gas flow meter shall be calibrated prior to the first 
reporting year and recalibrated either annually or at the minimum 
frequency specified by the manufacturer, whichever is more frequent. 
Each gas flow meter must have a rated accuracy of 5 percent or lower and be capable of correcting for the 
temperature and pressure and, if the gas composition monitor determines 
CH4 concentration on a dry basis, moisture content.



Sec. 98.365  Procedures for estimating missing data.

    (a) A complete record of all measured parameters used in the GHG 
emissions calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable (e.g., if a meter 
malfunctions during unit operation or if a required fuel sample is not 
taken), a substitute data value for the missing parameter shall be used 
in the calculations, according to the requirements in paragraph (b) of 
this section.
    (b) For missing gas flow rates or CH4 content data, the 
substitute data value shall be the arithmetic average of the quality-
assured values of that parameter immediately preceding and immediately 
following the missing data incident. If, for a particular parameter, no 
quality-assured data are available prior to the missing data incident, 
the substitute data value shall be the first quality-assured value 
obtained after the missing data period.



Sec. 98.366  Data reporting requirements.

    (a) In addition to the information required by Sec. 98.3(c), each 
annual report must contain the following information:
    (1) List of manure management system components at the facility.
    (2) Fraction of manure from each animal type that is handled in each 
manure management system component.
    (3) Average annual animal population (for each animal type) for 
static populations or the results of Equation JJ-4 for growing 
populations.
    (4) Average number of days that growing animals are kept at the 
facility (for each animal type).
    (5) The number of animals produced annually for growing populations 
(for each animal type).
    (6) Typical animal mass (for each animal type).
    (7) Total facility emissions (results of Equation JJ-15).
    (8) CH4 emissions from manure management system 
components listed in Sec. 98.360(b), except digesters (results of 
Equation JJ-2).
    (9) VS value used (for each animal type).
    (10) B0 value used (for each animal type).
    (11) Methane conversion factor used for each MMS component.
    (12) Average ambient temperature used to select each methane 
conversion factor.
    (13) N2O emissions (results of Equation JJ-13).
    (14) N value used for each animal type.
    (15) N2O emission factor selected for each MMS component.
    (b) Facilities with anaerobic digesters must also report:
    (1) CH4 emissions from anaerobic digesters (results of 
Equation JJ-5).
    (2) CH4 flow to the digester combustion device for each 
digester (results of Equation JJ-6, or value from fully integrated 
monitoring system as described in 98.363(b)).
    (3) CH4 destruction for each digester (results of 
Equation JJ-11).
    (4) CH4 leakage for each digester (results of Equation 
JJ-12).
    (5) Total annual volumetric biogas flow for each digester (results 
of Equation JJ-7).
    (6) Average annual CH4 concentration for each digester 
(results of Equation JJ-8).
    (7) Average annual temperature at which gas flow is measured for 
each digester (results of Equation JJ-9).
    (8) Average annual gas flow pressure at which gas flow is measured 
for each digester (results of Equation JJ-10).
    (9) Destruction efficiency used for each digester.
    (10) Number of days per year that each digester was operating.
    (11) Collection efficiency used for each digester.

[[Page 1007]]



Sec. 98.367  Records that must be retained.

    In addition to the information required by Sec. 98.3(g), you must 
retain the calibration records for all monitoring equipment, including 
the method or manufacturer's specification used for calibration.



Sec. 98.368  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.



 Sec. Table JJ-1 to Subpart JJ of Part 98--Animal Population Threshold 
Level Below Which Facilities Are Not Required To Report Emissions Under 
                            Subpart JJ \1 2\

------------------------------------------------------------------------
                                                          Average annual
                                                              animal
                      Animal group                          population
                                                            (Head) \3\
------------------------------------------------------------------------
Beef....................................................          29,300
Dairy...................................................           3,200
Swine...................................................          34,100
Poultry:
    Layers..............................................         723,600
    Broilers............................................      38,160,000
    Turkeys.............................................       7,710,000
------------------------------------------------------------------------
\1\ The threshold head populations in this table were calculated using
  the most conservative assumptions (high VS and N values, maximum
  ambient temperatures, and the application of an uncertainty factor) to
  ensure that facilities at or near the 25,000 metric ton CO2e threshold
  level were not excluded from reporting.
\2\ For facilities with more than one animal group present refer to Sec.
    98.360 (2) to estimate the combined animal group factor (CAGF),
  which is used to determine if a facility may be required to report.
\3\ For all animal groups except dairy, the average annual animal
  population represents the total number of animals present at the
  facility. For dairy facilities, the average annual animal population
  represents the number of mature dairy cows present at the facility
  (note that heifers and calves were included in the emission estimates
  for dairy facilities using the assumption that the average annual
  animal population of heifers and calves at dairy facilities are equal
  to 30 percent of the mature dairy cow average annual animal
  population, therefore the average annual population for dairy
  facilities should not include heifers and calves, only dairy cows).



  Sec. Table JJ-2 to Subpart JJ of Part 98--Waste Characteristics Data

----------------------------------------------------------------------------------------------------------------
                                                                                                      Maximum
                                                       Volatile solids                                methane
                                    Typical animal  excretion rate (kg VS/   Nitrogen excretion     generation
            Animal type                mass (kg)      day/1000 kg animal    rate (kg N/day/1000    potential, Bo
                                                            mass)             kg animal mass)      (m\3\ CH4/kg
                                                                                                     VS added)
----------------------------------------------------------------------------------------------------------------
Dairy Cows........................             604  See Table JJ-3.......  See Table JJ-3.......            0.24
Dairy Heifers.....................             476  See Table JJ-3.......  See Table JJ-3.......            0.17
Dairy Calves......................             118  6.41.................  0.30.................            0.17
Feedlot Steers....................             420  See Table JJ-3.......  See Table JJ-3.......            0.33
Feedlot heifers...................             420  See Table JJ-3.......  See Table JJ-3.......            0.33
Market Swine <60 lbs..............              16  8.80.................  0.60.................            0.48
Market Swine 60-119 lbs...........              41  5.40.................  0.42.................            0.48
Market Swine 120-179 lbs..........              68  5.40.................  0.42.................            0.48
Market Swine 180 lbs...              91  5.40.................  0.42.................            0.48
Breeding Swine....................             198  2.60.................  0.24.................            0.48
Feedlot Sheep.....................              25  9.20.................  0.42.................            0.36
Goats.............................              64  9.50.................  0.45.................            0.17
Horses............................             450  10.00................  0.30.................            0.33
Hens /= 1 yr...........             1.8  10.09................  0.83.................            0.39
Pullets...........................             1.8  10.09................  0.62.................            0.39
Other Chickens....................             1.8  10.80................  0.83.................            0.39
Broilers..........................             0.9  15.00................  1.10.................            0.36
Turkeys...........................             6.8  9.70.................  0.74.................            0.36
----------------------------------------------------------------------------------------------------------------


[[Page 1008]]



Sec. Table JJ-3 to Subpart JJ of Part 98--State-Specific Volatile Solids 
            (VS) and Nitrogen (N) Excretion Rates for Cattle

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                  Volatile solids excretion rate (kg VS/day/  Nitrogen excretion rate (kg VS/day/1000 kg
                                                                             1000 kg animal mass)                            animal mass)
                              State                              ---------------------------------------------------------------------------------------
                                                                    Dairy      Dairy     Feedlot    Feedlot     Dairy      Dairy     Feedlot    Feedlot
                                                                     cows     heifers     steer     heifers      cows     heifers     steer     heifers
--------------------------------------------------------------------------------------------------------------------------------------------------------
Alabama.........................................................       8.40       8.35       4.27       4.74       0.50       0.46       0.36       0.38
Alaska..........................................................       7.30       8.35       4.15       4.58       0.45       0.46       0.35       0.37
Arizona.........................................................      10.37       8.35       3.91       4.27       0.58       0.46       0.33       0.34
Arkansas........................................................       7.59       8.35       3.98       4.35       0.46       0.46       0.33       0.35
California......................................................      10.02       8.35       3.96       4.33       0.56       0.46       0.33       0.34
Colorado........................................................      10.25       8.35       3.97       4.34       0.58       0.46       0.33       0.35
Connecticut.....................................................       9.22       8.35       4.41       4.93       0.53       0.46       0.37       0.40
Delaware........................................................       8.63       8.35       4.19       4.64       0.51       0.46       0.35       0.37
Florida.........................................................       8.90       8.35       4.15       4.58       0.52       0.46       0.35       0.37
Georgia.........................................................       9.07       8.35       4.18       4.63       0.53       0.46       0.35       0.37
Hawaii..........................................................       7.00       8.35       4.15       4.58       0.44       0.46       0.35       0.37
Idaho...........................................................      10.11       8.35       4.03       4.42       0.57       0.46       0.34       0.35
Illinois........................................................       9.07       8.35       4.15       4.59       0.52       0.46       0.35       0.37
Indiana.........................................................       9.38       8.35       3.98       4.35       0.54       0.46       0.33       0.35
Iowa............................................................       9.46       8.35       3.93       4.28       0.54       0.46       0.33       0.34
Kansas..........................................................       9.63       8.35       3.97       4.35       0.55       0.46       0.33       0.35
Kentucky........................................................       7.89       8.35       4.20       4.65       0.48       0.46       0.35       0.37
Louisiana.......................................................       7.39       8.35       4.07       4.48       0.45       0.46       0.34       0.36
Maine...........................................................       8.99       8.35       4.07       4.47       0.52       0.46       0.34       0.36
Maryland........................................................       9.02       8.35       4.05       4.45       0.52       0.46       0.34       0.35
Massachusetts...................................................       8.63       8.35       4.15       4.58       0.51       0.46       0.35       0.37
Michigan........................................................      10.05       8.35       4.00       4.38       0.57       0.46       0.34       0.35
Minnesota.......................................................       9.17       8.35       3.89       4.24       0.53       0.46       0.33       0.34
Mississippi.....................................................       8.19       8.35       4.14       4.57       0.49       0.46       0.35       0.37
Missouri........................................................       8.02       8.35       4.08       4.49       0.48       0.46       0.34       0.36
Montana.........................................................       9.03       8.35       4.23       4.69       0.52       0.46       0.36       0.38
Nebraska........................................................       9.09       8.35       3.98       4.35       0.53       0.46       0.33       0.35
Nevada..........................................................       9.65       8.35       4.07       4.48       0.55       0.46       0.34       0.36
New Hampshire...................................................       9.44       8.35       3.94       4.30       0.54       0.46       0.33       0.34
New Jersey......................................................       8.51       8.35       3.98       4.36       0.50       0.46       0.33       0.35
New Mexico......................................................      10.34       8.35       3.88       4.22       0.58       0.46       0.32       0.33
New York........................................................       9.42       8.35       3.75       4.05       0.54       0.46       0.31       0.32
North Carolina..................................................       9.38       8.35       4.20       4.65       0.55       0.46       0.35       0.37
North Dakota....................................................       8.40       8.35       3.88       4.22       0.50       0.46       0.32       0.34
Ohio............................................................       9.01       8.35       3.96       4.33       0.52       0.46       0.33       0.34
Oklahoma........................................................       8.58       8.35       3.98       4.35       0.50       0.46       0.33       0.35
Oregon..........................................................       9.40       8.35       4.06       4.46       0.54       0.46       0.34       0.36
Pennsylvania....................................................       9.26       8.35       3.98       4.35       0.53       0.46       0.33       0.35
Rhode Island....................................................       8.94       8.35       4.36       4.87       0.52       0.46       0.37       0.39
South Carolina..................................................       9.05       8.35       4.15       4.58       0.53       0.46       0.35       0.37
South Dakota....................................................       9.45       8.35       4.01       4.39       0.54       0.46       0.34       0.35
Tennessee.......................................................       8.60       8.35       4.48       5.02       0.51       0.46       0.38       0.40
Texas...........................................................       9.51       8.35       3.95       4.32       0.54       0.46       0.33       0.34
Utah............................................................       9.70       8.35       3.88       4.22       0.55       0.46       0.32       0.34
Vermont.........................................................       9.03       8.35       4.10       4.52       0.52       0.46       0.34       0.36
Virginia........................................................       9.02       8.35       3.98       4.35       0.53       0.46       0.33       0.35
Washington......................................................      10.36       8.35       4.07       4.47       0.58       0.46       0.34       0.36
West Virginia...................................................       8.13       8.35       4.65       5.25       0.48       0.46       0.40       0.42
Wisconsin.......................................................       9.34       8.35       3.95       4.31       0.54       0.46       0.33       0.34
Wyoming.........................................................       9.29       8.35       4.17       4.61       0.53       0.46       0.35       0.37
--------------------------------------------------------------------------------------------------------------------------------------------------------



 Sec. Table JJ-4 to Subpart JJ of Part 98--Volatile Solids and Nitrogen 
                    Removal through Solids Separation

------------------------------------------------------------------------
                                    Volatile solids    Nitrogen removal
    Type of solids separation      removal (decimal)       (decimal)
------------------------------------------------------------------------
Gravity.........................                0.60                0.60
Mechanical:
    Stationary Screen...........                0.20                0.10
    Vibrating Screen............                0.15                0.15
    Screw Press.................                0.25                0.15
    Centrifuge..................                0.50                0.25
    Roller drum.................                0.25                0.15
    Belt press/screen...........                0.50                0.30
------------------------------------------------------------------------


[[Page 1009]]

[GRAPHIC] [TIFF OMITTED] TR30OC09.192



  Sec. Table JJ-6 to Subpart JJ of Part 98--Collection Efficiencies of 
                           Anaerobic Digesters

------------------------------------------------------------------------
                                                              Methane
      Anaerobic digester type            Cover type         collection
                                                            efficiency
------------------------------------------------------------------------
Covered anaerobic lagoon (biogas    Bank to bank,                  0.975
 capture).                           impermeable.
                                    Modular, impermeable            0.70
Complete mix, fixed film, or plug   Enclosed Vessel.....            0.99
 flow digester.
------------------------------------------------------------------------


[[Page 1010]]



Sec. Table JJ-7 to Subpart JJ of Part 98--Nitrous Oxide Emission Factors 
                     (kg N2O-N/kg Kjdl N)

------------------------------------------------------------------------
                                                                 N2O
             Manure management system component                emission
                                                                factor
------------------------------------------------------------------------
Uncovered anaerobic lagoon.................................            0
Liquid/Slurry (with crust cover)...........................        0.005
Liquid/Slurry (without crust cover)........................            0
Storage pits...............................................        0.002
Digesters..................................................            0
Solid manure storage.......................................        0.005
Dry lots (including feedlots)..............................         0.02
High-rise house for poultry (poultry without litter).......        0.001
Poultry production with litter.............................        0.001
Deep bedding for cattle and swine (active mix).............         0.07
Deep bedding for cattle and swine (no mix).................         0.01
Manure Composting (in vessel)..............................        0.006
Manure Composting (intensive)..............................          0.1
Manure Composting (passive)................................         0.01
Manure Composting (static).................................        0.006
Aerobic Treatment (forced aeration)........................        0.005
Aerobic Treatment (natural aeration).......................         0.01
------------------------------------------------------------------------

Subpart KK [Reserved]



             Subpart LL_Suppliers of Coal-based Liquid Fuels



Sec. 98.380  Definition of the source category.

    This source category consists of producers, importers, and exporters 
of products listed in Table MM-1 of subpart MM that are coal-based 
(coal-to-liquid products).
    (a) A producer is the owner or operator of a coal-to-liquids 
facility. A coal-to-liquids facility is any facility engaged in 
converting coal into liquid products using a process involving 
conversion of coal into gas and then into liquids (e.g., Fischer-
Tropsch) or conversion of coal directly into liquids (i.e., direct 
liquefaction).
    (b) An importer or exporter shall have the same meaning given in 
Sec. 98.6.



Sec. 98.381  Reporting threshold.

    Any supplier of coal-to-liquid products who meets the requirements 
of Sec. 98.2(a)(4) must report GHG emissions.



Sec. 98.382  GHGs to report.

    You must report the CO2 emissions that would result from 
the complete combustion or oxidation of fossil-fuel products (besides 
coal or crude oil) that you produce, use as feedstock, import, or export 
during the calendar year. Additionally, producers must report 
CO2 emissions that would result from the complete combustion 
or oxidation of any biomass co-processed with fossil fuel-based 
feedstocks.



Sec. 98.383  Calculating GHG emissions.

    You must follow the calculation methodologies of Sec. 98.393 as if 
they applied to the appropriate coal-to-liquid product supplier (i.e., 
calculation methodologies for refiners apply to producers of coal-to-
liquid products and calculation methodologies for importers and 
exporters of petroleum products apply to importers and exporters of 
coal-to-liquid products).
    (a) In calculation methodologies in Sec. 98.393 for petroleum 
products or petroleum-based products, suppliers of coal-to-liquid 
products shall also include coal-to-liquid products.
    (b) In calculation methodologies in Sec. 98.393 for non-crude 
feedstocks or non-crude petroleum feedstocks, producers of coal-to-
liquid products shall also include coal-to-liquid products that enter 
the facility to be further processed or otherwise used on site.
    (c) In calculation methodologies in Sec. 98.393 for petroleum 
feedstocks, suppliers of coal-to-liquid products shall also include coal 
and coal-to-liquid products that enter the facility to be further 
processed or otherwise used on site.



Sec. 98.384  Monitoring and QA/QC requirements.

    You must follow the monitoring and QA/QC requirements in Sec. 
98.394 as if they applied to the appropriate coal-to-liquid product 
supplier. Any monitoring and QA/QC requirement for petroleum products in 
Sec. 98.394 also applies to coal-to-liquid products.



Sec. 98.385  Procedures for estimating missing data.

    You must follow the procedures for estimating missing data in Sec. 
98.395 as if they applied to the appropriate coal-to-liquid product 
supplier. Any procedure for estimating missing data for petroleum 
products in Sec. 98.395 also applies to coal-to-liquid products.

[[Page 1011]]



Sec. 98.386  Data reporting requirements.

    In addition to the information required by Sec. 98.3(c), the 
following requirements apply:
    (a) Producers shall report the following information for each coal-
to-liquid facility:
    (1) [Reserved]
    (2) For each product listed in Table MM-1 of subpart MM of this part 
that enters the coal-to-liquid facility to be further processed or 
otherwise used on site, report the total annual quantity in metric tons 
or barrels. For natural gas liquids, quantity shall reflect the 
individual components of the product.
    (3) For each feedstock reported in paragraph (a)(2) of this section 
that was produced by blending a fossil fuel-based product with a 
biomass-based product, report the percent of the volume reported in 
paragraph (a)(2) of this section that is fossil fuel-based (excluding 
any denaturant that may be present in any ethanol product).
    (4) Each standard method or other industry standard practice used to 
measure each quantity reported in paragraph (a)(2) of this section.
    (5) [Reserved]
    (6) For each product (leaving the coal-to-liquid facility) listed in 
Table MM-1 of subpart MM of this part, report the total annual quantity 
in metric tons or barrels. For natural gas liquids, quantity shall 
reflect the individual components of the product. Those products that 
enter the facility, but are not reported in (a)(2), shall not be 
reported under this paragraph.
    (7) For each product reported in paragraph (a)(6) of this section 
that was produced by blending a fossil fuel-based product with a 
biomass-based product, report the percent of the volume reported in 
paragraph (a)(6) of this section that is fossil fuel-based (excluding 
any denaturant that may be present in any ethanol product).
    (8) Each standard method or other industry standard practice used to 
measure each quantity reported in paragraph (a)(6) of this section.
    (9) For every feedstock reported in paragraph (a)(2) of this section 
for which Calculation Methodology 2 of subpart MM of this part was used 
to determine an emissions factor, report:
    (i) The number of samples collected according to Sec. 98.394(c).
    (ii) The sampling standard method used.
    (iii) The carbon share test results in percent mass.
    (iv) The standard method used to test carbon share.
    (v) The calculated CO2 emissions factor in metric tons 
CO2 per barrel or per metric ton of product.
    (10) For every non-solid feedstock reported in paragraph (a)(2) of 
this section for which Calculation Methodology 2 of subpart MM of this 
part was used to determine an emissions factor, report:
    (i) The density test results in metric tons per barrel.
    (ii) The standard method used to test density.
    (11) For every product reported in paragraph (a)(6) of this section 
for which Calculation Methodology 2 of this subpart was used to 
determine an emissions factor, report:
    (i) The number of samples collected according to Sec. 98.394(c).
    (ii) The sampling standard method used.
    (iii) The carbon share test results in percent mass.
    (iv) The standard method used to test carbon share.
    (v) The calculated CO2 emissions factor in metric tons 
CO2 per barrel or metric ton of product.
    (12) For every non-solid product reported in paragraph (a)(6) of 
this section for which Calculation Method 2 of subpart MM of this part 
was used to determine an emissions factor, report:
    (i) The density test results in metric tons per barrel.
    (ii) The standard method used to test density.
    (13) [Reserved]
    (14) For each specific type of biomass that enters the coal-to-
liquid facility to be co-processed with fossil fuel-based feedstock to 
produce a product reported in paragraph (a)(6) of this section, report 
the annual quantity in metric tons or barrels.
    (15) Each standard method or other industry standard practice used 
to measure each quantity reported in paragraph (a)(14) of this section.

[[Page 1012]]

    (16) The CO2 emissions in metric tons that would result 
from the complete combustion or oxidation of each feedstock reported in 
paragraph (a)(2) of this section that were calculated according to Sec. 
98.393(b) or (h).
    (17) The CO2 emissions in metric tons that would result 
from the complete combustion or oxidation of each product (leaving the 
coal-to-liquid facility) reported in paragraph (a)(6) of this section 
that were calculated according to Sec. 98.393(a) or (h).
    (18) Annual CO2 emissions in metric tons that would 
result from the complete combustion or oxidation of each type of biomass 
feedstock co-processed with fossil fuel-based feedstocks reported in 
paragraph (a)(14) of this section, calculated according to Sec. 
98.393(c).
    (19) Annual CO2 emissions that would result from the 
complete combustion or oxidation of all products, calculated according 
to Sec. 98.393(d).
    (20) Annual quantity of bulk NGLs in metric tons or barrels received 
for processing during the reporting year.
    (b) In addition to the information required by Sec. 98.3(c), each 
importer shall report all of the following information at the corporate 
level:
    (1) [Reserved]
    (2) For each product listed in Table MM-1 of subpart MM of this 
part, report the total annual quantity in metric tons or barrels. For 
natural gas liquids, quantity shall reflect the individual components of 
the product as listed in Table MM-1 of subpart MM of this part.
    (3) For each product reported in paragraph (b)(2) of this section 
that was produced by blending a fossil fuel-based product with a 
biomass-based product, report the percent of the volume reported in 
paragraph (b)(2) of this section that is fossil fuel-based (excluding 
any denaturant that may be present in any ethanol product).
    (4) Each standard method or other industry standard practice used to 
measure each quantity reported in paragraph (b)(2) of this section.
    (5) For each product reported in paragraph (b)(2) of this section 
for which Calculation Methodology 2 of this subpart used was used to 
determine an emissions factor, report:
    (i) The number of samples collected according to Sec. 98.394(c)
    (ii) The sampling standard method used.
    (iii) The carbon share test results in percent mass.
    (iv) The standard method used to test carbon share.
    (v) The calculated CO2 emissions factor in metric tons 
per barrel or per metric ton of product.
    (6) For each non-solid product reported in paragraph (b)(2) of this 
section for which Calculation Methodology 2 of this subpart was used to 
determine an emissions factor, report:
    (i) The density test results in metric tons per barrel.
    (ii) The standard method used to test density.
    (7) The CO2 emissions in metric tons that would result 
from the complete combustion or oxidation of each imported product 
reported in paragraph (b)(2) of this section, calculated according to 
Sec. 98.393(a).
    (8) The total sum of CO2 emissions that would result from 
the complete combustion or oxidation of all imported products, 
calculated according to Sec. 98.393(e).
    (c) In addition to the information required by Sec. 98.3(c), each 
exporter shall report all of the following information at the corporate 
level:
    (1) [Reserved]
    (2) For each product listed in table MM-1 of subpart MM of this 
part, report the total annual quantity in metric tons or barrels. For 
natural gas liquids, quantity shall reflect the individual components of 
the product.
    (3) For each product reported in paragraph (c)(2) of this section 
that was produced by blending a fossil fuel-based product with a 
biomass-based product, report the percent of the volume reported in 
paragraph (c)(2) of this section that is fossil fuel-based (excluding 
any denaturant that may be present in any ethanol product).
    (4) Each standard method or other industry standard practice used to 
measure each quantity reported in paragraph (c)(2) of this section.
    (5) For each product reported in paragraph (c)(2) of this section 
for which

[[Page 1013]]

Calculation Methodology 2 of this subpart was used to determine an 
emissions factor, report:
    (i) The number of samples collected according to Sec. 98.394(c).
    (ii) The sampling standard method used.
    (iii) The carbon share test results in percent mass.
    (iv) The standard method used to test carbon share.
    (v) The calculated CO2 emissions factor in metric tons 
CO2 per barrel or per metric ton of product.
    (6) For each non-solid product reported in paragraph (c)(2) of this 
section for which Calculation Methodology 2 of this subpart used was 
used to determine an emissions factor, report:
    (i) The density test results in metric tons per barrel.
    (ii) The standard method used to test density.
    (7) The CO2 emissions in metric tons that would result 
from the complete combustion or oxidation of each exported product 
reported in paragraph (c)(2) of this section, calculated according to 
Sec. 98.393(a).
    (8) Total sum of CO2 emissions that would result from the 
complete combustion or oxidation of all exported products, calculated 
according to Sec. 98.393(e).
    (d) Blended feedstock and products. (1) Producers, exporters, and 
importers must report the following information for each blended product 
and feedstock where emissions were calculated according to Sec. 
98.393(i):
    (i) Volume or mass of each blending component.
    (ii) The CO2 emissions in metric tons that would result 
from the complete combustion or oxidation of each blended feedstock or 
product, using Equation MM-12 or Equation MM-13 of Sec. 98.393.
    (iii) Whether it is a blended feedstock or a blended product.
    (2) For a product that enters the facility to be further refined or 
otherwise used on site that is a blended feedstock, producers must meet 
the reporting requirements of paragraph (a)(2) of this section by 
reflecting the individual components of the blended feedstock.
    (3) For a product that is produced, imported, or exported that is a 
blended product, producers, importers, and exporters must meet the 
reporting requirements of paragraphs (a)(6), (b)(2), and (c)(2) of this 
section, as applicable, by reflecting the individual components of the 
blended product.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66475, Oct. 28, 2010; 
78 FR 71972, Nov. 29, 2013]



Sec. 98.387  Records that must be retained.

    You must retain records according to the requirements in Sec. 
98.397 as if they applied to the appropriate coal-to-liquid product 
supplier (e.g., retaining copies of all reports submitted to EPA under 
Sec. 98.386 and records to support information contained in those 
reports). Any records for petroleum products that are required to be 
retained in Sec. 98.397 are also required for coal-to-liquid products.



Sec. 98.388  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.



               Subpart MM_Suppliers of Petroleum Products



Sec. 98.390  Definition of the source category.

    This source category consists of petroleum refineries and importers 
and exporters of petroleum products and natural gas liquids as listed in 
Table MM-1 of this subpart.
    (a) A petroleum refinery for the purpose of this subpart is any 
facility engaged in producing petroleum products through the 
distillation of crude oil.
    (b) A refiner is the owner or operator of a petroleum refinery.
    (c) Importer has the same meaning given in Sec. 98.6 and includes 
any entity that imports petroleum products or natural gas liquids as 
listed in Table MM-1 of this subpart. Any blender or refiner of refined 
or semi-refined petroleum products shall be considered an importer if it 
otherwise satisfies the aforementioned definition.
    (d) Exporter has the same meaning given in Sec. 98.6 and includes 
any entity that exports petroleum products or

[[Page 1014]]

natural gas liquids as listed in Table MM-1 of this subpart. Any blender 
or refiner of refined or semi-refined petroleum products shall be 
considered an exporter if it otherwise satisfies the aforementioned 
definition.



Sec. 98.391  Reporting threshold.

    Any supplier of petroleum products who meets the requirements of 
Sec. 98.2(a)(4) must report GHG emissions.



Sec. 98.392  GHGs To report.

    Suppliers of petroleum products must report the CO2 
emissions that would result from the complete combustion or oxidation of 
each petroleum product and natural gas liquid produced, used as 
feedstock, imported, or exported during the calendar year. Additionally, 
refiners must report CO2 emissions that would result from the 
complete combustion or oxidation of any biomass co-processed with 
petroleum feedstocks.



Sec. 98.393  Calculating GHG emissions.

    (a) Calculation for individual products produced, imported, or 
exported. (1) Except as provided in paragraphs (h) and (i) of this 
section, any refiner, importer, or exporter shall calculate 
CO2 emissions from each individual petroleum product and 
natural gas liquid using Equation MM-1 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.152

Where:

CO2. = Annual CO2 emissions that would result from 
          the complete combustion or oxidation of each petroleum product 
          or natural gas liquid ``i'' (metric tons).
Producti = Annual volume of product ``i'' produced, imported, 
          or exported by the reporting party (barrels). For refiners, 
          this volume only includes products ex refinery gate, and 
          excludes products that entered the refinery but are not 
          reported under Sec. 98.396(a)(2). For natural gas liquids, 
          volumes shall reflect the individual components of the product 
          as listed in Table MM-1 to subpart MM.
EFi = Product-specific CO2 emission factor (metric 
          tons CO2 per barrel).

    (2) In the event that an individual petroleum product is produced as 
a solid rather than liquid any refiner, importer, or exporter shall 
calculate CO2 emissions using Equation MM-1 of this section.

Where:

CO2. = Annual CO2 emissions that would result from 
          the complete combustion or oxidation of each petroleum product 
          ``i'' (metric tons).
Producti = Annual mass of product ``i'' produced, imported, 
          or exported by the reporting party (metric tons). For 
          refiners, this mass only includes products ex refinery gate, 
          and excludes products that entered the refinery but are not 
          reported under Sec. 98.396(a)(2).
EFi = Product-specific CO2 emission factor (metric 
          tons CO2 per metric ton of product).

    (b) Calculation for individual products that enter a refinery as a 
non-crude feedstock. (1) Except as provided in paragraphs (h) and (i) of 
this section, any refiner shall calculate CO2 emissions from 
each non-crude feedstock using Equation MM-2 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.153

Where:

CO2. = Annual CO2 emissions that would result from 
          the complete combustion or oxidation of each non-crude 
          feedstock ``j'' (metric tons).
Feedstockj = Annual volume of a petroleum product or natural 
          gas liquid ``j'' that enters the refinery to be further 
          refined or otherwise used on site (barrels). For natural gas 
          liquids, volumes shall reflect the individual components of 
          the product as listed in table MM-1 of this subpart.
EFj = Feedstock-specific CO2 emission factor 
          (metric tons CO2 per barrel).

    (2) In the event that a non-crude feedstock enters a refinery as a 
solid rather than liquid, the refiner shall calculate CO2 
emissions using Equation MM-2 of this section.

Where:

CO2. = Annual CO2 emissions that would result from 
          the complete combustion or oxidation of each non-crude 
          feedstock ``j'' (metric tons).
Feedstockj = Annual mass of a petroleum product ``j'' that 
          enters the refinery to be further refined or otherwise used on 
          site (metric tons).
EFj = Feedstock-specific CO2 emission factor 
          (metric tons CO2 per metric ton of feedstock).

    (c) Calculation for biomass co-processed with petroleum feedstocks. 
(1) Refiners shall calculate CO2 emissions from

[[Page 1015]]

each type of biomass that enters a refinery and is co-processed with 
petroleum feedstocks using Equation MM-3 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.154

Where:

CO2. = Annual CO2 emissions that would result from 
          the complete combustion or oxidation of each type of biomass 
          ``m'' (metric tons).
Biomassm = Annual volume of a specific type of biomass that 
          enters the refinery and is co-processed with petroleum 
          feedstocks to produce a petroleum product reported under 
          paragraph (a) of this section (barrels).
EFm = Biomass-specific CO2 emission factor (metric 
          tons CO2 per barrel).

    (2) In the event that biomass enters a refinery as a solid rather 
than liquid and is co-processed with petroleum feedstocks, the refiner 
shall calculate CO2 emissions from each type of biomass using 
Equation MM-3 of this section.

Where:

CO2. = Annual CO2 emissions that would result from 
          the complete combustion or oxidation of each type of biomass 
          ``m'' (metric tons).
Biomassm = Total annual mass of a specific type of biomass 
          that enters the refinery to be co-processed with petroleum 
          feedstocks to produce a petroleum product reported under 
          paragraph (a) of this section (metric tons).
EFm = Biomass-specific CO2 emission factor (metric 
          tons CO2 per metric ton of biomass).

    (d) Summary calculation for refinery products. Refiners shall 
calculate annual CO2 emissions from all products using 
Equation MM-4 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.155

Where:

CO2. = Annual CO2 emissions that would result from 
          the complete combustion or oxidation of all petroleum products 
          and natural gas liquids (ex refinery gate) minus non-crude 
          feedstocks and any biomass to be co-processed with petroleum 
          feedstocks.
CO2. = Annual CO2 emissions that would result from 
          the complete combustion or oxidation of each petroleum product 
          or natural gas liquid ``i'' (metric tons).
CO2. = Annual CO2 emissions that would result from 
          the complete combustion or oxidation of each non-crude 
          feedstock ``j'' (metric tons).
CO2. = Annual CO2 emissions that would result from 
          the complete combustion or oxidation of each type of biomass 
          ``m'' (metric tons).

    (e) Summary calculation for importer and exporter products. 
Importers and exporters shall calculate annual CO2 emissions 
from all petroleum products and natural gas liquids imported or 
exported, respectively, using Equations MM-1 and MM-5 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.156

Where:

CO2. = Annual CO2 emissions that would result from 
          the complete combustion or oxidation of each petroleum product 
          or natural gas liquid ``i'' (metric tons).
CO2. = Annual CO2 emissions that would result from 
          the complete combustion or oxidation of all petroleum products 
          and natural gas liquids.

    (f) Emission factors for petroleum products and natural gas liquids. 
The emission factor (EFi,j) for each petroleum product and 
natural gas liquid shall be determined using either of the calculation 
methods described in paragraphs (f)(1) or (f)(2) of this section. The 
same calculation method must be used for the entire quantity of the 
product for the reporting year. For refiners, the quantity of a product 
that enters a refinery (i.e., a non-crude feedstock) is considered 
separate from the quantity of a product ex refinery gate.
    (1) Calculation Method 1. To determine the emission factor (i.e., 
EFi in Equation MM-1) for solid products, multiply the 
default carbon share factor (i.e., percent carbon by mass) in column B 
of Table MM-1 to this subpart for the appropriate product by 44/

[[Page 1016]]

12. For all other products, use the default CO2 emission 
factor listed in column C of Table MM-1 of this subpart for the 
appropriate product.
    (2) Calculation Method 2. (i) For solid products, develop emission 
factors according to Equation MM-6 of this section using a value of 1 
for density and direct measurements of carbon share according to methods 
set forth in Sec. 98.394(c). For all other products, develop emission 
factors according to Equation MM-6 of this section using direct 
measurements of density and carbon share according to methods set forth 
in Sec. 98.394(c).
[GRAPHIC] [TIFF OMITTED] TR30OC09.157

Where:

EFi,j = Emission factor of the petroleum product or natural 
          gas liquid (metric tons CO2 per barrel or per 
          metric ton of product).
Density = Density of the petroleum product or natural gas liquid (metric 
          tons per barrel for non-solid products, 1 for solid products).
Carbon share = Percent of total mass that carbon represents in the 
          petroleum product or natural gas liquid, expressed as a 
          fraction (e.g., 75% would be expressed as 0.75 in the above 
          equation).
44/12 = Conversion factor for carbon to carbon dioxide.

    (ii) If you use a standard method that involves gas chromatography 
to determine the percent mass of each component in a product, calculate 
the product's carbon share using Equation MM-7 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.158


Where:

Carbon Share = Percent of total mass that carbon represents in the 
          petroleum product or natural gas liquid.
%Composition i* * *n = Percent of total mass that each molecular 
          component in the petroleum product or natural gas liquid 
          represents as determined by the procedures in the selected 
          standard method.
%Massi* * *n = Percent of total mass that carbon represents 
          in each molecular component of the petroleum product or 
          natural gas liquid.

    (g) Emission factors for biomass co-processed with petroleum 
feedstocks. Refiners shall use the most appropriate default 
CO2 emission factor (EFm) for biomass in Table MM-
2 of this subpart to calculate CO2 emissions in paragraph (c) 
of this section.
    (h) Special procedures for blended biomass-based fuels. In the event 
that some portion of a petroleum product is biomass-based and was not 
derived by co-processing biomass and petroleum feedstocks together 
(i.e., the petroleum product was produced by blending a petroleum-based 
product with a biomass-based fuel), the reporting party shall calculate 
emissions for the petroleum product according to one of the methods in 
paragraphs (h)(1) through (h)(4) of this section, as appropriate.
    (1) A reporter using Calculation Method 1 to determine the emission 
factor of a petroleum product shall calculate the CO2 
emissions associated with that product using Equation MM-8 of this 
section in place of Equation MM-1 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.159


[[Page 1017]]


Where:

CO2. = Annual CO2 emissions that would result from 
          the complete combustion or oxidation of each petroleum product 
          ``i'' (metric tons).
Producti = Annual volume of each petroleum product ``i'' 
          produced, imported, or exported by the reporting party 
          (barrels). For refiners, this volume only includes products ex 
          refinery gate.
EFi = Petroleum product-specific CO2 emission 
          factor (metric tons CO2 per barrel) from Table MM-1 
          of this subpart.
%Voli = Percent volume of product ``i'' that is petroleum-
          based, not including any denaturant that may be present in any 
          ethanol product, expressed as a fraction (e.g., 75% would be 
          expressed as 0.75 in the above equation).

    (2) A refinery using Calculation Method 1 of this subpart to 
determine the emission factor of a non-crude petroleum feedstock shall 
calculate the CO2 emissions associated with that feedstock 
using Equation MM-9 of this section in place of Equation MM-2 of this 
section.
[GRAPHIC] [TIFF OMITTED] TR28OC10.037

Where:

CO2. = Annual CO2 emissions that would result from 
          the complete combustion or oxidation of each non-crude 
          feedstock ``j'' (metric tons).
Feedstockj = Annual volume of each petroleum product ``j'' 
          that enters the refinery as a feedstock to be further refined 
          or otherwise used on site (barrels).
EFj = Non-crude petroleum feedstock-specific CO2 
          emission factor (metric tons CO2 per barrel).
%Volj = Percent volume of feedstock ``j'' that is petroleum-
          based, not including any denaturant that may be present in any 
          ethanol product, expressed as a fraction (e.g., 75% would be 
          expressed as 0.75 in the above equation).

    (3) Calculation Method 2 procedures for products. (i) A reporter 
using Calculation Method 2 of this subpart to determine the emission 
factor of a petroleum product that does not contain denatured ethanol 
must calculate the CO2 emissions associated with that product 
using Equation MM-10 of this section in place of Equation MM-1 of this 
section.
[GRAPHIC] [TIFF OMITTED] TR28OC10.038

where:

CO2. = Annual CO2 emissions that would result from 
          the complete combustion or oxidation of each product ``i'' 
          (metric tons).
Producti = Annual volume of each petroleum product ``i'' 
          produced, imported, or exported by the reporting party 
          (barrels). For refiners, this volume only includes products ex 
          refinery gate.
EFi = Product-specific CO2 emission factor (metric 
          tons CO2 per barrel).
EFm = Default CO2 emission factor from Table MM-2 
          to subpart MM that most closely represents the component of 
          product ``i'' that is biomass-based.
%Volm = Percent volume of petroleum product ``i'' that is 
          biomass-based, expressed as a fraction (e.g., 75% would be 
          expressed as 0.75 in the above equation).

    (ii) In the event that a petroleum product contains denatured 
ethanol, importers and exporters must follow Calculation Method 1 
procedures in paragraph (h)(1) of this section; and refineries must 
sample the petroleum portion of the blended biomass-based fuel prior to 
blending and calculate CO2 emissions using Equation MM-10a of 
this section.
[GRAPHIC] [TIFF OMITTED] TR28OC10.039

where:

CO2. = Annual CO2 emissions that would result from 
          the complete combustion or oxidation of each biomass-blended 
          fuel ``i'' (metric tons).
Productp = Annual volume of the petroleum-based portion of 
          each biomass blended fuel ``i'' produced by the refiner 
          (barrels).

[[Page 1018]]

EFi = Petroleum product-specific CO2 emission 
          factor (metric tons CO2 per barrel).

    (4) Calculation Method 2 procedures for non-crude feedstocks. (i) A 
refiner using Calculation Method 2 of this subpart to determine the 
emission factor of a non-crude petroleum feedstock that does not contain 
denatured ethanol must calculate the CO2 emissions associated 
with that feedstock using Equation MM-11 of this section in place of 
Equation MM-2 of this section.
[GRAPHIC] [TIFF OMITTED] TR28OC10.040

where:

CO2. = Annual CO2 emissions that would result from 
          the complete combustion or oxidation of each non-crude 
          feedstock ``j'' (metric tons).
Feedstockj = Annual volume of each petroleum product ``j'' 
          that enters the refinery to be further refined or otherwise 
          used on site (barrels).
EFj = Feedstock-specific CO2 emission factor 
          (metric tons CO2 per barrel).
EFm = Default CO2 emission factor from Table MM-2 
          to subpart MM that most closely represents the component of 
          petroleum product ``j'' that is biomass-based.
%Volm = Percent volume of non-crude feedstock ``j'' that is 
          biomass-based, expressed as a fraction (e.g., 75% would be 
          expressed as 0.75 in the above equation).

    (ii) In the event that a non-crude feedstock contains denatured 
ethanol, refiners must follow Calculation Method 1 procedures in 
paragraph (h)(2) of this section.
    (i) Optional procedures for blended products that do not contain 
biomass. (1) In the event that a reporter produces, imports, or exports 
a blended product that does not include biomass, the reporter may 
calculate emissions for the blended product according to the method in 
paragraph (i)(2) of this section. In the event that a refiner receives a 
blended non-crude feedstock that does not include biomass, the refiner 
may calculate emission for the blended non-crude feedstock according to 
the method in paragraph (i)(3) of this section. The procedures in this 
section may be used only if all of the following criteria are met:
    (i) The reporter knows the relative proportion of each component of 
the blend (i.e., the mass or volume percentage).
    (ii) Each component of blended product ``i'' or blended non-crude 
feedstock ``j'' meets the strict definition of a product listed in Table 
MM-1 to subpart MM.
    (iii) The blended product or non-crude feedstock is not comprised 
entirely of natural gas liquids.
    (iv) The reporter uses Calculation Method 1.
    (v) Solid components are blended only with other solid components.
    (2) The reporter must calculate emissions for the blended product 
using Equation MM-12 of this section in place of Equation MM-1 of this 
section.
[GRAPHIC] [TIFF OMITTED] TR28OC10.041

where:

CO2. = Annual CO2 emissions that would result from 
          the complete combustion or oxidation of a blended product 
          ``i'' (metric tons).
Blending Componenti...n = Annual volume or mass of each 
          blending component that is blended (barrels or metric tons).
EFi...n = CO2 emission factors specific to each 
          blending component (metric tons CO2 per barrel or 
          per metric ton of product).
n = Number of blending components blended into blended product ``i''.

    (3) For refineries, the reporter must calculate emissions for the 
blended non-crude feedstock using Equation

[[Page 1019]]

MM-13 of this section in place of Equation MM-2 of this section.
[GRAPHIC] [TIFF OMITTED] TR28OC10.042

where:

CO2. = Annual CO2 emissions that would result from 
          the complete combustion or oxidation of a blended non-crude 
          feedstock ``j'' (metric tons).
Blending Componenti...n = Annual volume or mass of each 
          blending component that is blended (barrels or metric tons).
EFi...n = CO2 emission factors specific to each 
          blending component (metric tons CO2 per barrel or 
          per metric ton of product).
n = Number of blending components blended into blended non-crude 
          feedstock ``j''.

    (4) For refineries, if a blending component ``k'' used in paragraph 
(i)(2) of this section enters the refinery before blending as non-crude 
feedstock:
    (i) The emissions that would result from the complete combustion or 
oxidation of non-crude feedstock ``k'' must still be calculated 
separately using Equation MM-2 of this section and applied in Equation 
MM-4 of this section.
    (ii) The quantity of blending component ``k'' applied in Equation 
MM-12 of this section and the quantity of non-crude feedstock ``k'' 
applied in Equation MM-2 of this section must be determined using the 
same method or practice.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66475, Oct. 28, 2010; 
78 FR 71973, Nov. 29, 2013]



Sec. 98.394  Monitoring and QA/QC requirements.

    (a) Determination of quantity. (1) The quantity of petroleum 
products, natural gas liquids, and biomass, shall be determined as 
follows:
    (i) Where an appropriate standard method published by a consensus-
based standards organization exists, such a method shall be used. 
Consensus-based standards organizations include, but are not limited to, 
the following: ASTM International, the American National Standards 
Institute (ANSI), the American Gas Association (AGA), the American 
Society of Mechanical Engineers (ASME), the American Petroleum Institute 
(API), and the North American Energy Standards Board (NAESB).
    (ii) Where no appropriate standard method developed by a consensus-
based standards organization exists, industry standard practices shall 
be followed.
    (iii) For products that are liquid at 60 degrees Fahrenheit and one 
standard atmosphere, all measurements of quantity shall be temperature-
adjusted and pressure-adjusted to these conditions. For all other 
products, reporters shall use appropriate standard conditions specified 
in the standard method; if temperature and pressure conditions are not 
specified in the standard method or if a reporter uses an industry 
standard practice to determine quantity, the reporter shall use 
appropriate standard conditions according to established industry 
practices.
    (2) All measurement equipment (including, but not limited to, flow 
meters and tank gauges) used for compliance with this subpart shall be 
appropriate for the standard method or industry standard practice 
followed under paragraph (a)(1)(i) or (a)(1)(ii) of this section.
    (3) The annual quantity of crude oil received shall be determined 
according to one of the following methods. You may use an appropriate 
standard method published by a consensus-based standards organization or 
you may use an industry standard practice.
    (b) Equipment Calibration. (1) All measurement equipment shall be 
calibrated prior to its first use for reporting under this subpart, 
using an appropriate standard method published by a consensus based 
standards organization or according to the equipment manufacturer's 
directions.
    (2) Measurement equipment shall be recalibrated at the minimum 
frequency specified by the standard method used

[[Page 1020]]

or by the equipment manufacturer's directions.
    (3) For units and processes that operate continuously with 
infrequent outages, it may not be possible to complete the calibration 
of a flow meter or other measurement device without disrupting normal 
process operation. In such cases, the owner or operator may postpone the 
calibration until the next scheduled maintenance outage. The best 
available information from company records may be used in the interim. 
Such postponements shall be documented in the monitoring plan that is 
required under Sec. 98.3(g)(5).
    (c) Procedures for Calculation Method 2 of this subpart. (1) 
Reporting parties shall collect one sample of each petroleum product or 
natural gas liquid on any day of each calendar month of the reporting 
year in which the quantity of that product was measured in accordance 
with the requirements of this subpart. For example, if a given product 
was measured as entering the refinery continuously throughout the 
reporting year, twelve samples of that product shall be collected over 
the reporting year, one on any day of each calendar month of that year. 
If a given product was only measured from April 15 through June 10 of 
the reporting year, a refiner would collect three samples during that 
year, one during each of the calendar months of April, May and June on a 
day when the product was measured as either entering or exiting the 
refinery. Each sample shall be collected using an appropriate standard 
method published by a consensus-based standards organization.
    (2) Mixing and handling of samples shall be performed using an 
appropriate standard method published by a consensus-based standards 
organization.
    (3) Density measurement.
    (i) For all products that are not solid, reporters shall test for 
density using an appropriate standard method published by a consensus-
based standards organization.
    (ii) The density value for a given petroleum product shall be 
generated by either making a physical composite of all of the samples 
collected for the reporting year and testing that single sample or by 
measuring the individual samples throughout the year and defining the 
representative density value for the sample set by numerical means, 
i.e., a mathematical composite. If a physical composite is chosen as the 
option to obtain the density value, the reporter shall submit each of 
the individual samples collected during the reporting year to the 
laboratory responsible for generating the composite sample.
    (iii) For physical composites, the reporter shall handle the 
individual samples and the laboratory shall mix them in accordance with 
an appropriate standard method published by a consensus-based standards 
organization.
    (iv) All measurements of density shall be temperature-adjusted and 
pressure-adjusted to the conditions assumed for determining the 
quantities of the product reported under this subpart.
    (4) Carbon share measurement.
    (i) Reporters shall test for carbon share using an appropriate 
standard method published by a consensus-based standards organization.
    (ii) If a standard method that involves gas chromatography is used 
to determine the percent mass of each component in a product, the 
molecular formula for each component shall be obtained from the 
information provided in the standard method and the atomic mass of each 
element in a given molecular component shall be obtained from the 
periodic table of the elements.
    (iii) The carbon share value for a given petroleum product shall be 
generated by either making a physical composite of all of the samples 
collected for the reporting year and testing that single sample or by 
measuring the individual samples throughout the year and defining the 
representative carbon share value for the sample set by numerical means, 
i.e., a mathematical composite. If a physical composite is chosen as the 
option to obtain the carbon share value, the reporter shall submit each 
of the individual samples collected during the reporting year to the 
laboratory responsible for generating the composite sample.
    (iv) For physical composites, the reporter shall handle the 
individual samples and the laboratory shall mix them

[[Page 1021]]

in accordance with an appropriate standard method published by a 
consensus-based standards organization.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66477, Oct. 28, 2010; 
78 FR 71972, Nov. 29, 2013]



Sec. 98.395  Procedures for estimating missing data.

    (a) Determination of quantity. Whenever the quality assurance 
procedures in Sec. 98.394(a) cannot be followed to measure the quantity 
of one or more petroleum products, natural gas liquids, types of 
biomass, feedstocks, or crude oil during any period (e.g., if a meter 
malfunctions), the following missing data procedures shall be used:
    (1) For quantities of a product that are purchased or sold, a period 
of missing data shall be substituted using a reporter's established 
procedures for billing purposes in that period as agreed to by the party 
selling or purchasing the product.
    (2) For quantities of a product that are not purchased or sold but 
of which the custody is transferred, a period of missing data shall be 
substituted using a reporter's established procedures for tracking 
purposes in that period as agreed to by the party involved in custody 
transfer of the product.
    (b) Determination of emission factor. Whenever any of the procedures 
in Sec. 98.394(c) cannot be followed to develop an emission factor for 
any reason, Calculation Method 1 of this subpart must be used in place 
of Calculation Method 2 of this subpart for the entire reporting year.
    (c) Determination of API gravity and sulfur content of crude oil. 
For missing data on sulfur content or API gravity, the substitute data 
value shall be the arithmetic average of the quality-assured values of 
API gravity or sulfur content in the batch preceding and the batch 
immediately following the missing data incident. If no quality-assured 
data are available prior to the missing data incident, the substitute 
data value shall be the first quality-assured values for API gravity and 
sulfur content obtained from the batch after the missing data period.

[74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71973, Nov. 29, 2013]



Sec. 98.396  Data reporting requirements.

    In addition to the information required by Sec. 98.3(c), the 
following requirements apply:
    (a) Refiners shall report the following information for each 
facility:
    (1) [Reserved]
    (2) For each petroleum product or natural gas liquid listed in Table 
MM-1 of this subpart that enters the refinery to be further refined or 
otherwise used on site, report the annual quantity in metric tons or 
barrels. For natural gas liquids, quantity shall reflect the individual 
components of the product.
    (3) For each feedstock reported in paragraph (a)(2) of this section 
that was produced by blending a petroleum-based product with a biomass-
based product, report the percent of the volume reported in paragraph 
(a)(2) of this section that is petroleum-based (excluding any denaturant 
that may be present in any ethanol product).
    (4)-(5) [Reserved]
    (6) For each petroleum product and natural gas liquid (ex refinery 
gate) listed in Table MM-1 of this subpart, report the annual quantity 
in metric tons or barrels. For natural gas liquids, quantity shall 
reflect the individual components of the product. Petroleum products and 
natural gas liquids that enter the refinery, but are not reported in 
(a)(2), shall not be reported under this paragraph.
    (7) For each product reported in paragraph (a)(6) of this section 
that was produced by blending a petroleum-based product with a biomass-
based product, report the percent of the volume reported in paragraph 
(a)(6) of this section that is petroleum-based (excluding any denaturant 
that may be present in any ethanol product).
    (8) [Reserved]
    (9) For every feedstock reported in paragraph (a)(2) of this section 
for which Calculation Method 2 of this subpart was used to determine an 
emissions factor, report:
    (i) The number of samples collected according to Sec. 98.394(c)
    (ii) The sampling standard method used.
    (iii) The carbon share test results in percent mass.

[[Page 1022]]

    (iv) The standard method used to test carbon share.
    (v) The calculated CO2 emissions factor in metric tons 
CO2 per barrel or per metric ton of product.
    (10) For every non-solid feedstock reported in paragraph (a)(2) of 
this section for which Calculation Method 2 of this subpart was used to 
determine an emissions factor, report:
    (i) The density test results in metric tons per barrel.
    (ii) The standard method used to test density.
    (11) For every petroleum product and natural gas liquid reported in 
paragraph (a)(6) of this section for which Calculation Method 2 of this 
subpart was used to determine an emissions factor, report:
    (i) The number of samples collected according to Sec. 98.394(c).
    (ii) The sampling standard method used.
    (iii) The carbon share test results in percent mass.
    (iv) The standard method used to test carbon share.
    (v) The calculated CO2 emissions factor in metric tons 
CO2 per barrel or per metric ton of product.
    (12) For every non-solid petroleum product and natural gas liquid 
reported in paragraph (a)(6) for which Calculation Method 2 was used to 
determine an emissions factor, report:
    (i) The density test results in metric tons per barrel.
    (ii) The standard method used to test density.
    (13) [Reserved]
    (14) For each specific type of biomass that enters the refinery to 
be co-processed with petroleum feedstocks to produce a petroleum product 
reported in paragraph (a)(6) of this section, report the annual quantity 
in metric tons or barrels.
    (15) [Reserved]
    (16) The CO2 emissions in metric tons that would result 
from the complete combustion or oxidation of each petroleum product and 
natural gas liquid (ex refinery gate) reported in paragraph (a)(6) of 
this section that were calculated according to Sec. 98.393(a) or (h).
    (17) The CO2 emissions in metric tons that would result 
from the complete combustion or oxidation of each feedstock reported in 
paragraph (a)(2) of this section that were calculated according to Sec. 
98.393(b) or (h).
    (18) The CO2 emissions in metric tons that would result 
from the complete combustion or oxidation of each type of biomass 
feedstock co-processed with petroleum feedstocks reported in paragraph 
(a)(14) of this section, calculated according to Sec. 98.393(c).
    (19) The sum of CO2 emissions that would result from the 
complete combustion or oxidation of all products, calculated according 
to Sec. 98.393(d).
    (20) For all crude oil that enters the refinery, report the annual 
quantity in barrels.
    (21) The quantity of bulk NGLs in metric tons or barrels received 
for processing during the reporting year. Report only quantities of bulk 
NGLs not reported in (a)(2) of this section.
    (22) Volume of crude oil in barrels that you injected into a crude 
oil supply or reservoir.
    (b) In addition to the information required by Sec. 98.3(c), each 
importer shall report all of the following information at the corporate 
level:
    (1) [Reserved]
    (2) For each petroleum product and natural gas liquid listed in 
Table MM-1 of this subpart, report the annual quantity in metric tons or 
barrels. For natural gas liquids, quantity shall reflect the individual 
components of the product.
    (3) For each product reported in paragraph (b)(2) of this section 
that was produced by blending a petroleum-based product with a biomass-
based product, report the percent of the volume reported in paragraph 
(b)(2) of this section that is petroleum-based (excluding any denaturant 
that may be present in any ethanol product).
    (4) [Reserved]
    (5) For each product reported in paragraph (b)(2) of this section 
for which Calculation Method 2 of this subpart used was used to 
determine an emissions factor, report:
    (i) The number of samples collected according to Sec. 98.394(c).
    (ii) The sampling standard method used.
    (iii) The carbon share test results in percent mass.

[[Page 1023]]

    (iv) The standard method used to test carbon share.
    (v) The calculated CO2 emissions factor in metric tons 
CO2 per barrel or per metric ton of product.
    (6) For each non-solid product reported in paragraph (b)(2) of this 
section for which Calculation Method 2 of this subpart was used to 
determine an emissions factor, report:
    (i) The density test results in metric tons per barrel.
    (ii) The standard method used to test density.
    (7) The CO2 emissions in metric tons that would result 
from the complete combustion or oxidation of each imported petroleum 
product and natural gas liquid reported in paragraph (b)(2) of this 
section, calculated according to Sec. 98.393(a).
    (8) The sum of CO2 emissions that would result from the 
complete combustion oxidation of all imported products, calculated 
according to Sec. 98.393(e).
    (c) In addition to the information required by Sec. 98.3(c), each 
exporter shall report all of the following information at the corporate 
level:
    (1) [Reserved]
    (2) For each petroleum product and natural gas liquid listed in 
Table MM-1 of this subpart, report the annual quantity in metric tons or 
barrels. For natural gas liquids, quantity shall reflect the individual 
components of the product.
    (3) For each product reported in paragraph (c)(2) of this section 
that was produced by blending a petroleum-based product with a biomass-
based product, report the percent of the volume reported in paragraph 
(c)(2) of this section that is petroleum based (excluding any denaturant 
that may be present in any ethanol product).
    (4) [Reserved]
    (5) For each product reported in paragraph (c)(2) of this section 
for which Calculation Method 2 of this subpart was used to determine an 
emissions factor, report:
    (i) The number of samples collected according to Sec. 98.394(c).
    (ii) The sampling standard method used.
    (iii) The carbon share test results in percentmass.
    (iv) The standard method used to test carbon share.
    (v) The calculated CO2 emissions factor in metric tons 
CO2 per barrel or per metric ton of product.
    (6) For each non-solid product reported in paragraph (c)(2) of this 
section for which Calculation Method 2 of this subpart used was used to 
determine an emissions factor, report:
    (i) The density test results in metric tons per barrel.
    (ii) The standard method used to test density.
    (7) The CO2 emissions in metric tons that would result 
from the complete combustion or oxidation of for each exported petroleum 
product and natural gas liquid reported in paragraph (c)(2) of this 
section, calculated according to Sec. 98.393(a).
    (8) The sum of CO2 emissions that would result from the 
complete combustion or oxidation of all exported products, calculated 
according to Sec. 98.393(e).
    (d) Blended non-crude feedstock and products. (1) Refineries, 
exporters, and importers must report the following information for each 
blended product and non-crude feedstock where emissions were calculated 
according to Sec. 98.393(i):
    (i) Volume or mass of each blending component.
    (ii) The CO2 emissions in metric tons that would result 
from the complete combustion or oxidation of each blended non-crude 
feedstock or product, using Equation MM-12 or Equation MM-13 of this 
section.
    (iii) Whether it is a blended non-crude feedstock or a blended 
product.
    (2) For a product that enters the refinery to be further refined or 
otherwise used on site that is a blended non-crude feedstock, refiners 
must meet the reporting requirements of paragraph (a)(2) of this section 
by reflecting the individual components of the blended non-crude 
feedstock.
    (3) For a product that is produced, imported, or exported that is a 
blended product, refiners, importers, and exporters must meet the 
reporting requirements of paragraphs (a)(6), (b)(2), and (c)(2) of this 
section, as applicable,

[[Page 1024]]

by reflecting the individual components of the blended product.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66477, Oct. 28, 2010; 
78 FR 71973, Nov. 29, 2013]



Sec. 98.397  Records that must be retained.

    (a) All reporters shall retain copies of all reports submitted to 
EPA under Sec. 98.396. In addition, all reporters shall maintain 
sufficient records to support information contained in those reports, 
including but not limited to information on the characteristics of their 
feedstocks and products.
    (b) Reporters shall maintain records to support quantities that are 
reported under this subpart, including records documenting any 
estimations of missing data and the number of calendar days in the 
reporting year for which substitute data procedures were followed. For 
all reported quantities of petroleum products, natural gas liquids, and 
biomass, reporters shall maintain metering, gauging, and other records 
normally maintained in the course of business to document product and 
feedstock flows including the date of initial calibration and the 
frequency of recalibration for the measurement equipment used.
    (c) Reporters shall retain laboratory reports, calculations and 
worksheets used to estimate the CO2 emissions of the 
quantities of petroleum products, natural gas liquids, biomass, and 
feedstocks reported under this subpart.
    (d) Reporters shall maintain laboratory reports, calculations and 
worksheets used in the measurement of density and carbon share for any 
petroleum product or natural gas liquid for which CO2 
emissions were calculated using Calculation Method 2.
    (e) Estimates of missing data shall be documented and records 
maintained showing the calculations.
    (f) Reporters described in this subpart shall also retain all 
records described in Sec. 98.3(g).

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66478, Oct. 28, 2010; 
78 FR 71974, Nov. 29, 2013]



Sec. 98.398  Definitions.

    Except as specified in this section, all terms used in this subpart 
have the same meaning given in the Clean Air Act and subpart A of this 
part.
    Bulk NGLs for purposes of reporting under this subpart means 
mixtures of NGLs that are sold or delivered as undifferentiated product.
    Natural Gas Liquids (NGLs) for the purposes of reporting under this 
subpart means hydrocarbons that are separated from natural gas as 
liquids through the process of absorption, condensation, adsorption, or 
other methods, and are sold or delivered as differentiated product. 
Generally, such liquids consist of ethane, propane, butanes, or pentanes 
plus.

[75 FR 66478, Oct. 28, 2010, as amended at 78 FR 71974, Nov. 29, 2013]



Sec. Table MM-1 to Subpart MM of Part 98--Default Factors for Petroleum 
                 Products and Natural Gas Liquids \1 2\

------------------------------------------------------------------------
                                                              Column C:
                                    Column A:    Column B:     emission
                                     density       carbon       factor
             Products                (metric    share (% of    (metric
                                    tons/bbl)      mass)      tons CO2/
                                                                 bbl)
------------------------------------------------------------------------
Finished Motor Gasoline
------------------------------------------------------------------------
Conventional--Summer
    Regular......................       0.1181        86.66       0.3753
    Midgrade.....................       0.1183        86.63       0.3758
    Premium......................       0.1185        86.61       0.3763
Conventional--Winter
    Regular......................       0.1155        86.50       0.3663
    Midgrade.....................       0.1161        86.55       0.3684
    Premium......................       0.1167        86.59       0.3705
Reformulated--Summer
    Regular......................       0.1167        86.13       0.3686
    Midgrade.....................       0.1165        86.07       0.3677
    Premium......................       0.1164        86.00       0.3670

[[Page 1025]]

 
Reformulated--Winter
    Regular......................       0.1165        86.05       0.3676
    Midgrade.....................       0.1165        86.06       0.3676
    Premium......................       0.1166        86.06       0.3679
Gasoline--Other..................       0.1185        86.61       0.3763
------------------------------------------------------------------------
Blendstocks
------------------------------------------------------------------------
CBOB--Summer
    Regular......................       0.1181        86.66       0.3753
    Midgrade.....................       0.1183        86.63       0.3758
    Premium......................       0.1185        86.61       0.3763
CBOB--Winter
    Regular......................       0.1155        86.50       0.3663
    Midgrade.....................       0.1161        86.55       0.3684
    Premium......................       0.1167        86.59       0.3705
RBOB--Summer
    Regular......................       0.1167        86.13       0.3686
    Midgrade.....................       0.1165        86.07       0.3677
    Premium......................       0.1164        86.00       0.3670
RBOB--Winter
    Regular......................       0.1165        86.05       0.3676
    Midgrade.....................       0.1165        86.06       0.3676
    Premium......................       0.1166        86.06       0.3679
Blendstocks--Other...............       0.1185        86.61       0.3763
------------------------------------------------------------------------
Oxygenates
------------------------------------------------------------------------
Methanol.........................       0.1268        37.48       0.1743
GTBA.............................       0.1257        64.82       0.2988
MTBE.............................       0.1181        68.13       0.2950
ETBE.............................       0.1182        70.53       0.3057
TAME.............................       0.1229        70.53       0.3178
DIPE.............................       0.1156        70.53       0.2990
------------------------------------------------------------------------
Distillate Fuel Oil
------------------------------------------------------------------------
Distillate No. 1
    Ultra Low Sulfur.............       0.1346        86.40       0.4264
    Low Sulfur...................       0.1346        86.40       0.4264
    High Sulfur..................       0.1346        86.40       0.4264
Distillate No. 2
    Ultra Low Sulfur.............       0.1342        87.30       0.4296
    Low Sulfur...................       0.1342        87.30       0.4296
    High Sulfur..................       0.1342        87.30       0.4296
Distillate Fuel Oil No. 4........       0.1452        86.47       0.4604
Residual Fuel Oil No. 5 (Navy           0.1365        85.67       0.4288
 Special)........................
Residual Fuel Oil No. 6 (a.k.a.         0.1528        84.67       0.4744
 Bunker C).......................
Kerosene-Type Jet Fuel...........       0.1294        86.30       0.4095
Kerosene.........................       0.1346        86.40       0.4264
Diesel--Other....................       0.1452        86.47       0.4604
------------------------------------------------------------------------
Petrochemical Feedstocks
------------------------------------------------------------------------
    Naphthas (<401  deg.F).......       0.1158        84.11       0.3571
    Other Oils (401          0.1390        87.30       0.4450
     deg.F)......................
------------------------------------------------------------------------
Unfinished Oils
------------------------------------------------------------------------
Heavy Gas Oils...................       0.1476        85.80       0.4643
Residuum.........................       0.1622        85.70       0.5097
------------------------------------------------------------------------
Other Petroleum Products and Natural Gas Liquids
------------------------------------------------------------------------
Aviation Gasoline................       0.1120        85.00       0.3490
Special Naphthas.................       0.1222        84.76       0.3798
Lubricants.......................       0.1428        85.80       0.4492
Waxes............................       0.1285        85.30       0.4019
Petroleum Coke...................       0.1818        92.28       0.6151
Asphalt and Road Oil.............       0.1634        83.47       0.5001
Still Gas........................       0.1405        77.70       0.4003

[[Page 1026]]

 
Ethane \3\.......................       0.0579        79.89        0.170
Ethylene \4\.....................       0.0492        85.63        0.154
Propane \3\......................       0.0806        81.71        0.241
Propylene \3\....................       0.0827        85.63        0.260
Butane \3\.......................       0.0928        82.66        0.281
Butylene \3\.....................       0.0972        85.63        0.305
Isobutane \3\....................       0.0892        82.66        0.270
Isobutylene \3\..................       0.0949        85.63        0.298
------------------------------------------------------------------------
Isobutylene......................       0.0936        85.63       0.2939
Pentanes Plus....................       0.1055        83.63       0.3235
Miscellaneous Products...........       0.1380        85.49       0.4326
------------------------------------------------------------------------
\1\ In the case of products blended with some portion of biomass-based
  fuel, the carbon share in Table MM-1 of this subpart represents only
  the petroleum-based components.
\2\ Products that are derived entirely from biomass should not be
  reported, but products that were derived from both biomass and a
  petroleum product (i.e., co-processed) should be reported as the
  petroleum product that it most closely represents.
\3\ The density and emission factors for components of LPG determined at
  60 degrees Fahrenheit and saturation pressure (LPGs other than
  ethylene).
\4\ The density and emission factor for ethylene determined at 41
  degrees Fahrenheit and saturation pressure.


[74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71975, Nov. 29, 2013]



 Sec. Table MM-2 to Subpart MM of Part 98--Default Factors for Biomass-
                         Based Fuels and Biomass

------------------------------------------------------------------------
                                                              Column C:
                                    Column A:    Column B:     Emission
                                     Density       Carbon       factor
  Biomass-based fuel and biomass     (metric    share (% of    (metric
                                    tons/bbl)      mass)      tons CO2/
                                                                 bbl)
------------------------------------------------------------------------
Ethanol (100%)...................       0.1267        52.14       0.2422
Biodiesel (100%, methyl ester)...       0.1396        77.30       0.3957
Rendered Animal Fat..............       0.1333        76.19       0.3724
Vegetable Oil....................       0.1460        76.77       0.4110
------------------------------------------------------------------------



       Subpart NN_Suppliers of Natural Gas and Natural Gas Liquids



Sec. 98.400  Definition of the source category.

    This supplier category consists of natural gas liquids fractionators 
and local natural gas distribution companies.
    (a) Natural gas liquids fractionators are installations that 
fractionate natural gas liquids (NGLs) into their constituent liquid 
products or mixtures of products (ethane, propane, normal butane, 
isobutane or pentanes plus) for supply to downstream facilities.
    (b) Local Distribution Companies (LDCs) are companies that own or 
operate distribution pipelines, not interstate pipelines or intrastate 
pipelines, that physically deliver natural gas to end users and that are 
within a single state that are regulated as separate operating companies 
by State public utility commissions or that operate as independent 
municipally-owned distribution systems. LDCs do not include pipelines 
(both interstate and intrastate) delivering natural gas directly to 
major industrial users and farm taps upstream of the local distribution 
company inlet.
    (c) This supply category does not consist of the following 
facilities:
    (1) Field gathering and boosting stations.
    (2) Natural gas processing plants that separate NGLs from natural 
gas and produce bulk or y-grade NGLs but do not fractionate these NGLs 
into their constituent products.
    (3) Facilities that meet the definition of refineries and report 
under subpart MM of this part.
    (4) Facilities that meet the definition of petrochemical plants and 
report under subpart X of this part.

[74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71975, Nov. 29, 2013]

[[Page 1027]]



Sec. 98.401  Reporting threshold.

    Any supplier of natural gas and natural gas liquids that meets the 
requirements of Sec. 98.2(a)(4) must report GHG emissions.



Sec. 98.402  GHGs to report.

    (a) NGL fractionators must report the CO2 emissions that 
would result from the complete combustion or oxidation of the annual 
quantity of ethane, propane, normal butane, isobutane, and pentanes plus 
that is produced and sold or delivered to others.
    (b) LDCs must report the CO2 emissions that would result 
from the complete combustion or oxidation of the annual volumes of 
natural gas provided to end-users on their distribution systems.



Sec. 98.403  Calculating GHG emissions.

    (a) LDCs and fractionators shall, for each individual product 
reported under this part, calculate the estimated CO2 
emissions that would result from the complete combustion or oxidation of 
the products supplied using either of Calculation Methodology 1 or 2 of 
this subpart:
    (1) Calculation Methodology 1. NGL fractionators shall estimate 
CO2 emissions that would result from the complete combustion 
or oxidation of the product(s) supplied using Equation NN-1 of this 
section. LDCs shall estimate CO2 emissions that would result 
from the complete combustion or oxidation of the product received at the 
city gate using Equation NN-1. For each product, use the default value 
for higher heating value and CO2 emission factor in Table NN-
1 of this subpart. Alternatively, for each product, a reporter-specific 
higher heating value and CO2 emission factor may be used, in 
place of one or both defaults provided they are developed using methods 
outlined in Sec. 98.404. For each product, you must use the same volume 
unit throughout the equation.
[GRAPHIC] [TIFF OMITTED] TR30OC09.163

Where:

CO2. = Annual CO2 mass emissions that would result 
          from the combustion or oxidation of each product ``h'' for 
          redelivery to all recipients (metric tons).
Fuelh = Total annual volume of product ``h'' supplied (volume 
          per year, in thousand standard cubic feet (Mscf) for natural 
          gas and bbl for NGLs).
HHVh = Higher heating value of product ``h'' supplied (MMBtu/
          Mscf or MMBtu/bbl).
EFh = CO2 emission factor of product ``h'' (kg 
          CO2/MMBtu).
1 x 10-3 = Conversion factor from kilograms to metric tons 
          (MT/kg).

    (2) Calculation Methodology 2. NGL fractionators shall estimate 
CO2 emissions that would result from the complete combustion 
or oxidation of the product(s) supplied using Equation NN-2 of this 
section. LDCs shall estimate CO2 emissions that would result 
from the complete combustion or oxidation of the product received at the 
city gate using Equation NN-2. For each product, use the default 
CO2 emission factor found in Table NN-2 of this subpart. 
Alternatively, for each product, a reporter-specific CO2 
emission factor may be used in place of the default factor, provided it 
is developed using methods outlined in Sec. 98.404. For each product, 
you must use the same volume unit throughout the equation.
[GRAPHIC] [TIFF OMITTED] TR30OC09.164

Where:

CO2. = Annual CO2 mass emissions that would result 
          from the combustion or oxidation of each product ``h'' (metric 
          tons)
Fuelh = Total annual volume of product ``h'' supplied (volume 
          per year, in Mscf for natural gas and bbl for NGLs).
EFh = CO2 emission factor of product ``h'' (MT 
          CO2/bbl, or MT CO2/Mscf)

    (b) Each LDC shall follow the procedures below.
    (1) For natural gas that is received for redelivery to downstream 
gas transmission pipelines and other local distribution companies, use 
Equation NN-

[[Page 1028]]

3 of this section and the default values for the CO2 emission 
factors found in Table NN-2 of this subpart. Alternatively, reporter-
specific CO2 emission factors may be used, provided they are 
developed using methods outlined in Sec. 98.404.
[GRAPHIC] [TIFF OMITTED] TR30OC09.165

Where:

CO2. = Annual CO2 mass emissions that would result 
          from the combustion or oxidation of natural gas for redelivery 
          to transmission pipelines or other LDCs (metric tons).
Fuel = Total annual volume of natural gas supplied (Mscf per year).
EF = Fuel-specific CO2 emission factor (MT CO2/
          Mscf).

    (2)(i) For natural gas delivered to large end-users, use Equation 
NN-4 of this section and the default values for the CO2 
emission factors found in Table NN-2 of this subpart. A large end-user 
means any end-user facility receiving greater than or equal to 460,000 
Mscf of natural gas per year. If the LDC does not know the total 
quantity of gas delivered to the end-user facility based on readily 
available information in the LDCs possession, then large end-user means 
any single meter at an end-user facility to which the LDC delivers equal 
to or greater than 460,000 Mscf per year.
    (ii) Alternatively, reporter-specific CO2 emission 
factors may be used, provided they are developed using methods outlined 
in Sec. 98.404.
[GRAPHIC] [TIFF OMITTED] TR30OC09.166

Where:

CO2. = Annual CO2 mass emissions that would result 
          from the combustion or oxidation of natural gas delivered to 
          each large end-user k, as defined in paragraph (b)(2)(i) of 
          this section (metric tons).
Fuel = Total annual volume of natural gas supplied to each large end-
          user k, as defined in paragraph (b)(2)(i) of this section 
          (Mscf per year).
EF = Fuel-specific CO2 emission factor (MT CO2/
          Mscf).

    (3) For the net change in natural gas stored on system by the LDC 
during the reporting year, use Equation NN-5a of this section. For 
natural gas that is received by means other than through the city gate, 
and is not otherwise accounted for by Equation NN-1 or NN-2 of this 
section, use Equation NN-5b of this section.
    (i) For natural gas received by the LDC that is injected into on-
system storage, and/or liquefied and stored, and for gas removed from 
storage and used for deliveries, use Equation NN-5a of this section and 
the default value for the CO2 emission factors found in Table 
NN-2 of this subpart. Alternatively, a reporter-specific CO2 
emission factor may be used, provided it is developed using methods 
outlined in Sec. 98.404.
[GRAPHIC] [TIFF OMITTED] TR29NO13.028

Where:

CO2. = Annual CO2 mass emissions that would result 
          from the combustion or oxidation of the net change in natural 
          gas stored on system by the LDC within the reporting year 
          (metric tons).
Fuel1 = Total annual volume of natural gas added to storage 
          on-system or liquefied and stored in the reporting year (Mscf 
          per year).
Fuel2 = Total annual volume of natural gas that is removed 
          from storage or vaporized and removed from storage and used 
          for deliveries to customers or other LDCs by the LDC within 
          the reporting year (Mscf per year).
EF = Annual average CO2 emission factor for natural gas 
          placed into/removed from storage (MT CO2/Mscf).

    (ii) For natural gas received by the LDC that bypassed the city 
gate, use Equation NN-5b of this section. This includes natural gas 
received directly by LDC systems from producers or natural gas 
processing plants from local production, received as a liquid and 
vaporized for delivery, or received from any other source that bypassed 
the city gate. Use the default value for the CO2 emission 
factors found in Table NN-2 of this subpart. Alternatively, a

[[Page 1029]]

reporter-specific CO2 emission factor may be used, provided 
it is developed using methods outlined in Sec. 98.404.
[GRAPHIC] [TIFF OMITTED] TR29NO13.029

Where:

CO2. = Annual CO2 mass emissions that would result 
          from the combustion or oxidation of natural gas received that 
          bypassed the city gate and is not otherwise accounted for by 
          Equation NN-1 or NN-2 of this section (metric tons).
Fuelz = Total annual volume of natural gas received that was 
          not otherwise accounted for by Equation NN-1 or NN-2 of this 
          section (natural gas from producers and natural gas processing 
          plants from local production, or natural gas that was received 
          as a liquid, vaporized and delivered, and any other source 
          that bypassed the city gate). (Mscf per year)
EFz = Fuel-specific CO2 emission factor (MT 
          CO2/Mscf)

    (4) Calculate the total CO2 emissions that would result 
from the complete combustion or oxidation of the annual supply of 
natural gas to end-users that receive a supply less than 460,000 Mscf 
per year using Equation NN-6 of this section.
[GRAPHIC] [TIFF OMITTED] TR29NO13.030

Where:

CO2 = Annual CO2 mass emissions that would result 
          from the combustion or oxidation of natural gas delivered to 
          LDC end-users not covered in paragraph (b)(2) of this section 
          (metric tons).
CO2. = Annual CO2 mass emissions that would result 
          from the combustion or oxidation of natural gas received at 
          the city gate as calculated in paragraph (a)(1) or (2) of this 
          section (metric tons).
CO2. = Annual CO2 mass emissions that would result 
          from the combustion or oxidation of natural gas delivered to 
          transmission pipelines or other LDCs as calculated in 
          paragraph (b)(1) of this section (metric tons).
CO2. = Annual CO2 mass emissions that would result 
          from the combustion or oxidation of natural gas delivered to 
          each large end-user as calculated in paragraph (b)(2) of this 
          section (metric tons).
CO2. = Annual CO2 mass emissions that would result 
          from the combustion or oxidation of the net change in natural 
          gas stored by the LDC within the reported year as calculated 
          in paragraph (b)(3)(i) of this section (metric tons).
CO2. = Annual CO2 mass emissions that would result 
          from the combustion or oxidation of natural gas that was 
          received by the LDC directly from sources bypassing the city 
          gate, and is not otherwise accounted for in Equation NN-1 or 
          NN-2 of this section, as calculated in paragraph (b)(3)(ii) of 
          this section (metric tons).

    (c) Each NGL fractionator shall follow the following procedures.
    (1)(i) For fractionated NGLs received by the reporter from other NGL 
fractionators, you shall use Equation NN-7 of this section and the 
default values for the CO2 emission factors found in Table 
NN-2 of this subpart.
    (ii) Alternatively, reporter-specific CO2 emission 
factors may be used, provided they are developed using methods outlined 
in Sec. 98.404.
[GRAPHIC] [TIFF OMITTED] TR30OC09.169

Where:

CO2. = Annual CO2 mass emissions that would result 
          from the combustion or oxidation of each fractionated NGL 
          product ``g'' received from other fractionators (metric tons).
Fuelg = Total annual volume of each NGL product ``g'' 
          received (bbls).
EFg = Fuel-specific CO2 emission factor of NGL 
          product ``g'' (MT CO2/bbl).

    (2) Calculate the total CO2 equivalent emissions that 
would result from the combustion or oxidation of fractionated NGLs 
supplied less the

[[Page 1030]]

quantity received from other fractionators using Equation NN-8 of this 
section.
[GRAPHIC] [TIFF OMITTED] TR28OC10.043

Where:

CO2 = Annual CO2 mass emissions that would result 
          from the combustion or oxidation of fractionated NGLs 
          delivered to customers or on behalf of customers less the 
          quantity received from other fractionators (metric tons).
CO2. = Annual CO2 mass emissions that would result 
          from the combustion or oxidation of fractionated NGLs 
          delivered to all customers or on behalf of customers as 
          calculated in paragraph (a)(1) or (a)(2) of this section 
          (metric tons).
CO2. = Annual CO2 mass emissions that would result 
          from the combustion or oxidation of fractionated NGLs received 
          from other fractionators and calculated in paragraph (c)(1) of 
          this section (metric tons).

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66478, Oct. 28, 2010; 
78 FR 71975, Nov. 29, 2013]



Sec. 98.404  Monitoring and QA/QC requirements.

    (a) Determination of quantity. (1) NGL fractionators and LDCs shall 
determine the quantity of NGLs and natural gas using methods in common 
use in the industry for billing purposes as audited under existing 
Sarbanes Oxley regulationn.
    (i) Where an appropriate standard method published by a consensus-
based standards organization exists, such a method shall be used. 
Consensus-based standards organizations include, but are not limited to, 
the following: ASTM International, the American National Standards 
Institute (ANSI), the American Gas Association (AGA), the American 
Society of Mechanical Engineers (ASME), the American Petroleum Institute 
(API), and the North American Energy Standards Board (NAESB).
    (ii) Where no appropriate standard method developed by a consensus-
based standards organization exists, industry standard practices shall 
be followed.
    (2) NGL fractionators and LDCs shall base the minimum frequency of 
the product quantity measurements, to be summed to the annual quantity 
reported, on the reporter's standard practices for commercial 
operations.
    (i) For NGL fractionators the minimum frequency of measurements 
shall be the measurements taken at custody transfers summed to the 
annual reportable volume.
    (ii) For natural gas the minimum frequency of measurement shall be 
based on the LDC's standard measurement schedules used for billing 
purposes and summed to the annual reportable volume.
    (3) NGL fractionators shall use measurement for NGLs at custody 
tranfer meters or at such meters that are used to determine the NGL 
product slate delivered from the fractionation facility.
    (4) If a NGL fractionator supplies a product not listed in Table NN-
1 of this subpart that is a mixture or blend of two or more products 
listed in Tables NN-1 and NN-2 of this subpart, the NGL fractionator 
shall report the quantities of the constituents of the mixtures or 
blends separately.
    (5) For an LDC using Equation NN-1 or NN-2 of this subpart, the 
point(s) of measurement for the natural gas volume received shall be the 
LDC city gate meter(s).
    (i) If the LDC makes its own quantity measurements according to 
established business practices, its own measurements shall be used.
    (ii) If the LDC does not make its own quantity measurements 
according to established business practices, it shall use its delivering 
pipeline invoiced measurements for natural gas deliveries to the LDC 
city gate, used in determining daily system sendout.
    (6) An LDC using Equation NN-3 of this subpart shall measure natural 
gas at the custody transfer meters.
    (7) An LDC using Equation NN-4 of this subpart shall measure natural 
gas at the large end-user's meter(s). Where a large end-user is known to 
have more than one meter located at their facility, based on readily 
available information in the LDCs possession, the reporter shall measure 
the natural gas at each meter and sum the annual volume delivered to all 
meters located at the end-user's facility to determine the total volume 
delivered to the large end-user. Otherwise, the reporter shall

[[Page 1031]]

consider the total annual volume delivered through each single meter at 
a single particular location to be the volume delivered to an individual 
large end-user.
    (8) An LDC using Equation NN-5a and/or NN-5b of this subpart shall 
measure natural gas as follows:
    (i) Fuel1 shall be measured at the on-system storage 
injection meters and/or at the meters measuring natural gas to be 
liquefied.
    (ii) Fuel2 shall be measured at the meters used for 
measuring on-system storage withdrawals and/or LNG vaporization 
injection.
    (iii) Fuelz shall be measured using established business 
practices.
    (9) An LDC shall measure all natural gas under the following 
standard industry temperature and pressure conditions: Cubic foot of gas 
at a temperature of 60 degrees Fahrenheit and at an absolute pressure of 
one atmosphere.
    (b) Determination of higher heating values (HHV). (1) When a 
reporter uses the default HHV provided in this section to calculate 
Equation NN-1 of this subpart, the appropriate value shall be taken from 
Table NN-1 of this subpart.
    (2) When a reporter uses a reporter-specific HHV to calculate 
Equation NN-1 of this subpart, an appropriate standard test published by 
a consensus-based standards organization shall be used. Consensus-based 
standards organizations include, but are not limited to, the following: 
AGA and GPA.
    (i) If an LDC makes its own HHV measurements according to 
established business practices, then its own measurements shall be used.
    (ii) If an LDC does not make its own measurements according to 
established business practices, it shall use its delivering pipeline 
measurements.
    (c) Determination of emission factor (EF). (1) When a reporter used 
the default EF provided in this section to calculate Equation NN-1 of 
this subpart, the appropriate value shall be taken from Table NN-1 of 
this subpart.
    (2) When a reporter used the default EF provided in this section to 
calculate Equation NN-2, NN-3, NN-4, NN-5a, NN-5b, or NN-7 of this 
subpart, the appropriate value shall be taken from Table NN-2 of this 
subpart.
    (3) When a reporter uses a reporter-specific EF, the reporter shall 
use an appropriate standard method published by a consensus-based 
standards organization to conduct compositional analysis necessary to 
determine reporter-specific CO2 emission factors. Consensus-
based standards organizations include, but are not limited to, the 
following: AGA and GPA.
    (d) Equipment Calibration. (1) Equipment used to measure quantities 
in Equations NN-1, NN-2, NN-5a and NN-5b of this subpart shall be 
calibrated prior to its first use for reporting under this subpart, 
using a suitable standard method published by a consensus based 
standards organization or according to the equipment manufacturer's 
directions.
    (2) Equipment used to measure quantities in Equations NN-1, NN-2, 
NN-5a, and NN-5b of this subpart shall be recalibrated at the frequency 
specified by the standard method used or by the manufacturer's 
directions.
    (3) Equipment used to measure quantities in Equations NN-3 and NN-4 
of this subpart shall be recalibrated at the frequency commonly used 
within the industry.

[74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71976, Nov. 29, 2013]



Sec. 98.405  Procedures for estimating missing data.

    (a) Whenever a quality-assured value of the quantity of natural gas 
liquids or natural gas supplied during any period is unavailable (e.g., 
if a flow meter malfunctions), a substitute data value for the missing 
quantity measurement must be used in the calculations according to 
paragraphs (b) and (c) of this section.
    (b) Determination of quantity. (1) NGL fractionators shall 
substitute meter records provided by pipeline(s) for all pipeline 
receipts of NGLs; by manifests for deliveries made to trucks or rail 
cars; or metered quantities accepted by the entities purchasing the 
output from the fractionator whether by pipeline or by truck or rail 
car. In cases where the metered data from the receiving pipeline(s) or 
purchasing entities are not available, fractionators

[[Page 1032]]

may substitute estimates based on contract quantities required to be 
delivered under purchase or delivery contracts with other parties.
    (2) LDCs shall either substitute their delivering pipeline metered 
deliveries at the city gate or substitute nominations and scheduled 
delivery quantities for the period when metered values of actual 
deliveries are not available.
    (c) Determination of HHV and EF. (1) Whenever an LDC that makes its 
own HHV measurements according to established business practices cannot 
follow the quality assurance procedures for developing a reporter-
specific HHV, as specified in Sec. 98.404, during any period for any 
reason, the reporter shall use either its delivering pipeline 
measurements or the default HHV provided in Table NN-1 of this part for 
that period.
    (2) Whenever an LDC that does not make its own HHV measurements 
according to established business practices or an NGL fractionator 
cannot follow the quality assurance procedures for developing a 
reporter-specific HHV, as specified in Sec. 98.404, during any period 
for any reason, the reporter shall use the default HHV provided in Table 
NN-1 of this part for that period.
    (3) [Reserved]
    (4) Whenever a reporter cannot follow the quality assurance 
procedures for developing a reporter-specific EF, as specified in Sec. 
98.404, during any period for any reason, the reporter shall use the 
default EF provided in Sec. 98.408 for that period.

[74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71977, Nov. 29, 2013]



Sec. 98.406  Data reporting requirements.

    (a) In addition to the information required by Sec. 98.3(c), the 
annual report for each NGL fractionator covered by this rule shall 
contain the following information.
    (1) Annual quantity (in barrels) of each NGL product supplied to 
downstream facilities in the following product categories: ethane, 
propane, normal butane, isobutane, and pentanes plus.
    (2) Annual quantity (in barrels) of each NGL product received from 
other NGL fractionators in the following product categories: ethane, 
propane, normal butane, isobutane, and pentanes plus.
    (3) Annual volumes in Mscf of natural gas received for processing.
    (4) Annual quantities (in barrels) of y-grade, o-grade, and other 
bulk NGLs:
    (i) Received.
    (ii) Supplied to downstream users that are not fractionated by the 
reporter.
    (5) Annual quantity (in barrels) of propane that the NGL 
fractionator odorizes at the facility and delivers to others.
    (6) Annual CO2 emissions (metric tons) that would result 
from the complete combustion or oxidation of the quantities in 
paragraphs (a)(1) and (a)(2) of this section, calculated in accordance 
with Sec. 98.403(a) and (c)(1).
    (7) Annual CO2 mass emissions (metric tons) that would 
result from the combustion or oxidation of fractionated NGLs supplied 
less the quantity received from other fractionators, calculated in 
accordance with Sec. 98.403(c)(2). If the calculated value is negative, 
the reporter shall report the value as zero.
    (8) The specific industry standard used to measure each quantity 
reported in paragraph (a)(1) of this section.
    (9) If the NGL fractionator developed reporter-specific EFs or HHVs, 
report the following for each product type:
    (i) The specific industry standard(s) used to develop reporter-
specific higher heating value(s) and/or emission factor(s), pursuant to 
Sec. 98.404(b)(2) and (c)(3).
    (ii) The developed HHV(s).
    (iii) The developed EF(s).
    (b) In addition to the information required by Sec. 98.3(c), the 
annual report for each LDC shall contain the following information.
    (1) Annual volume in Mscf of natural gas received by the LDC at its 
city gate stations for redelivery on the LDC's distribution system, 
including for use by the LDC.
    (2) Annual volume in Mscf of natural gas placed into storage or 
liquefied and stored (Fuel1 in Equation NN-5a).
    (3) Annual volume in Mscf of natural gas withdrawn from on-system 
storage and annual volume in Mscf of vaporized liquefied natural gas 
(LNG) withdrawn

[[Page 1033]]

from storage for delivery on the distribution system (Fuel2 
in Equation NN-5a).
    (4) [Reserved]
    (5) Annual volume in Mscf of natural gas that bypassed the city 
gate(s) and was supplied through the LDC distribution system. This 
includes natural gas from producers and natural gas processing plants 
from local production, or natural gas that was vaporized upon receipt 
and delivered, and any other source that bypassed the city gate 
(Fuelz in Equation NN-5b).
    (6) Annual volume in Mscf of natural gas delivered to downstream gas 
transmission pipelines and other local distribution companies.
    (7) Annual volume in Mscf of natural gas delivered by the LDC to 
each large end-user as defined in Sec. 98.403(b)(2)(i) of this section.
    (8) The total annual CO2 mass emissions (metric tons) 
associated with the volumes in paragraphs (b)(1) through (b)(7) of this 
section, calculated in accordance with Sec. 98.403(a) and (b)(1) 
through (b)(3).
    (9) Annual CO2 emissions (metric tons) that would result 
from the complete combustion or oxidation of the annual supply of 
natural gas to end-users registering less than 460,000 Mscf, calculated 
in accordance with Sec. 98.403(b)(4). If the calculated value is 
negative, the reporter shall report the value as zero.
    (10) The specific industry standard used to develop the volume 
reported in paragraph (b)(1) of this section.
    (11) If the LDC developed reporter-specific EFs or HHVs, report the 
following:
    (i) The specific industry standard(s) used to develop reporter-
specific higher heating value(s) and/or emission factor(s), pursuant to 
Sec. 98.404 (b)(2) and (c)(3).
    (ii) The developed HHV(s).
    (iii) The developed EF(s).
    (12) The customer name, address, and meter number of each large end-
user reported in paragraph (b)(7) of this section. Additionally, report 
whether the quantity of natural gas reported in paragraph (b)(7) of this 
section is the total quantity delivered to a large end-user's facility, 
or the quantity delivered to a specific meter located at the facility.
    (i) If known, report the EIA identification number of each LDC 
customer.
    (ii) [Reserved]
    (13) The annual volume in Mscf of natural gas delivered by the local 
distribution company to each of the following end-use categories. For 
definitions of these categories, refer to EIA Form 176 (Annual Report of 
Natural Gas and Supplemental Gas Supply & Disposition) and Instructions.
    (i) Residential consumers.
    (ii) Commercial consumers.
    (iii) Industrial consumers.
    (iv) Electricity generating facilities.
    (c) Each reporter shall report the number of days in the reporting 
year for which substitute data procedures were used for the following 
purpose:
    (1) To measure quantity.
    (2) To develop HHV(s).
    (3) To develop EF(s).

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66479, Oct. 28, 2010; 
78 FR 71977, Nov. 29, 2013]



Sec. 98.407  Records that must be retained.

    In addition to the information required by Sec. 98.3(g), the 
reporter shall retain the following records:
    (a) Records of all meter readings and documentation to support 
volumes of natural gas and NGLs that are reported under this part.
    (b) Records documenting any estimates of missing metered data and 
showing the calculations of the values used for the missing data.
    (c) Calculations and worksheets used to estimate CO2 
emissions for the volumes reported under this part.
    (d) Records related to the large end-users identified in Sec. 
98.406(b)(7).
    (e) Records relating to measured Btu content or carbon content 
showing specific industry standards used to develop reporter-specific 
higher heating values and emission factors.
    (f) Records of such audits as required by Sarbanes Oxley regulations 
on the accuracy of measurements of volumes of natural gas and NGLs 
delivered to customers or on behalf of customers.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66479, Oct. 28, 2010]

[[Page 1034]]



Sec. 98.408  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.



     Sec. Table NN-1 to Subpart NN of Part 98--Default Factors for 
                Calculation Methodology 1 of This Subpart

------------------------------------------------------------------------
                                                              Default
                                                             CO[ihel2]
                                       Default higher        emission
               Fuel                   heating value \1\     factor (kg
                                                            CO[ihel2]/
                                                              MMBtu)
------------------------------------------------------------------------
Natural Gas.......................  1.026 MMBtu/Mscf....           53.06
Propane...........................  3.84 MMBtu/bbl......           62.87
Normal butane.....................  4.34 MMBtu/bbl......           64.77
Ethane............................  2.85 MMBtu/bbl......           59.60
Isobutane.........................  4.16 MMBtu/bbl......           64.94
Pentanes plus.....................  4.62 MMBtu/bbl......           70.02
------------------------------------------------------------------------
\1\ Conditions for higher heating values presented in MMBtu/bbl are 60
  deg.F and saturation pressure.


[78 FR 71977, Nov. 29, 2013]



Sec. Table NN-2 to Subpart NN of Part 98--Default Values for Calculation 
                      Methodology 2 of This Subpart

------------------------------------------------------------------------
                                                               Default
                                                              CO[ihel2]
                                                               emission
                Fuel                          Unit            value (MT
                                                              CO[ihel2]/
                                                              Unit) \1\
------------------------------------------------------------------------
Natural Gas........................  Mscf..................       0.0544
Propane............................  Barrel................        0.241
Normal butane......................  Barrel................        0.281
Ethane.............................  Barrel................        0.170
Isobutane..........................  Barrel................        0.270
Pentanes plus......................  Barrel................        0.324
------------------------------------------------------------------------
\1\ Conditions for emission value presented in MT CO[ihel2]/bbl are 60
  deg.F and saturation pressure.


[78 FR 71977, Nov. 29, 2013, as amended at 79 FR 3508, Jan. 22, 2014]



           Subpart OO_Suppliers of Industrial Greenhouse Gases



Sec. 98.410  Definition of the source category.

    (a) The industrial gas supplier source category consists of any 
facility that produces a fluorinated GHG or nitrous oxide, any bulk 
importer of fluorinated GHGs or nitrous oxide, and any bulk exporter of 
fluorinated GHGs or nitrous oxide.
    (b) To produce a fluorinated GHG means to manufacture a fluorinated 
GHG from any raw material or feedstock chemical. Producing a fluorinated 
GHG includes the manufacture of a fluorinated GHG as an isolated 
intermediate for use in a process that will result in its transformation 
either at or outside of the production facility. Producing a fluorinated 
GHG also includes the creation of a fluorinated GHG (with the exception 
of HFC-23) that is captured and shipped off site for any reason, 
including destruction. Producing a fluorinated GHG does not include the 
reuse or recycling of a fluorinated GHG, the creation of HFC-23 during 
the production of HCFC-22, the creation of intermediates that are 
created and transformed in a single process with no storage of the 
intermediates, or the creation of fluorinated GHGs that are released or 
destroyed at the production facility before the production measurement 
at Sec. 98.414(a).
    (c) To produce nitrous oxide means to produce nitrous oxide by 
thermally decomposing ammonium nitrate (NH4NO3). 
Producing nitrous oxide does not include the reuse or recycling of 
nitrous oxide or the creation of by-products that are released or 
destroyed at the production facility.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79167, Dec. 17, 2010]

[[Page 1035]]



Sec. 98.411  Reporting threshold.

    Any supplier of industrial greenhouse gases who meets the 
requirements of Sec. 98.2(a)(4) must report GHG emissions.



Sec. 98.412  GHGs to report.

    You must report the GHG emissions that would result from the release 
of the nitrous oxide and each fluorinated GHG that you produce, import, 
export, transform, or destroy during the calendar year.



Sec. 98.413  Calculating GHG emissions.

    (a) Calculate the total mass of each fluorinated GHG or nitrous 
oxide produced annually, except for amounts that are captured solely to 
be shipped off site for destruction, by using Equation OO-1 of this 
section: 
[GRAPHIC] [TIFF OMITTED] TR30OC09.171

P = Mass of fluorinated GHG or nitrous oxide produced annually.
Pp = Mass of fluorinated GHG or nitrous oxide produced over 
          the period ``p''.

    (b) Calculate the total mass of each fluorinated GHG or nitrous 
oxide produced over the period ``p'' by using Equation OO-2 of this 
section: 
[GRAPHIC] [TIFF OMITTED] TR30OC09.172

Where:

Pp = Mass of fluorinated GHG or nitrous oxide produced over 
          the period ``p'' (metric tons).
Op = Mass of fluorinated GHG or nitrous oxide that is 
          measured coming out of the production process over the period 
          p (metric tons).
Up = Mass of used fluorinated GHG or nitrous oxide that is 
          added to the production process upstream of the output 
          measurement over the period ``p'' (metric tons).

    (c) Calculate the total mass of each fluorinated GHG or nitrous 
oxide transformed by using Equation OO-3 of this section: 
[GRAPHIC] [TIFF OMITTED] TR30OC09.173

Where:

T = Mass of fluorinated GHG or nitrous oxide transformed annually 
          (metric tons).

FT = Mass of fluorinated GHG fed into the transformation 
process annually (metric tons).
ET = The fraction of the fluorinated GHG or nitrous oxide fed 
into the transformation process that is transformed in the process 
(metric tons).

    (d) Calculate the total mass of each fluorinated GHG destroyed by 
using Equation OO-4 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.174

Where:

D = Mass of fluorinated GHG destroyed annually (metric tons).
FD = Mass of fluorinated GHG fed into the destruction device 
          annually (metric tons).
DE = Destruction efficiency of the destruction device (fraction).



Sec. 98.414  Monitoring and QA/QC requirements.

    (a) The mass of fluorinated GHGs or nitrous oxide coming out of the 
production process shall be measured using flowmeters, weigh scales, or 
a combination of volumetric and density measurements with an accuracy 
and precision of one percent of full scale or better. If the measured 
mass includes more than one fluorinated GHG, the concentrations of each 
of the fluorinated GHGs, other than low-concentration constituents, 
shall be measured as set forth in paragraph (n) of this section. For 
each fluorinated GHG, the mean of the concentrations of that fluorinated 
GHG (mass fraction) measured under paragraph (n) of this section shall 
be multiplied by the mass measurement to obtain the mass of that 
fluorinated GHG coming out of the production process.
    (b) The mass of any used fluorinated GHGs or used nitrous oxide 
added back into the production process upstream of the output 
measurement in paragraph (a) of this section shall be measured using 
flowmeters, weigh scales, or a combination of volumetric and density 
measurements with an accuracy and precision of one percent of full scale 
or better. If the mass in paragraph (a) of this section is measured by 
weighing containers that include returned heels as well as newly 
produced fluorinated GHGs, the returned heels

[[Page 1036]]

shall be considered used fluorinated GHGs for purposes of this paragraph 
(b) of this section and Sec. 98.413(b).
    (c) The mass of fluorinated GHGs or nitrous oxide fed into the 
transformation process shall be measured using flowmeters, weigh scales, 
or a combination of volumetric and density measurements with an accuracy 
and precision of one percent of full scale or better.
    (d) The fraction of the fluorinated GHGs or nitrous oxide fed into 
the transformation process that is actually transformed shall be 
estimated considering yield calculations or quantities of unreacted 
fluorinated GHGs or nitrous oxide permanently removed from the process 
and recovered, destroyed, or emitted.
    (e) The mass of fluorinated GHG or nitrous oxide sent to another 
facility for transformation shall be measured using flowmeters, weigh 
scales, or a combination of volumetric and density measurements with an 
accuracy and precision of one percent of full scale or better.
    (f) The mass of fluorinated GHG sent to another facility for 
destruction shall be measured using flowmeters, weigh scales, or a 
combination of volumetric and density measurements with an accuracy and 
precision of one percent of full scale or better. If the measured mass 
includes more than trace concentrations of materials other than the 
fluorinated GHG, the concentration of the fluorinated GHG shall be 
estimated considering current or previous representative concentration 
measurements and other relevant process information. This concentration 
(mass fraction) shall be multiplied by the mass measurement to obtain 
the mass of the fluorinated GHG sent to another facility for 
destruction.
    (g) You must estimate the share of the mass of fluorinated GHGs in 
paragraph (f) of this section that is comprised of fluorinated GHGs that 
are not included in the mass produced in Sec. 98.413(a) because they 
are removed from the production process as by-products or other wastes.
    (h) You must measure the mass of each fluorinated GHG that is fed 
into the destruction device and that was previously produced as defined 
at Sec. 98.410(b). Such fluorinated GHGs include but are not limited to 
quantities that are shipped to the facility by another facility for 
destruction and quantities that are returned to the facility for 
reclamation but are found to be irretrievably contaminated and are 
therefore destroyed. You must use flowmeters, weigh scales, or a 
combination of volumetric and density measurements with an accuracy and 
precision of one percent of full scale or better. If the measured mass 
includes more than trace concentrations of materials other than the 
fluorinated GHG being destroyed, you must estimate the concentrations of 
the fluorinated GHG being destroyed considering current or previous 
representative concentration measurements and other relevant process 
information. You must multiply this concentration (mass fraction) by the 
mass measurement to obtain the mass of the fluorinated GHG fed into the 
destruction device.
    (i) Very small quantities of fluorinated GHGs that are difficult to 
measure because they are entrained in other media such as destroyed 
filters and destroyed sample containers are exempt from paragraphs (f) 
and (h) of this section.
    (j) [Reserved]
    (k) For purposes of Equation OO-4 of this subpart, the destruction 
efficiency can be equated to the destruction efficiency determined 
during a previous performance test of the destruction device or, if no 
performance test has been done, the destruction efficiency provided by 
the manufacturer of the destruction device.
    (l) In their estimates of the mass of fluorinated GHGs destroyed, 
fluorinated GHG production facilities that destroy fluorinated GHGs 
shall account for any temporary reductions in the destruction efficiency 
that result from any startups, shutdowns, or malfunctions of the 
destruction device, including departures from the operating conditions 
defined in state or local permitting requirements and/or oxidizer 
manufacturer specifications.
    (m) Calibrate all flow meters, weigh scales, and combinations of 
volumetric and density measures that are used to measure or calculate 
quantities that are to be reported under this subpart

[[Page 1037]]

prior to the first year for which GHG emissions are reported under this 
part. Calibrations performed prior to the effective date of this rule 
satisfy this requirement. Recalibrate all flow meters, weigh scales, and 
combinations of volumetric and density measures at the minimum frequency 
specified by the manufacturer. Use NIST-traceable standards and suitable 
methods published by a consensus standards organization (e.g., ASTM, 
ASME, ISO, or others).
    (n) If the mass coming out of the production process includes more 
than one fluorinated GHG, you shall measure the concentrations of all of 
the fluorinated GHGs, other than low-concentration constituents, as 
follows:
    (1) Analytical Methods. Use a quality-assured analytical measurement 
technology capable of detecting the analyte of interest at the 
concentration of interest and use a procedure validated with the analyte 
of interest at the concentration of interest. Where standards for the 
analyte are not available, a chemically similar surrogate may be used. 
Acceptable analytical measurement technologies include but are not 
limited to gas chromatography (GC) with an appropriate detector, 
infrared (IR), fourier transform infrared (FTIR), and nuclear magnetic 
resonance (NMR). Acceptable methods include EPA Method 18 in appendix A-
1 of 40 CFR part 60; EPA Method 320 in appendix A of 40 CFR part 63; the 
Protocol for Measuring Destruction or Removal Efficiency (DRE) of 
Fluorinated Greenhouse Gas Abatement Equipment in Electronics 
Manufacturing, Version 1, EPA-430-R-10-003, (March 2010) (incorporated 
by reference, see Sec. 98.7); ASTM D6348-03 Standard Test Method for 
Determination of Gaseous Compounds by Extractive Direct Interface 
Fourier Transform Infrared (FTIR) Spectroscopy (incorporated by 
reference, see Sec. 98.7); or other analytical methods validated using 
EPA Method 301 in appendix A of 40 CFR part 63 or some other 
scientifically sound validation protocol. The validation protocol may 
include analytical technology manufacturer specifications or 
recommendations.
    (2) Documentation in GHG Monitoring Plan. Describe the analytical 
method(s) used under paragraph (n)(1) of this section in the site GHG 
Monitoring Plan as required under Sec. 98.3(g)(5). At a minimum, 
include in the description of the method a description of the analytical 
measurement equipment and procedures, quantitative estimates of the 
method's accuracy and precision for the analytes of interest at the 
concentrations of interest, as well as a description of how these 
accuracies and precisions were estimated, including the validation 
protocol used.
    (3) Frequency of measurement. Perform the measurements at least once 
by February 15, 2011 if the fluorinated GHG product is being produced on 
December 17, 2010. Perform the measurements within 60 days of commencing 
production of any fluorinated GHG product that was not being produced on 
December 17, 2010. Repeat the measurements if an operational or process 
change occurs that could change the identities or significantly change 
the concentrations of the fluorinated GHG constituents of the 
fluorinated GHG product. Complete the repeat measurements within 60 days 
of the operational or process change.
    (4) Measure all product grades. Where a fluorinated GHG is produced 
at more than one purity level (e.g., pharmaceutical grade and 
refrigerant grade), perform the measurements for each purity level.
    (5) Number of samples. Analyze a minimum of three samples of the 
fluorinated GHG product that have been drawn under conditions that are 
representative of the process producing the fluorinated GHG product. If 
the relative standard deviation of the measured concentrations of any of 
the fluorinated GHG constituents (other than low-concentration 
constituents) is greater than or equal to 15 percent, draw and analyze 
enough additional samples to achieve a total of at least six samples of 
the fluorinated GHG product.
    (o) All analytical equipment used to determine the concentration of 
fluorinated GHGs, including but not limited to gas chromatographs and 
associated detectors, IR, FTIR and NMR devices, shall be calibrated at a 
frequency needed to support the type of

[[Page 1038]]

analysis specified in the site GHG Monitoring Plan as required under 
Sec. Sec. 98.414(n) and 98.3(g)(5) of this part. Quality assurance 
samples at the concentrations of concern shall be used for the 
calibration. Such quality assurance samples shall consist of or be 
prepared from certified standards of the analytes of concern where 
available; if not available, calibration shall be performed by a method 
specified in the GHG Monitoring Plan.
    (p) Isolated intermediates that are produced and transformed at the 
same facility are exempt from the monitoring requirements of this 
section.
    (q) Low-concentration constituents are exempt from the monitoring 
and QA/QC requirements of this section.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79167, Dec. 17, 2010]



Sec. 98.415  Procedures for estimating missing data.

    (a) A complete record of all measured parameters used in the GHG 
emissions calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable (e.g., if a meter 
malfunctions), a substitute data value for the missing parameter shall 
be used in the calculations, according to paragraph (b) of this section.
    (b) For each missing value of the mass produced, fed into the 
production process (for used material being reclaimed), fed into the 
transformation process, fed into destruction devices, sent to another 
facility for transformation, or sent to another facility for 
destruction, the substitute value of that parameter shall be a secondary 
mass measurement where such a measurement is available. For example, if 
the mass produced is usually measured with a flowmeter at the inlet to 
the day tank and that flowmeter fails to meet an accuracy or precision 
test, malfunctions, or is rendered inoperable, then the mass produced 
may be estimated by calculating the change in volume in the day tank and 
multiplying it by the density of the product. Where a secondary mass 
measurement is not available, the substitute value of the parameter 
shall be an estimate based on a related parameter. For example, if a 
flowmeter measuring the mass fed into a destruction device is rendered 
inoperable, then the mass fed into the destruction device may be 
estimated using the production rate and the previously observed 
relationship between the production rate and the mass flow rate into the 
destruction device.



Sec. 98.416  Data reporting requirements.

    In addition to the information required by Sec. 98.3(c), each 
annual report must contain the following information:
    (a) Each fluorinated GHG or nitrous oxide production facility shall 
report the following information:
    (1) Mass in metric tons of each fluorinated GHG or nitrous oxide 
produced at that facility by process, except for amounts that are 
captured solely to be shipped off site for destruction.
    (2) Mass in metric tons of each fluorinated GHG or nitrous oxide 
transformed at that facility, by process.
    (3) Mass in metric tons of each fluorinated GHG that is destroyed at 
that facility and that was previously produced as defined at Sec. 
98.410(b). Quantities to be reported under this paragraph (a)(3) of this 
section include but are not limited to quantities that are shipped to 
the facility by another facility for destruction and quantities that are 
returned to the facility for reclamation but are found to be 
irretrievably contaminated and are therefore destroyed.
    (4) [Reserved]
    (5) Total mass in metric tons of each fluorinated GHG or nitrous 
oxide sent to another facility for transformation.
    (6) Total mass in metric tons of each fluorinated GHG sent to 
another facility for destruction, except fluorinated GHGs that are not 
included in the mass produced in Sec. 98.413(a) because they are 
removed from the production process as by-products or other wastes. 
Quantities to be reported under this paragraph (a)(6) could include, for 
example, fluorinated GHGs that are returned to the facility for 
reclamation but are found to be irretrievably contaminated and are 
therefore sent to another facility for destruction.

[[Page 1039]]

    (7) Total mass in metric tons of each fluorinated GHG that is sent 
to another facility for destruction and that is not included in the mass 
produced in Sec. 98.413(a) because it is removed from the production 
process as a byproduct or other waste.
    (8)-(9) [Reserved]
    (10) Mass in metric tons of any fluorinated GHG or nitrous oxide fed 
into the transformation process, by process.
    (11) Mass in metric tons of each fluorinated GHG that is fed into 
the destruction device and that was previously produced as defined at 
Sec. 98.410(b). Quantities to be reported under this paragraph (a)(11) 
of this section include but are not limited to quantities that are 
shipped to the facility by another facility for destruction and 
quantities that are returned to the facility for reclamation but are 
found to be irretrievably contaminated and are therefore destroyed.
    (12) Mass in metric tons of each fluorinated GHG or nitrous oxide 
that is measured coming out of the production process, by process.
    (13) Mass in metric tons of each used fluorinated GHGs or nitrous 
oxide added back into the production process (e.g., for reclamation), 
including returned heels in containers that are weighed to measure the 
mass in Sec. 98.414(a), by process.
    (14) Names and addresses of facilities to which any nitrous oxide or 
fluorinated GHGs were sent for transformation, and the quantities 
(metric tons) of nitrous oxide and of each fluorinated GHG that were 
sent to each for transformation.
    (15) Names and addresses of facilities to which any fluorinated GHGs 
were sent for destruction, and the quantities (metric tons) of each 
fluorinated GHG that were sent to each for destruction.
    (16) Where missing data have been estimated pursuant to Sec. 
98.415, the reason the data were missing, the length of time the data 
were missing, the method used to estimate the missing data, and the 
estimates of those data.
    (b) By March 31, 2011 or within 60 days of commencing fluorinated 
GHG destruction, whichever is later, a fluorinated GHG production 
facility or importer that destroys fluorinated GHGs shall submit a one-
time report containing the following information for each destruction 
process:
    (1) Destruction efficiency (DE).
    (2) Methods used to determine the destruction efficiency.
    (3) Methods used to record the mass of fluorinated GHG destroyed.
    (4) Chemical identity of the fluorinated GHG(s) used in the 
performance test conducted to determine DE.
    (5) Name of all applicable federal or state regulations that may 
apply to the destruction process.
    (6) If any process changes affect unit destruction efficiency or the 
methods used to record mass of fluorinated GHG destroyed, then a revised 
report must be submitted to reflect the changes. The revised report must 
be submitted to EPA within 60 days of the change.
    (c) Each bulk importer of fluorinated GHGs or nitrous oxide shall 
submit an annual report that summarizes its imports at the corporate 
level, except for shipments including less than twenty-five kilograms of 
fluorinated GHGs or nitrous oxide, transshipments, and heels that meet 
the conditions set forth at Sec. 98.417(e). The report shall contain 
the following information for each import:
    (1) Total mass in metric tons of nitrous oxide and each fluorinated 
GHG imported in bulk, including each fluorinated GHG constituent of the 
fluorinated GHG product that makes up between 0.5 percent and 100 
percent of the product by mass.
    (2) Total mass in metric tons of nitrous oxide and each fluorinated 
GHG imported in bulk and sold or transferred to persons other than the 
importer for use in processes resulting in the transformation or 
destruction of the chemical.
    (3) Date on which the fluorinated GHGs or nitrous oxide were 
imported.
    (4) Port of entry through which the fluorinated GHGs or nitrous 
oxide passed.
    (5) Country from which the imported fluorinated GHGs or nitrous 
oxide were imported.
    (6) Commodity code of the fluorinated GHGs or nitrous oxide shipped.

[[Page 1040]]

    (7) Importer number for the shipment.
    (8) Total mass in metric tons of each fluorinated GHG destroyed by 
the importer.
    (9) If applicable, the names and addresses of the persons and 
facilities to which the nitrous oxide or fluorinated GHGs were sold or 
transferred for transformation, and the quantities (metric tons) of 
nitrous oxide and of each fluorinated GHG that were sold or transferred 
to each facility for transformation.
    (10) If applicable, the names and addresses of the persons and 
facilities to which the fluorinated GHGs were sold or transferred for 
destruction, and the quantities (metric tons) of each fluorinated GHG 
that were sold or transferred to each facility for destruction.
    (d) Each bulk exporter of fluorinated GHGs or nitrous oxide shall 
submit an annual report that summarizes its exports at the corporate 
level, except for shipments including less than twenty-five kilograms of 
fluorinated GHGs or nitrous oxide, transshipments, and heels. The report 
shall contain the following information for each export:
    (1) Total mass in metric tons of nitrous oxide and each fluorinated 
GHG exported in bulk.
    (2) Names and addresses of the exporter and the recipient of the 
exports.
    (3) Exporter's Employee Identification Number.
    (4) Commodity code of the fluorinated GHGs and nitrous oxide 
shipped.
    (5) Date on which, and the port from which, fluorinated GHGs and 
nitrous oxide were exported from the United States or its territories.
    (6) Country to which the fluorinated GHGs or nitrous oxide were 
exported.
    (e) By March 31, 2011, or within 60 days of commencing fluorinated 
GHG production, whichever is later, a fluorinated GHG production 
facility shall submit a one-time report describing the following 
information:
    (1) The method(s) by which the producer in practice measures the 
mass of fluorinated GHGs produced, including the instrumentation used 
(Coriolis flowmeter, other flowmeter, weigh scale, etc.) and its 
accuracy and precision.
    (2) The method(s) by which the producer in practice estimates the 
mass of fluorinated GHGs fed into the transformation process, including 
the instrumentation used (Coriolis flowmeter, other flowmeter, weigh 
scale, etc.) and its accuracy and precision.
    (3) The method(s) by which the producer in practice estimates the 
fraction of fluorinated GHGs fed into the transformation process that is 
actually transformed, and the estimated precision and accuracy of this 
estimate.
    (4) The method(s) by which the producer in practice estimates the 
masses of fluorinated GHGs fed into the destruction device, including 
the method(s) used to estimate the concentration of the fluorinated GHGs 
in the destroyed material, and the estimated precision and accuracy of 
this estimate.
    (5) The estimated percent efficiency of each production process for 
the fluorinated GHG produced.
    (f) By March 31, 2011, all fluorinated GHG production facilities 
shall submit a one-time report that includes the concentration of each 
fluorinated GHG constituent in each fluorinated GHG product as measured 
under Sec. 98.414(n). If the facility commences production of a 
fluorinated GHG product that was not included in the initial report or 
performs a repeat measurement under Sec. 98.414(n) that shows that the 
identities or concentrations of the fluorinated GHG constituents of a 
fluorinated GHG product have changed, then the new or changed 
concentrations, as well as the date of the change, must be reflected in 
a revision to the report. The revised report must be submitted to EPA by 
the March 31st that immediately follows the measurement under Sec. 
98.414(n).
    (g) Isolated intermediates that are produced and transformed at the 
same facility are exempt from the reporting requirements of this 
section.
    (h) Low-concentration constituents are exempt from the reporting 
requirements of this section.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79168, Dec. 17, 2010; 
76 FR 73905, Nov. 29, 2011]

[[Page 1041]]



Sec. 98.417  Records that must be retained.

    (a) In addition to the data required by Sec. 98.3(g), the 
fluorinated GHG production facility shall retain the following records:
    (1) Dated records of the data used to estimate the data reported 
under Sec. 98.416.
    (2) Records documenting the initial and periodic calibration of the 
analytical equipment (including but not limited to GC, IR, FTIR, or 
NMR), weigh scales, flowmeters, and volumetric and density measures used 
to measure the quantities reported under this subpart, including the 
manufacturer directions or industry standards used for calibration 
pursuant to Sec. 98.414(m) and (o).
    (3) Dated records of the total mass in metric tons of each reactant 
fed into the F-GHG or nitrous oxide production process, by process.
    (4) Dated records of the total mass in metric tons of the reactants, 
by-products, and other wastes permanently removed from the F-GHG or 
nitrous oxide production process, by process.
    (b) In addition to the data required by paragraph (a) of this 
section, any fluorinated GHG production facility that destroys 
fluorinated GHGs shall keep records of test reports and other 
information documenting the facility's one-time destruction efficiency 
report in Sec. 98.416(b).
    (c) In addition to the data required by Sec. 98.3(g), the bulk 
importer shall retain the following records substantiating each of the 
imports that they report:
    (1) A copy of the bill of lading for the import.
    (2) The invoice for the import.
    (3) The U.S. Customs entry form.
    (d) In addition to the data required by Sec. 98.3(g), the bulk 
exporter shall retain the following records substantiating each of the 
exports that they report:
    (1) A copy of the bill of lading for the export and
    (2) The invoice for the export.
    (e) Every person who imports a container with a heel that is not 
reported under Sec. 98.416(c) shall keep records of the amount brought 
into the United States that document that the residual amount in each 
shipment is less than 10 percent of the volume of the container and 
will:
    (1) Remain in the container and be included in a future shipment.
    (2) Be recovered and transformed.
    (3) Be recovered and destroyed.
    (4) Be recovered and included in a future shipment.
    (f) Isolated intermediates that are produced and transformed at the 
same facility are exempt from the recordkeeping requirements of this 
section.
    (g) Low-concentration constituents are exempt from the recordkeeping 
requirements of this section.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79168, Dec. 17, 2010; 
76 FR 73905, Nov. 29, 2011]



Sec. 98.418  Definitions.

    Except as provided below, all of the terms used in this subpart have 
the same meaning given in the Clean Air Act and subpart A of this part. 
If a conflict exists between a definition provided in this subpart and a 
definition provided in subpart A, the definition in this subpart shall 
take precedence for the reporting requirements in this subpart.
    Isolated intermediate means a product of a process that is stored 
before subsequent processing. An isolated intermediate is usually a 
product of chemical synthesis. Storage of an isolated intermediate marks 
the end of a process. Storage occurs at any time the intermediate is 
placed in equipment used solely for storage.
    Low-concentration constituent means, for purposes of fluorinated GHG 
production and export, a fluorinated GHG constituent of a fluorinated 
GHG product that occurs in the product in concentrations below 0.1 
percent by mass. For purposes of fluorinated GHG import, low-
concentration constituent means a fluorinated GHG constituent of a 
fluorinated GHG product that occurs in the product in concentrations 
below 0.5 percent by mass. Low-concentration constituents do not include 
fluorinated GHGs that are deliberately combined with the product (e.g., 
to affect the performance characteristics of the product).

[75 FR 79169, Dec. 17, 2010]

[[Page 1042]]



                 Subpart PP_Suppliers of Carbon Dioxide



Sec. 98.420  Definition of the source category.

    (a) The carbon dioxide (CO2) supplier source category 
consists of the following:
    (1) Facilities with production process units that capture a 
CO2 stream for purposes of supplying CO2 for 
commercial applications or that capture and maintain custody of a 
CO2 stream in order to sequester or otherwise inject it 
underground. Capture refers to the initial separation and removal of 
CO2 from a manufacturing process or any other process.
    (2) Facilities with CO2 production wells that extract or 
produce a CO2 stream for purposes of supplying CO2 
for commercial applications or that extract and maintain custody of a 
CO2 stream in order to sequester or otherwise inject it 
underground.
    (3) Importers or exporters of bulk CO2.
    (b) This source category is focused on upstream supply. It does not 
cover:
    (1) Storage of CO2 above ground or in geologic 
formations.
    (2) Use of CO2 in enhanced oil and gas recovery.
    (3) Transportation or distribution of CO2.
    (4) Purification, compression, or processing of CO2.
    (5) On-site use of CO2 captured on site.
    (c) This source category does not include CO2 imported or 
exported in equipment, such as fire extinguishers.



Sec. 98.421  Reporting threshold.

    Any supplier of CO2 who meets the requirements of Sec. 
98.2(a)(4) of subpart A of this part must report the mass of 
CO2 captured, extracted, imported, or exported.



Sec. 98.422  GHGs to report.

    (a) Mass of CO2 captured from production process units.
    (b) Mass of CO2 extracted from CO2 production 
wells.
    (c) Mass of CO2 imported.
    (d) Mass of CO2 exported.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79169, Dec. 17, 2010]



Sec. 98.423  Calculating CO[bdi2] supply.

    (a) Except as allowed in paragraph (b) of this section, calculate 
the annual mass of CO2 captured, extracted, imported, or 
exported through each flow meter in accordance with the procedures 
specified in either paragraph (a)(1) or (a)(2) of this section. If 
multiple flow meters are used, you shall calculate the annual mass of 
CO2 for all flow meters according to the procedures specified 
in paragraph (a)(3) of this section.
    (1) For each mass flow meter, you shall calculate quarterly the mass 
of CO2 in a CO2 stream in metric tons by 
multiplying the mass flow by the composition data, according to Equation 
PP-1 of this section. Mass flow and composition data measurements shall 
be made in accordance with Sec. 98.424 of this subpart. 
[GRAPHIC] [TIFF OMITTED] TR30OC09.175

Where:

CO2,u = Annual mass of CO2 (metric tons) through 
          flow meter u.
CCO2,p,u = Quarterly CO2 concentration 
          measurement in flow for flow meter u in quarter p (wt. 
          %CO2).
Qp,u = Quarterly mass flow rate measurement for flow meter u 
          in quarter p (metric tons).
p = Quarter of the year.
u = Flow meter.

    (2) For each volumetric flow meter, you shall calculate quarterly 
the mass of CO2 in a CO2 stream in metric tons by 
multiplying the volumetric flow by

[[Page 1043]]

the concentration and density data, according to Equation PP-2 of this 
section. Volumetric flow, concentration and density data measurements 
shall be made in accordance with Sec. 98.424 of this section. 
[GRAPHIC] [TIFF OMITTED] TR30OC09.176

Where:

CO2,u = Annual mass of CO2 (metric tons) through 
          flow meter u.
CCO2,p = Quarterly CO2 concentration measurement 
          in flow for flow meter u in quarter p (measured as either 
          volume % CO2 or weight % CO2).
Qp = Quarterly volumetric flow rate measurement for flow 
          meter u in quarter p (standard cubic meters).
Dp = Density of CO2 in quarter p (metric tons 
          CO2 per standard cubic meter) for flow meter u if 
          CCO2,p is measured as volume % CO2, or 
          density of the whole CO2 stream for flow meter u 
          (metric tons per standard cubic meter) if CCO2,p is 
          measured as weight % CO2.
p = Quarter of the year.
u = Flow meter.

    (3) To aggregate data, use either Equation PP-3a or PP-3b in this 
paragraph, as appropriate.
    (i) For facilities with production process units or production wells 
that capture or extract a CO2 stream and either measure it 
after segregation or do not segregate the flow, calculate the total 
CO2 supplied in accordance with Equation PP-3a in paragraph 
(a)(3).
[GRAPHIC] [TIFF OMITTED] TR17DE10.012

where:

CO2 = Total annual mass of CO2 (metric tons).
CO2,u = Annual mass of CO2 (metric tons) through 
          flow meter u.
u = Flow meter.

    (ii) For facilities with production process units that capture a 
CO2 stream and measure it ahead of segregation, calculate the 
total CO2 supplied in accordance with Equation PP-3b.
[GRAPHIC] [TIFF OMITTED] TR17DE10.013

where:

CO2 = Total annual mass of CO2 (metric tons).
CO2,u = Annual mass of CO2 (metric tons) through 
          main flow meter u.
CO2,v = Annual mass of CO2 (metric tons) through 
          subsequent flow meter v for use on site.
u = Main flow meter.
v = Subsequent flow meter.

    (b) As an alternative to paragraphs (a)(1) through (3) of this 
section for CO2 that is supplied in containers, calculate the 
annual mass of CO2 supplied in containers delivered by each 
CO2 stream in accordance with the procedures specified in 
either paragraph (b)(1) or (b)(2) of this section. If multiple 
CO2 streams are used to deliver CO2 to containers, 
you shall calculate the annual mass of CO2 supplied in 
containers delivered by all CO2 streams according to the 
procedures specified in paragraph (b)(3) of this section.

[[Page 1044]]

    (1) For each CO2 stream that delivers CO2 to 
containers, for which mass is measured, you shall calculate 
CO2 supply in containers using Equation PP-1 of this section.

where:

CO2,u = Annual mass of CO2 (metric tons) supplied 
          in containers delivered by CO2 stream u.
CCO2,p,u = Quarterly CO2 concentration measurement 
          of CO2 stream u that delivers CO2 to 
          containers in quarter p (wt. %CO2).
Qp,u = Quarterly mass of contents supplied in all containers 
          delivered by CO2 stream u in quarter p (metric 
          tons).
p = Quarter of the year.
u = CO2 stream that delivers to containers.

    (2) For each CO2 stream that delivers to containers, for 
which volume is measured, you shall calculate CO2 supply in 
containers using Equation PP-2 of this section.

where:

CO2,u = Annual mass of CO2 (metric tons) supplied 
          in containers delivered by CO2 stream u.
CCO2,p = Quarterly CO2 concentration measurement 
          of CO2 stream u that delivers CO2 to 
          containers in quarter p (measured as either volume % 
          CO2 or weight % CO2).
Qp = Quarterly volume of contents supplied in all containers 
          delivered by CO2 stream u in quarter p (standard 
          cubic meters).
Dp = Quarterly CO2 density determination for 
          CO2 stream u in quarter p (metric tons per standard 
          cubic meter) if CO2,p is measured as 
          volume % CO2, or density of CO2 stream u 
          (metric tons per standard cubic meter) if CO2,p is 
          measured as weight % CO2.
p = Quarter of the year.
u = CO2 stream that delivers to containers.

    (3) To aggregate data, sum the mass of CO2 supplied in 
containers delivered by all CO2 streams in accordance with 
Equation PP-3a of this section.
where:

CO2 = Annual mass of CO2 (metric tons) supplied in 
          containers delivered by all CO2 streams.
CO2,u = Annual mass of CO2 (metric tons) supplied 
          in containers delivered by CO2 stream u.
u = CO2 stream that delivers to containers.

    (c) Importers or exporters that import or export CO2 in 
containers shall calculate the total mass of CO2 imported or 
exported in metric tons based on summing the mass in each CO2 
container using weigh bills, scales, or load cells according to Equation 
PP-4 of this section.
[GRAPHIC] [TIFF OMITTED] TR17DE10.014

where:

CO2 = Annual mass of CO2 (metric tons).
Q = Annual mass in all CO2 containers imported or exported 
          during the reporting year (metric tons).

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79169, Dec. 17, 2010; 
78 FR 71977, Nov. 29, 2013]



Sec. 98.424  Monitoring and QA/QC requirements.

    (a) Determination of quantity. (1) Reporters following the 
procedures in Sec. 98.423(a) shall determine quantity using a flow 
meter or meters located in accordance with this paragraph.
    (i) If the CO2 stream is segregated such that only a 
portion is captured for commercial application or for injection, you 
must locate the flow meter according to the following:
    (A) For reporters following the procedures in Sec. 98.423(a)(3)(i), 
you must locate the flow meter(s) after the point of segregation.
    (B) For reporters following the procedures in paragraph (a)(3)(ii) 
of Sec. 98.423, you must locate the main flow meter(s) on the captured 
CO2 stream(s) prior to the point of segregation and the 
subsequent flow meter(s) on the CO2 stream(s) for on-site use 
after the point of segregation. You may only follow the procedures in 
paragraph (a)(3)(ii) of Sec. 98.423 if the CO2 stream(s) for 
on-site use is/are the only diversion(s) from the main, captured 
CO2 stream(s) after the main flow meter location(s).

[[Page 1045]]

    (ii) Reporters that have a mass flow meter or volumetric flow meter 
installed to measure the flow of a CO2 stream that meets the 
requirements of paragraph (a)(1)(i) of this section shall base 
calculations in Sec. 98.423 of this subpart on the installed mass flow 
or volumetric flow meters.
    (iii) Reporters that do not have a mass flow meter or volumetric 
flow meter installed to measure the flow of the CO2 stream 
that meets the requirements of paragraph (a)(1)(i) of this section shall 
base calculations in Sec. 98.423 of this subpart on the flow of gas 
transferred off site using a mass flow meter or a volumetric flow meter 
located at the point of off-site transfer.
    (2) Reporters following the procedures in paragraph (b) of Sec. 
98.423 shall determine quantity in accordance with this paragraph.
    (i) Reporters that supply CO2 in containers using weigh 
bills, scales, or load cells shall measure the mass of contents of each 
CO2 container to which the CO2 stream is 
delivered, sum the mass of contents supplied in all containers to which 
the CO2 stream is delivered during each quarter, sample the 
CO2 stream delivering CO2 to containers on a 
quarterly basis to determine the composition of the CO2 
stream, and apply Equation PP-1.
    (ii) Reporters that supply CO2 in containers using loaded 
container volumes shall measure the volume of contents of each 
CO2 container to which the CO2 stream is 
delivered, sum the volume of contents supplied in all containers to 
which the CO2 stream is delivered during each quarter, sample 
the CO2 stream on a quarterly basis to determine the 
composition of the CO2 stream, determine the density 
quarterly, and apply Equation PP-2.
    (3) Importers or exporters that import or export CO2 in 
containers shall measure the mass in each CO2 container using 
weigh bills, scales, or load cells and sum the mass in all containers 
imported or exported during the reporting year.
    (4) All flow meters, scales, and load cells used to measure 
quantities that are reported in Sec. 98.423 of this subpart shall be 
operated and calibrated according to the following procedure:
    (i) You shall use an appropriate standard method published by a 
consensus-based standards organization if such a method exists. 
Consensus-based standards organizations include, but are not limited to, 
the following: ASTM International, the American National Standards 
Institute (ANSI), the American Gas Association (AGA), the American 
Society of Mechanical Engineers (ASME), the American Petroleum Institute 
(API), and the North American Energy Standards Board (NAESB).
    (ii) Where no appropriate standard method developed by a consensus-
based standards organization exists, you shall follow industry standard 
practices.
    (iii) You must ensure that any flow meter calibrations performed are 
NIST traceable.
    (5) Reporters using Equation PP-2 of this subpart and measuring 
CO2 concentration as weight % CO2 shall determine 
the density of the CO2 stream on a quarterly basis in order 
to calculate the mass of the CO2 stream according to one of 
the following procedures:
    (i) You may use a method published by a consensus-based standards 
organization. Consensus-based standards organizations include, but are 
not limited to, the following: ASTM International (100 Barr Harbor 
Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, 
(800) 262-1373, http://www.astm.org), the American National Standards 
Institute (ANSI, 1819 L Street, NW., 6th floor, Washington, DC 20036, 
(202) 293-8020, http://www.ansi.org), the American Gas Association (AGA, 
400 North Capitol Street, NW., 4th Floor, Washington, DC 20001, (202) 
824-7000, http://www.aga.org), the American Society of Mechanical 
Engineers (ASME, Three Park Avenue, New York, NY 10016-5990, (800) 843-
2763, http://www.asme.org), the American Petroleum Institute (API, 1220 
L Street, NW., Washington, DC 20005-4070, (202) 682-8000, http://
www.api.org), and the North American Energy Standards Board (NAESB, 801 
Travis Street, Suite 1675, Houston, TX 77002, (713) 356-0060, http://
www.api.org). The method(s) used shall be documented in the Monitoring 
Plan required under Sec. 98.3(g)(5).

[[Page 1046]]

    (ii) You may follow an industry standard method.
    (b) Determination of concentration. (1) Reporters using Equation PP-
1 or PP-2 of this subpart shall sample the CO2 stream on a 
quarterly basis to determine the composition of the CO2 
stream.
    (2) Methods to measure the composition of the CO2 stream 
must conform to applicable chemical analytical standards. Acceptable 
methods include, but are not limited to, the U.S. Food and Drug 
Administration food-grade specifications for CO2 (see 21 CFR 
184.1240) and ASTM standard E1747-95 (Reapproved 2005) Standard Guide 
for Purity of Carbon Dioxide Used in Supercritical Fluid Applications 
(ASTM International, 100 Barr Harbor Drive, P.O. Box CB700, West 
Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373, http://
www.astm.org).
    (c) You shall convert the density of the CO2 stream(s) 
and all measured volumes of carbon dioxide to the following standard 
industry temperature and pressure conditions: Standard cubic meters at a 
temperature of 60 degrees Fahrenheit and at an absolute pressure of 1 
atmosphere. If you apply the density value for CO2 at 
standard conditions, you must use 0.001868 metric tons per standard 
cubic meter.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79170, Dec. 17, 2010]



Sec. 98.425  Procedures for estimating missing data.

    (a) Whenever the quality assurance procedures in Sec. 98.424(a)(1) 
of this subpart cannot be followed to measure quarterly mass flow or 
volumetric flow of CO2, the most appropriate of the following 
missing data procedures shall be followed:
    (1) A quarterly CO2 mass flow or volumetric flow value 
that is missing may be substituted with a quarterly value measured 
during another quarter of the current reporting year.
    (2) A quarterly CO2 mass flow or volumetric flow value 
that is missing may be substituted with a quarterly value measured 
during the same quarter from the past reporting year.
    (3) If a mass or volumetric flow meter is installed to measure the 
CO2 stream, you may substitute data from a mass or volumetric 
flow meter measuring the CO2 stream transferred for any 
period during which the installed meter is inoperable.
    (4) The mass or volumetric flow used for purposes of product 
tracking and billing according to the reporter's established procedures 
may be substituted for any period during which measurement equipment is 
inoperable.
    (b) Whenever the quality assurance procedures in Sec. 98.424(b) of 
this subpart cannot be followed to determine concentration of the 
CO2 stream, the most appropriate of the following missing 
data procudures shall be followed:
    (1) A quarterly concentration value that is missing may be 
substituted with a quarterly value measured during another quarter of 
the current reporting year.
    (2) A quarterly concentration value that is missing may be 
substituted with a quarterly value measured during the same quarter from 
the previous reporting year.
    (3) The concentration used for purposes of product tracking and 
billing according to the reporter's established procedures may be 
substituted for any quarterly value.
    (c) Missing data on density of the CO2 stream shall be 
substituted with quarterly or annual average values from the previous 
calendar year.
    (d) Whenever the quality assurance procedures in Sec. 98.424(a)(2) 
of this subpart cannot be followed to measure quarterly quantity of 
CO2 in containers, the most appropriate of the following 
missing data procedures shall be followed:
    (1) A quarterly quantity of CO2 in containers that is 
missing may be substituted with a quarterly value measured during 
another representative quarter of the current reporting year.
    (2) A quarterly quantity of CO2 in containers that is 
missing may be substituted with a quarterly value measured during the 
same quarter from the past reporting year.
    (3) The quarterly quantity of CO2 in containers recorded 
for purposes of product tracking and billing according to the reporter's 
established procedures

[[Page 1047]]

may be substituted for any period during which measurement equipment is 
inoperable.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79171, Dec. 17, 2010]



Sec. 98.426  Data reporting requirements.

    In addition to the information required by Sec. 98.3(c) of subpart 
A of this part, the annual report shall contain the following 
information, as applicable:
    (a) If you use Equation PP-1 of this subpart, report the following 
information for each mass flow meter or CO2 stream that 
delivers CO2 to containers:
    (1) Annual mass in metric tons of CO2.
    (2) Quarterly mass in metric tons of CO2.
    (3) Quarterly concentration of the CO2 stream.
    (4) The standard used to measure CO2 concentration.
    (5) The location of the flow meter in your process chain in relation 
to the points of CO2 stream capture, dehydration, 
compression, and other processing.
    (b) If you use Equation PP-2 of this subpart, report the following 
information for each volumetric flow meter or CO2 stream that 
delivers CO2 to containers:
    (1) Annual mass in metric tons of CO2.
    (2) Quarterly volume in standard cubic meters of CO2.
    (3) Quarterly concentration of the CO2 stream in volume 
or weight percent.
    (4) Report density as follows:
    (i) Quarterly density of the CO2 stream in metric tons 
per standard cubic meter if you report the concentration of the 
CO2 stream in paragraph (b)(3) of this section in weight 
percent.
    (ii) Quarterly density of CO2 in metric tons per standard 
cubic meter if you report the concentration of the CO2 stream 
in paragraph (b)(3) of this section in volume percent.
    (5) The method used to measure density.
    (6) The standard used to measure CO2 concentration.
    (7) The location of the flow meter in your process chain in relation 
to the points of CO2 stream capture, dehydration, 
compression, and other processing.
    (c) For the aggregated annual mass of CO2 emissions 
calculated using Equation PP-3a or PP-3b, report the following:
    (1) If you use Equation PP-3a of this subpart, report the annual 
CO2 mass in metric tons from all flow meters and 
CO2 streams that deliver CO2 to containers.
    (2) If you use Equation PP-3b of this subpart, report:
    (i) The total annual CO2 mass through main flow meter(s) 
in metric tons.
    (ii) The total annual CO2 mass through subsequent flow 
meter(s) in metric tons.
    (iii) The total annual CO2 mass supplied in metric tons.
    (iv) The location of each flow meter in relation to the point of 
segregation.
    (d) If you use Equation PP-4 of this subpart, report at the 
corporate level the annual mass of CO2 in metric tons in all 
CO2 containers that are imported or exported.
    (e) Each reporter shall report the following information:
    (1) The type of equipment used to measure the total flow of the 
CO2 stream or the total mass or volume in CO2 
containers.
    (2) The standard used to operate and calibrate the equipment 
reported in (e)(1) of this section.
    (3) The number of days in the reporting year for which substitute 
data procedures were used for the following purpose:
    (i) To measure quantity.
    (ii) To measure concentration.
    (iii) To measure density.
    (f) Report the aggregated annual quantity of CO2 in 
metric tons that is transferred to each of the following end use 
applications, if known:
    (1) Food and beverage.
    (2) Industrial and municipal water/wastewater treatment.
    (3) Metal fabrication, including welding and cutting.
    (4) Greenhouse uses for plant growth.
    (5) Fumigants (e.g., grain storage) and herbicides.
    (6) Pulp and paper.
    (7) Cleaning and solvent use.

[[Page 1048]]

    (8) Fire fighting.
    (9) Transportation and storage of explosives.
    (10) Injection of carbon dioxide for enhanced oil and natural gas 
recovery that is covered by subpart UU of this part.
    (11) Geologic sequestration of carbon dioxide that is covered by 
subpart RR of this part.
    (12) Research and development.
    (13) Other.
    (g) Each production process unit that captures a CO2 
stream for purposes of supplying CO2 for commercial 
applications or in order to sequester or otherwise inject it underground 
when custody of the CO2 is maintained shall report the 
percentage of that stream, if any, that is biomass-based during the 
reporting year.
    (h) If you capture a CO2 stream from an electricity 
generating unit that is subject to subpart D of this part and transfer 
CO2 to any facilities that are subject to subpart RR of this 
part, you must:
    (1) Report the facility identification number associated with the 
annual GHG report for the subpart D facility;
    (2) Report each facility identification number associated with the 
annual GHG reports for each subpart RR facility to which CO2 
is transferred; and
    (3) Report the annual quantity of CO2 in metric tons that 
is transferred to each subpart RR facility.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79171, Dec. 17, 2010; 
78 FR 71977, Nov. 29, 2013; 80 FR 64660, Oct. 23, 2015]



Sec. 98.427  Records that must be retained.

    In addition to the records required by Sec. 98.3(g) of subpart A of 
this part, you must retain the records specified in paragraphs (a) 
through (c) of this section, as applicable.
    (a) The owner or operator of a facility containing production 
process units must retain quarterly records of captured or transferred 
CO2 streams and composition.
    (b) The owner or operator of a CO2 production well 
facility must maintain quarterly records of the mass flow or volumetric 
flow of the extracted or transferred CO2 stream and 
concentration and density if volumetric flow meters are used.
    (c) Importers or exporters of CO2 must retain annual 
records of the mass flow, volumetric flow, and mass of CO2 
imported or exported.
    (d) Facilities subject to Sec. 98.426(h) must retain records of 
CO2 in metric tons that is transferred to each subpart RR 
facility.

[74 FR 56374, Oct. 30, 2009, as amended at 80 FR 64660, Oct. 23, 2015]



Sec. 98.428  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.



   Subpart QQ_Importers and Exporters of Fluorinated Greenhouse Gases 
         Contained in Pre-Charged Equipment or Closed-Cell Foams

    Source: 75 FR 74856, Dec. 1, 2010, unless otherwise noted.



Sec. 98.430  Definition of the source category.

    (a) The source category, importers and exporters of fluorinated GHGs 
contained in pre-charged equipment or closed-cell foams, consists of any 
entity that imports or exports pre-charged equipment that contains a 
fluorinated GHG, and any entity that imports or exports closed-cell 
foams that contain a fluorinated GHG.



Sec. 98.431  Reporting threshold.

    Any importer or exporter of fluorinated GHGs contained in pre-
charged equipment or closed-cell foams who meets the requirements of 
Sec. 98.2(a)(4) must report each fluorinated GHG contained in the 
imported or exported pre-charged equipment or closed-cell foams.



Sec. 98.432  GHGs to report.

    You must report the mass of each fluorinated GHG contained in pre-
charged equipment or closed-cell foams that you import or export during 
the calendar year. For imports and exports of closed-cell foams where 
you do not know the identity and mass of the

[[Page 1049]]

fluorinated GHG, you must report the mass of fluorinated GHG in 
CO2e.



Sec. 98.433  Calculating GHG contained in pre-charged equipment
or closed-cell foams.

    (a) The total mass of each fluorinated GHG imported and exported 
inside equipment or foams must be estimated using Equation QQ-1 of this 
section:
[GRAPHIC] [TIFF OMITTED] TR01DE10.054


where:

I = Total mass of the fluorinated GHG imported or exported annually 
          (metric tons).
t = Equipment/foam type containing the fluorinated GHG.
St = Mass of fluorinated GHG per unit of equipment type t or 
          foam type t (charge per piece of equipment, kg) or density of 
          fluorinated GHG in foam (charge per cubic foot of foam, kg per 
          cubic foot).
Nt = Number of units of equipment type t or foam type t 
          imported or exported annually (pieces of equipment or cubic 
          feet of foam).
0.001 = Factor converting kg to metric tons.

    (b) When the identity and mass of fluorinated GHGs in a closed-cell 
foam is unknown to the importer or exporter, the total mass in 
CO2e for the fluorinated GHGs imported and exported inside 
closed-cell foams must be estimated using Equation QQ-2 of this section:
[GRAPHIC] [TIFF OMITTED] TR01DE10.055


where:

I = Total mass in CO2e of the fluorinated GHGs imported or 
          exported in close-cell foams annually (metric tons).
t = Equipment/foam type containing the fluorinated GHG.
St = Mass in CO2e of the fluorinated GHGs per unit 
          of equipment type t or foam type t (charge per piece of 
          equipment, kg) or density of fluorinated GHG in foam 
          (CO2e per cubic foot of foam, kg CO2e 
          per cubic foot).
Nt = Number of units of equipment type t or foam type t 
          imported or exported annually (pieces of equipment or cubic 
          feet of foam).
0.001 = Factor converting kg to metric tons.

[74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71978, Nov. 29, 2013]



Sec. 98.434  Monitoring and QA/QC requirements.

    (a) For calendar year 2011 monitoring, you may follow the provisions 
of Sec. 98.3(d)(1) through (d)(2) for best available monitoring methods 
rather than follow the monitoring requirements of this section. For 
purposes of this subpart, any reference in Sec. 98.3(d)(1) through 
(d)(2) to the year 2010 means 2011, to March 31 means June 30, and to 
April 1 means July 1. Any reference to the effective date or date of 
promulgation in Sec. 98.3(d)(1) through (d)(2) means February 28, 2011.
    (b) The inputs to the annual submission must be reviewed against the 
import or export transaction records to ensure that the information 
submitted to EPA is being accurately transcribed as the correct chemical 
or blend in the correct pre-charged equipment or closed-cell foam in the 
correct quantities and units.

[74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71978, Nov. 29, 2013]



Sec. 98.435  Procedures for estimating missing data.

    Procedures for estimating missing data are not provided for 
importers and exporters of fluorinated GHGs contained in pre-charged 
equipment or

[[Page 1050]]

closed-cell foams. A complete record of all measured parameters used in 
tracking fluorinated GHGs contained in pre-charged equipment or closed-
cell foams is required.



Sec. 98.436  Data reporting requirements.

    (a) Each importer of fluorinated GHGs contained in pre-charged 
equipment or closed-cell foams must submit an annual report that 
summarizes its imports at the corporate level, except for 
transshipments, as specified:
    (1) Total mass in metric tons of each fluorinated GHG imported in 
pre-charged equipment or closed-cell foams.
    (2) For each type of pre-charged equipment with a unique combination 
of charge size and charge type, the identity of the fluorinated GHG used 
as a refrigerant or electrical insulator, charge size (holding charge, 
if applicable), and number imported.
    (3) For closed-cell foams that are imported inside of equipment, the 
identity of the fluorinated GHG contained in the foam, the mass of the 
fluorinated GHG contained in the foam in each piece of equipment, and 
the number of pieces of equipment imported with each unique combination 
of mass and identity of fluorinated GHG within the closed-cell foams.
    (4) For closed cell-foams that are not imported inside of equipment, 
the identity of the fluorinated GHG in the foam, the density of the 
fluorinated GHG in the foam (kg fluorinated GHG/cubic foot), and the 
volume of foam imported (cubic feet) for each type of closed-cell foam 
with a unique combination of fluorinated GHG density and identity.
    (5) Dates on which the pre-charged equipment or closed-cell foams 
were imported.
    (6) If the importer does not know the identity and mass of the 
fluorinated GHGs within the closed-cell foam, the importer must report 
the following:
    (i) Total mass in metric tons of CO2e of the fluorinated 
GHGs imported in closed-cell foams.
    (ii) For closed-cell foams that are imported inside of equipment, 
the mass of the fluorinated GHGs in CO2e contained in the 
foam in each piece of equipment and the number of pieces of equipment 
imported for each equipment type.
    (iii) For closed-cell foams that are not imported inside of 
equipment, the density in CO2e of the fluorinated GHGs in the 
foam (kg CO2e/cubic foot) and the volume of foam imported 
(cubic feet) for each type of closed-cell foam.
    (iv) Dates on which the closed-cell foams were imported.
    (v) Name of the foam manufacturer for each type of closed-cell foam 
where the identity and mass of the fluorinated GHGs is unknown.
    (vi) Certification that the importer was unable to obtain 
information on the identity and mass of the fluorinated GHGs within the 
closed-cell foam from the closed-cell foam manufacturer or 
manufacturers.
    (b) Each exporter of fluorinated GHGs contained in pre-charged 
equipment or closed-cell foams must submit an annual report that 
summarizes its exports at the corporate level, except for 
transshipments, as specified:
    (1) Total mass in metric tons of each fluorinated GHG exported in 
pre-charged equipment or closed-cell foams.
    (2) For each type of pre-charged equipment with a unique combination 
of charge size and charge type, the identity of the fluorinated GHG used 
as a refrigerant or electrical insulator, charge size (including holding 
charge, if applicable), and number exported.
    (3) For closed-cell foams that are exported inside of equipment, the 
identity of the fluorinated GHG contained in the foam in each piece of 
equipment, the mass of the fluorinated GHG contained in the foam in each 
piece of equipment, and the number of pieces of equipment exported with 
each unique combination of mass and identity of fluorinated GHG within 
the closed-cell foams.
    (4) For closed-cell foams that are not exported inside of equipment, 
the identity of the fluorinated GHG in the foam, the density of the 
fluorinated GHG in the foam (kg fluorinated GHG/cubic foot), and the 
volume of foam exported (cubic feet) for each type of closed-cell foam 
with a unique combination of fluorinated GHG density and identity.

[[Page 1051]]

    (5) Dates on which the pre-charged equipment or closed-cell foams 
were exported.
    (6) If the exporter does not know the identity and mass of the 
fluorinated GHG within the closed-cell foam, the exporter must report 
the following:
    (i) Total mass in metric tons of CO2e of the fluorinated 
GHGs exported in closed-cell foams.
    (ii) For closed-cell foams that are exported inside of equipment, 
the mass of the fluorinated GHGs in CO2e contained in the 
foam in each piece of equipment and the number of pieces of equipment 
imported for each equipment type.
    (iii) For closed-cell foams that are not exported inside of 
equipment, the density in CO2e of the fluorinated GHGs in the 
foam (kg CO2 e/cubic foot) and the volume of foam imported 
(cubic feet) for each type of closed-cell foam.
    (iv) Dates on which the closed-cell foams were exported.
    (v) Name of the foam manufacturer for each type of closed-cell foam 
where the identity and mass of the fluorinated GHGg is unknown.
    (vi) Certification that the exporter was unable to obtain 
information on the identity and mass of the fluorinated GHGs within the 
closed-cell foam from the closed-cell foam manufacturer or 
manufacturers.

[74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71978, Nov. 29, 2013]



Sec. 98.437  Records that must be retained.

    (a) In addition to the data required by Sec. 98.3(g), importers of 
fluorinated GHGs in pre-charged equipment and closed-cell foams must 
retain the following records substantiating each of the imports that 
they report:
    (1) A copy of the bill of lading for the import.
    (2) The invoice for the import.
    (3) The U.S. Customs entry form.
    (4) Ports of entry through which the pre-charged equipment or 
closed-cell foams passed.
    (5) Countries from which the pre-charged equipment or closed-cell 
foams were imported.
    (6) For importers that report the mass of fluorinated GHGs within 
closed-cell foams on a CO2e basis, correspondence or other 
documents that show the importer was unable to obtain information on the 
identity and mass of fluorinated GHG within closed-cell foams from the 
foam manufacturer.
    (b) In addition to the data required by Sec. 98.3(g), exporters of 
fluorinated GHGs in pre-charged equipment and closed-cell foams must 
retain the following records substantiating each of the exports that 
they report:
    (1) A copy of the bill of lading for the export and
    (2) The invoice for the export.
    (3) Ports of exit through which the pre-charged equipment or closed-
cell foams passed.
    (4) Countries to which the pre-charged equipment or closed-cell 
foams were exported.
    (5) For exporters that report the mass of fluorinated GHGs within 
closed-cell foams on a CO2e basis, correspondence or other 
documents that show the exporter was unable to obtain information on the 
identity and mass of fluorinated GHG within closed-cell foams from the 
foam manufacturer.
    (c) For importers and exports of fluorinated GHGs inside pre-charged 
equipment and closed-cell foams, the GHG Monitoring Plans, as described 
in Sec. 98.3(g)(5), must be completed by April 1, 2011.
    (d) Persons who transship pre-charged equipment and closed-cell 
foams containing fluorinated GHGs must maintain records that indicated 
that the pre-charged equipment or foam originated in a foreign country 
and was destined for another foreign country and did not enter into 
commerce in the United States.



Sec. 98.438  Definitions.

    Except as provided in this section, all of the terms used in this 
subpart have the same meaning given in the Clean Air Act and subpart A 
of this part. If a conflict exists between a definition provided in this 
subpart and a definition provided in subpart A, the definition in this 
subpart must take precedence for the reporting requirements in this 
subpart.

[[Page 1052]]

    Appliance means any device which contains and uses a fluorinated 
greenhouse gas refrigerant and which is used for household or commercial 
purposes, including any air conditioner, refrigerator, chiller, or 
freezer.
    Closed-cell foam means any foam product, excluding packaging foam, 
that is constructed with a closed-cell structure and a blowing agent 
containing a fluorinated GHG. Closed-cell foams include but are not 
limited to polyurethane (PU) foam contained in equipment, PU continuous 
and discontinuous panel foam, PU one component foam, PU spray foam, 
extruded polystyrene (XPS) boardstock foam, and XPS sheet foam. 
Packaging foam means foam used exclusively during shipment or storage to 
temporarily enclose items.
    Electrical equipment means gas-insulated substations, circuit 
breakers, other switchgear, gas-insulated lines, or power transformers.
    Fluorinated GHG refrigerant means, for purposes of this subpart, any 
substance consisting in part or whole of a fluorinated greenhouse gas 
and that is used for heat transfer purposes and provides a cooling 
effect.
    Pre-charged appliance means any appliance charged with fluorinated 
greenhouse gas refrigerant prior to sale or distribution or offer for 
sale or distribution in interstate commerce. This includes both 
appliances that contain the full charge necessary for operation and 
appliances that contain a partial ``holding'' charge of the fluorinated 
greenhouse gas refrigerant (e.g., for shipment purposes).
    Pre-charged appliance component means any portion of an appliance, 
including but not limited to condensers, compressors, line sets, and 
coils, that is charged with fluorinated greenhouse gas refrigerant prior 
to sale or distribution or offer for sale or distribution in interstate 
commerce.
    Pre-charged electrical equipment means any electrical equipment, 
including but not limited to gas-insulated substations, circuit 
breakers, other switchgear, gas-insulated lines, or power transformers 
containing a fluorinated GHG prior to sale or distribution, or offer for 
sale or distribution in interstate commerce. This includes both 
equipment that contain the full charge necessary for operation and 
equipment that contain a partial ``holding'' charge of the fluorinated 
GHG (e.g., for shipment purposes).
    Pre-charged electrical equipment component means any portion of 
electrical equipment that is charged with a fluorinated greenhouse gas 
prior to sale or distribution or offer for sale or distribution in 
interstate commerce.
    Pre-charged equipment means any pre-charged appliance, pre-charged 
appliance component, pre-charged electrical equipment, or pre-charged 
electrical equipment component.

[74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71978, Nov. 29, 2013]



           Subpart RR_Geologic Sequestration of Carbon Dioxide

    Source: 75 FR 75078, Dec. 1, 2010, unless otherwise noted.



Sec. 98.440  Definition of the source category.

    (a) The geologic sequestration of carbon dioxide (CO2) 
source category comprises any well or group of wells that inject a 
CO2 stream for long-term containment in subsurface geologic 
formations.
    (b) This source category includes all wells permitted as Class VI 
under the Underground Injection Control program.
    (c) This source category does not include a well or group of wells 
where a CO2 stream is being injected in subsurface geologic 
formations to enhance the recovery of oil or natural gas unless one of 
the following applies:
    (1) The owner or operator injects the CO2 stream for 
long-term containment in subsurface geologic formations and has chosen 
to submit a proposed monitoring, reporting, and verification (MRV) plan 
to EPA and received an approved plan from EPA.
    (2) The well is permitted as Class VI under the Underground 
Injection Control program.
    (d) Exemption for research and development projects. Research and 
development projects shall receive an exemption from reporting under 
this subpart

[[Page 1053]]

for the duration of the research and development activity.
    (1) Process for obtaining an exemption. If you are a research and 
development project, you must submit the information in paragraph (d)(2) 
of this section to EPA by the time you would be otherwise required to 
submit an MRV plan under Sec. 98.448. EPA will use this information to 
verify that the project is a research and development project.
    (2) Content of submission. A submission in support of an exemption 
as a research and development project must contain the following 
information:
    (i) The planned duration of CO2 injection for the 
project.
    (ii) The planned annual CO2 injection volumes during this 
time period.
    (iii) The research purposes of the project.
    (iv) The source and type of funding for the project.
    (v) The class and duration of Underground Injection Control permit 
or, for an offshore facility not subject to the Safe Drinking Water Act, 
a description of the legal instrument authorizing geologic 
sequestration.
    (3) Determination by the Administrator.
    (i) The Administrator shall determine if a project meets the 
definition of research and development project within 60 days of receipt 
of the submission of a request for exemption. In making this 
determination, the Administrator shall take into account any information 
you submit demonstrating that the planned duration of CO2 
injection for the project and the planned annual CO2 
injection volumes during the duration of the project are consistent with 
the purpose of the research and development project.
    (ii) Any appeal of the Administrator's determination is subject to 
the provisions of part 78 of this chapter.
    (iii) A project that the Administrator determines is not eligible 
for an exemption as a research and development project must submit a 
proposed MRV plan to EPA within 180 days of the Administrator's 
determination. You may request one extension of up to an additional 180 
days in which to submit the proposed MRV plan.



Sec. 98.441  Reporting threshold.

    (a) You must report under this subpart if any well or group of wells 
within your facility injects any amount of CO2 for long-term 
containment in subsurface geologic formations. There is no threshold.
    (b) Request for discontinuation of reporting. The requirements of 
Sec. 98.2(i) do not apply to this subpart. Once a well or group of 
wells is subject to the requirements of this subpart, the owner or 
operator must continue for each year thereafter to comply with all 
requirements of this subpart, including the requirement to submit annual 
reports, until the Administrator has issued a final decision on an owner 
or operator's request to discontinue reporting.
    (1) Timing of request. The owner or operator of a facility may 
submit a request to discontinue reporting any time after the well or 
group of wells is plugged and abandoned in accordance with applicable 
requirements.
    (2) Content of request. A request for discontinuation of reporting 
must contain either paragraph (b)(2)(i) or (b)(2)(ii) of this section.
    (i) For wells permitted as Class VI under the Underground Injection 
Control program, a copy of the applicable Underground Injection Control 
program Director's authorization of site closure.
    (ii) For all other wells, and as an alternative for wells permitted 
as Class VI under the Underground Injection Control program, a 
demonstration that current monitoring and model(s) show that the 
injected CO2 stream is not expected to migrate in the future 
in a manner likely to result in surface leakage.
    (3) Notification. The Administrator will issue a final decision on 
the request to discontinue reporting within a reasonable time. Any 
appeal of the Administrator's final decision is subject to the 
provisions of part 78 of this chapter.



Sec. 98.442  GHGs to report.

    You must report:
    (a) Mass of CO2 received.
    (b) Mass of CO2 injected into the subsurface.
    (c) Mass of CO2 produced.

[[Page 1054]]

    (d) Mass of CO2 emitted by surface leakage.
    (e) Mass of CO2 emissions from equipment leaks and vented 
emissions of CO2 from surface equipment located between the 
injection flow meter and the injection wellhead.
    (f) Mass of CO2 emissions from equipment leaks and vented 
emissions of CO2 from surface equipment located between the 
production flow meter and the production wellhead.
    (g) Mass of CO2 sequestered in subsurface geologic 
formations.
    (h) Cumulative mass of CO2 reported as sequestered in 
subsurface geologic formations in all years since the facility became 
subject to reporting requirements under this subpart.

[75 FR 75078, Dec. 1, 2010, as amended at 76 FR 73905, Nov. 29, 2011]



Sec. 98.443  Calculating CO[bdi2] geologic sequestration.

    You must calculate the mass of CO2 received using 
CO2 received equations (Equations RR-1 to RR-3 of this 
section), unless you follow the procedures in Sec. 98.444(a)(4). You 
must calculate CO2 sequestered using injection equations 
(Equations RR-4 to RR-6 of this section), production/recycling equations 
(Equations RR-7 to RR-9 of this section), surface leakage equations 
(Equation RR-10 of this section), and sequestration equations (Equations 
RR-11 and RR-12 of this section). For your first year of reporting, you 
must calculate CO2 sequestered starting from the date set 
forth in your approved MRV plan.
    (a) You must calculate and report the annual mass of CO2 
received by pipeline using the procedures in paragraphs (a)(1) or (a)(2) 
of this section and the procedures in paragraph (a)(3) of this section, 
if applicable.
    (1) For a mass flow meter, you must calculate the total annual mass 
of CO2 in a CO2 stream received in metric tons by 
multiplying the mass flow by the CO2 concentration in the 
flow, according to Equation RR-1 of this section. You must collect these 
data quarterly. Mass flow and concentration data measurements must be 
made in accordance with Sec. 98.444.
[GRAPHIC] [TIFF OMITTED] TR01DE10.172

where:

CO2T,r = Net annual mass of CO2 received through 
          flow meter r (metric tons).
Qr,p = Quarterly mass flow through a receiving flow meter r 
          in quarter p (metric tons).
Sr,p = Quarterly mass flow through a receiving flow meter r 
          that is redelivered to another facility without being injected 
          into your well in quarter p (metric tons).
CCO2,p,r = Quarterly CO2 concentration measurement 
          in flow for flow meter r in quarter p (wt. percent 
          CO2, expressed as a decimal fraction).
p = Quarter of the year.
r = Receiving flow meter.

    (2) For a volumetric flow meter, you must calculate the total annual 
mass of CO2 in a CO2 stream received in metric 
tons by multiplying the volumetric flow at standard conditions by the 
CO2 concentration in the flow and the density of 
CO2 at standard conditions, according to Equation RR-2 of 
this section. You must collect these data quarterly. Volumetric flow and 
concentration data measurements must be made in accordance with Sec. 
98.444.
[GRAPHIC] [TIFF OMITTED] TR01DE10.173


[[Page 1055]]


where:

CO2T,r = Net annual mass of CO2 received through 
          flow meter r (metric tons).
Qr,p = Quarterly volumetric flow through a receiving flow 
          meter r in quarter p at standard conditions (standard cubic 
          meters).
Sr,p = Quarterly volumetric flow through a receiving flow 
          meter r that is redelivered to another facility without being 
          injected into your well in quarter p (standard cubic meters).
D = Density of CO2 at standard conditions (metric tons per 
          standard cubic meter): 0.0018682.
CCO2,p,r = Quarterly CO2 concentration measurement 
          in flow for flow meter r in quarter p (vol. percent 
          CO2, expressed as a decimal fraction).
p = Quarter of the year.
r = Receiving flow meter.

    (3) If you receive CO2 through more than one flow meter, 
you must sum the mass of all CO2 received in accordance with 
the procedure specified in Equation RR-3 of this section.
[GRAPHIC] [TIFF OMITTED] TR01DE10.174

where:

CO2 = Total net annual mass of CO2 received 
          (metric tons).
CO2T,r = Net annual mass of CO2 received (metric 
          tons) as calculated in Equation RR-1 or RR-2 for flow meter r.
r = Receiving flow meter.

    (b) You must calculate and report the annual mass of CO2 
received in containers using the procedures in paragraphs (b)(1) or 
(b)(2) of this section.
    (1) If you are measuring the mass of contents in a container under 
the provisions of Sec. 98.444(a)(2)(i), you must calculate the 
CO2 received for injection in containers using Equation RR-1 
of this section.

where:

CO2T,r = Net annual mass of CO2 received in 
          containers r (metric tons).
CCO2,p,r = Quarterly CO2 concentration measurement 
          of contents in containers r in quarter p (wt. percent 
          CO2, expressed as a decimal fraction).
Qr,p = Quarterly mass of contents in containers r in quarter 
          p (metric tons).
Sr,p = Quarterly volume of contents in containers r 
          redelivered to another facility without being injected into 
          your well in quarter p (standard cubic meters).
p = Quarter of the year.
r = Containers.

    (2) If you are measuring the volume of contents in a container under 
the provisions of Sec. 98.444(a)(2)(ii), you must calculate the 
CO2 received for injection in containers using Equation RR-2 
of this section.

where:

CO2T,r = Net annual mass of CO2 received in 
          containers r (metric tons).
CCO2,p,r = Quarterly CO2 concentration measurement 
          of contents in containers r in quarter p (vol. percent 
          CO2, expressed as a decimal fraction).
Qr,p = Quarterly volume of contents in containers r in 
          quarter p (standard cubic meters).
Sr,p = Quarterly mass of contents in containers r redelivered 
          to another facility without being injected into your well in 
          quarter p (metric tons).
D = Density of the CO2 received in containers at standard 
          conditions (metric tons per standard cubic meter):0.0018682.
p = Quarter of the year.
r = Containers.

    (c) You must report the annual mass of CO2 injected in 
accordance with the procedures specified in paragraphs (c)(1) through 
(c)(3) of this section.
    (1) If you use a mass flow meter to measure the flow of an injected 
CO2 stream, you must calculate annually the total mass of 
CO2 (in metric tons) in the CO2 stream injected 
each year in metric tons by multiplying the mass flow by the 
CO2 concentration in the flow, according to Equation RR-4 of 
this section. Mass flow and concentration data measurements must be made 
in accordance with Sec. 98.444.

[[Page 1056]]

[GRAPHIC] [TIFF OMITTED] TR01DE10.175

where:

CO2,u = Annual CO2 mass injected (metric tons) as 
          measured by flow meter u.
Qp,u = Quarterly mass flow rate measurement for flow meter u 
          in quarter p (metric tons per quarter).
CCO2,p,u = Quarterly CO2 concentration measurement 
          in flow for flow meter u in quarter p (wt. percent 
          CO2, expressed as a decimal fraction).
p = Quarter of the year.
u = Flow meter.

    (2) If you use a volumetric flow meter to measure the flow of an 
injected CO2 stream, you must calculate annually the total 
mass of CO2 (in metric tons) in the CO2 stream 
injected each year in metric tons by multiplying the volumetric flow at 
standard conditions by the CO2 concentration in the flow and 
the density of CO2 at standard conditions, according to 
Equation RR-5 of this section. Volumetric flow and concentration data 
measurements must be made in accordance with Sec. 98.444.
[GRAPHIC] [TIFF OMITTED] TR01DE10.176

where:

CO2,u = Annual CO2 mass injected (metric tons) as 
          measured by flow meter u.
Qp,u = Quarterly volumetric flow rate measurement for flow 
          meter u in quarter p at standard conditions (standard cubic 
          meters per quarter).
D = Density of CO2 at standard conditions (metric tons per 
          standard cubic meter): 0.0018682.
CCO2,p,u = CO2 concentration measurement in flow 
          for flow meter u in quarter p (vol. percent CO2, 
          expressed as a decimal fraction).
p = Quarter of the year.
u = Flow meter.

    (3) To aggregate injection data for all wells covered under this 
subpart, you must sum the mass of all CO2 injected through 
all injection wells in accordance with the procedure specified in 
Equation RR-6 of this section.
[GRAPHIC] [TIFF OMITTED] TR01DE10.177

where:

CO2. = Total annual CO2 mass injected (metric 
          tons) through all injection wells.
CO2,u = Annual CO2 mass injected (metric tons) as 
          measured by flow meter u.
u = Flow meter.

    (d) You must calculate the annual mass of CO2 produced 
from oil or gas production wells or from other fluid wells for each 
separator that sends a stream of gas into a recycle or end use system in 
accordance with the procedures specified in paragraphs (d)(1) through 
(d)(3) of this section. You must account for any CO2 that is 
produced and not processed through a separator. You must account only 
for wells that produce the CO2 that was injected into the 
well or wells covered by this source category.
    (1) For each gas-liquid separator for which flow is measured using a 
mass flow meter, you must calculate annually the total mass of 
CO2 produced from an oil or other fluid stream in metric tons 
that is separated from the fluid by multiplying the mass gas flow by the 
CO2 concentration in the gas

[[Page 1057]]

flow, according to Equation RR-7 of this section. You must collect these 
data quarterly. Mass flow and concentration data measurements must be 
made in accordance with Sec. 98.444.
[GRAPHIC] [TIFF OMITTED] TR01DE10.178

Where:

CO2,w = Annual CO2 mass produced (metric tons) 
          through separator w.
Qp,w = Quarterly gas mass flow rate measurement for separator 
          w in quarter p (metric tons).
CCO2,p,w = Quarterly CO2 concentration measurement 
          in flow for separator w in quarter p (wt. percent 
          CO2, expressed as a decimal fraction).
p = Quarter of the year.
w = Separator.

    (2) For each gas-liquid separator for which flow is measured using a 
volumetric flow meter, you must calculate annually the total mass of 
CO2 produced from an oil or other fluid stream in metric tons 
that is separated from the fluid by multiplying the volumetric gas flow 
at standard conditions by the CO2 concentration in the gas 
flow and the density of CO2 at standard conditions, according 
to Equation RR-8 of this section. You must collect these data quarterly. 
Volumetric flow and concentration data measurements must be made in 
accordance with Sec. 98.444.
[GRAPHIC] [TIFF OMITTED] TR01DE10.179

Where:

CO2,w = Annual CO2 mass produced (metric tons) 
          through separator w.
Qp,w = Volumetric gas flow rate measurement for separator w 
          in quarter p at standard conditions (standard cubic meters).
D = Density of CO2 at standard conditions (metric tons per 
          standard cubic meter): 0.0018682.
CCO2,p,w = CO2 concentration measurement in flow 
          for separator w in quarter p (vol. percent CO2, 
          expressed as a decimal fraction).
p = Quarter of the year.
w = Separator.

    (3) To aggregate production data, you must sum the mass of all of 
the CO2 separated at each gas-liquid separator in accordance 
with the procedure specified in Equation RR-9 of this section. You must 
assume that the total CO2 measured at the separator(s) 
represents a percentage of the total CO2 produced. In order 
to account for the percentage of CO2 produced that is 
estimated to remain with the produced oil or other fluid, you must 
multiply the quarterly mass of CO2 measured at the 
separator(s) by a percentage estimated using a methodology in your 
approved MRV plan. If fluids containing CO2 from injection 
wells covered under this source category are produced and not processed 
through a gas-liquid separator, the concentration of CO2 in 
the produced fluids must be measured at a flow meter located prior to 
reinjection or reuse using methods in Sec. 98.444(f)(1). The 
considerations you intend to use to calculate CO2 from 
produced fluids for the mass balance equation must be described in your 
approved MRV plan in accordance with Sec. 98.448(a)(5).

[[Page 1058]]

[GRAPHIC] [TIFF OMITTED] TR29NO11.003

Where:

CO2. = Total annual CO2 mass produced (metric 
          tons) through all separators in the reporting year.
CO2,w = Annual CO2 mass produced (metric tons) 
          through separator w in the reporting year.
X = Entrained CO2 in produced oil or other fluid divided by 
          the CO2 separated through all separators in the 
          reporting year (weight percent CO2, expressed as a 
          decimal fraction).
w = Separator.

    (e) You must report the annual mass of CO2 that is 
emitted by surface leakage in accordance with your approved MRV plan. 
You must calculate the total annual mass of CO2 emitted from 
all leakage pathways in accordance with the procedure specified in 
Equation RR-10 of this section.
[GRAPHIC] [TIFF OMITTED] TR01DE10.181

where:

CO2. = Total annual CO2 mass emitted by surface 
          leakage (metric tons) in the reporting year.
CO2,x = Annual CO2 mass emitted (metric tons) at 
          leakage pathway x in the reporting year.
x = Leakage pathway.

    (f) You must report the annual mass of CO2 that is 
sequestered in subsurface geologic formations in the reporting year in 
accordance with the procedures specified in paragraphs (f)(1) and (f)(2) 
of this section.
    (1) If you are actively producing oil or natural gas or if you are 
producing any other fluids, you must calculate the annual mass of 
CO2 that is sequestered in the underground subsurface 
formation in the reporting year in accordance with the procedure 
specified in Equation RR-11 of this section.
[GRAPHIC] [TIFF OMITTED] TR01DE10.182

where:

CO2 = Total annual CO2 mass sequestered in 
          subsurface geologic formations (metric tons) at the facility 
          in the reporting year.
CO2. = Total annual CO2 mass injected (metric 
          tons) in the well or group of wells covered by this source 
          category in the reporting year.
CO2P = Total annual CO2 mass produced (metric 
          tons) in the reporting year.
CO2. = Total annual CO2 mass emitted (metric tons) 
          by surface leakage in the reporting year.
CO2FI = Total annual CO2 mass emitted (metric 
          tons) from equipment leaks and vented emissions of 
          CO2 from equipment located on the surface between 
          the flow meter used to measure injection quantity and the 
          injection wellhead, for which a calculation procedure is 
          provided in subpart W of this part.
CO2FP = Total annual CO2 mass emitted (metric 
          tons) from equipment leaks and vented emissions of 
          CO2 from equipment located on the surface between 
          the production wellhead and the flow meter used to measure 
          production quantity, for which a calculation procedure is 
          provided in subpart W of this part.

    (2) If you are not actively producing oil or natural gas or any 
other fluids, you must calculate the annual mass of CO2 that 
is sequestered in subsurface geologic formations in the reporting year 
in accordance with the procedures specified in Equation RR-12 of this 
section.

[[Page 1059]]

[GRAPHIC] [TIFF OMITTED] TR01DE10.183

where:

CO2 = Total annual CO2 mass sequestered in 
          subsurface geologic formations (metric tons) at the facility 
          in the reporting year.
CO2. = Total annual CO2 mass injected (metric 
          tons) in the well or group of wells covered by this source 
          category in the reporting year.
CO2. = Total annual CO2 mass emitted (metric tons) 
          by surface leakage in the reporting year.
CO2FI = Total annual CO2 mass emitted (metric 
          tons) from equipment leaks and vented emissions of 
          CO2 from equipment located on the surface between 
          the flow meter used to measure injection quantity and the 
          injection wellhead, for which a calculation procedure is 
          provided in subpart W of this part.

[75 FR 75078, Dec. 1, 2010, as amended at 76 FR 73906, Nov. 29, 2011; 78 
FR 71978, Nov. 29, 2013]



Sec. 98.444  Monitoring and QA/QC requirements.

    (a) CO2 received. (1) Except as provided in paragraph (a)(4) of this 
section, you must determine the quarterly flow rate of CO2 
received by pipeline by following the most appropriate of the following 
procedures:
    (i) You may measure flow rate at the receiving custody transfer 
meter prior to any subsequent processing operations at the facility and 
collect the flow rate quarterly.
    (ii) If you took ownership of the CO2 in a commercial 
transaction, you may use the quarterly flow rate data from the sales 
contract if it is a one-time transaction or from invoices or manifests 
if it is an ongoing commercial transaction with discrete shipments.
    (iii) If you inject CO2 received from a production 
process unit that is part of your facility, you may use the quarterly 
CO2 flow rate that was measured at the equivalent of a 
custody transfer meter following procedures provided in subpart PP of 
this part. To be the equivalent of a custody transfer meter, a meter 
must measure the flow of CO2 being transported to an 
injection well to the same degree of accuracy as a meter used for 
commercial transactions.
    (2) Except as provided in paragraph (a)(4) of this section, you must 
determine the quarterly mass or volume of contents in all containers if 
you receive CO2 in containers by following the most 
appropriate of the following procedures:
    (i) You may measure the mass of contents of containers summed 
quarterly using weigh bills, scales, or load cells.
    (ii) You may determine the volume of the contents of containers 
summed quarterly.
    (iii) If you took ownership of the CO2 in a commercial 
transaction, you may use the quarterly mass or volume of contents from 
the sales contract if it is a one-time transaction or from invoices or 
manifests if it is an ongoing commercial transaction with discrete 
shipments.
    (3) Except as provided in paragraph (a)(4) of this section, you must 
determine a quarterly concentration of the CO2 received that 
is representative of all CO2 received in that quarter by 
following the most appropriate of the following procedures:
    (i) You may sample the CO2 stream at least once per 
quarter at the point of receipt and measure its CO2 
concentration.
    (ii) If you took ownership of the CO2 in a commercial 
transaction for which the sales contract was contingent on 
CO2 concentration, and if the supplier of the CO2 
sampled the CO2 stream in a quarter and measured its 
concentration per the sales contract terms, you may use the 
CO2 concentration data from the sales contract for that 
quarter.
    (iii) If you inject CO2 from a production process unit 
that is part of your facility, you may report the quarterly 
CO2 concentration of the CO2 stream supplied that 
was measured following the procedures provided in subpart PP of this 
part.
    (4) If the CO2 you receive is wholly injected and is not 
mixed with any other supply of CO2, you may report the annual 
mass of CO2 injected that

[[Page 1060]]

you determined following the requirements under paragraph (b) of this 
section as the total annual mass of CO2 received instead of 
using Equation RR-1 or RR-2 of this subpart to calculate CO2 
received.
    (5) You must assume that the CO2 you receive meets the 
definition of a CO2 stream unless you can trace it through 
written records to a source other than a CO2 stream.
    (b) CO2 injected. (1) You must select a point or points of 
measurement at which the CO2 stream(s) is representative of 
the CO2 stream(s) being injected. You may use as the point or 
points of measurement the location(s) of the flow meter(s) used to 
comply with the flow monitoring and reporting provisions in your 
Underground Injection Control permit.
    (2) You must measure flow rate of CO2 injected with a 
flow meter and collect the flow rate quarterly.
    (3) You must sample the injected CO2 stream at least once 
per quarter immediately upstream or downstream of the flow meter used to 
measure flow rate of that CO2 stream and measure the 
CO2 concentration of the sample.
    (c) CO2 produced. (1) The point of measurement for the quantity of 
CO2 produced from oil or other fluid production wells is a 
flow meter directly downstream of each separator that sends a stream of 
gas into a recycle or end use system.
    (2) You must sample the produced gas stream at least once per 
quarter immediately upstream or downstream of the flow meter used to 
measure flow rate of that gas stream and measure the CO2 
concentration of the sample.
    (3) You must measure flow rate of gas produced with a flow meter and 
collect the flow rate quarterly.
    (d) CO2 emissions from equipment leaks and vented emissions of CO2. 
If you have equipment located on the surface between the flow meter used 
to measure injection quantity and the injection wellhead or between the 
flow meter used to measure production quantity and the production 
wellhead, you must follow the monitoring and QA/QC requirements 
specified in subpart W of this part for the equipment.
    (e) Measurement devices. (1) All flow meters must be operated 
continuously except as necessary for maintenance and calibration.
    (2) You must calibrate all flow meters used to measure quantities 
reported in Sec. 98.446 according to the calibration and accuracy 
requirements in Sec. 98.3(i).
    (3) You must operate all measurement devices according to one of the 
following. You may use an appropriate standard method published by a 
consensus-based standards organization if such a method exists or an 
industry standard practice. Consensus-based standards organizations 
include, but are not limited to, the following: ASTM International, the 
American National Standards Institute (ANSI), the American Gas 
Association (AGA), the American Society of Mechanical Engineers (ASME), 
the American Petroleum Institute (API), and the North American Energy 
Standards Board (NAESB).
    (4) You must ensure that any flow meter calibrations performed are 
National Institute of Standards and Technology (NIST) traceable.
    (f) General. (1) If you measure the concentration of any 
CO2 quantity for reporting, you must measure according to one 
of the following. You may use an appropriate standard method published 
by a consensus-based standards organization if such a method exists or 
an industry standard practice.
    (2) You must convert all measured volumes of CO2 to the 
following standard industry temperature and pressure conditions for use 
in Equations RR-2, RR-5 and RR-8 of this subpart: Standard cubic meters 
at a temperature of 60 degrees Fahrenheit and at an absolute pressure of 
1 atmosphere.
    (3) For 2011, you may follow the provisions of Sec. 98.3(d)(1) 
through (2) for best available monitoring methods only for parameters 
required by paragraphs (a) and (b) of Sec. 98.443 rather than follow 
the monitoring requirements of paragraph (a) of this section. For 
purposes of this subpart, any reference to the year 2010 in Sec. 
98.3(d)(1) through (2) shall mean 2011.

[75 FR 75078, Dec. 1, 2010, as amended at 76 FR 73906, Nov. 29, 2011]

[[Page 1061]]



Sec. 98.445  Procedures for estimating missing data.

    A complete record of all measured parameters used in the GHG 
quantities calculations is required. Whenever the monitoring procedures 
cannot be followed, you must use the following missing data procedures:
    (a) A quarterly flow rate of CO2 received that is missing 
must be estimated as follows:
    (1) Another calculation methodology listed in Sec. 98.444(a)(1) 
must be used if possible.
    (2) If another method listed in Sec. 98.444(a)(1) cannot be used, a 
quarterly flow rate value that is missing must be estimated using a 
representative flow rate value from the nearest previous time period.
    (b) A quarterly mass or volume of contents in containers received 
that is missing must be estimated as follows:
    (1) Another calculation methodology listed in Sec. 98.444(a)(2) 
must be used if possible.
    (2) If another method listed in Sec. 98.444(a)(2) cannot be used, a 
quarterly mass or volume value that is missing must be estimated using a 
representative mass or volume value from the nearest previous time 
period.
    (c) A quarterly CO2 concentration of a CO2 
stream received that is missing must be estimated as follows:
    (1) Another calculation methodology listed in Sec. 98.444(a)(3) 
must be used if possible.
    (2) If another method listed in Sec. 98.444(a)(3) cannot be used, a 
quarterly concentration value that is missing must be estimated using a 
representative concentration value from the nearest previous time 
period.
    (d) A quarterly quantity of CO2 injected that is missing 
must be estimated using a representative quantity of CO2 
injected from the nearest previous period of time at a similar injection 
pressure.
    (e) For any values associated with CO2 emissions from 
equipment leaks and vented emissions of CO2 from surface 
equipment at the facility that are reported in this subpart, missing 
data estimation procedures should be followed in accordance with those 
specified in subpart W of this part.
    (f) The quarterly quantity of CO2 produced from 
subsurface geologic formations that is missing must be estimated using a 
representative quantity of CO2 produced from the nearest 
previous period of time.
    (g) You must estimate the mass of CO2 emitted by surface 
leakage that is missing as required by your approved MRV plan.
    (h) You must estimate other missing data as required by your 
approved MRV plan.

[75 FR 75078, Dec. 1, 2010, as amended at 76 FR 73906, Nov. 29, 2011]



Sec. 98.446  Data reporting requirements.

    In addition to the information required by Sec. 98.3(c), report the 
information listed in this section.
    (a) If you receive CO2 by pipeline, report the following 
for each receiving flow meter:
    (1) The total net mass of CO2 received (metric tons) 
annually.
    (2) If a volumetric flow meter is used to receive CO2 
report the following unless you reported yes to paragraph (a)(4) of this 
section:
    (i) The volumetric flow through a receiving flow meter at standard 
conditions (in standard cubic meters) in each quarter.
    (ii) The volumetric flow through a receiving flow meter that is 
redelivered to another facility without being injected into your well 
(in standard cubic meters) in each quarter.
    (iii) The CO2 concentration in the flow (volume percent 
CO2 expressed as a decimal fraction) in each quarter.
    (3) If a mass flow meter is used to receive CO2 report 
the following unless you reported yes to paragraph (a)(4) of this 
section:
    (i) The mass flow through a receiving flow meter (in metric tons) in 
each quarter.
    (ii) The mass flow through a receiving flow meter that is 
redelivered to another facility without being injected into your well 
(in metric tons) in each quarter.
    (iii) The CO2 concentration in the flow (weight percent 
CO2 expressed as a decimal fraction) in each quarter.
    (4) If the CO2 received is wholly injected and not mixed 
with any other

[[Page 1062]]

supply of CO2, report whether you followed the procedures in 
Sec. 98.444(a)(4).
    (5) The standard or method used to calculate each value in 
paragraphs (a)(2) through (a)(3) of this section.
    (6) The number of times in the reporting year for which substitute 
data procedures were used to calculate values reported in paragraphs 
(a)(2) through (a)(3) of this section.
    (7) Whether the flow meter is mass or volumetric.
    (8) A numerical identifier for the flow meter.
    (b) If you receive CO2 in containers, report:
    (1) The mass (in metric tons) or volume at standard conditions (in 
standard cubic meters) of contents in containers received in each 
quarter.
    (2) The concentration of CO2 of contents in containers 
(volume or wt. percent CO2 expressed as a decimal fraction) 
in each quarter.
    (3) The mass (in metric tons) or volume (in standard cubic meters) 
of contents in containers that is redelivered to another facility 
without being injected into your well in each quarter.
    (4) The net mass of CO2 received (in metric tons) 
annually.
    (5) The standard or method used to calculate each value in 
paragraphs (b)(1), (b)(2), and (b)(3) of this section.
    (6) The number of times in the reporting year for which substitute 
data procedures were used to calculate values reported in paragraphs 
(b)(1) and (b)(2) of this section.
    (c) If you use more than one receiving flow meter, report the total 
net mass of CO2 received (metric tons) through all flow 
meters annually.
    (d) The source of the CO2 received according to the 
following categories:
    (1) CO2 production wells.
    (2) Electric generating unit.
    (3) Ethanol plant.
    (4) Pulp and paper mill.
    (5) Natural gas processing.
    (6) Gasification operations.
    (7) Other anthropogenic source.
    (8) Discontinued enhanced oil and gas recovery project.
    (9) Unknown.
    (e) Report the date that you began collecting data for calculating 
total amount sequestered according to Sec. 98.448(a)(7) of this 
subpart.
    (f) Report the following. If the date specified in paragraph (e) of 
this section is during the reporting year for this annual report, report 
the following starting on the date specified in paragraph (e) of this 
section.
    (1) For each injection flow meter (mass or volumetric), report:
    (i) The mass of CO2 injected (metric tons) annually.
    (ii) The CO2 concentration in flow (volume or weight 
percent CO2 expressed as a decimal fraction) in each quarter.
    (iii) If a volumetric flow meter is used, the volumetric flow rate 
at standard conditions (in standard cubic meters) in each quarter.
    (iv) If a mass flow meter is used, the mass flow rate (in metric 
tons) in each quarter.
    (v) A numerical identifier for the flow meter.
    (vi) Whether the flow meter is mass or volumetric.
    (vii) The standard used to calculate each value in paragraphs 
(f)(1)(ii) through (f)(1)(iv) of this section.
    (viii) The number of times in the reporting year for which 
substitute data procedures were used to calculate values reported in 
paragraphs (f)(1)(ii) through (f)(1)(iv) of this section.
    (ix) The location of the flow meter.
    (2) The total CO2 injected (metric tons) in the reporting 
year as calculated in Equation RR-6 of this subpart.
    (3) For CO2 emissions from equipment leaks and vented 
emissions of CO2, report the following:
    (i) The mass of CO2 emitted (in metric tons) annually 
from equipment leaks and vented emissions of CO2 from 
equipment located on the surface between the flow meter used to measure 
injection quantity and the injection wellhead.
    (ii) The mass of CO2 emitted (in metric tons) annually 
from equipment leaks and vented emissions of CO2 from 
equipment located on the surface between the production wellhead and the 
flow meter used to measure production quantity.
    (4) For each separator flow meter (mass or volumetric), report:
    (i) CO2 mass produced (metric tons) annually.

[[Page 1063]]

    (ii) CO2 concentration in flow (volume or weight percent 
CO2 expressed as a decimal fraction) in each quarter.
    (iii) If a volumetric flow meter is used, volumetric flow rate at 
standard conditions (standard cubic meters) in each quarter.
    (iv) If a mass flow meter, mass flow rate (metric tons) in each 
quarter.
    (v) A numerical identifier for the flow meter.
    (vi) Whether the flow meter is mass or volumetric.
    (vii) The standard used to calculate each value in paragraphs 
(f)(4)(ii) through (f)(4)(iv) of this section.
    (viii) The number of times in the reporting year for which 
substitute data procedures were used to calculate values reported in 
paragraphs (f)(4)(ii) through (f)(4)(iv) of this section.
    (5) The entrained CO2 in produced oil or other fluid 
divided by the CO2 separated through all separators in the 
reporting year (weight percent CO2 expressed as a decimal 
fraction) used as the value for X in Equation RR-9 of this subpart and 
as determined according to your EPA-approved MRV plan.
    (6) Annual CO2 produced in the reporting year as 
calculated in Equation RR-9 of this subpart.
    (7) For each leakage pathway through which CO2 emissions 
occurred, report:
    (i) A numerical identifier for the leakage pathway.
    (ii) The CO2 (metric tons) emitted through that pathway 
in the reporting year.
    (8) Annual CO2 mass emitted (metric tons) by surface 
leakage in the reporting year as calculated by Equation RR-10 of this 
subpart.
    (9) Annual CO2 (metric tons) sequestered in subsurface 
geologic formations in the reporting year as calculated by Equation RR-
11 or RR-12 of this subpart.
    (10) Cumulative mass of CO2 (metric tons) reported as 
sequestered in subsurface geologic formations in all years since the 
well or group of wells became subject to reporting requirements under 
this subpart.
    (11) Date that the most recent MRV plan was approved by EPA and the 
MRV plan approval number that was issued by EPA.
    (12) An annual monitoring report that contains the following 
components:
    (i) A narrative history of the monitoring efforts conducted over the 
previous calendar year, including a listing of all monitoring equipment 
that was operated, its period of operation, and any relevant tests or 
surveys that were conducted.
    (ii) A description of any changes to the monitoring program that you 
concluded were not material changes warranting submission of a revised 
MRV plan under Sec. 98.448(d).
    (iii) A narrative history of any monitoring anomalies that were 
detected in the previous calendar year and how they were investigated 
and resolved.
    (iv) A description of any surface leakages of CO2, 
including a discussion of all methodologies and technologies involved in 
detecting and quantifying the surface leakages and any assumptions and 
uncertainties involved in calculating the amount of CO2 
emitted.
    (13) If a well is permitted under the Underground Injection Control 
program, for each injection well, report:
    (i) The well identification number used for the Underground 
Injection Control permit.
    (ii) The Underground Injection Control permit class.
    (14) If an offshore well is not subject to the Safe Drinking Water 
Act, for each injection well, report any well identification number and 
any identification number used for the legal instrument authorizing 
geologic sequestration.

[75 FR 75078, Dec. 1, 2010, as amended at 76 FR 73906, Nov. 29, 2011; 78 
FR 71979, Nov. 29, 2013]



Sec. 98.447  Records that must be retained.

    (a) You must follow the record retention requirements specified by 
Sec. 98.3(g). In addition to the records required by Sec. 98.3(g), you 
must retain the records specified in paragraphs (a)(1) through (7) of 
this section, as applicable. You must retain all required records for at 
least 3 years.
    (1) Quarterly records of CO2 received, including mass 
flow rate of contents of containers (mass or volumetric) at

[[Page 1064]]

standard conditions and operating conditions, operating temperature and 
pressure, and concentration of these streams.
    (2) Quarterly records of produced CO2, including mass 
flow or volumetric flow at standard conditions and operating conditions, 
operating temperature and pressure, and concentration of these streams.
    (3) Quarterly records of injected CO2 including mass flow 
or volumetric flow at standard conditions and operating conditions, 
operating temperature and pressure, and concentration of these streams.
    (4) Annual records of information used to calculate the 
CO2 emitted by surface leakage from leakage pathways.
    (5) Annual records of information used to calculate the 
CO2 emitted from equipment leaks and vented emissions of 
CO2 from equipment located on the surface between the flow 
meter used to measure injection quantity and the injection wellhead.
    (6) Annual records of information used to calculate the 
CO2 emitted from equipment leaks and vented emissions of 
CO2 from equipment located on the surface between the 
production wellhead and the flow meter used to measure production 
quantity.
    (7) Any other records as specified for retention in your EPA-
approved MRV plan.
    (b) You must complete your monitoring plans, as described in Sec. 
98.3(g)(5), by April 1 of the year you begin collecting data.

[75 FR 75078, Dec. 1, 2010, as amended at 76 FR 73906, Nov. 29, 2011]



Sec. 98.448  Geologic sequestration monitoring, reporting,
and verification (MRV) plan.

    (a) Contents of MRV plan. You must develop and submit to the 
Administrator a proposed MRV plan for monitoring, reporting, and 
verification of geologic sequestration at your facility. Your proposed 
MRV plan must contain the following components:
    (1) Delineation of the maximum monitoring area and the active 
monitoring areas. The first period for your active monitoring area will 
begin from the date determined in your MRV plan through the date at 
which the plan calls for the first expansion of the monitoring area. The 
length of each monitoring period can be any time interval chosen by you 
that is greater than 1 year.
    (2) Identification of potential surface leakage pathways for 
CO2 in the maximum monitoring area and the likelihood, 
magnitude, and timing, of surface leakage of CO2 through 
these pathways.
    (3) A strategy for detecting and quantifying any surface leakage of 
CO2.
    (4) A strategy for establishing the expected baselines for 
monitoring CO2 surface leakage.
    (5) A summary of the considerations you intend to use to calculate 
site-specific variables for the mass balance equation. This includes, 
but is not limited to, considerations for calculating CO2 
emissions from equipment leaks and vented emissions of CO2 
between the injection flow meter and injection well and/or the 
production flow meter and production well, and considerations for 
calculating CO2 in produced fluids.
    (6) If a well is permitted under the Underground Injection Control 
program, for each injection well, report the well identification number 
used for the Underground Injection Control permit and the Underground 
Injection Control permit class. If the well is not yet permitted, and 
you have applied for an Underground Injection Control permit, report the 
well identification numbers in the permit application. If an offshore 
well is not subject to the Safe Drinking Water Act, for each injection 
well, report any well identification number and any identification 
number used for the legal instrument authorizing geologic sequestration. 
If you are submitting your Underground Injection Control permit 
application as part of your proposed MRV plan, you must notify EPA when 
the permit has been approved. If you are an offshore facility not 
subject to the Safe Drinking Water Act, and are submitting your 
application for the legal instrument authorizing geologic sequestration 
as part of your proposed MRV plan, you must notify EPA when the legal 
instrument authorizing geologic sequestration has been approved.

[[Page 1065]]

    (7) Proposed date to begin collecting data for calculating total 
amount sequestered according to equation RR-11 or RR-12 of this subpart. 
This date must be after expected baselines as required by paragraph 
(a)(4) of this section are established and the leakage detection and 
quantification strategy as required by paragraph (a)(3) of this section 
is implemented in the initial AMA.
    (b) Timing. You must submit a proposed MRV plan to EPA according to 
the following schedule:
    (1) You must submit a proposed MRV plan to EPA by June 30, 2011 if 
you were issued a final Underground Injection Control permit authorizing 
the injection of CO2 into the subsurface on or before 
December 31, 2010. You will be allowed to request one extension of up to 
an additional 180 days in which to submit your proposed MRV plan.
    (2) You must submit a proposed MRV plan to EPA within 180 days of 
receiving a final Underground Injection Control permit authorizing the 
injection of CO2 into the subsurface. If your facility is an 
offshore facility not subject to the Safe Drinking Water Act, you must 
submit a proposed MRV plan to EPA within 180 days of receiving 
authorization to begin geologic sequestration of CO2. You 
will be allowed to request one extension of the submittal date of up to 
an additional 180 days.
    (3) If you are injecting a CO2 stream in subsurface 
geologic formations to enhance the recovery of oil or natural gas and 
you are not permitted as Class VI under the Underground Injection 
Control program, you may opt to submit an MRV plan at any time.
    (4) If EPA determines that your proposed MRV plan is incomplete, you 
must submit an updated MRV plan within 45 days of EPA notification, 
unless otherwise specified by EPA.
    (c) Final MRV plan. The Administrator will issue a final MRV plan 
within a reasonable period of time. The Administrator's final MRV plan 
is subject to the provisions of part 78 of this chapter. Once the MRV 
plan is final and no longer subject to administrative appeal under part 
78 of this chapter, you must implement the plan starting on the day 
after the day on which the plan becomes final and is no longer subject 
to such appeal.
    (d) MRV plan revisions. You must revise and submit the MRV plan 
within 180 days to the Administrator for approval if any of the 
following in paragraphs (d)(1) through (d)(4) of this section applies. 
You must include the reason(s) for the revisions in your submittal.
    (1) A material change was made to monitoring and/or operational 
parameters that was not anticipated in the original MRV plan. Examples 
of material changes include but are not limited to: Large changes in the 
volume of CO2 injected; the construction of new injection 
wells not identified in the MRV plan; failures of the monitoring system 
including monitoring system sensitivity, performance, location, or 
baseline; changes to surface land use that affects baseline or 
operational conditions; observed plume location that differs 
significantly from the predicted plume area used for developing the MRV 
plan; a change in the maximum monitoring area or active monitoring area; 
or a change in monitoring technology that would result in coverage or 
detection capability different from the MRV plan.
    (2) A change in the permit class of your Underground Injection 
Control permit.
    (3) If you are notified by EPA of substantive errors in your MRV 
plan or monitoring report.
    (4) You choose to revise your MRV plan for any other reason in any 
reporting year.
    (e) Revised MRV plan. The requirements of paragraph (c) of this 
section apply to any submission of a revised MRV plan. You must continue 
reporting under your currently approved plan while awaiting approval of 
a revised MRV plan.
    (f) Format. Each proposed MRV plan or revision and each annual 
report must be submitted electronically in a format specified by the 
Administrator.
    (g) Certificate of representation. You must submit a certificate of 
representation according to the provisions in Sec. 98.4 at least 60 
days before submission of your MRV plan, your research and development 
exemption request, your

[[Page 1066]]

MRV plan submission extension request, or your initial annual report 
under this part, whichever is earlier.

[75 FR 75078, Dec. 1, 2010, as amended at 76 FR 73907, Nov. 29, 2011]



Sec. 98.449  Definitions.

    Except as provided below, all terms used in this subpart have the 
same meaning given in the Clean Air Act and subpart A of this part.
    Active monitoring area is the area that will be monitored over a 
specific time interval from the first year of the period (n) to the last 
year in the period (t). The boundary of the active monitoring area is 
established by superimposing two areas:
    (1) The area projected to contain the free phase CO2 
plume at the end of year t, plus an all around buffer zone of one-half 
mile or greater if known leakage pathways extend laterally more than 
one-half mile.
    (2) The area projected to contain the free phase CO2 
plume at the end of year t + 5.
    CO2 received means the CO2 stream that you receive to be 
injected for the first time into a well on your facility that is covered 
by this subpart. CO2 received includes, but is not limited 
to, a CO2 stream from a production process unit inside your 
facility and a CO2 stream that was injected into a well on 
another facility, removed from a discontinued enhanced oil or natural 
gas or other production well, and transferred to your facility.
    Equipment leak means those emissions that could not reasonably pass 
through a stack, chimney, vent, or other functionally-equivalent 
opening.
    Expected baseline is the anticipated value of a monitored parameter 
that is compared to the measured monitored parameter.
    Maximum monitoring area means the area that must be monitored under 
this regulation and is defined as equal to or greater than the area 
expected to contain the free phase CO2 plume until the 
CO2 plume has stabilized plus an all-around buffer zone of at 
least one-half mile.
    Research and development project means a project for the purpose of 
investigating practices, monitoring techniques, or injection 
verification, or engaging in other applied research, that will enable 
safe and effective long-term containment of a CO2 stream in 
subsurface geologic formations, including research and short duration 
CO2 injection tests conducted as a precursor to long-term 
storage.
    Separator means a vessel in which streams of multiple phases are 
gravity separated into individual streams of single phase.
    Surface leakage means the movement of the injected CO2 
stream from the injection zone to the surface, and into the atmosphere, 
indoor air, oceans, or surface water.
    Underground Injection Control permit means a permit issued under the 
authority of Part C of the Safe Drinking Water Act at 42 U.S.C. 300h et 
seq.
    Underground Injection Control program means the program responsible 
for regulating the construction, operation, permitting, and closure of 
injection wells that place fluids underground for storage or disposal 
for purposes of protecting underground sources of drinking water from 
endangerment pursuant to Part C of the Safe Drinking Water Act at 42 
U.S.C. 300h et seq.
    Vented emissions means intentional or designed releases of 
CH4 or CO2 containing natural gas or hydrocarbon 
gas (not including stationary combustion flue gas), including process 
designed flow to the atmosphere through seals or vent pipes, equipment 
blowdown for maintenance, and direct venting of gas used to power 
equipment (such as pneumatic devices).

[75 FR 75078, Dec. 1, 2010, as amended at 76 FR 73907, Nov. 29, 2011]



      Subpart SS_Electrical Equipment Manufacture or Refurbishment

    Source: 75 FR 74859, Dec. 1, 2010, unless otherwise noted.



Sec. 98.450  Definition of the source category.

    The electrical equipment manufacturing or refurbishment category 
consists of processes that manufacture or refurbish gas-insulated 
substations, circuit breakers, other switchgear, gas-insulated lines, or 
power transformers (including gas-containing components

[[Page 1067]]

of such equipment) containing sulfur-hexafluoride (SF6) or 
perfluorocarbons (PFCs). The processes include equipment testing, 
installation, manufacturing, decommissioning and disposal, refurbishing, 
and storage in gas cylinders and other containers.



Sec. 98.451  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains an electrical equipment manufacturing or refurbishing process 
and the facility meets the requirements of Sec. 98.2(a)(1). Electrical 
equipment manufacturing and refurbishing facilities covered by this rule 
are those that have total annual purchases of SF6 and PFCs 
that exceed 23,000 pounds.



Sec. 98.452  GHGs to report.

    (a) You must report SF6 and PFC emissions at the facility 
level. Annual emissions from the facility must include SF6 
and PFC emissions from equipment that is installed at an off-site 
electric power transmission or distribution location whenever emissions 
from installation activities (e.g., filling) occur before the title to 
the equipment is transferred to the electric power transmission or 
distribution entity.
    (b) You must report CO2, N2O and 
CH4 emissions from each stationary combustion unit. You must 
calculate and report these emissions under subpart C of this part 
(General Stationary Fuel Combustion Sources) by following the 
requirements of subpart C of this part.



Sec. 98.453  Calculating GHG emissions.

    (a) For each electrical equipment manufacturer or refurbisher, 
estimate the annual SF6 and PFC emissions using the mass-
balance approach in Equation SS-1 of this section:
[GRAPHIC] [TIFF OMITTED] TR01DE10.056

where:

Decrease in SF6 Inventory = (Pounds of SF6 stored 
          in containers at the beginning of the year) - (Pounds of 
          SF6 stored in containers at the end of the year).
Acquisitions of SF6 = (Pounds of SF6 purchased 
          from chemical producers or suppliers in bulk) + (Pounds of 
          SF6 returned by equipment users) + (Pounds of 
          SF6 returned to site after off-site recycling).
Disbursements of SF6 = (Pounds of SF6 contained in 
          new equipment delivered to customers) + (Pounds of 
          SF6 delivered to equipment users in containers) + 
          (Pounds of SF6 returned to suppliers) + (Pounds of 
          SF6 sent off site for recycling) + (Pounds of 
          SF6 sent off-site for destruction).

    (b) Use the mass-balance method in paragraph (a) of this section to 
estimate emissions of PFCs associated with the manufacture or 
refurbishment of power transformers, substituting the relevant PFC(s) 
for SF6 in Equation SS-1 of this section.
    (c) Estimate the disbursements of SF6 or PFCs sent to 
customers in new equipment or cylinders or sent off-site for other 
purposes including for recycling, for destruction or to be returned to 
suppliers using Equation SS-2 of this section:
[GRAPHIC] [TIFF OMITTED] TR01DE10.057

where:

DGHG = The annual disbursement of SF6 or PFCs sent 
          to customers in new equipment or cylinders or sent off-site 
          for other purposes including for recycling, for destruction or 
          to be returned to suppliers.
Qp = The mass of the SF6 or PFCs charged into 
          equipment or containers over the period p sent to customers or 
          sent off-site for other purposes including for recycling, for 
          destruction or to be returned to suppliers.
n = The number of periods in the year.

    (d) Estimate the mass of SF6 or PFCs disbursed to 
customers in new equipment or cylinders over the period p by monitoring 
the mass flow of the SF6 or PFCs into the new equipment or 
cylinders using a flowmeter, or by weighing containers before and after 
gas

[[Page 1068]]

from containers is used to fill equipment or cylinders, or by using the 
nameplate capacity of the equipment.
    (e) If the mass of SF6 or the PFC disbursed to customers 
in new equipment or cylinders over the period p is estimated by weighing 
containers before and after gas from containers is used to fill 
equipment or cylinders, estimate this quantity using Equation SS-3 of 
this section:
[GRAPHIC] [TIFF OMITTED] TR01DE10.058

where:

Qp = The mass of SF6 or the PFC charged into 
          equipment or containers over the period p sent to customers or 
          sent off-site for other purposes including for recycling, for 
          destruction or to be returned to suppliers.
MB = The mass of the contents of the containers used to fill 
          equipment or cylinders at the beginning of period p.
ME = The mass of the contents of the containers used to fill 
          equipment or cylinders at the end of period p.
EL = The mass of SF6 or the PFC emitted during the 
          period p downstream of the containers used to fill equipment 
          or cylinders and in cases where a flowmeter is used, 
          downstream of the flowmeter during the period p (e.g., 
          emissions from hoses or other flow lines that connect the 
          container to the equipment or cylinder that is being filled).

    (f) If the mass of SF6 or the PFC disbursed to customers 
in new equipment or cylinders over the period p is determined using a 
flowmeter, estimate this quantity using Equation SS-4 of this section:
[GRAPHIC] [TIFF OMITTED] TR01DE10.059

where:

Qp = The mass of SF6 or the PFC charged into 
          equipment or containers over the period p sent to customers or 
          sent off-site for other purposes including for recycling, for 
          destruction or to be returned to suppliers.
Mmr = The mass of the SF6 or the PFC that has 
          flowed through the flowmeter during the period p.
EL = The mass of SF6 or the PFC emitted during the 
          period p downstream of the containers used to fill equipment 
          or cylinders and in cases where a flowmeter is used, 
          downstream of the flowmeter during the period p (e.g., 
          emissions from hoses or other flow lines that connect the 
          container to the equipment that is being filled).

    (g) Estimate the mass of SF6 or the PFC emitted during 
the period p downstream of the containers used to fill equipment or 
cylinders (e.g., emissions from hoses or other flow lines that connect 
the container to the equipment or cylinder that is being filled) using 
Equation SS-5 of this section:
[GRAPHIC] [TIFF OMITTED] TR01DE10.060

where:

EL = The mass of SF6 or the PFC emitted during the 
          period p downstream of the containers used to fill equipment 
          or cylinders and in cases where a flowmeter is used, 
          downstream of the flowmeter during the period p (e.g., 
          emissions from hoses or other flow lines that connect the 
          container to the equipment or cylinder that is being filled)
FCi = The total number of fill operations over the period p 
          for the valve-hose combination Ci.
EFCi = The emission factor for the valve-hose combination Ci.

[[Page 1069]]

n = The number of different valve-hose combinations C used during the 
          period p.

    (h) If the mass of SF6 or the PFC disbursed to customers 
in new equipment or cylinders over the period p is determined by using 
the nameplate capacity, or by using the nameplate capacity of the 
equipment and calculating the partial shipping charge, use the methods 
in either paragraph (h)(1) or (h)(2) of this section.
    (1) Determine the equipment's actual nameplate capacity, by 
measuring the nameplate capacities of a representative sample of each 
make and model and calculating the mean value for each make and model as 
specified at Sec. 98.454(f).
    (2) If equipment is shipped with a partial charge, calculate the 
partial shipping charge by multiplying the nameplate capacity of the 
equipment by the ratio of the densities of the partial charge to the 
full charge.
    (i) Estimate the annual SF6 and PFC emissions from the 
equipment that is installed at an off-site electric power transmission 
or distribution location before the title to the equipment is 
transferred by using Equation SS-6 of this section:
[GRAPHIC] [TIFF OMITTED] TR01DE10.061

where:

EI = Total annual SF6 or PFC emissions from equipment 
          installation at electric transmission or distribution 
          facilities.
MF = The total annual mass of the SF6 or PFCs, in pounds, used to fill 
          equipment during equipment installation at electric 
          transmission or distribution facilities.
MC = The total annual mass of the SF6 or PFCs, in pounds, 
          used to charge the equipment prior to leaving the electrical 
          equipment manufacturer facility.
NI = The total annual nameplate capacity of the equipment, in pounds, 
          installed at electric transmission or distribution facilities.

[75 FR 75078, Dec. 1, 2010, as amended at 78 FR 71979, Nov. 29, 2013]



Sec. 98.454  Monitoring and QA/QC requirements.

    (a) For calendar year 2011 monitoring, you may follow the provisions 
of Sec. 98.3(d)(1) through (d)(2) for best available monitoring methods 
rather than follow the monitoring requirements of this section. For 
purposes of this subpart, any reference in Sec. 98.3(d)(1) through 
(d)(2) to 2010 means 2011, March 31 means June 30, and April 1 means 
July 1. Any reference to the effective date in Sec. 98.3(d)(1) through 
(d)(2) means February 28, 2011.
    (b) Ensure that all the quantities required by the equations of this 
subpart have been measured using either flowmeters with an accuracy and 
precision of 1 percent of full scale or better or 
scales with an accuracy and precision of 1 percent 
of the filled weight (gas plus tare) of the containers of SF6 
or PFCs that are typically weighed on the scale. For scales that are 
generally used to weigh cylinders containing 115 pounds of gas when 
full, this equates to 1 percent of the sum of 115 
pounds and approximately 120 pounds tare, or slightly more than 2 pounds. Account for the tare weights of the 
containers. You may accept gas masses or weights provided by the gas 
supplier e.g., for the contents of cylinders containing new gas or for 
the heels remaining in cylinders returned to the gas supplier) if the 
supplier provides documentation verifying that accuracy standards are 
met; however, you remain responsible for the accuracy of these masses 
and weights under this subpart.
    (c) All flow meters, weigh scales, and combinations of volumetric 
and density measures that are used to measure or calculate quantities 
under this subpart must be calibrated using calibration procedures 
specified by the flowmeter, scale, volumetric or density measure 
equipment manufacturer. Calibration must be performed prior to the first 
reporting year. After the initial calibration, recalibration must be 
performed at the minimum frequency specified by the manufacturer.
    (d) For purposes of Equations SS-5 of this subpart, the emission 
factor for the valve-hose combination (EFC) must

[[Page 1070]]

be estimated using measurements and/or engineering assessments or 
calculations based on chemical engineering principles or physical or 
chemical laws or properties. Such assessments or calculations may be 
based on, as applicable, the internal volume of hose or line that is 
open to the atmosphere during coupling and decoupling activities, the 
internal pressure of the hose or line, the time the hose or line is open 
to the atmosphere during coupling and decoupling activities, the 
frequency with which the hose or line is purged and the flow rate during 
purges. You must develop a value for EFc (or use an industry-
developed value) for each combination of hose and valve fitting, to use 
in Equation SS-5 of this subpart. The value for EFC must be 
determined for each combination of hose and valve fitting of a given 
diameter or size. The calculation must be recalculated annually to 
account for changes to the specifications of the valves or hoses that 
may occur throughout the year.
    (e) Electrical equipment manufacturers and refurbishers must account 
for SF6 or PFC emissions that occur as a result of unexpected 
events or accidental losses, such as a malfunctioning hose or leak in 
the flow line, during the filling of equipment or containers for 
disbursement by including these losses in the estimated mass of 
SF6 or the PFC emitted downstream of the container or 
flowmeter during the period p.
    (f) If the mass of SF6 or the PFC disbursed to customers 
in new equipment over the period p is determined by assuming that it is 
equal to the equipment's nameplate capacity or, in cases where equipment 
is shipped with a partial charge, equal to its partial shipping charge, 
equipment samples for conducting the nameplate capacity tests must be 
selected using the following stratified sampling strategy in this 
paragraph. For each make and model, group the measurement conditions to 
reflect predictable variability in the facility's filling practices and 
conditions (e.g., temperatures at which equipment is filled). Then, 
independently select equipment samples at random from each make and 
model under each group of conditions. To account for variability, a 
certain number of these measurements must be performed to develop a 
robust and representative average nameplate capacity (or shipping 
charge) for each make, model, and group of conditions. A Student T 
distribution calculation should be conducted to determine how many 
samples are needed for each make, model, and group of conditions as a 
function of the relative standard deviation of the sample measurements. 
To determine a sufficiently precise estimate of the nameplate capacity, 
the number of measurements required must be calculated to achieve a 
precision of one percent of the true mean, using a 95 percent confidence 
interval. To estimate the nameplate capacity for a given make and model, 
you must use the lowest mean value among the different groups of 
conditions, or provide justification for the use of a different mean 
value for the group of conditions that represents the typical practices 
and conditions for that make and model. Measurements can be conducted 
using SF6, another gas, or a liquid. Re-measurement of 
nameplate capacities should be conducted every five years to reflect 
cumulative changes in manufacturing methods and conditions over time.
    (g) Ensure the following QA/QC methods are employed throughout the 
year:
    (1) Procedures are in place and followed to track and weigh all 
cylinders or other containers at the beginning and end of the year.
    (h) You must adhere to the following QA/QC methods for reviewing the 
completeness and accuracy of reporting:
    (1) Review inputs to Equation SS-1 of this subpart to ensure inputs 
and outputs to the company's system are included.
    (2) Do not enter negative inputs and confirm that negative emissions 
are not calculated. However, the decrease in SF6 inventory 
may be calculated as negative.
    (3) Ensure that beginning-of-year inventory matches end-of-year 
inventory from the previous year.
    (4) Ensure that in addition to SF6 purchased from bulk 
gas distributors, SF6 returned from equipment users with or 
inside equipment and SF6 returned from off-site recycling are 
also accounted for among the total additions.

[[Page 1071]]



Sec. 98.455  Procedures for estimating missing data.

    A complete record of all measured parameters used in the GHG 
emissions calculations is required. Replace missing data, if needed, 
based on data from similar manufacturing operations, and from similar 
equipment testing and decommissioning activities for which data are 
available.



Sec. 98.456  Data reporting requirements.

    In addition to the information required by Sec. 98.3(c), each 
annual report must contain the following information for each chemical 
at the facility level:
    (a) Pounds of SF6 and PFCs stored in containers at the 
beginning of the year.
    (b) Pounds of SF6 and PFCs stored in containers at the 
end of the year.
    (c) Pounds of SF6 and PFCs purchased in bulk.
    (d) Pounds of SF6 and PFCs returned by equipment users 
with or inside equipment.
    (e) Pounds of SF6 and PFCs returned to site from off site 
after recycling.
    (f) Pounds of SF6 and PFCs inside new equipment delivered 
to customers.
    (g) Pounds of SF6 and PFCs delivered to equipment users 
in containers.
    (h) Pounds of SF6 and PFCs returned to suppliers.
    (i) Pounds of SF6 and PFCs sent off site for destruction.
    (j) Pounds of SF6 and PFCs sent off site to be recycled.
    (k) The nameplate capacity of the equipment, in pounds, delivered to 
customers with SF6 or PFCs inside, if different from the 
quantity in paragraph (f) of this section.
    (l) A description of the engineering methods and calculations used 
to determine emissions from hoses or other flow lines that connect the 
container to the equipment that is being filled.
    (m) The values for EFci of Equation SS-5 of this subpart 
for each hose and valve combination and the associated valve fitting 
sizes and hose diameters.
    (n) The total number of fill operations for each hose and valve 
combination, or, FCi of Equation SS-5 of this subpart.
    (o) If the mass of SF6 or the PFC disbursed to customers 
in new equipment over the period p is determined according to the 
methods required in Sec. 98.453(h), report the mean value of nameplate 
capacity in pounds for each make, model, and group of conditions.
    (p) If the mass of SF6 or the PFC disbursed to customers 
in new equipment over the period p is determined according to the 
methods required in Sec. 98.453(h), report the number of samples and 
the upper and lower bounds on the 95 percent confidence interval for 
each make, model, and group of conditions.
    (q) Pounds of SF6 and PFCs used to fill equipment at off-
site electric power transmission or distribution locations, or 
MF, of Equation SS-6 of this subpart.
    (r) Pounds of SF6 and PFCs used to charge the equipment 
prior to leaving the electrical equipment manufacturer or refurbishment 
facility, or MC, of Equation SS-6 of this subpart.
    (s) The nameplate capacity of the equipment, in pounds, installed at 
off-site electric power transmission or distribution locations used to 
determine emissions from installation, or NI, of Equation SS-
6 of this subpart.
    (t) For any missing data, you must report the reason the data were 
missing, the parameters for which the data were missing, the substitute 
parameters used to estimate emissions in their absence, and the quantity 
of emissions thereby estimated.

[75 FR 75078, Dec. 1, 2010, as amended at 78 FR 71979, Nov. 29, 2013]



Sec. 98.457  Records that must be retained.

    In addition to the information required by Sec. 98.3(g), you must 
retain the following records:
    (a) All information reported and listed in Sec. 98.456.
    (b) Accuracy certifications and calibration records for all scales 
and monitoring equipment, including the method or manufacturer's 
specification used for calibration.
    (c) Certifications of the quantity of gas, in pounds, charged into 
equipment at the electrical equipment manufacturer or refurbishment 
facility as well as the actual quantity of gas, in pounds, charged into 
equipment at installation.

[[Page 1072]]

    (d) Check-out and weigh-in sheets and procedures for cylinders.
    (e) Residual gas amounts, in pounds, in cylinders sent back to 
suppliers.
    (f) Invoices for gas purchases and sales.
    (g) GHG Monitoring Plans, as described in Sec. 98.3(g)(5), must be 
completed by April 1, 2011.



Sec. 98.458  Definitions.

    All terms used in this subpart have the same meaning given in the 
CAA and subpart A of this part.



                  Subpart TT_Industrial Waste Landfills

    Source: 75 FR 39773, July 12, 2010, unless otherwise noted.



Sec. 98.460  Definition of the source category.

    (a) This source category applies to industrial waste landfills that 
accepted waste on or after January 1, 1980, and that are located at a 
facility whose total landfill design capacity is greater than or equal 
to 300,000 metric tons.
    (b) An industrial waste landfill is a landfill other than a 
municipal solid waste landfill, a RCRA Subtitle C hazardous waste 
landfill, or a TSCA hazardous waste landfill, in which industrial solid 
waste, such as RCRA Subtitle D wastes (non-hazardous industrial solid 
waste, defined in 40 CFR 257.2), commercial solid wastes, or 
conditionally exempt small quantity generator wastes, is placed. An 
industrial waste landfill includes all disposal areas at the facility.
    (c) This source category does not include:
    (1) Construction and demolition waste landfills.
    (2) Industrial waste landfills that only receive one or more of the 
following inert waste materials:
    (i) Coal combustion or incinerator ash (e.g., fly ash).
    (ii) Cement kiln dust.
    (iii) Rocks and/or soil from excavation and construction and similar 
activities.
    (iv) Glass.
    (v) Non-chemically bound sand (e.g., green foundry sand).
    (vii) Clay, gypsum, or pottery cull.
    (viii) Bricks, mortar, or cement.
    (ix) Furnace slag.
    (x) Materials used as refractory (e.g., alumina, silicon, fire clay, 
fire brick).
    (xi) Plastics (e.g., polyethylene, polypropylene, polyethylene 
terephthalate, polystyrene, polyvinyl chloride).
    (xii) Other waste material that has a volatile solids concentration 
of 0.5 weight percent (on a dry basis) or less.
    (xiii) Other waste material that has a DOC value of 0.3 weight 
percent (on a wet basis) or less. DOC value must be determined using a 
60-day anaerobic biodegradation test procedure identified in Sec. 
98.464(b)(4)(i).
    (d) This source category consists of the following sources at 
industrial waste landfills: Landfills, gas collection systems at 
landfills, and destruction devices for landfill gases (including 
flares).

[75 FR 39773, July 12, 2010, as amended at 76 FR 73907, Nov. 29, 2011, 
77 FR 51495, Aug. 24, 2012; 78 FR 71979, Nov. 29, 2013]



Sec. 98.461  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains an industrial waste landfill meeting the criteria in Sec. 
98.460 and the facility meets the requirements of Sec. 98.2(a)(2). For 
the purposes of Sec. 98.2(a)(2), the emissions from the industrial 
waste landfill are to be determined using the methane generation 
corrected for oxidation as determined using Equation TT-6 of this 
subpart times the global warming potential for methane in Table A-1 of 
subpart A of this part.



Sec. 98.462  GHGs to report.

    (a) You must report CH4 generation and CH4 
emissions from industrial waste landfills.
    (b) You must report CH4 destruction resulting from 
landfill gas collection and destruction devices, if present.
    (c) You must report under subpart C of this part (General Stationary 
Fuel Combustion Sources) the emissions of CO2, 
CH4, and N2O from each stationary combustion unit 
associated with the landfill gas destruction device, if present, by 
following the requirements of subpart C of this part.

[[Page 1073]]



Sec. 98.463  Calculating GHG emissions.

    (a) For each industrial waste landfill subject to the reporting 
requirements of this subpart, calculate annual modeled CH4 
generation according to the applicable requirements in paragraphs (a)(1) 
through (a)(3) of this section. Apply Equation TT-1 of this section for 
each waste stream disposed of in the landfill and sum the CH4 
generation rates for all waste streams disposed of in the landfill to 
calculate the total annual modeled CH4 generation rate for 
the landfill.
    (1) Calculate annual modeled CH4 generation using 
Equation TT-1 of this section.
[GRAPHIC] [TIFF OMITTED] TR29NO11.004

Where:

GCH4 = Modeled methane generation in reporting year T (metric 
          tons CH4).
X = Year in which waste was disposed.
S = Start year of calculation. Use the year 1960 or the opening year of 
          the landfill, whichever is more recent.
T = Reporting year for which emissions are calculated.
WX = Quantity of waste disposed in the industrial waste 
          landfill in year X from measurement data and/or other company 
          records (metric tons, as received (wet weight)).
DOCX = Degradable organic carbon for waste disposed in year X 
          from Table TT-1 to this subpart or from measurement data [as 
          specified in paragraph (a)(3) of this section], if available 
          [fraction (metric tons C/metric ton waste)].
DOCF = Fraction of DOC dissimilated (fraction); use the 
          default value of 0.5. If measured values of DOC are available 
          using the 60-day anaerobic biodegradation test procedure 
          identified in Sec. 98.464(b)(4)(i), use a default value of 
          1.0.
MCF = Methane correction factor (fraction). Use the default value of 1 
          unless there is active aeration of waste within the landfill 
          during the reporting year. If there is active aeration of 
          waste within the landfill during the reporting year, use 
          either the default value of 1 or select an alternative value 
          no less than 0.5 based on site-specific aeration parameters.
F = Fraction by volume of CH4 in landfill gas (fraction, dry 
          basis, corrected to 0% oxygen). If you have a gas collection 
          system, use the annual average CH4 concentration 
          from measurement data for the current reporting year; 
          otherwise, use the default value of 0.5.
k = Decay rate constant from Table TT-1 to this subpart (yr-1). Select 
          the most applicable k value for the majority of the past 10 
          years (or operating life, whichever is shorter).

    (2) Waste stream quantities. Determine annual waste quantities as 
specified in paragraphs (a)(2)(i) through (ii) of this section for each 
year starting with January 1, 1960 or the year the landfills first 
accepted waste if after January 1, 1960, up until the most recent 
reporting year. The choice of method for determining waste quantities 
will vary according to the availability of historical data. Beginning in 
the first emissions reporting year (2011 or later) and for each year 
thereafter, use the procedures in paragraph (a)(2)(i) of this section to 
determine waste stream quantities. These procedures should also be used 
for any year prior to the first emissions reporting year for which the 
data are available. For other historical years, use paragraph (a)(2)(i) 
of this section, where waste disposal records are available, and use the 
procedures outlined in paragraph (a)(2)(ii) of this section when waste 
disposal records are unavailable, to determine waste stream quantities. 
Historical disposal quantities deposited (i.e., prior to the first year 
in which monitoring begins) should only be determined once, as part of 
the first annual report, and the same values should be used for all 
subsequent annual reports, supplemented by the next year's data on new 
waste disposal.
    (i) Determine the quantity of waste (in metric tons as received, 
i.e., wet weight) disposed of in the landfill separately for each waste 
stream by any one or a combination of the following methods.
    (A) Direct mass measurements.

[[Page 1074]]

    (B) Direct volume measurements multiplied by waste stream density 
determined from periodic density measurement data or process knowledge.
    (C) Mass balance procedures, determining the mass of waste as the 
difference between the mass of the process inputs and the mass of the 
process outputs.
    (D) The number of loads (e.g., trucks) multiplied by the mass of 
waste per load based on the working capacity of the container or 
vehicle.
    (ii) Determine the historical disposal quantities for landfills 
using the Waste Disposal Factor approach in paragraphs (a)(2)(ii)(A) and 
(B) of this section when historical production or processing data are 
available. If production or processing data are available for a given 
year, you must use Equation TT-3 of this section for that year. 
Determine historical disposal quantities using the method specified in 
paragraph (a)(2)(ii)(C) of this section when historical production or 
processing data are not available, and for waste streams received from 
an off-site facility when historical disposal quantities cannot be 
determined using the methods specified in paragraph (a)(2)(i) of this 
section.
    (A) Determining Waste Disposal Factor: For each waste stream 
disposed of in the landfill, calculate the average waste disposal rate 
per unit of production or unit throughput using all available waste 
quantity data and corresponding production or processing rates for the 
process generating that waste or, if appropriate, the facility, using 
Equation TT-2 of this section.
[GRAPHIC] [TIFF OMITTED] TR12JY10.021

Where:

WDF = Average waste disposal factor as determined for the first annual 
          report required for this industrial waste landfill (metric 
          tons per production unit).
X = Year in which waste was disposed. Include only those years for which 
          disposal and production data are both available; the years do 
          not need to be sequential.
Y1 = First year in which disposal and production/throughput 
          data are both available.
Y2 = First year for which GHG emissions from this industrial 
          waste landfill must be reported.
N = Number of years for which disposal and production/throughput data 
          are both available.
Wx = Quantity of waste placed in the industrial waste 
          landfill in year X from measurement data and/or other company 
          records (metric tons, as received (wet weight)).
Px = Quantity of product produced or feedstock entering the 
          process or facility in year X from measurement data and/or 
          other company records (production units). You must use the 
          same basis for all years in the calculation. That is, 
          Px must be determined based on production (quantity 
          of product produced) for all ``N'' years or Px must 
          be determined based on throughput (quantity of feedstock) for 
          all ``N'' years.

    (B) Calculate waste: For each waste stream disposed of in the 
landfill, calculate the waste disposal quantities for historic years in 
which direct waste disposal measurements are not available using 
historical production data and Equation TT-3 of this section.
[GRAPHIC] [TIFF OMITTED] TR12JY10.022

Where:

X = Historic year in which waste was disposed.
Wx = Calculated quantity of waste placed in the landfill in 
          year X (metric tons).
WDF = Average waste disposal factor from Equation TT-2 of this section 
          (metric tons per production unit).
Px = Quantity of product produced or feedstock entering the 
          process or facility in year X from measurement data and/or 
          other company records (production units). You must use the 
          same basis for Px (either production only or 
          throughput only) as used to determine WDF in Equation TT-2 of 
          this section.

    (C) For any year in which historic production or processing data are 
not available such that historic waste quantities cannot be estimated 
using Equation TT-3 of this section, calculate an average annual bulk 
waste disposal quantity using either Equation TT-4a of this section when 
data are available consecutively for the most recent disposal years or 
Equation TT-4b of this section when data are available for sporadic 
(non-consecutive) years.

[[Page 1075]]

[GRAPHIC] [TIFF OMITTED] TR29NO11.005

Where:

WX = Quantity of waste placed in the landfill in year X 
          (metric tons, wet basis). This annual bulk waste disposal 
          quantity applies for all years from ``YrOpen'' to ``YrData'' 
          inclusive.
LFC = Capacity of the landfill used (or the total quantity of waste-in-
          place) at the end of the ``YrData'' from design drawings or 
          engineering estimates (metric tons). For closed landfills for 
          which waste quantity data are not available, use the 
          landfill's design capacity.
YrData = The year prior to the year when waste disposal data are first 
          available for all subsequent years from company records or 
          from Equation TT-3 of this section. For landfills for which 
          waste quantity data are not available, the year in which the 
          landfill last received waste.
YrOpen = Year 1960 or the year in which the landfill first received 
          waste from company records, whichever is more recent. If no 
          data are available for estimating YrOpen for a closed 
          landfill, use 1960 as the default ``YrOpen'' for the landfill.
          [GRAPHIC] [TIFF OMITTED] TR29NO11.006
          
Where:

WX = Quantity of waste placed in the landfill in year X 
          (metric tons, wet basis). This annual bulk waste disposal 
          quantity applies for all years for which waste quantity data 
          are not available from company records or from Equation TT-3 
          of this section.
WIP = Quantity of waste in-place at the start of the reporting year from 
          design drawings or engineering estimates (metric tons). For 
          closed landfills for which waste in-place quantities are not 
          available, use the landfill's design capacity.
Wmeas,n = Annual quantity of waste placed in the landfill for 
          the nth measurement year from company records or from Equation 
          TT-3 of this section.
YrLast = The last year, prior to the reporting year, that the landfill 
          received waste.
YrOpen = Year 1960 or the year in which the landfill first received 
          waste from company records, whichever is more recent. If no 
          data are available for estimating YrOpen for a closed 
          landfill, use 1960 as the default ``YrOpen'' for the landfill.
NYrData = The number of years for which annual waste disposal quantities 
          are available from company records or from Equation TT-3 of 
          this section from YrOpen to YrLast inclusive.

    (3) Degradable organic content (DOC). For any year, X, in Equation 
TT-1 of this section, use either the applicable default DOC values 
provided in Table TT-1 of this subpart or determine values for 
DOCx as specified in paragraphs (a)(3)(i) through (iv) of 
this section. When developing historical waste quantity data, you may 
use default DOC values from Table TT-1 of this subpart for certain years 
and determined values for DOCx for other years. The 
historical values for DOC or DOCx must be developed only for 
the first annual report required for the industrial waste landfill; and 
used for all subsequent annual reports (e.g., if DOC for year x = 1990 
was determined to be 0.15 in the first reporting year, you must use 0.15 
for the 1990 DOC value for all subsequent annual reports).
    (i) For the first year in which GHG emissions from this industrial 
waste landfill must be reported, determine the DOCx value of 
each waste stream disposed of in the landfill no less frequently than 
once per quarter using the methods specified in Sec. 98.464(b). 
Calculate annual DOCx for each waste stream as the arithmetic 
average of all DOCx values for that waste stream that were 
measured during the year.
    (ii) For subsequent years (after the first year in which GHG 
emissions from this industrial waste landfill must be reported), either 
use the DOCx of each

[[Page 1076]]

waste stream calculated for the most recent reporting year for which DOC 
values were determined according to paragraph (a)(3)(i) of this section, 
or determine new DOC values for that year following the requirements in 
paragraph (a)(3)(i) of this section. You must determine new DOC values 
following the requirements in paragraph (a)(3)(i) of this section if 
changes in the process operations occurred during the previous reporting 
year that can reasonably be expected to alter the characteristics of the 
waste stream, such as the water content or volatile solids 
concentration. Should changes to the waste stream occur, you must revise 
the GHG Monitoring Plan as required in Sec. 98.3(g)(5)(iii) and report 
the new DOCx value according to the requirements of Sec. 
98.466.
    (iii) If DOCx measurement data for each waste stream are 
available according to the methods specified in Sec. 98.464(b) for 
years prior to the first year in which GHG emissions from this 
industrial waste landfill must be reported, determine DOCx 
for each waste stream as the arithmetic average of all DOCx 
values for that waste stream that were measured in Year X. A single 
measurement value is acceptable for determining DOCx for 
years prior to the first reporting year.
    (iv) For historical years for which DOCx measurement 
data, determined according to the methods specified in Sec. 98.464(b), 
are not available, determine the historical values for DOCx 
using the applicable methods specified in paragraphs (a)(3)(iv)(A) and 
(B) of this section. Determine these historical values for 
DOCx only for the first annual report required for this 
industrial waste landfill; historical values for DOCx 
calculated for this first annual report should be used for all 
subsequent annual reports.
    (A) For years in which waste stream-specific disposal quantities are 
determined (as required in paragraphs (a)(2) (ii)(A) and (B) of this 
section), calculate the average DOC value for a given waste stream as 
the arithmetic average of all DOC measurements of that waste stream that 
follow the methods provided in Sec. 98.464(b), including any 
measurement values for years prior to the first reporting year and the 
four measurement values required in the first reporting year. Use the 
resulting waste-specific average DOC value for all applicable years 
(i.e., years in which waste stream-specific disposal quantities are 
determined) for which direct DOC measurement data are not available.
    (B) For years for which bulk waste disposal quantities are 
determined according to paragraphs (a)(2)(ii)(C) of this section, 
calculate the weighted average bulk DOC value according to the 
following: Calculate the average DOC value for each waste stream as the 
arithmetic average of all DOC measurements of that waste stream that 
follows the methods provided in Sec. 98.464(b) (generally, this will 
include only the DOC values determined in the first year in which GHG 
emissions from this industrial waste landfill must be reported); 
calculate the average annual disposal quantity for each waste stream as 
the arithmetic average of the annual disposal quantities for each year 
in which waste stream-specific disposal quantities have been determined; 
and calculate the bulk waste DOC value using Equation TT-5 of this 
section. Use the bulk waste DOC value as DOCx for all years 
for which bulk waste disposal quantities are determined according to 
paragraphs (a)(2)(ii)(C) of this section.
[GRAPHIC] [TIFF OMITTED] TR12JY10.024


[[Page 1077]]


Where:

DOCbulk = Degradable organic content value for bulk 
          historical waste placed in the landfill (mass fraction).
N = Number of different waste streams placed in the landfill.
n = Index for waste stream.
DOCave,n = Average degradable organic content value for waste 
          stream ``n'' based on available measurement data (mass 
          fraction).
Wave,n = Average annual quantity of waste stream ``n'' placed 
          in the landfill for years in which waste stream-specific 
          disposal quantities have been determined (metric tons per 
          year, wet basis).

    (b) For each landfill, calculate CH4 generation (adjusted 
for oxidation in cover materials) and CH4 emissions (taking 
into account any CH4 recovery, if applicable, and oxidation 
in cover materials) according to the applicable methods in paragraphs 
(b)(1) through (b)(3) of this section.
    (1) For each landfill, calculate CH4 generation, adjusted 
for oxidation, from the modeled CH4 (GCH4 from 
Equation TT-1 of this section) using Equation TT-6 of this section.
[GRAPHIC] [TIFF OMITTED] TR12JY10.025


Where:

MG = Methane generation, adjusted for oxidation, from the landfill in 
          the reporting year (metric tons CH4).
GCH4 = Modeled methane generation rate in reporting year from 
          Equation TT-1 of this section (metric tons CH4).
OX = Oxidation fraction from Table HH-4 of subpart HH of this part.

    (2) For landfills that do not have landfill gas collection systems 
operating during the reporting year, the CH4 emissions are 
equal to the CH4 generation (MG) calculated in Equation TT-6 
of this section.
    (3) For landfills with landfill gas collection systems in operation 
during any portion of the reporting year, perform all of the 
calculations specified in paragraphs (b)(3)(i) through (iv) of this 
section.
    (i) Calculate the quantity of CH4 recovered according to 
the requirements at Sec. 98.343(b).
    (ii) Calculate CH4 emissions using the Equation HH-6 of 
Sec. 98.343(c)(3)(i), except use GCH4 determined using 
Equation TT-1 of this section in Equation HH-6 of Sec. 98.343(c)(3)(i).
    (iii) Calculate CH4 generation (MG) from the quantity of 
CH4 recovered using Equation HH-7 of Sec. 98.343(c)(3)(ii).
    (iv) Calculate CH4 emissions from the quantity of 
CH4 recovered using Equation HH-8 of Sec. 98.343(c)(3)(ii).

[75 FR 39773, July 12, 2010, as amended at 76 FR 73907, Nov. 29, 2011; 
78 FR 71979, Nov. 29, 2013]



Sec. 98.464  Monitoring and QA/QC requirements.

    (a) For calendar year 2011 monitoring, the facility may submit a 
request to the Administrator to use one or more best available 
monitoring methods as listed in Sec. 98.3(d)(1)(i) through (iv). The 
request must be submitted no later than October 12, 2010 and must 
contain the information in Sec. 98.3(d)(2)(ii). To obtain approval, the 
request must demonstrate to the Administrator's satisfaction that it is 
not reasonably feasible to acquire, install, and operate a required 
piece of monitoring equipment by January 1, 2011. The use of best 
available monitoring methods will not be approved beyond December 31, 
2011.
    (b) For each waste stream placed in the landfill during the 
reporting year for which you choose to determine volatile solids 
concentration and/or a waste stream-specific DOCX, you must 
collect and test a representative sample of that waste stream using the 
methods specified in paragraphs (b)(1) through (b)(4) of this section, 
as applicable.
    (1) Develop and follow a sampling plan to collect a representative 
sample (in terms of composition and moisture content) of each waste 
stream placed in the landfill for which testing is elected.
    (2) Determine the percent total solids and the percent volatile 
solids of each sample following Standard Method 2540G ``Total, Fixed, 
and Volatile Solids in Solid and Semisolid Samples'' (incorporated by 
reference; see Sec. 98.7).
    (3) For the purposes of Sec. 98.460(c)(2)(xii), the volatile solids 
concentration (weight percent on a dry basis) is the percent volatile 
solids determined using Standard Method 2540G ``Total, Fixed, and 
Volatile Solids in Solid and Semisolid Samples'' (incorporated by 
reference; see Sec. 98.7).

[[Page 1078]]

    (4) Determine DOC value of a waste stream by either using at least a 
60-day anaerobic biodegradation test as specified in paragraph (b)(4)(i) 
of this section or by estimating the DOC value based on the total and 
volatile solids measurements as specified in paragraph (b)(4)(ii) of 
this section.
    (i) Perform an anaerobic biodegradation test and determine the DOC 
value of a waste stream following the procedures and requirements in 
paragraphs (b)(4)(i)(A) through (E) of this section.
    (A) You may use the procedures published by a consensus-based 
standards organization to conduct a minimum of a 60-day anaerobic 
biodegradation test. Consensus-based standards organizations include, 
but are not limited to, the following: ASTM International (100 Barr 
Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-
B2959, (800) 262-1373, http://www.astm.org), the American National 
Standards Institute (ANSI, 1819 L Street, NW., 6th floor, Washington, DC 
20036, (202) 293-8020, http://www.ansi.org), the American Society of 
Mechanical Engineers (ASME, Three Park Avenue, New York, NY 10016-5990, 
(800) 843-2763, http://www.asme.org), and the North American Energy 
Standards Board (NAESB, 801 Travis Street, Suite 1675, Houston, TX 
77002, (713) 356-0060, http://www.api.org).
    (B) Use a minimum of four samples: Two waste stream samples, a 
control sample using a known substrate (such as ethanol), and a digester 
sludge blank sample. Each waste stream sample must be appropriately 
ground to ensure the waste material is fully exposed to the anaerobic 
digester sludge.
    (C) Determine the net mass of carbon degraded in the control sample 
as the difference in the results of the control sample and the digester 
sludge blank sample. Determine the net mass of carbon degraded in each 
waste stream sample as the difference in the results of each waste 
stream sample and the digester sludge blank sample.
    (D) Determine the fraction of carbon degraded in the control sample 
as the net mass of carbon degraded in the control sample divided by the 
mass of carbon added via the substrate material in the control sample. 
If less than 50 percent of the theoretical mass of carbon in the control 
sample is degraded, the test run is invalid.
    (E) Determine the DOC of each waste sample using Equation TT-7 of 
this section. If the DOC values for the two waste stream samples differ 
by more than 20 percent, the test run is invalid. The DOC of the waste 
stream is determined as the average DOC value of the two waste stream 
samples determined during a valid test.
[GRAPHIC] [TIFF OMITTED] TR29NO13.026

Where:

DOCX = Degradable organic content of the waste stream in Year 
          X (weight fraction, wet basis)
MCDsample,x = Mass of carbon degraded in the waste stream 
          sample in Year X as determined in paragraph (b)(4)(i)(C) of 
          this section [milligrams (mg)].
Msample,x = Mass of waste stream sample used in the anaerobic 
          degradation test in Year X (mg, wet basis).

    (ii) Calculate the waste stream-specific DOCX value using 
Equation TT-8 of this section.
[GRAPHIC] [TIFF OMITTED] TR29NO11.008


[[Page 1079]]


Where:

DOCX = Degradable organic content of waste stream in Year X 
          (weight fraction, wet basis)
FDOC = Fraction of the volatile residue that is degradable 
          organic carbon (weight fraction). Use a default value of 0.6.
% Volatile SolidsX = Percent volatile solids determined using 
          Standard Method 2540G Total, ``Fixed, and Volatile Solids in 
          Solid and Semisolid Samples'' (incorporated by reference; see 
          Sec. 98.7) for Year X [milligrams (mg) volatile solids per 
          100 mg dried solids].
% Total SolidsX = Percent total solids determined using 
          Standard Method 2540G ``Total, Fixed, and Volatile Solids in 
          Solid and Semisolid Samples'' (incorporated by reference; see 
          Sec. 98.7) for Year X (mg dried solids per 100 mg wet waste).

    (c) For each waste stream that was historically managed in the 
landfill for which you choose to determine volatile solids concentration 
and/or a waste stream-specific DOCX, you must determine 
volatile solids concentration or DOCX of the waste stream as 
initially placed in the landfill using the methods specified in 
paragraph (c)(1) or (2) of this section, as applicable.
    (1) If you can identify a similar waste stream to the waste stream 
that was historically managed in the landfill, you must determine the 
volatile solids concentration or DOCX of the similar waste 
stream using the applicable procedures in paragraphs (b)(1) through (4) 
of this section.
    (2) If you cannot identify a similar waste stream to the waste 
stream that was historically managed in the landfill, you may determine 
the volatile solids concentration or DOCX of the historically 
managed waste stream using process knowledge. You must document the 
basis for the volatile solids concentration or DOCX value as 
determined through process knowledge.
    (d) For landfills with gas collection systems, operate, maintain, 
and calibrate a gas composition monitor capable of measuring the 
concentration of CH4 according to the requirements specified 
at Sec. 98.344(b).
    (e) For landfills with gas collection systems, install, operate, 
maintain, and calibrate a gas flow meter capable of measuring the 
volumetric flow rate of the recovered landfill gas according to the 
requirements specified at Sec. 98.344(c).
    (f) For landfills with gas collection systems, all temperature, 
pressure, and if applicable, moisture content monitors must be 
calibrated using the procedures and frequencies specified by the 
manufacturer.
    (g) For landfills electing to measure the fraction by volume of 
CH4 in landfill gas (F), follow the requirements in 
paragraphs (g)(1) and (g)(2) of this section.
    (1) Use a gas composition monitor capable of measuring the 
concentration of CH4 on a dry basis that is properly 
operated, calibrated, and maintained according to the requirements 
specified at Sec. 98.344(b). You must either use a gas composition 
monitor that is also capable of measuring the O2 
concentration correcting for excess (infiltration) air or you must 
operate, maintain, and calibrate a second monitor capable of measuring 
the O2 concentration on a dry basis according to the 
manufacturer's specifications.
    (2) Use Equation TT-9 of this section to correct the measured 
CH4 concentration to 0% oxygen. If multiple CH4 
concentration measurements are made during the reporting year, determine 
F separately for each measurement made during the reporting year, and 
use the results to determine the arithmetic average value of F for use 
in Equation TT-1 of this part.
[GRAPHIC] [TIFF OMITTED] TR29NO11.009

Where:

F = Fraction by volume of CH4 in landfill gas (fraction, dry 
          basis, corrected to 0% oxygen).

[[Page 1080]]

CCH4 = Measured CH4 concentration in landfill gas 
          (volume %, dry basis).
20.9c = Defined O2 correction basis, (volume %, 
          dry basis).
20.9 = O2 concentration in air (volume %, dry basis).
%O2 = Measured O2 concentration in landfill gas 
          (volume %, dry basis).

    (h) The facility shall document the procedures used to ensure the 
accuracy of the estimates of disposal quantities and, if the industrial 
waste landfill has a gas collection system, gas flow rate, gas 
composition, temperature, pressure, and moisture content measurements. 
These procedures include, but are not limited to, calibration of 
weighing equipment, fuel flow meters, and other measurement devices. The 
estimated accuracy of measurements made with these devices shall also be 
recorded, and the technical basis for these estimates shall be provided.

[75 FR 39773, July 12, 2010, as amended at 76 FR 73908, Nov. 29, 2011; 
77 FR 51495, Aug. 24, 2012; 78 FR 71979, Nov. 29, 2013]



Sec. 98.465  Procedures for estimating missing data.

    (a) A complete record of all measured parameters used in the GHG 
emissions calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable (e.g., if a meter 
malfunctions during unit operation or if a required fuel sample is not 
taken), a substitute data value for the missing parameter shall be used 
in the calculations, in accordance with paragraph (b) of this section.
    (b) For industrial waste landfills with gas collection systems, 
follow the procedures for estimating missing data specified in Sec. 
98.345(a) and (b).



Sec. 98.466  Data reporting requirements.

    In addition to the information required by Sec. 98.3(c), each 
annual report must contain the following information for each landfill.
    (a) Report the following general landfill information:
    (1) A classification of the landfill as ``open'' (actively received 
waste in the reporting year) or ``closed'' (no longer receiving waste).
    (2) The year in which the landfill first started accepting waste for 
disposal.
    (3) The last year the landfill accepted waste (for open landfills, 
enter the estimated year of landfill closure).
    (4) The capacity (in metric tons) of the landfill.
    (5) An indication of whether leachate recirculation is used during 
the reporting year and its typical frequency of use over the past 10 
years (e.g., used several times a year for the past 10 years, used at 
least once a year for the past 10 years, used occasionally but not every 
year over the past 10 years, not used).
    (b) Report the following waste characterization and modeling 
information:
    (1) The number of waste steams (including ``Other Industrial Solid 
Waste (not otherwise listed)'' and ``Inerts'') for which Equation TT-1 
of this subpart is used to calculate modeled CH4 generation.
    (2) A description of each waste stream (including the types of 
materials in each waste stream) for which Equation TT-1 of this subpart 
is used to calculate modeled CH4 generation.
    (3) The fraction of CH4 in the landfill gas, F, (volume 
fraction, dry basis, corrected to 0% oxygen) for the reporting year and 
an indication as to whether this was the default value or a value 
determined through measurement data.
    (4) The methane correction factor (MCF) value used in the 
calculations. If an MCF value other than the default of 1 is used, 
provide a description of the aeration system, including aeration blower 
capacity, the fraction of the landfill containing waste affected by the 
aeration, the total number of hours during the year the aeration blower 
was operated, and other factors used as a basis for the selected MCF 
value.
    (5) For each waste stream, the decay rate (k) value used in the 
calculations.
    (c) Report the following historical waste information:
    (1) [Reserved]
    (2) For each waste stream identified in paragraph (b) of this 
section, the method(s) for estimating historical waste disposal 
quantities and the range of years for which each method applies.
    (3) For each waste stream identified in paragraph (b) of this 
section for which Equation TT-2 of this subpart is used, provide:

[[Page 1081]]

    (i) [Reserved]
    (ii) The year of the data used in Equation TT-2 of Sec. 98.463 for 
the waste disposal quantity and production quantity, for each year used 
in Equation TT-2 to calculate the average waste disposal factor (WDF).
    (iii) [Reserved]
    (4) If Equation TT-4a of this subpart is used, provide:
    (i) The value of landfill capacity (LFC).
    (ii) YrData.
    (iii) YrOpen.
    (5) If Equation TT-4b of this subpart is used, provide:
    (i) WIP (i.e., the quantity of waste in-place at the start of the 
reporting year from design drawings or engineering estimates (metric 
tons) or, for closed landfills for which waste in-place quantities are 
not available, the landfill's design capacity).
    (ii) The cumulative quantity of waste placed in the landfill for the 
years for which disposal quantities are available from company record or 
from Equation TT-3 of this part.
    (iii) YrLast.
    (iv) YrOpen.
    (v) NYrData.
    (d) For each year of landfilling starting with the ``Start Year'' 
(S) and each year thereafter up to the current reporting year, report 
the following information:
    (1) The calendar year for which the following data elements apply.
    (2) The quantity of waste (WX) disposed of in the 
landfill (metric tons, wet weight) for the specified year for each waste 
stream identified in paragraph (b) of this section.
    (3) For each waste stream, the degradable organic carbon 
(DOCX) value (mass fraction) for the specified year and an 
indication as to whether this was the default value from Table TT-1 to 
this subpart, a measured value using a 60-day anaerobic biodegradation 
test as specified in Sec. 98.464(b)(4)(i), or a value based on total 
and volatile solids measurements as specified in Sec. 98.464(b)(4)(ii). 
If DOCX was determined by a 60-day anaerobic biodegradation 
test, specify the test method used.
    (e) Report the following information describing the landfill cover 
material:
    (1) The type of cover material used (as either organic cover, clay 
cover, sand cover, or other soil mixtures).
    (2) For each type of cover material used, the surface area (in 
square meters) at the start of the reporting year for the landfill 
sections that contain waste and that are associated with the selected 
cover type.
    (f) The modeled annual methane generation (GCH4) for the 
reporting year (metric tons CH4) calculated using Equation 
TT-1 of this subpart.
    (g) For landfills without gas collection systems, provide:
    (1) The annual methane emissions (i.e., the methane generation (MG), 
adjusted for oxidation, calculated using Equation TT-6 of this subpart), 
reported in metric tons CH4.
    (2) An indication of whether passive vents and/or passive flares 
(vents or flares that are not considered part of the gas collection 
system as defined in Sec. 98.6) are present at this landfill.
    (h) For landfills with gas collection systems, in addition to the 
reporting requirements in paragraphs (a) through (f) of this section, 
provide:
    (1) The annual methane generation, adjusted for oxidation, 
calculated using Equation TT-6 of this subpart, reported in metric tons 
CH4.
    (2) The oxidation factor used in Equation TT-6 of this subpart.
    (3) All information required under 40 CFR 98.346(i)(1) through (7) 
and 40 CFR 98.346(i)(9) through (12).

[75 FR 39773, July 12, 2010, as amended at 76 FR 73909, Nov. 29, 2011; 
78 FR 71980, Nov. 29, 2013; 79 FR 63799, Oct. 24, 2014]



Sec. 98.467  Records that must be retained.

    (a) The calibration records for all monitoring equipment, including 
the method or manufacturer's specification used for calibration, and all 
measurement data used for the purposes of Sec. 98.460(c)(2)(xii) or 
(xiii) or used to determine waste stream-specific DOCX values 
for use in Equation TT-1 of Sec. 98.463.
    (b) Verification software records. You must keep a record of the 
file generated by the verification software specified in Sec. 98.5(b) 
for the applicable data specified in paragraphs (b)(1) and (2) of this 
section. Retention of this file

[[Page 1082]]

satisfies the recordkeeping requirement for the data in paragraphs 
(b)(1) and (2) of this section.
    (1) Quantity of each product produced or feedstock entering the 
process or facility per waste stream per year, from measurement data 
and/or other company records. You must use the same basis for all years 
in the calculation (i.e., based on production or based on quantity of 
feedstock) (metric tons) (Equation TT-2 of Sec. 98.463).
    (2) [Reserved]

[79 FR 63799, Oct. 24, 2014]



Sec. 98.468  Definitions.

    Except as provided below, all terms used in this subpart have the 
same meaning given in the CAA and subpart A of this part.
    Construction and demolition (C&D) waste landfill means a solid waste 
disposal facility subject to the requirements of subparts A or B of part 
257 of this chapter that receives construction and demolition waste and 
does not receive hazardous waste (defined in Sec. 261.3 of this 
chapter) or industrial solid waste (defined in Sec. 258.2 of this 
chapter) or municipal solid waste (defined in Sec. 98.6 of this part) 
other than residential lead-based paint waste. A C&D waste landfill 
typically receives any one or more of the following types of solid 
wastes: roadwork material, excavated material, demolition waste, 
construction/renovation waste, and site clearance waste.
    Design capacity means the maximum amount of solid waste a landfill 
can accept. For the purposes of this subpart, for landfills that have a 
permit, the design capacity can be determined in terms of volume or mass 
in the most recent permit issued by the state, local, or Tribal agency 
responsible for regulating the landfill, plus any in-place waste not 
accounted for in the most recent permit. If the owner or operator 
chooses to convert the design capacity from volume to mass to determine 
its design capacity, the calculation must include a site-specific 
density. If the design capacity is within 10 percent of the 
applicability threshold in Sec. 98.460(a) and there is a change in the 
production process that can reasonably be expected to change the site-
specific waste density, the site-specific waste density must be 
redetermined and the design capacity must be recalculated based on the 
new waste density.
    Industrial sludge means the residual, semi-solid material left from 
industrial wastewater treatment processes or wet air pollution control 
devices (e.g., wet scrubbers). Industrial sludge includes underflow 
material collected in primary or secondary clarifiers, settling basins, 
or precipitation tanks as well as dredged materials from wastewater 
tanks or impoundments. Industrial sludge also includes the semi-solid 
materials remaining after these materials are dewatered via a belt 
process, centrifuge, or similar dewatering process.
    Solid waste has the meaning established by the Administrator 
pursuant to the Solid Waste Disposal Act (42 U.S.C.A. 6901 et seq.).
    Waste stream means industrial solid waste material that is generated 
by a specific manufacturing process or client. For wastes generated at 
the facility that includes the industrial waste landfill, a waste stream 
is the industrial solid waste material generated by a specific 
processing unit at that facility. For industrial solid wastes that are 
received from off-site facilities, a waste stream can be defined as each 
waste shipment or group of waste shipments received from a single client 
or group of clients that produce industrial solid wastes with similar 
waste properties.

[75 FR 39773, July 12, 2010, as amended at 76 FR 73910, Nov. 29, 2011; 
78 FR 71980, Nov. 29, 2013]

[[Page 1083]]



  Sec. Table TT-1 to Subpart TT of Part 98--Default DOC and Decay Rate 
                  Values for Industrial Waste Landfills

----------------------------------------------------------------------------------------------------------------
                                       DOC (weight           k [dry                                  k [wet
        Industry/Waste Type           fraction, wet     climate\a\] (yr-      k [moderate       climate\a\] (yr-
                                          basis)               1)          climate\a\] (yr-1)          1)
----------------------------------------------------------------------------------------------------------------
Food Processing (other than                      0.22               0.06                 0.12               0.18
 industrial sludge)...............
Pulp and Paper (other than                       0.20               0.02                 0.03               0.04
 industrial sludge)...............
Wood and Wood Product (other than                0.43               0.02                 0.03               0.04
 industrial sludge)...............
Construction and Demolition.......               0.08               0.02                 0.03               0.04
Industrial Sludge.................               0.09               0.02                 0.04               0.06
----------------------------------------------------------------------------------------------------------------
Inert Waste [i.e., wastes listed                    0                  0                    0                  0
 in Sec. 98.460(c)(2)]..........
Other Industrial Solid Waste (not                0.20               0.02                 0.04               0.06
 otherwise listed)................
----------------------------------------------------------------------------------------------------------------
\a\ The applicable climate classification is determined based on the annual rainfall plus the recirculated
  leachate application rate. Recirculated leachate application rate (in inches/year) is the total volume of
  leachate recirculated from company records or engineering estimates and applied to the landfill divided by the
  area of the portion of the landfill containing waste [with appropriate unit conversions].
(1) Dry climate = precipitation plus recirculated leachate less than 20 inches/year
(2) Moderate climate = precipitation plus recirculated leachate from 20 to 40 inches/year (inclusive)
(3) Wet climate = precipitation plus recirculated leachate greater than 40 inches/year
Alternatively, landfills that use leachate recirculation can elect to use the k value for wet climate rather
  than calculating the recirculated leachate rate.
\(1)\ Dry climate = precipitation plus recirculated leachate less than 20 inches/year.
\(2)\ Moderate climate = precipitation plus recirculated leachate from 20 to 40 inches/year (inclusive).
\(3)\ Wet climate = precipitation plus recirculated leachate greater than 40 inches/year.


[75 FR 39773, July 12, 2010, as amended at 76 FR 73910, Nov. 29, 2011; 
78 FR 71981, Nov. 29, 2013]



                 Subpart UU_Injection of Carbon Dioxide

    Source: 75 FR 75086, Dec. 1, 2010, unless otherwise noted.



Sec. 98.470  Definition of the source category.

    (a) The injection of carbon dioxide (CO2) source category 
comprises any well or group of wells that inject a CO2 stream 
into the subsurface.
    (b) If you report under subpart RR of this part for a well or group 
of wells, you are not required to report under this subpart for that 
well or group of wells.
    (c) A facility that is subject to this part only because it is 
subject to subpart UU of this part is not required to report emissions 
under subpart C of this part or any other subpart listed in Sec. 
98.2(a)(1) or (a)(2).



Sec. 98.471  Reporting threshold.

    (a) You must report under this subpart if your facility injects any 
amount of CO2 into the subsurface.
    (b) For purposes of this subpart, any reference to CO2 
emissions in Sec. 98.2(i) shall mean CO2 received.



Sec. 98.472  GHGs to report.

    You must report the mass of CO2 received.



Sec. 98.473  Calculating CO[bdi2] received.

    (a) You must calculate and report the annual mass of CO2 
received by pipeline using the procedures in paragraphs (a)(1) or (a)(2) 
of this section and the procedures in paragraph (a)(3) of this section, 
if applicable.
    (1) For a mass flow meter, you must calculate the total annual mass 
of CO2 in a CO2 stream received in metric tons by 
multiplying the mass flow by the CO2 concentration in the 
flow, according to Equation UU-1 of this section. You must collect these 
data quarterly. Mass flow and concentration data measurements must be 
made in accordance with Sec. 98.474.

[[Page 1084]]

[GRAPHIC] [TIFF OMITTED] TR01DE10.184

where:

CO2T,r = Net annual mass of CO2 received through 
          flow meter r (metric tons).
Qr,p = Quarterly mass flow through a receiving flow meter r 
          in quarter p (metric tons).
Sr,p = Quarterly mass flow through a receiving flow meter r 
          that is redelivered to another facility without being injected 
          into your well in quarter p (metric tons).
CCO2,p,r = Quarterly CO2 concentration measurement 
          in flow for flow meter r in quarter p (wt. percent 
          CO2, expressed as a decimal fraction).
p = Quarter of the year.
r = Receiving flow meter.

    (2) For a volumetric flow meter, you must calculate the total annual 
mass of CO2 in a CO2 stream received in metric 
tons by multiplying the volumetric flow at standard conditions by the 
CO2 concentration in the flow and the density of 
CO2 at standard conditions, according to Equation UU-2 of 
this section. You must collect these data quarterly. Volumetric flow and 
concentration data measurements must be made in accordance with Sec. 
98.474.
[GRAPHIC] [TIFF OMITTED] TR01DE10.185

where:

CO2T,r = Net annual mass of CO2 received through 
          flow meter r (metric tons).
Qr,p = Quarterly volumetric flow through a receiving flow 
          meter r in quarter p at standard conditions (standard cubic 
          meters).
Sr,p = Quarterly volumetric flow through a receiving flow 
          meter r that is redelivered to another facility without being 
          injected into your well in quarter p (standard cubic meters).
D = Density of CO2 at standard conditions (metric tons per 
          standard cubic meter): 0.0018682.
CCO2,p,r = Quarterly CO2 concentration measurement 
          in flow for flow meter r in quarter p (vol. percent 
          CO2, expressed as a decimal fraction).
p = Quarter of the year.
r = Receiving flow meter.

    (3) If you receive CO2 through more than one flow meter, 
you must sum the mass of all CO2 received in accordance with 
the procedure specified in Equation UU-3 of this section.
[GRAPHIC] [TIFF OMITTED] TR01DE10.186

where:

CO2 = Total net annual mass of CO2 received 
          (metric tons).
CO2T,r = Net annual mass of CO2 received (metric 
          tons) as calculated in Equation UU-1 or UU-2 for flow meter r.
r = Receiving flow meter.

    (b) You must calculate and report the annual mass of CO2 
received in containers using the procedures specified in either 
paragraph (b)(1) or (b)(2) of this section.
    (1) If you are measuring the mass of contents in a container under 
the provisions of Sec. 98.474(a)(2)(i), you must calculate the 
CO2 received in containers using Equation UU-1 of this 
section.

where:

CO2T,r = Annual mass of CO2 received in containers 
          r (metric tons).

[[Page 1085]]

CCO2,p,r = Quarterly CO2 concentration measurement 
          of contents in containers r in quarter p (wt. percent 
          CO2, expressed as a decimal fraction).
Qr,p = Quarterly mass of contents in containers r in quarter 
          p (metric tons).
Sr,p = Quarterly mass of contents in containers r that is 
          redelivered to another facility without being injected into 
          your well in quarter p (standard cubic meters).
p = Quarter of the year.
r = Containers.

    (2) If you are measuring the volume of contents in a container under 
the provisions of Sec. 98.474(a)(2)(ii), you must calculate the 
CO2 received in containers using Equation UU-2 of this 
section.

where:

CO2T,r = Annual mass of CO2 received in containers 
          r (metric tons).
CCO2,p,r = Quarterly CO2 concentration measurement 
          of contents in containers r in quarter p (vol. percent 
          CO2, expressed as a decimal fraction).
Sr,p = Quarterly volume of contents in containers r that is 
          redelivered to another facility without being injected into 
          your well in quarter p (standard cubic meters).
Qr,p = Quarterly volume of contents in containers r in 
          quarter p (standard cubic meters).
D = Density of the CO2 received in containers at standard 
          conditions (metric tons per standard cubic meter): 0.0018682.
p = Quarter of the year.
r = Containers.

[75 FR 75078, Dec. 1, 2010, as amended at 78 FR 71981, Nov. 29, 2013]



Sec. 98.474  Monitoring and QA/QC requirements.

    (a) CO2 received. (1) You must determine the quarterly 
flow rate of CO2 received by pipeline by following the most 
appropriate of the following procedures:
    (i) You may measure flow rate at the receiving custody transfer 
meter prior to any subsequent processing operations at the facility and 
collect the flow rate quarterly.
    (ii) If you took ownership of the CO2 in a commercial 
transaction, you may use the quarterly flow rate data from the sales 
contract if it is a one-time transaction or from invoices or manifests 
if it is an ongoing commercial transaction with discrete shipments.
    (iii) If you inject CO2 from a production process unit 
that is part of your facility, you may use the quarterly CO2 
flow rate that was measured at the equivalent of a custody transfer 
meter following procedures provided in subpart PP of this part. To be 
the equivalent of a custody transfer meter, a meter must measure the 
flow of CO2 being transported to an injection well to the 
same degree of accuracy as a meter used for commercial transactions.
    (2) You must determine the quarterly mass or volume of contents in 
all containers if you receive CO2 in containers by the most 
appropriate of the following procedures:
    (i) You may measure the mass of contents of containers summed 
quarterly using weigh bills, scales, or load cells.
    (ii) You may determine the volume of the contents of containers 
summed quarterly.
    (iii) If you took ownership of the CO2 in a commercial 
transaction, you may use the quarterly mass or volume of contents from 
the sales contract if it is a one-time transaction or from invoices or 
manifests if it is an ongoing commercial transaction with discrete 
shipments.
    (3) You must determine a quarterly concentration of the 
CO2 received that is representative of all CO2 
received in that quarter by following the most appropriate of the 
following procedures:
    (i) You may sample the CO2 stream at least once per 
quarter at the point of receipt and measure its CO2 
concentration.
    (ii) If you took ownership of the CO2 in a commercial 
transaction for which the sales contract was contingent on 
CO2 concentration, and if the supplier of the CO2 
sampled the CO2 stream in a quarter and measured its 
concentration per the sales contract terms, you may use the 
CO2 concentration data from the sales contract for that 
quarter.
    (iii) If you inject CO2 from a production process unit 
that is part of your facility, you may report the quarterly 
CO2 concentration of the CO2 stream supplied that 
was measured following procedures provided in subpart PP of this part as 
the quarterly CO2 concentration of the CO2 stream 
received.
    (4) You must assume that the CO2 you receive meets the 
definition of a

[[Page 1086]]

CO2 stream unless you can trace it through written records to 
a source other than a CO2 stream.
    (b) Measurement devices. (1) All flow meters must be operated 
continuously except as necessary for maintenance and calibration.
    (2) You must calibrate all flow meters used to measure quantities 
reported in Sec. 98.476 according to the calibration and accuracy 
requirements in Sec. 98.3(i).
    (3) You must operate all measurement devices according to one of the 
following. You may use an appropriate standard method published by a 
consensus-based standards organization if such a method exists or an 
industry standard practice. Consensus-based standards organizations 
include, but are not limited to, the following: ASTM International, the 
American National Standards Institute (ANSI), the American Gas 
Association (AGA), the American Society of Mechanical Engineers (ASME), 
the American Petroleum Institute (API), and the North American Energy 
Standards Board (NAESB).
    (4) You must ensure that any flow meter calibrations performed are 
National Institute of Standards and Technology (NIST) traceable.
    (c) General. (1) If you measure the concentration of any 
CO2 quantity for reporting, you must measure according to one 
of the following. You may use an appropriate standard method published 
by a consensus-based standards organization if such a method exists or 
an industry standard practice.
    (2) You must convert all measured volumes of CO2 to the 
following standard industry temperature and pressure conditions for use 
in Equations UU-2 of this subpart: standard cubic meters at a 
temperature of 60 degrees Fahrenheit and at an absolute pressure of 1 
atmosphere.
    (3) For 2011, you may follow the provisions of Sec. 98.3(d)(1) 
through (2) for best available monitoring methods rather than follow the 
monitoring requirements of this section. For purposes of this subpart, 
any reference to the year 2010 in Sec. 98.3(d)(1) through (2) shall 
mean 2011.



Sec. 98.475  Procedures for estimating missing data.

    A complete record of all measured parameters used in the GHG 
quantities calculations is required.
    (a) Whenever the monitoring procedures for all facilities that used 
flow meters covered under this subpart cannot be followed to measure 
flow, the following missing data procedures must be followed:
    (1) Another calculation methodology listed in Sec. 98.474(a)(1) 
must be used if possible.
    (2) If another method listed in Sec. 98.474(a)(1) cannot be used, a 
quarterly flow rate value that is missing must be estimated using a 
representative flow rate value from the nearest previous time period.
    (b) Whenever the monitoring procedures of this subpart cannot be 
followed to measure quarterly quantity of CO2 received in 
containers, the most appropriate of the following missing data 
procedures must be followed:
    (1) Another calculation methodology listed in Sec. 98.474(a)(2) 
must be used if possible.
    (2) If another method listed in Sec. 98.474(a)(2) cannot be used, a 
quarterly mass or volume that is missing must be estimated using a 
representative mass or volume from the nearest previous time period.
    (c) Whenever the monitoring procedures cannot be followed to measure 
CO2 concentration, the following missing data procedures must 
be followed:
    (1) Another calculation methodology listed in Sec. 98.474(a)(3) 
must be used if possible.
    (2) If another method listed in Sec. 98.474(a)(3) cannot be used, a 
quarterly concentration value that is missing must be estimated using a 
representative concentration value from the nearest previous time 
period.



Sec. 98.476  Data reporting requirements.

    If you are subject to this part and report under this subpart, you 
are not required to report the information in Sec. 98.3(c)(4) for this 
subpart. In addition to the information required by Sec. 98.3(c)(1) 
through Sec. 98.3(c)(3) and by Sec. 98.3(c)(5) through Sec. 
98.3(c)(9), you must report the information listed in this section.

[[Page 1087]]

    (a) If you receive CO2 by pipeline, report the following 
for each receiving flow meter:
    (1) The total net mass of CO2 received (metric tons) 
annually.
    (2) If a volumetric flow meter is used to receive CO2:
    (i) The volumetric flow through a receiving flow meter at standard 
conditions (in standard cubic meters) in each quarter.
    (ii) The volumetric flow through a receiving flow meter that is 
redelivered to another facility without being injected into your well 
(in standard cubic meters) in each quarter.
    (iii) The CO2 concentration in the flow (volume percent 
CO2 expressed as a decimal fraction) in each quarter.
    (3) If a mass flow meter is used to receive CO2:
    (i) The mass flow through a receiving flow meter (in metric tons) in 
each quarter.
    (ii) The mass flow through a receiving flow meter that is 
redelivered to another facility without being injected into your well 
(in metric tons) in each quarter.
    (iii) The CO2 concentration in the flow (weight percent 
CO2 expressed as a decimal fraction) in each quarter.
    (4) The standard or method used to calculate each value in 
paragraphs (a)(2) through (a)(3) of this section.
    (5) The number of times in the reporting year for which substitute 
data procedures were used to calculate values reported in paragraphs 
(a)(2) through (a)(3) of this section.
    (6) Whether the flow meter is mass or volumetric.
    (b) If you receive CO2 in containers, report:
    (1) The mass (in metric tons) or volume at standard conditions (in 
standard cubic meters) of contents in containers in each quarter.
    (2) The concentration of CO2 of contents in containers 
(volume or weight percent CO2 expressed as a decimal 
fraction) in each quarter.
    (3) The mass (in metric tons) or volume (in standard cubic meters) 
of contents in containers that is redelivered to another facility 
without being injected into your well in each quarter.
    (4) The net total mass of CO2 received (in metric tons) 
annually.
    (5) The standard or method used to calculate each value in 
paragraphs (b)(1), (b)(2), and (b)(3) of this section.
    (6) The number of times in the reporting year for which substitute 
data procedures were used to calculate values reported in paragraphs 
(b)(1) and (b)(2) of this section.
    (c) If you use more than one receiving flow meter, report the net 
total mass of CO2 received (metric tons) through all flow 
meters annually.
    (d) The source of the CO2 received according to the 
following categories:
    (1) CO2 production wells.
    (2) Electric generating unit.
    (3) Ethanol plant.
    (4) Pulp and paper mill.
    (5) Natural gas processing.
    (6) Gasification operations.
    (7) Other anthropogenic source.
    (8) Discontinued enhanced oil and gas recovery project.
    (9) Unknown.
    (e) Report the following:
    (1) Whether the facility received a Research and Development project 
exemption from reporting under 40 CFR part 98, subpart RR, for this 
reporting year. If you received an exemption, report the start and end 
dates of the exemption approved by EPA.
    (2) Whether the facility includes a well or group of wells where a 
CO2 stream was injected into subsurface geologic formations 
to enhance the recovery of oil during this reporting year.
    (3) Whether the facility includes a well or group of wells where a 
CO2 stream was injected into subsurface geologic formations 
to enhance the recovery of natural gas during this reporting year.
    (4) Whether the facility includes a well or group of wells where a 
CO2 stream was injected into subsurface geologic formations 
for acid gas disposal during this reporting year.
    (5) Whether the facility includes a well or group of wells where a 
CO2 stream was injected for a purpose other than those listed 
in paragraphs (e)(1) through (4) of this section. If you injected 
CO2 for another purpose, report the purpose of the injection.

[75 FR 75078, Dec. 1, 2010, as amended at 78 FR 71981, Nov. 29, 2013]

[[Page 1088]]



Sec. 98.477  Records that must be retained.

    (a) You must follow the record retention requirements specified by 
Sec. 98.3(g). In addition to the records required by Sec. 98.3(g), you 
must retain quarterly records of CO2 received, including mass 
flow rate or contents of containers (mass or volumetric) at standard 
conditions and operating conditions, operating temperature and pressure, 
and concentration of these streams. You must retain all required records 
for at least 3 years.
    (b) You must complete your monitoring plans, as described in Sec. 
98.3(g)(5), by April 1 of the year you begin collecting data.



Sec. 98.478  Definitions.

    Except as provided below, all terms used in this subpart have the 
same meaning given in the Clean Air Act and subpart A of this part.
    CO2 received means the CO2 stream that you 
receive to be injected for the first time into a well on your facility 
that is covered by this subpart. CO2 received includes, but 
is not limited to, a CO2 stream from a production process 
unit inside your facility and a CO2 stream that was injected 
into a well on another facility, removed from a discontinued enhanced 
oil or natural gas or other production well, and transferred to your 
facility.

                           PART 99 [RESERVED]

[[Page 1089]]



                              FINDING AIDS




  --------------------------------------------------------------------

  A list of CFR titles, subtitles, chapters, subchapters and parts and 
an alphabetical list of agencies publishing in the CFR are included in 
the CFR Index and Finding Aids volume to the Code of Federal Regulations 
which is published separately and revised annually.

  Table of CFR Titles and Chapters
  Alphabetical List of Agencies Appearing in the CFR
  List of CFR Sections Affected

[[Page 1091]]



                    Table of CFR Titles and Chapters




                      (Revised as of July 1, 2016)

                      Title 1--General Provisions

         I  Administrative Committee of the Federal Register 
                (Parts 1--49)
        II  Office of the Federal Register (Parts 50--299)
       III  Administrative Conference of the United States (Parts 
                300--399)
        IV  Miscellaneous Agencies (Parts 400--500)

                    Title 2--Grants and Agreements

            Subtitle A--Office of Management and Budget Guidance 
                for Grants and Agreements
         I  Office of Management and Budget Governmentwide 
                Guidance for Grants and Agreements (Parts 2--199)
        II  Office of Management and Budget Guidance (Parts 200--
                299)
            Subtitle B--Federal Agency Regulations for Grants and 
                Agreements
       III  Department of Health and Human Services (Parts 300--
                399)
        IV  Department of Agriculture (Parts 400--499)
        VI  Department of State (Parts 600--699)
       VII  Agency for International Development (Parts 700--799)
      VIII  Department of Veterans Affairs (Parts 800--899)
        IX  Department of Energy (Parts 900--999)
         X  Department of the Treasury (Parts 1000--1099)
        XI  Department of Defense (Parts 1100--1199)
       XII  Department of Transportation (Parts 1200--1299)
      XIII  Department of Commerce (Parts 1300--1399)
       XIV  Department of the Interior (Parts 1400--1499)
        XV  Environmental Protection Agency (Parts 1500--1599)
     XVIII  National Aeronautics and Space Administration (Parts 
                1800--1899)
        XX  United States Nuclear Regulatory Commission (Parts 
                2000--2099)
      XXII  Corporation for National and Community Service (Parts 
                2200--2299)
     XXIII  Social Security Administration (Parts 2300--2399)
      XXIV  Housing and Urban Development (Parts 2400--2499)
       XXV  National Science Foundation (Parts 2500--2599)
      XXVI  National Archives and Records Administration (Parts 
                2600--2699)
     XXVII  Small Business Administration (Parts 2700--2799)

[[Page 1092]]

    XXVIII  Department of Justice (Parts 2800--2899)
      XXIX  Department of Labor (Parts 2900--2999)
       XXX  Department of Homeland Security (Parts 3000--3099)
      XXXI  Institute of Museum and Library Services (Parts 3100--
                3199)
     XXXII  National Endowment for the Arts (Parts 3200--3299)
    XXXIII  National Endowment for the Humanities (Parts 3300--
                3399)
     XXXIV  Department of Education (Parts 3400--3499)
      XXXV  Export-Import Bank of the United States (Parts 3500--
                3599)
     XXXVI  Office of National Drug Control Policy, Executive 
                Office of the President (Parts 3600--3699)
    XXXVII  Peace Corps (Parts 3700--3799)
     LVIII  Election Assistance Commission (Parts 5800--5899)
       LIX  Gulf Coast Ecosystem Restoration Council (Parts 5900--
                5999)

                        Title 3--The President

         I  Executive Office of the President (Parts 100--199)

                           Title 4--Accounts

         I  Government Accountability Office (Parts 1--199)

                   Title 5--Administrative Personnel

         I  Office of Personnel Management (Parts 1--1199)
        II  Merit Systems Protection Board (Parts 1200--1299)
       III  Office of Management and Budget (Parts 1300--1399)
        IV  Office of Personnel Management and Office of the 
                Director of National Intelligence (Parts 1400--
                1499)
         V  The International Organizations Employees Loyalty 
                Board (Parts 1500--1599)
        VI  Federal Retirement Thrift Investment Board (Parts 
                1600--1699)
      VIII  Office of Special Counsel (Parts 1800--1899)
        IX  Appalachian Regional Commission (Parts 1900--1999)
        XI  Armed Forces Retirement Home (Parts 2100--2199)
       XIV  Federal Labor Relations Authority, General Counsel of 
                the Federal Labor Relations Authority and Federal 
                Service Impasses Panel (Parts 2400--2499)
       XVI  Office of Government Ethics (Parts 2600--2699)
       XXI  Department of the Treasury (Parts 3100--3199)
      XXII  Federal Deposit Insurance Corporation (Parts 3200--
                3299)
     XXIII  Department of Energy (Parts 3300--3399)
      XXIV  Federal Energy Regulatory Commission (Parts 3400--
                3499)
       XXV  Department of the Interior (Parts 3500--3599)
      XXVI  Department of Defense (Parts 3600--3699)
    XXVIII  Department of Justice (Parts 3800--3899)

[[Page 1093]]

      XXIX  Federal Communications Commission (Parts 3900--3999)
       XXX  Farm Credit System Insurance Corporation (Parts 4000--
                4099)
      XXXI  Farm Credit Administration (Parts 4100--4199)
    XXXIII  Overseas Private Investment Corporation (Parts 4300--
                4399)
     XXXIV  Securities and Exchange Commission (Parts 4400--4499)
      XXXV  Office of Personnel Management (Parts 4500--4599)
     XXXVI  Department of Homeland Security (Parts 4600--4699)
    XXXVII  Federal Election Commission (Parts 4700--4799)
        XL  Interstate Commerce Commission (Parts 5000--5099)
       XLI  Commodity Futures Trading Commission (Parts 5100--
                5199)
      XLII  Department of Labor (Parts 5200--5299)
     XLIII  National Science Foundation (Parts 5300--5399)
       XLV  Department of Health and Human Services (Parts 5500--
                5599)
      XLVI  Postal Rate Commission (Parts 5600--5699)
     XLVII  Federal Trade Commission (Parts 5700--5799)
    XLVIII  Nuclear Regulatory Commission (Parts 5800--5899)
      XLIX  Federal Labor Relations Authority (Parts 5900--5999)
         L  Department of Transportation (Parts 6000--6099)
       LII  Export-Import Bank of the United States (Parts 6200--
                6299)
      LIII  Department of Education (Parts 6300--6399)
       LIV  Environmental Protection Agency (Parts 6400--6499)
        LV  National Endowment for the Arts (Parts 6500--6599)
       LVI  National Endowment for the Humanities (Parts 6600--
                6699)
      LVII  General Services Administration (Parts 6700--6799)
     LVIII  Board of Governors of the Federal Reserve System 
                (Parts 6800--6899)
       LIX  National Aeronautics and Space Administration (Parts 
                6900--6999)
        LX  United States Postal Service (Parts 7000--7099)
       LXI  National Labor Relations Board (Parts 7100--7199)
      LXII  Equal Employment Opportunity Commission (Parts 7200--
                7299)
     LXIII  Inter-American Foundation (Parts 7300--7399)
      LXIV  Merit Systems Protection Board (Parts 7400--7499)
       LXV  Department of Housing and Urban Development (Parts 
                7500--7599)
      LXVI  National Archives and Records Administration (Parts 
                7600--7699)
     LXVII  Institute of Museum and Library Services (Parts 7700--
                7799)
    LXVIII  Commission on Civil Rights (Parts 7800--7899)
      LXIX  Tennessee Valley Authority (Parts 7900--7999)
       LXX  Court Services and Offender Supervision Agency for the 
                District of Columbia (Parts 8000--8099)
      LXXI  Consumer Product Safety Commission (Parts 8100--8199)
    LXXIII  Department of Agriculture (Parts 8300--8399)
     LXXIV  Federal Mine Safety and Health Review Commission 
                (Parts 8400--8499)

[[Page 1094]]

     LXXVI  Federal Retirement Thrift Investment Board (Parts 
                8600--8699)
    LXXVII  Office of Management and Budget (Parts 8700--8799)
      LXXX  Federal Housing Finance Agency (Parts 9000--9099)
   LXXXIII  Special Inspector General for Afghanistan 
                Reconstruction (Parts 9300--9399)
    LXXXIV  Bureau of Consumer Financial Protection (Parts 9400--
                9499)
    LXXXVI  National Credit Union Administration (Parts 9600--
                9699)
     XCVII  Department of Homeland Security Human Resources 
                Management System (Department of Homeland 
                Security--Office of Personnel Management) (Parts 
                9700--9799)
     XCVII  Council of the Inspectors General on Integrity and 
                Efficiency (Parts 9800--9899)
      XCIX  Military Compensation and Retirement Modernization 
                Commission (Parts 9900--9999)
         C  National Council on Disability (Partys 10000--10049)

                      Title 6--Domestic Security

         I  Department of Homeland Security, Office of the 
                Secretary (Parts 1--199)
         X  Privacy and Civil Liberties Oversight Board (Parts 
                1000--1099)

                         Title 7--Agriculture

            Subtitle A--Office of the Secretary of Agriculture 
                (Parts 0--26)
            Subtitle B--Regulations of the Department of 
                Agriculture
         I  Agricultural Marketing Service (Standards, 
                Inspections, Marketing Practices), Department of 
                Agriculture (Parts 27--209)
        II  Food and Nutrition Service, Department of Agriculture 
                (Parts 210--299)
       III  Animal and Plant Health Inspection Service, Department 
                of Agriculture (Parts 300--399)
        IV  Federal Crop Insurance Corporation, Department of 
                Agriculture (Parts 400--499)
         V  Agricultural Research Service, Department of 
                Agriculture (Parts 500--599)
        VI  Natural Resources Conservation Service, Department of 
                Agriculture (Parts 600--699)
       VII  Farm Service Agency, Department of Agriculture (Parts 
                700--799)
      VIII  Grain Inspection, Packers and Stockyards 
                Administration (Federal Grain Inspection Service), 
                Department of Agriculture (Parts 800--899)
        IX  Agricultural Marketing Service (Marketing Agreements 
                and Orders; Fruits, Vegetables, Nuts), Department 
                of Agriculture (Parts 900--999)
         X  Agricultural Marketing Service (Marketing Agreements 
                and Orders; Milk), Department of Agriculture 
                (Parts 1000--1199)

[[Page 1095]]

        XI  Agricultural Marketing Service (Marketing Agreements 
                and Orders; Miscellaneous Commodities), Department 
                of Agriculture (Parts 1200--1299)
       XIV  Commodity Credit Corporation, Department of 
                Agriculture (Parts 1400--1499)
        XV  Foreign Agricultural Service, Department of 
                Agriculture (Parts 1500--1599)
       XVI  Rural Telephone Bank, Department of Agriculture (Parts 
                1600--1699)
      XVII  Rural Utilities Service, Department of Agriculture 
                (Parts 1700--1799)
     XVIII  Rural Housing Service, Rural Business-Cooperative 
                Service, Rural Utilities Service, and Farm Service 
                Agency, Department of Agriculture (Parts 1800--
                2099)
        XX  Local Television Loan Guarantee Board (Parts 2200--
                2299)
       XXV  Office of Advocacy and Outreach, Department of 
                Agriculture (Parts 2500--2599)
      XXVI  Office of Inspector General, Department of Agriculture 
                (Parts 2600--2699)
     XXVII  Office of Information Resources Management, Department 
                of Agriculture (Parts 2700--2799)
    XXVIII  Office of Operations, Department of Agriculture (Parts 
                2800--2899)
      XXIX  Office of Energy Policy and New Uses, Department of 
                Agriculture (Parts 2900--2999)
       XXX  Office of the Chief Financial Officer, Department of 
                Agriculture (Parts 3000--3099)
      XXXI  Office of Environmental Quality, Department of 
                Agriculture (Parts 3100--3199)
     XXXII  Office of Procurement and Property Management, 
                Department of Agriculture (Parts 3200--3299)
    XXXIII  Office of Transportation, Department of Agriculture 
                (Parts 3300--3399)
     XXXIV  National Institute of Food and Agriculture (Parts 
                3400--3499)
      XXXV  Rural Housing Service, Department of Agriculture 
                (Parts 3500--3599)
     XXXVI  National Agricultural Statistics Service, Department 
                of Agriculture (Parts 3600--3699)
    XXXVII  Economic Research Service, Department of Agriculture 
                (Parts 3700--3799)
   XXXVIII  World Agricultural Outlook Board, Department of 
                Agriculture (Parts 3800--3899)
       XLI  [Reserved]
      XLII  Rural Business-Cooperative Service and Rural Utilities 
                Service, Department of Agriculture (Parts 4200--
                4299)

                    Title 8--Aliens and Nationality

         I  Department of Homeland Security (Immigration and 
                Naturalization) (Parts 1--499)

[[Page 1096]]

         V  Executive Office for Immigration Review, Department of 
                Justice (Parts 1000--1399)

                 Title 9--Animals and Animal Products

         I  Animal and Plant Health Inspection Service, Department 
                of Agriculture (Parts 1--199)
        II  Grain Inspection, Packers and Stockyards 
                Administration (Packers and Stockyards Programs), 
                Department of Agriculture (Parts 200--299)
       III  Food Safety and Inspection Service, Department of 
                Agriculture (Parts 300--599)

                           Title 10--Energy

         I  Nuclear Regulatory Commission (Parts 0--199)
        II  Department of Energy (Parts 200--699)
       III  Department of Energy (Parts 700--999)
         X  Department of Energy (General Provisions) (Parts 
                1000--1099)
      XIII  Nuclear Waste Technical Review Board (Parts 1300--
                1399)
      XVII  Defense Nuclear Facilities Safety Board (Parts 1700--
                1799)
     XVIII  Northeast Interstate Low-Level Radioactive Waste 
                Commission (Parts 1800--1899)

                      Title 11--Federal Elections

         I  Federal Election Commission (Parts 1--9099)
        II  Election Assistance Commission (Parts 9400--9499)

                      Title 12--Banks and Banking

         I  Comptroller of the Currency, Department of the 
                Treasury (Parts 1--199)
        II  Federal Reserve System (Parts 200--299)
       III  Federal Deposit Insurance Corporation (Parts 300--399)
        IV  Export-Import Bank of the United States (Parts 400--
                499)
         V  Office of Thrift Supervision, Department of the 
                Treasury (Parts 500--599)
        VI  Farm Credit Administration (Parts 600--699)
       VII  National Credit Union Administration (Parts 700--799)
      VIII  Federal Financing Bank (Parts 800--899)
        IX  Federal Housing Finance Board (Parts 900--999)
         X  Bureau of Consumer Financial Protection (Parts 1000--
                1099)
        XI  Federal Financial Institutions Examination Council 
                (Parts 1100--1199)
       XII  Federal Housing Finance Agency (Parts 1200--1299)
      XIII  Financial Stability Oversight Council (Parts 1300--
                1399)
       XIV  Farm Credit System Insurance Corporation (Parts 1400--
                1499)

[[Page 1097]]

        XV  Department of the Treasury (Parts 1500--1599)
       XVI  Office of Financial Research (Parts 1600--1699)
      XVII  Office of Federal Housing Enterprise Oversight, 
                Department of Housing and Urban Development (Parts 
                1700--1799)
     XVIII  Community Development Financial Institutions Fund, 
                Department of the Treasury (Parts 1800--1899)

               Title 13--Business Credit and Assistance

         I  Small Business Administration (Parts 1--199)
       III  Economic Development Administration, Department of 
                Commerce (Parts 300--399)
        IV  Emergency Steel Guarantee Loan Board (Parts 400--499)
         V  Emergency Oil and Gas Guaranteed Loan Board (Parts 
                500--599)

                    Title 14--Aeronautics and Space

         I  Federal Aviation Administration, Department of 
                Transportation (Parts 1--199)
        II  Office of the Secretary, Department of Transportation 
                (Aviation Proceedings) (Parts 200--399)
       III  Commercial Space Transportation, Federal Aviation 
                Administration, Department of Transportation 
                (Parts 400--1199)
         V  National Aeronautics and Space Administration (Parts 
                1200--1299)
        VI  Air Transportation System Stabilization (Parts 1300--
                1399)

                 Title 15--Commerce and Foreign Trade

            Subtitle A--Office of the Secretary of Commerce (Parts 
                0--29)
            Subtitle B--Regulations Relating to Commerce and 
                Foreign Trade
         I  Bureau of the Census, Department of Commerce (Parts 
                30--199)
        II  National Institute of Standards and Technology, 
                Department of Commerce (Parts 200--299)
       III  International Trade Administration, Department of 
                Commerce (Parts 300--399)
        IV  Foreign-Trade Zones Board, Department of Commerce 
                (Parts 400--499)
       VII  Bureau of Industry and Security, Department of 
                Commerce (Parts 700--799)
      VIII  Bureau of Economic Analysis, Department of Commerce 
                (Parts 800--899)
        IX  National Oceanic and Atmospheric Administration, 
                Department of Commerce (Parts 900--999)
        XI  Technology Administration, Department of Commerce 
                (Parts 1100--1199)
      XIII  East-West Foreign Trade Board (Parts 1300--1399)

[[Page 1098]]

       XIV  Minority Business Development Agency (Parts 1400--
                1499)
            Subtitle C--Regulations Relating to Foreign Trade 
                Agreements
        XX  Office of the United States Trade Representative 
                (Parts 2000--2099)
            Subtitle D--Regulations Relating to Telecommunications 
                and Information
     XXIII  National Telecommunications and Information 
                Administration, Department of Commerce (Parts 
                2300--2399)

                    Title 16--Commercial Practices

         I  Federal Trade Commission (Parts 0--999)
        II  Consumer Product Safety Commission (Parts 1000--1799)

             Title 17--Commodity and Securities Exchanges

         I  Commodity Futures Trading Commission (Parts 1--199)
        II  Securities and Exchange Commission (Parts 200--399)
        IV  Department of the Treasury (Parts 400--499)

          Title 18--Conservation of Power and Water Resources

         I  Federal Energy Regulatory Commission, Department of 
                Energy (Parts 1--399)
       III  Delaware River Basin Commission (Parts 400--499)
        VI  Water Resources Council (Parts 700--799)
      VIII  Susquehanna River Basin Commission (Parts 800--899)
      XIII  Tennessee Valley Authority (Parts 1300--1399)

                       Title 19--Customs Duties

         I  U.S. Customs and Border Protection, Department of 
                Homeland Security; Department of the Treasury 
                (Parts 0--199)
        II  United States International Trade Commission (Parts 
                200--299)
       III  International Trade Administration, Department of 
                Commerce (Parts 300--399)
        IV  U.S. Immigration and Customs Enforcement, Department 
                of Homeland Security (Parts 400--599)

                     Title 20--Employees' Benefits

         I  Office of Workers' Compensation Programs, Department 
                of Labor (Parts 1--199)
        II  Railroad Retirement Board (Parts 200--399)
       III  Social Security Administration (Parts 400--499)
        IV  Employees' Compensation Appeals Board, Department of 
                Labor (Parts 500--599)

[[Page 1099]]

         V  Employment and Training Administration, Department of 
                Labor (Parts 600--699)
        VI  Office of Workers' Compensation Programs, Department 
                of Labor (Parts 700--799)
       VII  Benefits Review Board, Department of Labor (Parts 
                800--899)
      VIII  Joint Board for the Enrollment of Actuaries (Parts 
                900--999)
        IX  Office of the Assistant Secretary for Veterans' 
                Employment and Training Service, Department of 
                Labor (Parts 1000--1099)

                       Title 21--Food and Drugs

         I  Food and Drug Administration, Department of Health and 
                Human Services (Parts 1--1299)
        II  Drug Enforcement Administration, Department of Justice 
                (Parts 1300--1399)
       III  Office of National Drug Control Policy (Parts 1400--
                1499)

                      Title 22--Foreign Relations

         I  Department of State (Parts 1--199)
        II  Agency for International Development (Parts 200--299)
       III  Peace Corps (Parts 300--399)
        IV  International Joint Commission, United States and 
                Canada (Parts 400--499)
         V  Broadcasting Board of Governors (Parts 500--599)
       VII  Overseas Private Investment Corporation (Parts 700--
                799)
        IX  Foreign Service Grievance Board (Parts 900--999)
         X  Inter-American Foundation (Parts 1000--1099)
        XI  International Boundary and Water Commission, United 
                States and Mexico, United States Section (Parts 
                1100--1199)
       XII  United States International Development Cooperation 
                Agency (Parts 1200--1299)
      XIII  Millennium Challenge Corporation (Parts 1300--1399)
       XIV  Foreign Service Labor Relations Board; Federal Labor 
                Relations Authority; General Counsel of the 
                Federal Labor Relations Authority; and the Foreign 
                Service Impasse Disputes Panel (Parts 1400--1499)
        XV  African Development Foundation (Parts 1500--1599)
       XVI  Japan-United States Friendship Commission (Parts 
                1600--1699)
      XVII  United States Institute of Peace (Parts 1700--1799)

                          Title 23--Highways

         I  Federal Highway Administration, Department of 
                Transportation (Parts 1--999)
        II  National Highway Traffic Safety Administration and 
                Federal Highway Administration, Department of 
                Transportation (Parts 1200--1299)

[[Page 1100]]

       III  National Highway Traffic Safety Administration, 
                Department of Transportation (Parts 1300--1399)

                Title 24--Housing and Urban Development

            Subtitle A--Office of the Secretary, Department of 
                Housing and Urban Development (Parts 0--99)
            Subtitle B--Regulations Relating to Housing and Urban 
                Development
         I  Office of Assistant Secretary for Equal Opportunity, 
                Department of Housing and Urban Development (Parts 
                100--199)
        II  Office of Assistant Secretary for Housing-Federal 
                Housing Commissioner, Department of Housing and 
                Urban Development (Parts 200--299)
       III  Government National Mortgage Association, Department 
                of Housing and Urban Development (Parts 300--399)
        IV  Office of Housing and Office of Multifamily Housing 
                Assistance Restructuring, Department of Housing 
                and Urban Development (Parts 400--499)
         V  Office of Assistant Secretary for Community Planning 
                and Development, Department of Housing and Urban 
                Development (Parts 500--599)
        VI  Office of Assistant Secretary for Community Planning 
                and Development, Department of Housing and Urban 
                Development (Parts 600--699) [Reserved]
       VII  Office of the Secretary, Department of Housing and 
                Urban Development (Housing Assistance Programs and 
                Public and Indian Housing Programs) (Parts 700--
                799)
      VIII  Office of the Assistant Secretary for Housing--Federal 
                Housing Commissioner, Department of Housing and 
                Urban Development (Section 8 Housing Assistance 
                Programs, Section 202 Direct Loan Program, Section 
                202 Supportive Housing for the Elderly Program and 
                Section 811 Supportive Housing for Persons With 
                Disabilities Program) (Parts 800--899)
        IX  Office of Assistant Secretary for Public and Indian 
                Housing, Department of Housing and Urban 
                Development (Parts 900--1699)
         X  Office of Assistant Secretary for Housing--Federal 
                Housing Commissioner, Department of Housing and 
                Urban Development (Interstate Land Sales 
                Registration Program) (Parts 1700--1799)
       XII  Office of Inspector General, Department of Housing and 
                Urban Development (Parts 2000--2099)
        XV  Emergency Mortgage Insurance and Loan Programs, 
                Department of Housing and Urban Development (Parts 
                2700--2799) [Reserved]
        XX  Office of Assistant Secretary for Housing--Federal 
                Housing Commissioner, Department of Housing and 
                Urban Development (Parts 3200--3899)
      XXIV  Board of Directors of the HOPE for Homeowners Program 
                (Parts 4000--4099) [Reserved]
       XXV  Neighborhood Reinvestment Corporation (Parts 4100--
                4199)

[[Page 1101]]

                           Title 25--Indians

         I  Bureau of Indian Affairs, Department of the Interior 
                (Parts 1--299)
        II  Indian Arts and Crafts Board, Department of the 
                Interior (Parts 300--399)
       III  National Indian Gaming Commission, Department of the 
                Interior (Parts 500--599)
        IV  Office of Navajo and Hopi Indian Relocation (Parts 
                700--799)
         V  Bureau of Indian Affairs, Department of the Interior, 
                and Indian Health Service, Department of Health 
                and Human Services (Part 900)
        VI  Office of the Assistant Secretary-Indian Affairs, 
                Department of the Interior (Parts 1000--1199)
       VII  Office of the Special Trustee for American Indians, 
                Department of the Interior (Parts 1200--1299)

                      Title 26--Internal Revenue

         I  Internal Revenue Service, Department of the Treasury 
                (Parts 1--End)

           Title 27--Alcohol, Tobacco Products and Firearms

         I  Alcohol and Tobacco Tax and Trade Bureau, Department 
                of the Treasury (Parts 1--399)
        II  Bureau of Alcohol, Tobacco, Firearms, and Explosives, 
                Department of Justice (Parts 400--699)

                   Title 28--Judicial Administration

         I  Department of Justice (Parts 0--299)
       III  Federal Prison Industries, Inc., Department of Justice 
                (Parts 300--399)
         V  Bureau of Prisons, Department of Justice (Parts 500--
                599)
        VI  Offices of Independent Counsel, Department of Justice 
                (Parts 600--699)
       VII  Office of Independent Counsel (Parts 700--799)
      VIII  Court Services and Offender Supervision Agency for the 
                District of Columbia (Parts 800--899)
        IX  National Crime Prevention and Privacy Compact Council 
                (Parts 900--999)
        XI  Department of Justice and Department of State (Parts 
                1100--1199)

                            Title 29--Labor

            Subtitle A--Office of the Secretary of Labor (Parts 
                0--99)
            Subtitle B--Regulations Relating to Labor
         I  National Labor Relations Board (Parts 100--199)

[[Page 1102]]

        II  Office of Labor-Management Standards, Department of 
                Labor (Parts 200--299)
       III  National Railroad Adjustment Board (Parts 300--399)
        IV  Office of Labor-Management Standards, Department of 
                Labor (Parts 400--499)
         V  Wage and Hour Division, Department of Labor (Parts 
                500--899)
        IX  Construction Industry Collective Bargaining Commission 
                (Parts 900--999)
         X  National Mediation Board (Parts 1200--1299)
       XII  Federal Mediation and Conciliation Service (Parts 
                1400--1499)
       XIV  Equal Employment Opportunity Commission (Parts 1600--
                1699)
      XVII  Occupational Safety and Health Administration, 
                Department of Labor (Parts 1900--1999)
        XX  Occupational Safety and Health Review Commission 
                (Parts 2200--2499)
       XXV  Employee Benefits Security Administration, Department 
                of Labor (Parts 2500--2599)
     XXVII  Federal Mine Safety and Health Review Commission 
                (Parts 2700--2799)
        XL  Pension Benefit Guaranty Corporation (Parts 4000--
                4999)

                      Title 30--Mineral Resources

         I  Mine Safety and Health Administration, Department of 
                Labor (Parts 1--199)
        II  Bureau of Safety and Environmental Enforcement, 
                Department of the Interior (Parts 200--299)
        IV  Geological Survey, Department of the Interior (Parts 
                400--499)
         V  Bureau of Ocean Energy Management, Department of the 
                Interior (Parts 500--599)
       VII  Office of Surface Mining Reclamation and Enforcement, 
                Department of the Interior (Parts 700--999)
       XII  Office of Natural Resources Revenue, Department of the 
                Interior (Parts 1200--1299)

                 Title 31--Money and Finance: Treasury

            Subtitle A--Office of the Secretary of the Treasury 
                (Parts 0--50)
            Subtitle B--Regulations Relating to Money and Finance
         I  Monetary Offices, Department of the Treasury (Parts 
                51--199)
        II  Fiscal Service, Department of the Treasury (Parts 
                200--399)
        IV  Secret Service, Department of the Treasury (Parts 
                400--499)
         V  Office of Foreign Assets Control, Department of the 
                Treasury (Parts 500--599)
        VI  Bureau of Engraving and Printing, Department of the 
                Treasury (Parts 600--699)
       VII  Federal Law Enforcement Training Center, Department of 
                the Treasury (Parts 700--799)

[[Page 1103]]

      VIII  Office of International Investment, Department of the 
                Treasury (Parts 800--899)
        IX  Federal Claims Collection Standards (Department of the 
                Treasury--Department of Justice) (Parts 900--999)
         X  Financial Crimes Enforcement Network, Department of 
                the Treasury (Parts 1000--1099)

                      Title 32--National Defense

            Subtitle A--Department of Defense
         I  Office of the Secretary of Defense (Parts 1--399)
         V  Department of the Army (Parts 400--699)
        VI  Department of the Navy (Parts 700--799)
       VII  Department of the Air Force (Parts 800--1099)
            Subtitle B--Other Regulations Relating to National 
                Defense
       XII  Defense Logistics Agency (Parts 1200--1299)
       XVI  Selective Service System (Parts 1600--1699)
      XVII  Office of the Director of National Intelligence (Parts 
                1700--1799)
     XVIII  National Counterintelligence Center (Parts 1800--1899)
       XIX  Central Intelligence Agency (Parts 1900--1999)
        XX  Information Security Oversight Office, National 
                Archives and Records Administration (Parts 2000--
                2099)
       XXI  National Security Council (Parts 2100--2199)
      XXIV  Office of Science and Technology Policy (Parts 2400--
                2499)
     XXVII  Office for Micronesian Status Negotiations (Parts 
                2700--2799)
    XXVIII  Office of the Vice President of the United States 
                (Parts 2800--2899)

               Title 33--Navigation and Navigable Waters

         I  Coast Guard, Department of Homeland Security (Parts 
                1--199)
        II  Corps of Engineers, Department of the Army (Parts 
                200--399)
        IV  Saint Lawrence Seaway Development Corporation, 
                Department of Transportation (Parts 400--499)

                          Title 34--Education

            Subtitle A--Office of the Secretary, Department of 
                Education (Parts 1--99)
            Subtitle B--Regulations of the Offices of the 
                Department of Education
         I  Office for Civil Rights, Department of Education 
                (Parts 100--199)
        II  Office of Elementary and Secondary Education, 
                Department of Education (Parts 200--299)
       III  Office of Special Education and Rehabilitative 
                Services, Department of Education (Parts 300--399)

[[Page 1104]]

        IV  Office of Career, Technical and Adult Education, 
                Department of Education (Parts 400--499)
         V  Office of Bilingual Education and Minority Languages 
                Affairs, Department of Education (Parts 500--599) 
                [Reserved]
        VI  Office of Postsecondary Education, Department of 
                Education (Parts 600--699)
       VII  Office of Educational Research and Improvement, 
                Department of Education (Parts 700--799) 
                [Reserved]
            Subtitle C--Regulations Relating to Education
        XI  [Reserved]
       XII  National Council on Disability (Parts 1200--1299)

                          Title 35 [Reserved]

             Title 36--Parks, Forests, and Public Property

         I  National Park Service, Department of the Interior 
                (Parts 1--199)
        II  Forest Service, Department of Agriculture (Parts 200--
                299)
       III  Corps of Engineers, Department of the Army (Parts 
                300--399)
        IV  American Battle Monuments Commission (Parts 400--499)
         V  Smithsonian Institution (Parts 500--599)
        VI  [Reserved]
       VII  Library of Congress (Parts 700--799)
      VIII  Advisory Council on Historic Preservation (Parts 800--
                899)
        IX  Pennsylvania Avenue Development Corporation (Parts 
                900--999)
         X  Presidio Trust (Parts 1000--1099)
        XI  Architectural and Transportation Barriers Compliance 
                Board (Parts 1100--1199)
       XII  National Archives and Records Administration (Parts 
                1200--1299)
        XV  Oklahoma City National Memorial Trust (Parts 1500--
                1599)
       XVI  Morris K. Udall Scholarship and Excellence in National 
                Environmental Policy Foundation (Parts 1600--1699)

             Title 37--Patents, Trademarks, and Copyrights

         I  United States Patent and Trademark Office, Department 
                of Commerce (Parts 1--199)
        II  U.S. Copyright Office, Library of Congress (Parts 
                200--299)
       III  Copyright Royalty Board, Library of Congress (Parts 
                300--399)
        IV  Assistant Secretary for Technology Policy, Department 
                of Commerce (Parts 400--599)

           Title 38--Pensions, Bonuses, and Veterans' Relief

         I  Department of Veterans Affairs (Parts 0--199)
        II  Armed Forces Retirement Home (Parts 200--299)

[[Page 1105]]

                       Title 39--Postal Service

         I  United States Postal Service (Parts 1--999)
       III  Postal Regulatory Commission (Parts 3000--3099)

                  Title 40--Protection of Environment

         I  Environmental Protection Agency (Parts 1--1099)
        IV  Environmental Protection Agency and Department of 
                Justice (Parts 1400--1499)
         V  Council on Environmental Quality (Parts 1500--1599)
        VI  Chemical Safety and Hazard Investigation Board (Parts 
                1600--1699)
       VII  Environmental Protection Agency and Department of 
                Defense; Uniform National Discharge Standards for 
                Vessels of the Armed Forces (Parts 1700--1799)
      VIII  Gulf Coast Ecosystem Restoration Council (Parts 1800--
                1899)

          Title 41--Public Contracts and Property Management

            Subtitle A--Federal Procurement Regulations System 
                [Note]
            Subtitle B--Other Provisions Relating to Public 
                Contracts
        50  Public Contracts, Department of Labor (Parts 50-1--50-
                999)
        51  Committee for Purchase From People Who Are Blind or 
                Severely Disabled (Parts 51-1--51-99)
        60  Office of Federal Contract Compliance Programs, Equal 
                Employment Opportunity, Department of Labor (Parts 
                60-1--60-999)
        61  Office of the Assistant Secretary for Veterans' 
                Employment and Training Service, Department of 
                Labor (Parts 61-1--61-999)
   62--100  [Reserved]
            Subtitle C--Federal Property Management Regulations 
                System
       101  Federal Property Management Regulations (Parts 101-1--
                101-99)
       102  Federal Management Regulation (Parts 102-1--102-299)
  103--104  [Reserved]
       105  General Services Administration (Parts 105-1--105-999)
       109  Department of Energy Property Management Regulations 
                (Parts 109-1--109-99)
       114  Department of the Interior (Parts 114-1--114-99)
       115  Environmental Protection Agency (Parts 115-1--115-99)
       128  Department of Justice (Parts 128-1--128-99)
  129--200  [Reserved]
            Subtitle D--Other Provisions Relating to Property 
                Management [Reserved]
            Subtitle E--Federal Information Resources Management 
                Regulations System [Reserved]
            Subtitle F--Federal Travel Regulation System
       300  General (Parts 300-1--300-99)
       301  Temporary Duty (TDY) Travel Allowances (Parts 301-1--
                301-99)

[[Page 1106]]

       302  Relocation Allowances (Parts 302-1--302-99)
       303  Payment of Expenses Connected with the Death of 
                Certain Employees (Part 303-1--303-99)
       304  Payment of Travel Expenses from a Non-Federal Source 
                (Parts 304-1--304-99)

                        Title 42--Public Health

         I  Public Health Service, Department of Health and Human 
                Services (Parts 1--199)
        IV  Centers for Medicare & Medicaid Services, Department 
                of Health and Human Services (Parts 400--599)
         V  Office of Inspector General-Health Care, Department of 
                Health and Human Services (Parts 1000--1999)

                   Title 43--Public Lands: Interior

            Subtitle A--Office of the Secretary of the Interior 
                (Parts 1--199)
            Subtitle B--Regulations Relating to Public Lands
         I  Bureau of Reclamation, Department of the Interior 
                (Parts 400--999)
        II  Bureau of Land Management, Department of the Interior 
                (Parts 1000--9999)
       III  Utah Reclamation Mitigation and Conservation 
                Commission (Parts 10000--10099)

             Title 44--Emergency Management and Assistance

         I  Federal Emergency Management Agency, Department of 
                Homeland Security (Parts 0--399)
        IV  Department of Commerce and Department of 
                Transportation (Parts 400--499)

                       Title 45--Public Welfare

            Subtitle A--Department of Health and Human Services 
                (Parts 1--199)
            Subtitle B--Regulations Relating to Public Welfare
        II  Office of Family Assistance (Assistance Programs), 
                Administration for Children and Families, 
                Department of Health and Human Services (Parts 
                200--299)
       III  Office of Child Support Enforcement (Child Support 
                Enforcement Program), Administration for Children 
                and Families, Department of Health and Human 
                Services (Parts 300--399)
        IV  Office of Refugee Resettlement, Administration for 
                Children and Families, Department of Health and 
                Human Services (Parts 400--499)
         V  Foreign Claims Settlement Commission of the United 
                States, Department of Justice (Parts 500--599)

[[Page 1107]]

        VI  National Science Foundation (Parts 600--699)
       VII  Commission on Civil Rights (Parts 700--799)
      VIII  Office of Personnel Management (Parts 800--899)
         X  Office of Community Services, Administration for 
                Children and Families, Department of Health and 
                Human Services (Parts 1000--1099)
        XI  National Foundation on the Arts and the Humanities 
                (Parts 1100--1199)
       XII  Corporation for National and Community Service (Parts 
                1200--1299)
      XIII  Office of Human Development Services, Department of 
                Health and Human Services (Parts 1300--1399)
       XVI  Legal Services Corporation (Parts 1600--1699)
      XVII  National Commission on Libraries and Information 
                Science (Parts 1700--1799)
     XVIII  Harry S. Truman Scholarship Foundation (Parts 1800--
                1899)
       XXI  Commission on Fine Arts (Parts 2100--2199)
     XXIII  Arctic Research Commission (Part 2301)
      XXIV  James Madison Memorial Fellowship Foundation (Parts 
                2400--2499)
       XXV  Corporation for National and Community Service (Parts 
                2500--2599)

                          Title 46--Shipping

         I  Coast Guard, Department of Homeland Security (Parts 
                1--199)
        II  Maritime Administration, Department of Transportation 
                (Parts 200--399)
       III  Coast Guard (Great Lakes Pilotage), Department of 
                Homeland Security (Parts 400--499)
        IV  Federal Maritime Commission (Parts 500--599)

                      Title 47--Telecommunication

         I  Federal Communications Commission (Parts 0--199)
        II  Office of Science and Technology Policy and National 
                Security Council (Parts 200--299)
       III  National Telecommunications and Information 
                Administration, Department of Commerce (Parts 
                300--399)
        IV  National Telecommunications and Information 
                Administration, Department of Commerce, and 
                National Highway Traffic Safety Administration, 
                Department of Transportation (Parts 400--499)

           Title 48--Federal Acquisition Regulations System

         1  Federal Acquisition Regulation (Parts 1--99)
         2  Defense Acquisition Regulations System, Department of 
                Defense (Parts 200--299)

[[Page 1108]]

         3  Health and Human Services (Parts 300--399)
         4  Department of Agriculture (Parts 400--499)
         5  General Services Administration (Parts 500--599)
         6  Department of State (Parts 600--699)
         7  Agency for International Development (Parts 700--799)
         8  Department of Veterans Affairs (Parts 800--899)
         9  Department of Energy (Parts 900--999)
        10  Department of the Treasury (Parts 1000--1099)
        12  Department of Transportation (Parts 1200--1299)
        13  Department of Commerce (Parts 1300--1399)
        14  Department of the Interior (Parts 1400--1499)
        15  Environmental Protection Agency (Parts 1500--1599)
        16  Office of Personnel Management, Federal Employees 
                Health Benefits Acquisition Regulation (Parts 
                1600--1699)
        17  Office of Personnel Management (Parts 1700--1799)
        18  National Aeronautics and Space Administration (Parts 
                1800--1899)
        19  Broadcasting Board of Governors (Parts 1900--1999)
        20  Nuclear Regulatory Commission (Parts 2000--2099)
        21  Office of Personnel Management, Federal Employees 
                Group Life Insurance Federal Acquisition 
                Regulation (Parts 2100--2199)
        23  Social Security Administration (Parts 2300--2399)
        24  Department of Housing and Urban Development (Parts 
                2400--2499)
        25  National Science Foundation (Parts 2500--2599)
        28  Department of Justice (Parts 2800--2899)
        29  Department of Labor (Parts 2900--2999)
        30  Department of Homeland Security, Homeland Security 
                Acquisition Regulation (HSAR) (Parts 3000--3099)
        34  Department of Education Acquisition Regulation (Parts 
                3400--3499)
        51  Department of the Army Acquisition Regulations (Parts 
                5100--5199)
        52  Department of the Navy Acquisition Regulations (Parts 
                5200--5299)
        53  Department of the Air Force Federal Acquisition 
                Regulation Supplement (Parts 5300--5399) 
                [Reserved]
        54  Defense Logistics Agency, Department of Defense (Parts 
                5400--5499)
        57  African Development Foundation (Parts 5700--5799)
        61  Civilian Board of Contract Appeals, General Services 
                Administration (Parts 6100--6199)
        63  Department of Transportation Board of Contract Appeals 
                (Parts 6300--6399)
        99  Cost Accounting Standards Board, Office of Federal 
                Procurement Policy, Office of Management and 
                Budget (Parts 9900--9999)

[[Page 1109]]

                       Title 49--Transportation

            Subtitle A--Office of the Secretary of Transportation 
                (Parts 1--99)
            Subtitle B--Other Regulations Relating to 
                Transportation
         I  Pipeline and Hazardous Materials Safety 
                Administration, Department of Transportation 
                (Parts 100--199)
        II  Federal Railroad Administration, Department of 
                Transportation (Parts 200--299)
       III  Federal Motor Carrier Safety Administration, 
                Department of Transportation (Parts 300--399)
        IV  Coast Guard, Department of Homeland Security (Parts 
                400--499)
         V  National Highway Traffic Safety Administration, 
                Department of Transportation (Parts 500--599)
        VI  Federal Transit Administration, Department of 
                Transportation (Parts 600--699)
       VII  National Railroad Passenger Corporation (AMTRAK) 
                (Parts 700--799)
      VIII  National Transportation Safety Board (Parts 800--999)
         X  Surface Transportation Board (Parts 1000--1399)
        XI  Research and Innovative Technology Administration, 
                Department of Transportation (Parts 1400--1499) 
                [Reserved]
       XII  Transportation Security Administration, Department of 
                Homeland Security (Parts 1500--1699)

                   Title 50--Wildlife and Fisheries

         I  United States Fish and Wildlife Service, Department of 
                the Interior (Parts 1--199)
        II  National Marine Fisheries Service, National Oceanic 
                and Atmospheric Administration, Department of 
                Commerce (Parts 200--299)
       III  International Fishing and Related Activities (Parts 
                300--399)
        IV  Joint Regulations (United States Fish and Wildlife 
                Service, Department of the Interior and National 
                Marine Fisheries Service, National Oceanic and 
                Atmospheric Administration, Department of 
                Commerce); Endangered Species Committee 
                Regulations (Parts 400--499)
         V  Marine Mammal Commission (Parts 500--599)
        VI  Fishery Conservation and Management, National Oceanic 
                and Atmospheric Administration, Department of 
                Commerce (Parts 600--699)

[[Page 1111]]





           Alphabetical List of Agencies Appearing in the CFR




                      (Revised as of July 1, 2016)

                                                  CFR Title, Subtitle or 
                     Agency                               Chapter

Administrative Committee of the Federal Register  1, I
Administrative Conference of the United States    1, III
Advisory Council on Historic Preservation         36, VIII
Advocacy and Outreach, Office of                  7, XXV
Afghanistan Reconstruction, Special Inspector     5, LXXXIII
     General for
African Development Foundation                    22, XV
  Federal Acquisition Regulation                  48, 57
Agency for International Development              2, VII; 22, II
  Federal Acquisition Regulation                  48, 7
Agricultural Marketing Service                    7, I, IX, X, XI
Agricultural Research Service                     7, V
Agriculture Department                            2, IV; 5, LXXIII
  Advocacy and Outreach, Office of                7, XXV
  Agricultural Marketing Service                  7, I, IX, X, XI
  Agricultural Research Service                   7, V
  Animal and Plant Health Inspection Service      7, III; 9, I
  Chief Financial Officer, Office of              7, XXX
  Commodity Credit Corporation                    7, XIV
  Economic Research Service                       7, XXXVII
  Energy Policy and New Uses, Office of           2, IX; 7, XXIX
  Environmental Quality, Office of                7, XXXI
  Farm Service Agency                             7, VII, XVIII
  Federal Acquisition Regulation                  48, 4
  Federal Crop Insurance Corporation              7, IV
  Food and Nutrition Service                      7, II
  Food Safety and Inspection Service              9, III
  Foreign Agricultural Service                    7, XV
  Forest Service                                  36, II
  Grain Inspection, Packers and Stockyards        7, VIII; 9, II
       Administration
  Information Resources Management, Office of     7, XXVII
  Inspector General, Office of                    7, XXVI
  National Agricultural Library                   7, XLI
  National Agricultural Statistics Service        7, XXXVI
  National Institute of Food and Agriculture      7, XXXIV
  Natural Resources Conservation Service          7, VI
  Operations, Office of                           7, XXVIII
  Procurement and Property Management, Office of  7, XXXII
  Rural Business-Cooperative Service              7, XVIII, XLII
  Rural Development Administration                7, XLII
  Rural Housing Service                           7, XVIII, XXXV
  Rural Telephone Bank                            7, XVI
  Rural Utilities Service                         7, XVII, XVIII, XLII
  Secretary of Agriculture, Office of             7, Subtitle A
  Transportation, Office of                       7, XXXIII
  World Agricultural Outlook Board                7, XXXVIII
Air Force Department                              32, VII
  Federal Acquisition Regulation Supplement       48, 53
Air Transportation Stabilization Board            14, VI
Alcohol and Tobacco Tax and Trade Bureau          27, I
Alcohol, Tobacco, Firearms, and Explosives,       27, II
     Bureau of
AMTRAK                                            49, VII
American Battle Monuments Commission              36, IV
American Indians, Office of the Special Trustee   25, VII

[[Page 1112]]

Animal and Plant Health Inspection Service        7, III; 9, I
Appalachian Regional Commission                   5, IX
Architectural and Transportation Barriers         36, XI
     Compliance Board
Arctic Research Commission                        45, XXIII
Armed Forces Retirement Home                      5, XI
Army Department                                   32, V
  Engineers, Corps of                             33, II; 36, III
  Federal Acquisition Regulation                  48, 51
Bilingual Education and Minority Languages        34, V
     Affairs, Office of
Blind or Severely Disabled, Committee for         41, 51
     Purchase from People Who Are
Broadcasting Board of Governors                   22, V
  Federal Acquisition Regulation                  48, 19
Career, Technical and Adult Education, Office of  34, IV
Census Bureau                                     15, I
Centers for Medicare & Medicaid Services          42, IV
Central Intelligence Agency                       32, XIX
Chemical Safety and Hazardous Investigation       40, VI
     Board
Chief Financial Officer, Office of                7, XXX
Child Support Enforcement, Office of              45, III
Children and Families, Administration for         45, II, III, IV, X
Civil Rights, Commission on                       5, LXVIII; 45, VII
Civil Rights, Office for                          34, I
Council of the Inspectors General on Integrity    5, XCVIII
     and Efficiency
Court Services and Offender Supervision Agency    5, LXX
     for the District of Columbia
Coast Guard                                       33, I; 46, I; 49, IV
Coast Guard (Great Lakes Pilotage)                46, III
Commerce Department                               2, XIII; 44, IV; 50, VI
  Census Bureau                                   15, I
  Economic Analysis, Bureau of                    15, VIII
  Economic Development Administration             13, III
  Emergency Management and Assistance             44, IV
  Federal Acquisition Regulation                  48, 13
  Foreign-Trade Zones Board                       15, IV
  Industry and Security, Bureau of                15, VII
  International Trade Administration              15, III; 19, III
  National Institute of Standards and Technology  15, II
  National Marine Fisheries Service               50, II, IV
  National Oceanic and Atmospheric                15, IX; 50, II, III, IV, 
       Administration                             VI
  National Telecommunications and Information     15, XXIII; 47, III, IV
       Administration
  National Weather Service                        15, IX
  Patent and Trademark Office, United States      37, I
  Productivity, Technology and Innovation,        37, IV
       Assistant Secretary for
  Secretary of Commerce, Office of                15, Subtitle A
  Technology Administration                       15, XI
  Technology Policy, Assistant Secretary for      37, IV
Commercial Space Transportation                   14, III
Commodity Credit Corporation                      7, XIV
Commodity Futures Trading Commission              5, XLI; 17, I
Community Planning and Development, Office of     24, V, VI
     Assistant Secretary for
Community Services, Office of                     45, X
Comptroller of the Currency                       12, I
Construction Industry Collective Bargaining       29, IX
     Commission
Consumer Financial Protection Bureau              5, LXXXIV; 12, X
Consumer Product Safety Commission                5, LXXI; 16, II
Copyright Royalty Board                           37, III
Corporation for National and Community Service    2, XXII; 45, XII, XXV
Cost Accounting Standards Board                   48, 99
Council on Environmental Quality                  40, V
Court Services and Offender Supervision Agency    5, LXX; 28, VIII
     for the District of Columbia
Customs and Border Protection                     19, I
Defense Contract Audit Agency                     32, I

[[Page 1113]]

Defense Department                                2, XI; 5, XXVI; 32, 
                                                  Subtitle A; 40, VII
  Advanced Research Projects Agency               32, I
  Air Force Department                            32, VII
  Army Department                                 32, V; 33, II; 36, III; 
                                                  48, 51
  Defense Acquisition Regulations System          48, 2
  Defense Intelligence Agency                     32, I
  Defense Logistics Agency                        32, I, XII; 48, 54
  Engineers, Corps of                             33, II; 36, III
  National Imagery and Mapping Agency             32, I
  Navy Department                                 32, VI; 48, 52
  Secretary of Defense, Office of                 2, XI; 32, I
Defense Contract Audit Agency                     32, I
Defense Intelligence Agency                       32, I
Defense Logistics Agency                          32, XII; 48, 54
Defense Nuclear Facilities Safety Board           10, XVII
Delaware River Basin Commission                   18, III
District of Columbia, Court Services and          5, LXX; 28, VIII
     Offender Supervision Agency for the
Drug Enforcement Administration                   21, II
East-West Foreign Trade Board                     15, XIII
Economic Analysis, Bureau of                      15, VIII
Economic Development Administration               13, III
Economic Research Service                         7, XXXVII
Education, Department of                          2, XXXIV; 5, LIII
  Bilingual Education and Minority Languages      34, V
       Affairs, Office of
  Career, Technical and Adult Education, Office   34, IV
       of
  Civil Rights, Office for                        34, I
  Educational Research and Improvement, Office    34, VII
       of
  Elementary and Secondary Education, Office of   34, II
  Federal Acquisition Regulation                  48, 34
  Postsecondary Education, Office of              34, VI
  Secretary of Education, Office of               34, Subtitle A
  Special Education and Rehabilitative Services,  34, III
       Office of
  Career, Technical, and Adult Education, Office  34, IV
       of
Educational Research and Improvement, Office of   34, VII
Election Assistance Commission                    2, LVIII; 11, II
Elementary and Secondary Education, Office of     34, II
Emergency Oil and Gas Guaranteed Loan Board       13, V
Emergency Steel Guarantee Loan Board              13, IV
Employee Benefits Security Administration         29, XXV
Employees' Compensation Appeals Board             20, IV
Employees Loyalty Board                           5, V
Employment and Training Administration            20, V
Employment Standards Administration               20, VI
Endangered Species Committee                      50, IV
Energy, Department of                             2, IX; 5, XXIII; 10, II, 
                                                  III, X
  Federal Acquisition Regulation                  48, 9
  Federal Energy Regulatory Commission            5, XXIV; 18, I
  Property Management Regulations                 41, 109
Energy, Office of                                 7, XXIX
Engineers, Corps of                               33, II; 36, III
Engraving and Printing, Bureau of                 31, VI
Environmental Protection Agency                   2, XV; 5, LIV; 40, I, IV, 
                                                  VII
  Federal Acquisition Regulation                  48, 15
  Property Management Regulations                 41, 115
Environmental Quality, Office of                  7, XXXI
Equal Employment Opportunity Commission           5, LXII; 29, XIV
Equal Opportunity, Office of Assistant Secretary  24, I
     for
Executive Office of the President                 3, I
  Environmental Quality, Council on               40, V
  Management and Budget, Office of                2, Subtitle A; 5, III, 
                                                  LXXVII; 14, VI; 48, 99

[[Page 1114]]

  National Drug Control Policy, Office of         2, XXXVI; 21, III
  National Security Council                       32, XXI; 47, 2
  Presidential Documents                          3
  Science and Technology Policy, Office of        32, XXIV; 47, II
  Trade Representative, Office of the United      15, XX
       States
Export-Import Bank of the United States           2, XXXV; 5, LII; 12, IV
Family Assistance, Office of                      45, II
Farm Credit Administration                        5, XXXI; 12, VI
Farm Credit System Insurance Corporation          5, XXX; 12, XIV
Farm Service Agency                               7, VII, XVIII
Federal Acquisition Regulation                    48, 1
Federal Aviation Administration                   14, I
  Commercial Space Transportation                 14, III
Federal Claims Collection Standards               31, IX
Federal Communications Commission                 5, XXIX; 47, I
Federal Contract Compliance Programs, Office of   41, 60
Federal Crop Insurance Corporation                7, IV
Federal Deposit Insurance Corporation             5, XXII; 12, III
Federal Election Commission                       5, XXXVII; 11, I
Federal Emergency Management Agency               44, I
Federal Employees Group Life Insurance Federal    48, 21
     Acquisition Regulation
Federal Employees Health Benefits Acquisition     48, 16
     Regulation
Federal Energy Regulatory Commission              5, XXIV; 18, I
Federal Financial Institutions Examination        12, XI
     Council
Federal Financing Bank                            12, VIII
Federal Highway Administration                    23, I, II
Federal Home Loan Mortgage Corporation            1, IV
Federal Housing Enterprise Oversight Office       12, XVII
Federal Housing Finance Agency                    5, LXXX; 12, XII
Federal Housing Finance Board                     12, IX
Federal Labor Relations Authority                 5, XIV, XLIX; 22, XIV
Federal Law Enforcement Training Center           31, VII
Federal Management Regulation                     41, 102
Federal Maritime Commission                       46, IV
Federal Mediation and Conciliation Service        29, XII
Federal Mine Safety and Health Review Commission  5, LXXIV; 29, XXVII
Federal Motor Carrier Safety Administration       49, III
Federal Prison Industries, Inc.                   28, III
Federal Procurement Policy Office                 48, 99
Federal Property Management Regulations           41, 101
Federal Railroad Administration                   49, II
Federal Register, Administrative Committee of     1, I
Federal Register, Office of                       1, II
Federal Reserve System                            12, II
  Board of Governors                              5, LVIII
Federal Retirement Thrift Investment Board        5, VI, LXXVI
Federal Service Impasses Panel                    5, XIV
Federal Trade Commission                          5, XLVII; 16, I
Federal Transit Administration                    49, VI
Federal Travel Regulation System                  41, Subtitle F
Financial Crimes Enforcement Network              31, X
Financial Research Office                         12, XVI
Financial Stability Oversight Council             12, XIII
Fine Arts, Commission on                          45, XXI
Fiscal Service                                    31, II
Fish and Wildlife Service, United States          50, I, IV
Food and Drug Administration                      21, I
Food and Nutrition Service                        7, II
Food Safety and Inspection Service                9, III
Foreign Agricultural Service                      7, XV
Foreign Assets Control, Office of                 31, V
Foreign Claims Settlement Commission of the       45, V
     United States
Foreign Service Grievance Board                   22, IX
Foreign Service Impasse Disputes Panel            22, XIV
Foreign Service Labor Relations Board             22, XIV
Foreign-Trade Zones Board                         15, IV

[[Page 1115]]

Forest Service                                    36, II
General Services Administration                   5, LVII; 41, 105
  Contract Appeals, Board of                      48, 61
  Federal Acquisition Regulation                  48, 5
  Federal Management Regulation                   41, 102
  Federal Property Management Regulations         41, 101
  Federal Travel Regulation System                41, Subtitle F
  General                                         41, 300
  Payment From a Non-Federal Source for Travel    41, 304
       Expenses
  Payment of Expenses Connected With the Death    41, 303
       of Certain Employees
  Relocation Allowances                           41, 302
  Temporary Duty (TDY) Travel Allowances          41, 301
Geological Survey                                 30, IV
Government Accountability Office                  4, I
Government Ethics, Office of                      5, XVI
Government National Mortgage Association          24, III
Grain Inspection, Packers and Stockyards          7, VIII; 9, II
     Administration
Gulf Coast Ecosystem Restoration Council          2, LIX; 40, VIII
Harry S. Truman Scholarship Foundation            45, XVIII
Health and Human Services, Department of          2, III; 5, XLV; 45, 
                                                  Subtitle A,
  Centers for Medicare & Medicaid Services        42, IV
  Child Support Enforcement, Office of            45, III
  Children and Families, Administration for       45, II, III, IV, X
  Community Services, Office of                   45, X
  Family Assistance, Office of                    45, II
  Federal Acquisition Regulation                  48, 3
  Food and Drug Administration                    21, I
  Human Development Services, Office of           45, XIII
  Indian Health Service                           25, V
  Inspector General (Health Care), Office of      42, V
  Public Health Service                           42, I
  Refugee Resettlement, Office of                 45, IV
Homeland Security, Department of                  2, XXX; 5, XXXVI; 6, I; 8, 
                                                  I
  Coast Guard                                     33, I; 46, I; 49, IV
  Coast Guard (Great Lakes Pilotage)              46, III
  Customs and Border Protection                   19, I
  Federal Emergency Management Agency             44, I
  Human Resources Management and Labor Relations  5, XCVII
       Systems
  Immigration and Customs Enforcement Bureau      19, IV
  Transportation Security Administration          49, XII
HOPE for Homeowners Program, Board of Directors   24, XXIV
     of
Housing and Urban Development, Department of      2, XXIV; 5, LXV; 24, 
                                                  Subtitle B
  Community Planning and Development, Office of   24, V, VI
       Assistant Secretary for
  Equal Opportunity, Office of Assistant          24, I
       Secretary for
  Federal Acquisition Regulation                  48, 24
  Federal Housing Enterprise Oversight, Office    12, XVII
       of
  Government National Mortgage Association        24, III
  Housing--Federal Housing Commissioner, Office   24, II, VIII, X, XX
       of Assistant Secretary for
  Housing, Office of, and Multifamily Housing     24, IV
       Assistance Restructuring, Office of
  Inspector General, Office of                    24, XII
  Public and Indian Housing, Office of Assistant  24, IX
       Secretary for
  Secretary, Office of                            24, Subtitle A, VII
Housing--Federal Housing Commissioner, Office of  24, II, VIII, X, XX
     Assistant Secretary for
Housing, Office of, and Multifamily Housing       24, IV
     Assistance Restructuring, Office of
Human Development Services, Office of             45, XIII
Immigration and Customs Enforcement Bureau        19, IV
Immigration Review, Executive Office for          8, V

[[Page 1116]]

Independent Counsel, Office of                    28, VII
Independent Counsel, Offices of                   28, VI
Indian Affairs, Bureau of                         25, I, V
Indian Affairs, Office of the Assistant           25, VI
     Secretary
Indian Arts and Crafts Board                      25, II
Indian Health Service                             25, V
Industry and Security, Bureau of                  15, VII
Information Resources Management, Office of       7, XXVII
Information Security Oversight Office, National   32, XX
     Archives and Records Administration
Inspector General
  Agriculture Department                          7, XXVI
  Health and Human Services Department            42, V
  Housing and Urban Development Department        24, XII, XV
Institute of Peace, United States                 22, XVII
Inter-American Foundation                         5, LXIII; 22, X
Interior Department                               2, XIV
  American Indians, Office of the Special         25, VII
       Trustee
  Endangered Species Committee                    50, IV
  Federal Acquisition Regulation                  48, 14
  Federal Property Management Regulations System  41, 114
  Fish and Wildlife Service, United States        50, I, IV
  Geological Survey                               30, IV
  Indian Affairs, Bureau of                       25, I, V
  Indian Affairs, Office of the Assistant         25, VI
       Secretary
  Indian Arts and Crafts Board                    25, II
  Land Management, Bureau of                      43, II
  National Indian Gaming Commission               25, III
  National Park Service                           36, I
  Natural Resource Revenue, Office of             30, XII
  Ocean Energy Management, Bureau of              30, V
  Reclamation, Bureau of                          43, I
  Safety and Enforcement Bureau, Bureau of        30, II
  Secretary of the Interior, Office of            2, XIV; 43, Subtitle A
  Surface Mining Reclamation and Enforcement,     30, VII
       Office of
Internal Revenue Service                          26, I
International Boundary and Water Commission,      22, XI
     United States and Mexico, United States 
     Section
International Development, United States Agency   22, II
     for
  Federal Acquisition Regulation                  48, 7
International Development Cooperation Agency,     22, XII
     United States
International Joint Commission, United States     22, IV
     and Canada
International Organizations Employees Loyalty     5, V
     Board
International Trade Administration                15, III; 19, III
International Trade Commission, United States     19, II
Interstate Commerce Commission                    5, XL
Investment Security, Office of                    31, VIII
James Madison Memorial Fellowship Foundation      45, XXIV
Japan-United States Friendship Commission         22, XVI
Joint Board for the Enrollment of Actuaries       20, VIII
Justice Department                                2, XXVIII; 5, XXVIII; 28, 
                                                  I, XI; 40, IV
  Alcohol, Tobacco, Firearms, and Explosives,     27, II
       Bureau of
  Drug Enforcement Administration                 21, II
  Federal Acquisition Regulation                  48, 28
  Federal Claims Collection Standards             31, IX
  Federal Prison Industries, Inc.                 28, III
  Foreign Claims Settlement Commission of the     45, V
       United States
  Immigration Review, Executive Office for        8, V
  Independent Counsel, Offices of                 28, VI
  Prisons, Bureau of                              28, V
  Property Management Regulations                 41, 128
Labor Department                                  2, XXIX; 5, XLII
  Employee Benefits Security Administration       29, XXV
  Employees' Compensation Appeals Board           20, IV

[[Page 1117]]

  Employment and Training Administration          20, V
  Employment Standards Administration             20, VI
  Federal Acquisition Regulation                  48, 29
  Federal Contract Compliance Programs, Office    41, 60
       of
  Federal Procurement Regulations System          41, 50
  Labor-Management Standards, Office of           29, II, IV
  Mine Safety and Health Administration           30, I
  Occupational Safety and Health Administration   29, XVII
  Public Contracts                                41, 50
  Secretary of Labor, Office of                   29, Subtitle A
  Veterans' Employment and Training Service,      41, 61; 20, IX
       Office of the Assistant Secretary for
  Wage and Hour Division                          29, V
  Workers' Compensation Programs, Office of       20, I, VII
Labor-Management Standards, Office of             29, II, IV
Land Management, Bureau of                        43, II
Legal Services Corporation                        45, XVI
Library of Congress                               36, VII
  Copyright Royalty Board                         37, III
  U.S. Copyright Office                           37, II
Local Television Loan Guarantee Board             7, XX
Management and Budget, Office of                  5, III, LXXVII; 14, VI; 
                                                  48, 99
Marine Mammal Commission                          50, V
Maritime Administration                           46, II
Merit Systems Protection Board                    5, II, LXIV
Micronesian Status Negotiations, Office for       32, XXVII
Military Compensation and Retirement              5, XCIX
     Modernization Commission
Millennium Challenge Corporation                  22, XIII
Mine Safety and Health Administration             30, I
Minority Business Development Agency              15, XIV
Miscellaneous Agencies                            1, IV
Monetary Offices                                  31, I
Morris K. Udall Scholarship and Excellence in     36, XVI
     National Environmental Policy Foundation
Museum and Library Services, Institute of         2, XXXI
National Aeronautics and Space Administration     2, XVIII; 5, LIX; 14, V
  Federal Acquisition Regulation                  48, 18
National Agricultural Library                     7, XLI
National Agricultural Statistics Service          7, XXXVI
National and Community Service, Corporation for   2, XXII; 45, XII, XXV
National Archives and Records Administration      2, XXVI; 5, LXVI; 36, XII
  Information Security Oversight Office           32, XX
National Capital Planning Commission              1, IV
National Commission for Employment Policy         1, IV
National Commission on Libraries and Information  45, XVII
     Science
National Council on Disability                    5, C; 34, XII
National Counterintelligence Center               32, XVIII
National Credit Union Administration              5, LXXXVI; 12, VII
National Crime Prevention and Privacy Compact     28, IX
     Council
National Drug Control Policy, Office of           2, XXXVI; 21, III
National Endowment for the Arts                   2, XXXII
National Endowment for the Humanities             2, XXXIII
National Foundation on the Arts and the           45, XI
     Humanities
National Geospatial-Intelligence Agency           32, I
National Highway Traffic Safety Administration    23, II, III; 47, VI; 49, V
National Imagery and Mapping Agency               32, I
National Indian Gaming Commission                 25, III
National Institute of Food and Agriculture        7, XXXIV
National Institute of Standards and Technology    15, II
National Intelligence, Office of Director of      5, IV; 32, XVII
National Labor Relations Board                    5, LXI; 29, I
National Marine Fisheries Service                 50, II, IV
National Mediation Board                          29, X
National Oceanic and Atmospheric Administration   15, IX; 50, II, III, IV, 
                                                  VI

[[Page 1118]]

National Park Service                             36, I
National Railroad Adjustment Board                29, III
National Railroad Passenger Corporation (AMTRAK)  49, VII
National Science Foundation                       2, XXV; 5, XLIII; 45, VI
  Federal Acquisition Regulation                  48, 25
National Security Council                         32, XXI
National Security Council and Office of Science   47, II
     and Technology Policy
National Telecommunications and Information       15, XXIII; 47, III, IV
     Administration
National Transportation Safety Board              49, VIII
Natural Resources Conservation Service            7, VI
Natural Resource Revenue, Office of               30, XII
Navajo and Hopi Indian Relocation, Office of      25, IV
Navy Department                                   32, VI
  Federal Acquisition Regulation                  48, 52
Neighborhood Reinvestment Corporation             24, XXV
Northeast Interstate Low-Level Radioactive Waste  10, XVIII
     Commission
Nuclear Regulatory Commission                     2, XX; 5, XLVIII; 10, I
  Federal Acquisition Regulation                  48, 20
Occupational Safety and Health Administration     29, XVII
Occupational Safety and Health Review Commission  29, XX
Ocean Energy Management, Bureau of                30, V
Oklahoma City National Memorial Trust             36, XV
Operations Office                                 7, XXVIII
Overseas Private Investment Corporation           5, XXXIII; 22, VII
Patent and Trademark Office, United States        37, I
Payment From a Non-Federal Source for Travel      41, 304
     Expenses
Payment of Expenses Connected With the Death of   41, 303
     Certain Employees
Peace Corps                                       2, XXXVII; 22, III
Pennsylvania Avenue Development Corporation       36, IX
Pension Benefit Guaranty Corporation              29, XL
Personnel Management, Office of                   5, I, XXXV; 5, IV; 45, 
                                                  VIII
  Human Resources Management and Labor Relations  5, XCVII
       Systems, Department of Homeland Security
  Federal Acquisition Regulation                  48, 17
  Federal Employees Group Life Insurance Federal  48, 21
       Acquisition Regulation
  Federal Employees Health Benefits Acquisition   48, 16
       Regulation
Pipeline and Hazardous Materials Safety           49, I
     Administration
Postal Regulatory Commission                      5, XLVI; 39, III
Postal Service, United States                     5, LX; 39, I
Postsecondary Education, Office of                34, VI
President's Commission on White House             1, IV
     Fellowships
Presidential Documents                            3
Presidio Trust                                    36, X
Prisons, Bureau of                                28, V
Privacy and Civil Liberties Oversight Board       6, X
Procurement and Property Management, Office of    7, XXXII
Productivity, Technology and Innovation,          37, IV
     Assistant Secretary
Public Contracts, Department of Labor             41, 50
Public and Indian Housing, Office of Assistant    24, IX
     Secretary for
Public Health Service                             42, I
Railroad Retirement Board                         20, II
Reclamation, Bureau of                            43, I
Refugee Resettlement, Office of                   45, IV
Relocation Allowances                             41, 302
Research and Innovative Technology                49, XI
     Administration
Rural Business-Cooperative Service                7, XVIII, XLII
Rural Development Administration                  7, XLII
Rural Housing Service                             7, XVIII, XXXV
Rural Telephone Bank                              7, XVI
Rural Utilities Service                           7, XVII, XVIII, XLII

[[Page 1119]]

Safety and Environmental Enforcement, Bureau of   30, II
Saint Lawrence Seaway Development Corporation     33, IV
Science and Technology Policy, Office of          32, XXIV
Science and Technology Policy, Office of, and     47, II
     National Security Council
Secret Service                                    31, IV
Securities and Exchange Commission                5, XXXIV; 17, II
Selective Service System                          32, XVI
Small Business Administration                     2, XXVII; 13, I
Smithsonian Institution                           36, V
Social Security Administration                    2, XXIII; 20, III; 48, 23
Soldiers' and Airmen's Home, United States        5, XI
Special Counsel, Office of                        5, VIII
Special Education and Rehabilitative Services,    34, III
     Office of
State Department                                  2, VI; 22, I; 28, XI
  Federal Acquisition Regulation                  48, 6
Surface Mining Reclamation and Enforcement,       30, VII
     Office of
Surface Transportation Board                      49, X
Susquehanna River Basin Commission                18, VIII
Technology Administration                         15, XI
Technology Policy, Assistant Secretary for        37, IV
Tennessee Valley Authority                        5, LXIX; 18, XIII
Thrift Supervision Office, Department of the      12, V
     Treasury
Trade Representative, United States, Office of    15, XX
Transportation, Department of                     2, XII; 5, L
  Commercial Space Transportation                 14, III
  Contract Appeals, Board of                      48, 63
  Emergency Management and Assistance             44, IV
  Federal Acquisition Regulation                  48, 12
  Federal Aviation Administration                 14, I
  Federal Highway Administration                  23, I, II
  Federal Motor Carrier Safety Administration     49, III
  Federal Railroad Administration                 49, II
  Federal Transit Administration                  49, VI
  Maritime Administration                         46, II
  National Highway Traffic Safety Administration  23, II, III; 47, IV; 49, V
  Pipeline and Hazardous Materials Safety         49, I
       Administration
  Saint Lawrence Seaway Development Corporation   33, IV
  Secretary of Transportation, Office of          14, II; 49, Subtitle A
  Transportation Statistics Bureau                49, XI
Transportation, Office of                         7, XXXIII
Transportation Security Administration            49, XII
Transportation Statistics Bureau                  49, XI
Travel Allowances, Temporary Duty (TDY)           41, 301
Treasury Department                               2, X;5, XXI; 12, XV; 17, 
                                                  IV; 31, IX
  Alcohol and Tobacco Tax and Trade Bureau        27, I
  Community Development Financial Institutions    12, XVIII
       Fund
  Comptroller of the Currency                     12, I
  Customs and Border Protection                   19, I
  Engraving and Printing, Bureau of               31, VI
  Federal Acquisition Regulation                  48, 10
  Federal Claims Collection Standards             31, IX
  Federal Law Enforcement Training Center         31, VII
  Financial Crimes Enforcement Network            31, X
  Fiscal Service                                  31, II
  Foreign Assets Control, Office of               31, V
  Internal Revenue Service                        26, I
  Investment Security, Office of                  31, VIII
  Monetary Offices                                31, I
  Secret Service                                  31, IV
  Secretary of the Treasury, Office of            31, Subtitle A
  Thrift Supervision, Office of                   12, V
Truman, Harry S. Scholarship Foundation           45, XVIII
United States and Canada, International Joint     22, IV
     Commission
United States and Mexico, International Boundary  22, XI
   and Water Commission, United States Section
[[Page 1120]]

U.S. Copyright Office                             37, II
Utah Reclamation Mitigation and Conservation      43, III
     Commission
Veterans Affairs Department                       2, VIII; 38, I
  Federal Acquisition Regulation                  48, 8
Veterans' Employment and Training Service,        41, 61; 20, IX
     Office of the Assistant Secretary for
Vice President of the United States, Office of    32, XXVIII
Wage and Hour Division                            29, V
Water Resources Council                           18, VI
Workers' Compensation Programs, Office of         20, I, VII
World Agricultural Outlook Board                  7, XXXVIII

[[Page 1121]]



List of CFR Sections Affected



All changes in this volume of the Code of Federal Regulations (CFR) that 
were made by documents published in the Federal Register since January 
1, 2011 are enumerated in the following list. Entries indicate the 
nature of the changes effected. Page numbers refer to Federal Register 
pages. The user should consult the entries for chapters, parts and 
subparts as well as sections for revisions.
For changes to this volume of the CFR prior to this listing, consult the 
annual edition of the monthly List of CFR Sections Affected (LSA). The 
LSA is available at www.fdsys.gov. For changes to this volume of the CFR 
prior to 2001, see the ``List of CFR Sections Affected, 1949-1963, 1964-
1972, 1973-1985, and 1986-2000'' published in 11 separate volumes. The 
``List of CFR Sections Affected 1986-2000'' is available at 
www.fdsys.gov.

                                  2011

40 CFR
                                                                   76 FR
                                                                    Page
Chapter I
97 Policy statement................................................42055
97.401--97.435 (Subpart AAAAA) Added...............................48379
97.501--97.535 (Subpart BBBBB) Added...............................48406
97.510 Revised.....................................................80775
97.521 (a), (b) introductory text, (1), (2) and (3) amended........80777
97.601--97.635 (Subpart CCCCC) Added...............................48432
97.701--97.735 (Subpart DDDDD) Added...............................48458
98.1 (a) revised...................................................73898
    (c) added......................................................80573
98.2 (d), (e), (f) introductory text, (h) and (i)(3) revised.......73899
98.3 (b) introductory text, (c)(4)(vii) and (d)(3) introductory 
        text revised; second (c)(4)(vi) redesignated as 
        (c)(4)(viii)...............................................14818
    98.3 (c)(4)(vii) revised.......................................53065
    (b) introductory text, (c)(5)(ii), (7), (10) and (11) revised; 
(b)(1) and (4) added; (g) introductory text amended................73899
98.4 (m)(4) revised................................................73900
98.6 Amended................................................73900, 80573
98.9 Introductory text revised.....................................73900
98.1--98.9 (Subpart A) Table A-6 amended...........................14818
    98.1--98.9 (Subpart A) Table A-6 revised; Table A-7 added......53065
    Table A-3 amended..............................................73900
    Table A-5 amended..............................................73901
98.93 (a)(2)(ii) introductory text revised.........................59551
98.94 (a)(1) introductory text and (4)(i) revised..................59551
    98.94 (a)(1) introductory text, (3) introductory text, (i) and 
(4)(i) revised.....................................................36342
98.230 (a)(2), (3), (4) and (8) revised............................80574
98.232 (a), (c) introductory text, (22), (d) introductory text, 
        (e) introductory text, (f) introductory text, (g) 
        introductory text, (h) introductory text, (i) and (k) 
        revised; (j) removed.......................................80574

[[Page 1122]]

98.233 (f)(3)(i), (ii), (g)(1)(ii)(D), (5) and (h)(1) removed; 
        (g)(1)(ii)(A), (B), (C), (6), (i), (ii), (h)(2), (3) 
        introductory text, (n)(9), (z)(4), (5) and (6) 
        redesignated as (g)(1)(iii), (iv), (v), new (5), (i), 
        (ii), new (h)(1), (2) introductory text, (n)(10), 
        (z)(2)(iv), (v) and (vi); (a), (c), (d)(2), (4) 
        introductory text, (e)(2), (5) introductory text, (f)(3) 
        introductory text, (g)(1)(ii), (j)(1), (5), (8), (m)(3), 
        (n)(4), (o)(6), (7), (p)(7)(i) introductory text, (9), 
        (r), (t)(1), (2), (v), (w)(3), (x)(2) and new (z)(2)(vi) 
        amended; (a)(3), (k)(2)(iv), new (n)(9), (11), (t)(3) and 
        new (z)(4) added; (d) introductory text, (1), (3), (e) 
        introductory text, (1) introductory text, (vii), (xi) 
        introductory text, (A), (B), (C), (2) introductory text, 
        (6), (f)(1) introductory text, (i)(A), (B), (C), (2), (g) 
        introductory text, (1) introductory text, (i), (ii) 
        introductory text, new (iii), new (iv), new (v), (3), (h) 
        introductory text, new (1), (i), (j)(1)(vii) introductory 
        text, (B), (C), (2), (3) introductory text, (i), (4) 
        introductory text, (k) introductory text, (1), (2) 
        introductory text, (i). (4), (l)(1), (3), (m)(1), 
        (n)(2)(ii), (iii), (q) introductory text, (8), (r) 
        introductory text, (2)(i)(A), (6)(i), (ii), (t) 
        introductory text, (1) introductory text, (2), (u) 
        introductory text, (2), (z) introductory text, (1), (2) 
        introductory text, (i), (ii), (iii) and (3) revised........80575
98.234 (f)(2) introductory text, (3) introductory text, (5)(i), 
        (ii), (iii)(A), (iv)(A), (6) introductory text, (i), 
        (ii)(D), (iii), (7) introductory text, (i) and (iii) 
        revised....................................................22827
    98.234 (f)(1) introductory text, (2) introductory text, (3) 
introductory text, (4) introductory text, (5) and (8) revised; 
(f)(6) and (7) removed.............................................59540
    (a)(1), (2), (5), (c) introductory text and (d)(3) revised; 
(a)(4) removed; (e) amended; (g) added.............................80586
98.236 (a) introductory text, (8), (b), (c) introductory text, 
        (1)(iv), (2)(ii), (3)(ii) through (v), (4)(i)(H), (J), 
        (ii)(B), (C), (iii)(B), (5), (6) introductory text, (i), 
        (ii)(B), (D), (7), (8)(i) introductory text, (J), (ii) 
        introductory text, (D), (G), (iii) introductory text, (F), 
        (9) introductory text, (i), (10) introductory text, (iv), 
        (11) introductory text, (iii), (12)(vi), (15) introductory 
        text, (i)(A), (B), (C), (ii)(A), (B), (C), (16), (17)(v), 
        (18) introductory text, (iii), (19)(iii), (v), (vi) and 
        (vii) revised; (c)(3)(vi), (vii), (4)(i)(K), (L), (ii)(D), 
        (6)(ii)(E), (8)(i)(K), (L), (ii)(H), (I), (iii)(G), (H), 
        (iv)(B), (9)(ii), (iii), (10)(v), (11)(iv), (12)(vii) 
        through (xi) and (e) added.................................80587
98.237 (e) added...................................................80590
98.238 Amended.....................................................80590
98.230--98.238 (Subpart W) Table W-1A revised......................80591
    Table W-2 revised..............................................80592
    Tables W-3 and W-4 revised.....................................80593
    Tables W-5, W-6 and W-7 revised................................80594
98.322 (f) revised.................................................73901
98.323 (a), (2), (b) introductory text and (1) amended; (c) 
        introductory text revised..................................73901
98.324 (b)(1), (2), (c), (d), (e) introductory text, (g) and (h) 
        revised....................................................73901
98.325 (b) amended.................................................73903
98.326 (f), (h), (j), (k) and (o) revised..........................73903
98.350 (b) introductory text amended...............................73903
98.352 (d) revised.................................................73903
98.353 (a)(2) introductory text, (c) introductory text, (1) 
        introductory text, (2), (d) introductory text and (2) 
        introductory text revised; (c)(1), (d)(1) and (2) amended 
                                                                   73903

[[Page 1123]]

98.354 (c) amended; (d) introductory text, (f), (g) introductory 
        text, (h) introductory text, (5) and (k) revised...........73904
98.355 (b) revised.................................................73905
98.356 (a) introductory text, (b)(3), (4), (d) introductory text, 
        (2), (4), (6) and (8) revised..............................73905
98.416 (a)(8) and (9) removed; (a)(10) revised.....................73905
98.417 (a)(3) and (4) added........................................73905
98.442 (e) and (f) revised.........................................73905
98.443 (d) introductory text and (3) introductory text revised; 
        (f)(1) and (2) amended.....................................73906
98.444 (d) heading revised.........................................73906
98.445 (e) revised.................................................73906
98.446 (a)(2) introductory text, (3) introductory text, (e), (f) 
        introductory text, (1)(vii) and (3) revised................73906
98.447 (a)(5) and (6) revised......................................73906
98.448 (a)(5) and (e) revised......................................73907
98.449 Amended.....................................................73907
98.460 (c)(1) and (2)(i) revised...................................73907
98.463 (a)(1), (2) introductory text and (ii)(C) revised...........73907
98.464 (b) introductory text, (1), (3) and (4) revised; (c) 
        through (f) redesignated as (d), (e), (f) and (h); new (c) 
        and (g) added..............................................73908
98.466 (b) introductory text, (2), (c)(3)(ii), (d), (f) and (g)(1) 
        revised; (b)(3) and (4) added..............................73909
98.467 Revised.....................................................73910
98.468 Amended.....................................................73910
98.460--98.468 (Subpart TT) Table TT-1 amended.....................73910

                                  2012

40 CFR
                                                                   77 FR
                                                                    Page
Chapter I
97 State implementation plan determinations.........................5710
97.406 (c)(3) redesignated as (c)(3)(i) in part; (c)(3)(ii) added; 
        new (c)(3)(ii) and (e)(2) amended..........................10334
97.410 Revised.....................................................10334
    (a)(2)(iv), (v), (6), (11), (14), (16), (20), (b)(2), (6), 
(11), (14), (16) and (20) revised..................................10347
    Regulation at 77 FR 10347 withdrawn............................28786
    (a)(2)(iv), (v), (6), (11), (14), (16), (20), (b)(2), (6), 
(11), (14), (16) and (20) revised; eff. 8-13-12....................34844
97.425 (b)(1) introductory text amended............................10336
97.506 (c)(3) redesignated as (c)(3)(i) in part and amended; 
        (c)(3)(ii) added...........................................10336
97.510 Revised.....................................................10336
    (a)(2), (4)(iv), (v), (9), (12), (13), (15), (17), (18), (22), 
(b)(2), (4), (9), (12), (13), (15), (17), (18) and (22) revised....10348
    Regulation at 77 FR 10348 withdrawn............................28786
    (a)(2), (4)(iv), (v), (9), (12), (13), (15), (17), (18), (22), 
(b)(2), (4), (9), (12), (13), (15), (17), (18) and (22) revised; 
eff. 8-13-12.......................................................34845
97.525 (b)(1) introductory text amended............................10338
97.606 (c)(3) redesignated as (c)(3)(i) in part and amended; 
        (c)(3)(ii) added; (e)(2) amended...........................10338
97.610 Revised.....................................................10339
    (a)(2), (7)(ii), (v), (9), (11), (b)(2), (9) and (11) revised 
                                                                   10348
    Regulation at 77 FR 10348 withdrawn............................28786
    (a)(2), (7)(ii), (v), (9), (11), (b)(2), (9) and (11) revised; 
eff. 8-13-12.......................................................34846
97.625 (b)(1) introductory text amended............................10340
97.706 (c)(3) redesignated as (c)(3)(i) in part and amended; 
        (c)(3)(ii) added; (e)(2) amended...........................10340
97.710 Revised.....................................................10340
    (a)(2)(iv), (v), (3), (5), (6), (b)(2), (3), (5) and (6) 
revised............................................................10349
    Regulation at 77 FR 10349 withdrawn............................28786
    (a)(2)(iv), (v), (3), (5), (6), (b)(2), (3), (5) and (6) 
revised; eff. 8-13-12..............................................34846
97.725 (b)(1) introductory text amended............................10340
98.3 (c)(4) introductory text, (i), (iii)(E) and (vi) revised; 
        (c)(4)(iii)(F) added.......................................51488
98.1--98.9 (Subpart A) Tables A-6 and A-7 amended..................48088

[[Page 1124]]

    Table A-7 amended..............................................51489
98.90 (a)(5) revised...............................................10380
98.91 (a)(4) amended...............................................10380
98.92 (a) introductory text and (5) revised........................10380
98.93 (h) introductory text revised; (h) amended; (h)(1) and (2) 
        added......................................................10380
98.94 (h) introductory text and (3) revised........................10380
    (a)(2)(iii), (3)(iii) and (4)(iii) revised.....................48089
98.95 (b) revised..................................................10381
98.96 (c)(4), (r) and (s) revised; (u) and (v) added...............10381
98.98 Amended......................................................10381
98.90--98.98 (Subpart I) Table I-2 revised.........................10381
98.126 (a) introductory text and (5) revised; (j) added............51489
98.127 Introductory text revised; (k) added........................51490
98.128 Amended.....................................................51490
98.233 (e)(5), (f)(1), (2), (3), (g), (1)(ii), (iii), (h), (i)(3), 
        (j), (l)(3) introductory text, (o)(5) introductory text, 
        (6), (7), (p)(7) introductory text, (i) introductory text, 
        (t)(1), (v), (z)(2)(iii) and (vi) amended; (f)(1) 
        introductory text, (1)(i) introductory text, (A), (3) 
        introductory text, (g)(1) introductory text, (3)(i), 
        (j)(5) introductory text, (r)(2) introductory text, 
        (6)(ii) introductory text and (t) introductory text, (1) 
        introductory text revised; (n)(7) removed..................51490
98.236 (c)(5)(ii)(D), (9) introductory text, (13)(i)(G), (ii)(C), 
        (iii)(C), (iv), (v)(B), (14)(i)(C), (ii)(C), (iii)(C), 
        (iv), (v)(B), (15)(i)(B), (i)(C), (ii)(A) and (17)(v) 
        revised....................................................51494
98.230--98.238 (Subpart W) Table A-1A revised......................51494
    Table W-5 amended..............................................51495
98.460 (c)(2)(xiii) added..........................................51495
98.464 (b) revised.................................................51495

                                  2013

40 CFR
                                                                   78 FR
                                                                    Page
Chapter I
98.3 (c)(1), (h)(4) and (j)(3)(ii) revised; (c)(11)(viii), (13), 
        (k) and (l) added..........................................71946
98.6 Amended.......................................................71948
98.7 (e)(30), (m)(3) and (n)(1) revised; (n)(2) removed............68202
    (n) removed....................................................71948
98.1--98.9 (Subpart A) amended.....................................68202
    Table A-1 revised..............................................71948
    Table A-6 amended..............................................71949
    Table A-7 amended..............................................71950
98.33 (b)(1)(viii) added; (b)(3)(ii)(A) and (e)(1)(ii) revised.....71950
98.36 (b)(3) revised; (c)(3) introductory text amended; (b)(11), 
        (c)(1)(xi), (2)(x), (xi), (3)(x), (d)(1)(x), (2)(ii)(J) 
        and (iii)(J) added.........................................71950
98.30--98.38 (Subpart C) Table C-1 revised.........................71950
    Table C-2 revised..............................................71952
98.53 (b)(3), (d) introductory text and (e) revised; (e), (g)(1), 
        (2) and (3) amended........................................71952
98.54 (e) and (f) revised..........................................71953
98.73 (b)(4) introductory text revised; (b)(4) and (5) amended.....71953
98.75 (b) revised..................................................71953
98.76 (a) introductory text, (b) introductory text and (13) 
        revised....................................................71953
98.86 (a)(2) revised...............................................71953
98.91 (a)(3) and (b) amended.......................................68202
98.92 (a) introductory text, (1) and (6) revised; (a)(2) and (3) 
        removed....................................................68202
98.93 (a), (b), (c) introductory text, (d) introductory text, (e) 
        introductory text, (g) and (h) introductory text revised; 
        (f) and (h)(2) removed; (c), (d), (e), (h) amended; (i) 
        added......................................................68202
98.94 (a), (d), (e), (g)(1) and (2) removed; (b), (c) introductory 
        text, (2), (f), (g)(3), (4), (h) introductory text, (3) 
        and (i) revised; (c)(3), (j) and (k) added.................68209

[[Page 1125]]

98.96 (m)(i) through (iv) redesignated as (m)(1) through (4); (a), 
        (b), (c) introductory text, (1), (2), (3), (m) 
        introductory text, new (m)(1), new (3), new (4), (p), (q), 
        (r) and (s) revised; (c)(5), (m)(5), (w), (x) and (y) 
        added; (f), (g), (h), (i), (j), (k), (l), (n), (o), (t), 
        (u) and (v) removed........................................68215
    (y)(3)(i) revised..............................................71954
98.97 (b) removed; (c), (d) introductory text, (1) and (4) 
        revised; (d)(5) through (9) and (i) through (s) added......68218
98.98 Amended......................................................68220
98.90--98.98 (Subpart I) Table I-1 amended.........................68221
    Table I-3 Revised..............................................68222
    Table I-4 Revised..............................................68223
    Table I-5 Heading revised; amended.............................68225
    Table I-6 Heading revised; amended.............................68225
    Table I-7 Heading revised; amended.............................68226
    Table I-9 Added................................................68227
    Table I-10 Added...............................................68228
    Table I-11 Added...............................................68229
    Table I-12 Added...............................................68230
    Table I-13 Added...............................................68231
    Table I-14 Added...............................................68232
    Table I-15 Added...............................................68233
    Table I-16 Added...............................................68234
    Table I-17 Added...............................................68234
    Appendix A Added...............................................68234
98.113 (d)(1) amended..............................................71954
98.116 (e)(2) added................................................71954
98.126 (j) introductory text, (1) and (3)(i) revised...............71954
98.143 Introductory text and (b) introductory text revised; 
        (b)(2)(iv) amended.........................................71954
98.144 (b) revised.................................................71954
98.146 (b)(4), (6) and (7) revised.................................71954
98.147 (b)(5) revised..............................................71954
98.153 (c) introductory text and (d) introductory text revised; 
        (d) amended................................................71955
98.154 (j) revised.................................................71955
98.156 (c) revised.................................................71955
98.163 (b) introductory text revised; (b)(1), (2) and (3) amended 
                                                                   71955
98.164 (b)(3), (4) and (5) introductory text revised; (c) and (d) 
        removed....................................................71955
98.166 (a)(2), (3), (b)(2) and (5) revised.........................71955
98.167 (c) and (d) added...........................................71956
98.170 Amended.....................................................71956
98.173 (b)(1)(i), (ii), (iii), (iv), (v), (vi) and (vii) amended; 
        (c) and (d) revised........................................71956
98.174 (b)(1) amended; (c)(2) revised..............................71957
98.175 (a) revised.................................................71958
98.176 (e) introductory text revised...............................71958
98.177 (b) revised.................................................71958
98.190 (a) revised.................................................71958
98.193 (a), (b)(1), (2) introductory text, (ii) introductory text, 
        (iii) introductory text and (iv) introductory text 
        revised; (b)(2)(ii), (iii) and (iv) amended................71958
98.194 (a), (b) and (c) introductory text revised..................71958
98.195 (a) revised.................................................71959
98.196 (a)(1), (2), (4), (5), (7), (b)(1) through (6), (9), (10), 
        (11) and (14) revised......................................71959
98.222 (a) revised.................................................71959
98.223 (b) introductory text, (1), (3), (d) introductory text, (e) 
        introductory text, (g)(2) introductory text, (3) 
        introductory text and (i) revised; (e), (g)(1), (2), (3) 
        and (4) amended............................................71959
98.224 (c) introductory text, (e) and (f) revised..................71960
98.226 (a) and (p) revised; (o) added..............................71960
    (n) introductory text corrected; CFR correction................23149
98.233 (a), (c) and (v) amended....................................71960
98.234 Regulation at 78 FR 11589 withdrawn.........................19605
    (f)(8)(i) revised..............................................25395
98.234 (f)(8)(i) revised...........................................11589
98.242 (b)(2) revised..............................................71960
98.243 (b), (c)(3), (4) and (d)(3)(i) revised; (c)(5)(i) amended 
                                                                   71961
98.244 (b)(4) introductory text, (xiii), (xiv) and (xv)(A) 
        revised; (c) added.........................................71961
98.245 Revised.....................................................71962
98.246 (a)(6), (8), (9), (11) introductory text, (iii), (b)(2) 
        through (5) and (c)(4) revised; (b)(6) removed.............71962

[[Page 1126]]

98.247 (b) introductory text, (2) and (3) revised..................71962
98.248 Amended.....................................................71963
98.252 (a) introductory text amended; (i) revised..................71963
98.253 (b)(2) and (3), (f)(4) amended; (f)(2), (3), (4) 
        introductory text, (j) introductory text, (k) introductory 
        text and (m) introductory text revised.....................71963
98.256 (f)(6), (h) introductory text, (2) through (6), (k)(4) and 
        (o)(4)(vi) revised; (j)(10) and (k)(6) added; (o)(5), (6) 
        and (7) removed............................................71963
98.263 (b)(1)(ii) introductory text revised; (b)(1)(ii) amended....71964
98.264 (a) and (b) revised.........................................71964
98.265 Revised.....................................................71964
98.266 (a), (b), (d), (f)(5), (6) and (8) revised..................71964
98.267 (a) and (c) revised.........................................71965
98.273 (a)(3) introductory text revised; (a)(3) amended............71965
98.276 (e) and (k) revised.........................................71965
98.270--98.278 (Subpart AA) Table AA-1 revised.....................71965
    Table AA-2 revised.............................................71965
98.282 (a) revised.................................................71966
98.283 Introductory text, (a), (b) introductory text and (2) 
        introductory text revised; (b)(2) amended; (d) removed.....71966
98.286 (b) introductory text revised...............................71966
98.304 (c)(1) and (2) revised......................................71966
98.320 (b)(1) and (2) revised......................................71966
98.322 (b) and (d) revised.........................................71966
98.323 (a)(2), (b)(1) and (c) introductory text revised; (a), (b), 
        (2) and (c)(1) amended.....................................71966
98.324 (b) introductory text and (c)(2) revised....................71967
98.326 (a), (f), (h), (i), (j), (o) and (r) revised; (t) added.....71967
98.340 (a) revised.................................................71968
98.343 (a)(1), (b)(1) and (c)(1) amended; (b)(2)(i), (ii), 
        (iii)(A), (B), (c)(3)(i) and (ii) revised..................71968
98.344 (e) revised; (f) added......................................71969
98.345 (c) revised.................................................71970
98.346 (d)(1), (e), (h), (i)(5) through (8), (10), (11) and (12) 
        revised....................................................71970
98.348 Amended.....................................................71970
98.340--98.348 (Subpart HH) Table HH-1 amended.....................71970
    Table HH-2 revised.............................................71971
    Table HH-4 added...............................................71971
98.353 (d)(2) amended..............................................71972
98.386 (a)(1), (5), (13), (b)(1) and (c)(1) removed; (a)(4), (8), 
        (9)(v), (11)(v), (12) introductory text, (14), (15), (18), 
        (b)(4), (5)(v), (6)(i), (c)(4), (5)(v), (d)(2) and (3) 
        revised....................................................71972
98.393 (a)(1) and (2) amended; (h)(1) introductory text and (2) 
        introductory text revised..................................71973
98.394 (a)(1) introductory text, (3), (c) introductory text 
        revised; (b)(3) added; (d) removed.........................71973
98.395 (a) introductory text and (b) revised; (c) removed..........71973
98.396 (a)(1), (4), (5), (8), (13), (15), (23), (b)(1), (4), 
        (c)(1) and (4) removed; (a)(9) introductory text, (iii), 
        (v), (10) introductory text, (11) introductory text, 
        (iii), (18), (20), (21), (22), (b)(2), (5) introductory 
        text, (6) introductory text, (c)(5) introductory text, (6) 
        introductory text, (d)(2) and (3) revised..................71973
98.397 (b) and (d) revised.........................................71974
98.398 Amended.....................................................71974
98.390--98.398 (Subpart MM) Table MM-1 amended.....................71974
98.400 (a) and (b) revised.........................................71975
98.403 (a)(2), (b)(2)(ii) and (c)(2) amended; (b)(1) introductory 
        text, (2)(i), (3), (4) and (c)(2) introductory text 
        revised....................................................71975
98.404 (a)(8)(iii) and (d)(3) added; (a)(5) introductory text, 
        (7), (8) introductory text, (ii), (9), (c)(2), (d)(1) and 
        (2) revised................................................71976
98.405 (c)(3) removed..............................................71977
98.406 (a)(4), (7), (b)(2), (3), (5), (7), (9) and (12) 
        introductory text revised; (b)(4) removed..................71977
98.407 Introductory text revised...................................71977
98.400--98.408 (Subpart NN) Table NN-1 revised.....................71977
    Table NN-2 revised.............................................71977
98.423 (a)(3)(i) introductory text revised.........................71977
98.426 (b)(4)(i), (ii), (f)(10) and (11) revised...................71977
98.433 (a) and (b) amended.........................................71978
98.434 (b) revised.................................................71978

[[Page 1127]]

98.436 (a)(3), (4), (6)(ii), (iii), (b)(3), (4), (6)(ii) and (iii) 
        revised; (a)(5), (6)(iv), (b)(5) and (6)(iv) removed.......71978
98.438 Amended.....................................................71978
98.443 (b)(2), (d)(3) introductory text and (f)(2) amended.........71978
98.446 (b)(5) revised..............................................71979
98.453 (d) and (h) revised; (i) amended............................71979
98.456 (m), (o) and (p) revised....................................71979
98.460 (c)(2)(xiii) revised........................................71979
98.463 (a)(1), (2)(ii)(C) and (b)(1) amended.......................71979
98.464 (b) introductory text and (c) revised; (b)(4)(i)(E) amended
                                                                   71979
98.466 (c)(1) removed; (b)(5) and (c)(5) added; (b)(1), (c) 
        introductory text, (2), (3) introductory text, (4) 
        introductory text, (d)(3) and (h) revised..................71980
98.467 Revised.....................................................71980
98.468 Amended.....................................................71980
98.460--98.468 (Subpart TT) Table TT-1 amended.....................71981
98.473 (a)(2) and (b)(2) amended...................................71981
98.476 (b)(5) revised; (e) added...................................71981

                                  2014

40 CFR
                                                                   79 FR
                                                                    Page
Chapter I
97 Policy statement................................................71674
97.406 Amended; interim............................................71672
97.410 Amended; interim............................................71672
97.411 Amended; interim............................................71672
97.412 Amended; interim............................................71672
97.421 Amended; interim............................................71672
97.425 Amended; interim............................................71672
97.430 Amended; interim............................................71672
97.434 Amended; interim............................................71672
97.506 Amended; interim............................................71672
97.510 Amended; interim............................................71672
97.511 Amended; interim............................................71672
97.512 Amended; interim............................................71672
97.521 Amended; interim............................................71672
97.525 Amended; interim............................................71672
97.530 Amended; interim............................................71672
97.534 Amended; interim............................................71672
97.606 Amended; interim............................................71672
97.610 Amended; interim............................................71672
97.611 Amended; interim............................................71672
97.612 Amended; interim............................................71672
97.621 Amended; interim............................................71672
97.625 Amended; interim............................................71672
97.630 Amended; interim............................................71672
97.634 Amended; interim............................................71672
97.706 Amended; interim............................................71672
97.710 Amended; interim............................................71672
97.711 Amended; interim............................................71672
97.712 Amended; interim............................................71672
97.721 Amended; interim............................................71672
97.725 Amended; interim............................................71672
97.730 Amended; interim............................................71672
97.734 Amended; interim............................................71672
98.2 (b)(1), (4) and (f)(1) revised................................73776
98.3 (c)(4)(vii), (d)(3)(v), (g) introductory text and (2)(i) 
        revised....................................................63779
    (c)(4)(iii)(E), (F), (5)(i), (ii), (k), (l) introductory text, 
(1), (2) introductory text, (i), (ii)(C), (D), (E) and (iii) 
revised; (c)(4)(vi) removed........................................73777
    (l) introductory text, (1) introductory text and (2) 
introductory text correctly revised................................77391
98.5 Revised.......................................................63780
    (b) revised....................................................73778
98.6 Amended................................................70385, 73778
98.1--98.9 (Subpart A) Table A-7 revised....................63780, 73783
    Table A-1 revised..............................................73779
98.36 (a), (b)(9)(iii), (c)(2)(ix), (x) and (e)(2)(ii)(C) revised; 
        (b)(9)(iv), (e)(2)(ii)(E) and (f) added....................63782
98.37 Revised......................................................63783
98.56 Introductory text revised; (b), (c), (j)(1) and (3) removed; 
        (m) and (n) added..........................................63784
98.57 Introductory text revised; (i) added.........................63784
98.66 (a), (c)(2) and (g) removed; (c)(3), (e)(1) and (f)(1) 
        revised....................................................63784
98.67 (i) added....................................................63784
98.76 (b)(2) and (7) through (11) removed; (b)(14) and (15) added 
                                                                   63785
98.77 Introductory text revised; (c) added.........................63785
98.86 (b)(2), (5), (6), (8), (10) and (12) removed; (b)(13) and 
        (15) revised; (b)(16), (17) and (18) added.................63785
98.87 (c) added....................................................63785
98.93 (a)(1)(i), (g) introductory text and (i)(2)(iii) correctly 
        amended....................................................25682
    (i)(2) revised.................................................73785

[[Page 1128]]

    (i)(2) introductory text correctly revised.....................77391
98.94 (j)(5)(ii)(C) removed; (j)(8)(i) revised.....................73785
98.96 (r) introductory text, (1) and (2) amended; (x) revised......73785
98.116 (b) and (e)(6) revised; (e)(4) and (5) removed..............63785
98.117 Introductory text revised; (e) added........................63785
98.122 (c) revised; (d), (e) and (f) added.........................73785
98.123 Introductory text, (b), (c)(1)(v), (g)(1), (2)(ii) and (iv) 
        revised; (a) and (c)(1)(vi) removed; (e)(i) and (ii) 
        redesignated as (e)(1) and (2); (h) added..................73785
98.124 (b), (c)(1), (2) and (5) revised; (c)(7), (8) and (9) 
        redesignated as (c)(6), (7) and (8)........................73787
98.126 (a) through (e), (g)(2) and (h)(1) revised; (f)(1), (5), 
        (g)(1) and (h)(2) removed; (k) added.......................73787
98.127 introductory text, (a)(1), (2), (b), (c) introductory text 
        and (3) revised; (a)(3), (4) and (l) added.................73788
98.128 Amended.....................................................73789
98.120--98.128 (Subpart L) Table L-1 and Appendix A added..........73789
98.146 (b)(2) revised; (b)(4) and (6) removed......................63786
98.147 Introductory text revised; (d) added........................63786
98.156 (a)(2), (7) through (10), (b)(1), (2), (d)(1), (5) and 
        (e)(1) removed; (d) introductory text revised..............63786
98.157 (c) added...................................................63786
98.166 Introductory text revised; (b)(2), (5) and (6) removed; 
        (b)(7) and (e) added.......................................63787
98.167 Introductory text revised; (e) added........................63787
98.176 (b) revised; (e)(1), (3), (4), (f)(2), (3), (4) and (g) 
        removed; (e)(6) added......................................63787
98.177 Introductory text revised; (f) added........................63788
98.186 (b)(6) and (7) removed; (b)(8) revised......................63792
98.187 Introductory text revised; (d) added........................63792
98.196 (b) introductory text revised; (b)(2), (3), (5), (6), (8), 
        (10), (11) and (12) removed; (b)(18) added.................63792
98.197 Introductory text revised; (c) added........................63792
98.216 (b), (e)(1), (2) and (f) removed............................63792
98.217 Introductory text revised; (e) added........................63793
98.226 (c) correctly reinstated; CFR correction....................63539
    Introductory text revised; (c), (d), (i), (j), (m)(1), (3) 
through (6) and (p) removed; (q) added.............................63793
98.227 Introductory text revised; (h) added........................63793
98.230 (a)(2) revised..............................................70385
98.232 (c)(11), (d)(1), (e)(1), (f)(1), (g)(1), (h)(1) and (i)(1) 
        through (7) revised; (e)(6), (f)(4), (g)(4) and (h)(5) 
        added......................................................70385
98.233 (j)(3) and (4) removed; (j)(5) through (9) redesignated as 
        new (j)(3) through (7); introductory text, (a) 
        introductory text, (1), (2), (c) through (i), (j) 
        introductory text, (1) introductory text, (vii) 
        introductory text, (2), new (3) through (7), (k) through 
        (r), (s)(2) introductory text, (i), (3), (4), (t) 
        introductory text, (1), (2), (u) introductory text, 
        (2)(iii) through (vii), (v), (w) introductory text, (1), 
        (3) introductory text, (x) introductory text, (1) and 
        (z)(1) revised; (a)(4) added; (w)(3), (x)(2), (z)(2)(iii) 
        and (vi) amended...........................................70386
98.234 (a) introductory text, (d)(1) and (f) revised; (g) removed; 
        (h) added..................................................70410
98.235 Revised.....................................................70410
98.236 (c)(6)(i)(B), (D), (E), (F), (8)(i)(F) and (ii)(A) revised; 
        (c)(20) added..............................................63793
    Revised........................................................70411
98.237 (f) added...................................................70424
98.238 Amended..............................................63794, 70424
98.246 (a) introductory text, (2), (4) and (b) introductory text 
        revised; (a)(12), (13), (b)(9) and (10) added..............63794

[[Page 1129]]

98.247 Introductory text revised; (d) added........................63794
98.256 (e)(6), (7) introductory text, (9), (10), (f)(7), (10) 
        through (13), (h)(5), (i)(5), (7), (8), (j)(5) through 
        (9), (k)(3), (4), (l)(5), (m)(3), (o)(4)(v) and (p)(2) 
        revised; (e)(7)(ii), (h)(4), (j)(2), (o)(2)(ii), (4)(ii), 
        (iii), (iv), (6) and (7) removed...........................63795
98.257 Revised.....................................................63796
98.266 (f)(5) and (6) removed......................................63797
98.267 Introductory text revised; (d) added........................63797
98.276 Introductory text and (c) revised; (b), (d) and (f) through 
        (i) removed; (l) added.....................................63797
98.277 Introductory text revised; (g) added........................63798
98.286 (b)(1), (4) and (6) removed.................................63798
98.287 Introductory text revised; (c) added........................63798
98.296 (b)(5), (6) and (7) removed; (b)(10)(v) and (vi) added......63798
98.297 Introductory text revised; (c) added........................63798
98.316 (b)(6) and (9) removed......................................63799
98.317 Introductory text revised; (c) added........................63799
98.336 (b)(6), (7) and (10) removed................................63799
98.337 Introductory text revised; (c) added........................63799
98.400--98.408 (Subpart NN) Table NN-2 correctly amended............3508
98.466 (c)(3)(i) and (iii) removed; (c)(3)(ii) revised.............63799
98.467 Revised.....................................................63799

                                  2015

40 CFR
                                                                   80 FR
                                                                    Page
Chapter I
97 Policy statement...................................44882, 69883, 7466
98 Authority citation revised......................................64660
98.90--98.98 (Subpart I) Tables I-5, I-6 and I-7 corrected; CFR 
        correction.................................................12934
98.153 (d) introductory text amended; CFR correction...............33425
98.230 (a)(9) and (10) added.......................................64283
98.231 (a) revised.................................................64284
98.232 (a), (c)(6), (8) and (k) revised; (j) and (m) added.........64284
98.233 (a), (c), (g)(1)(iii), (iv) and (1)(2)(i) amended; (a)(2), 
        (d)(8)(iii), (g) introductory text, (1) introductory text, 
        (i), (ii) heading, (v), (vi), (2) introductory text, (4) 
        introductory text, (i)(2) introductory text, (j) 
        introductory text, (1), (2), (3), (6), (n)(2)(i), (o) 
        introductory text, (10), (p) introductory text, (10), (r) 
        introductory text, (2) introductory text, (i), (u)(2)(i), 
        (iii), (z) introductory text and (1)(ii) revised; 
        (g)(1)(vii) and (2)(iv) added..............................64284
98.234 (g) added...................................................64291
98.236 (l)(1)(ii) through (vi), (2)(ii) through (vii), (3)(ii) 
        through (v) and (4)(ii) through (vi) redesignated as 
        (l)(1)(iii) through (vii), (2)(iii) through (viii), 
        (3)(iii) through (vi) and (4)(iii) through (vii); (a) 
        introductory text, (d)(1)(i), (vi), (e)(1)(i), (xviii), 
        (f)(1)(ii), (xi)(A), (xii)(A), (2)(i), (g) introductory 
        text, (1), (2), (5), (6), (h)(1)(i), (iv), (2)(i), (iv), 
        (3)(i), (4)(i), (i) introductory text, (1) introductory 
        text, (j) introductory text, (1) introductory text, (i), 
        (iii), (iv), (v), (vii), (viii), (2)(i) introductory text, 
        (A), (B), (C), (ii), (iii) introductory text, (A), (B), 
        (3) introductory text, (l)(1) introductory text, new (v), 
        (2) introductory text, new (v), (3) introductory text, new 
        (iv), (4) introductory text, new (iv), (m)(1), (5), (6), 
        (7)(i), (8)(i), (n)(1), (o) introductory text, (5) 
        introductory text, (p), (r)(1) introductory text, (i), (3) 
        introductory text, (ii) introductory text, (z) 
        introductory text, (aa) introductory text, (1)(ii)(D) 
        through (H) and (cc) revised; (a)(9), (10), (i)(3), new 
        (l)(1)(ii), new (2)(ii), new (3)(ii). new (4)(ii), 
        (aa)(10) and (11) added....................................64291
98.238 Amended.....................................................64296
98.230--98.238 (Subpart W) Table W-1A revised......................64297
    Table W-1B heading revised.....................................64298

[[Page 1130]]

98.244 (b)(4)(ix) correctly reinstated; CFR correction.............21650
98.426 (h) added...................................................64660
98.427 (d) added...................................................64660

                                  2016

   (Regulations published from January 1, 2016, through July 1, 2016)

40 CFR
                                                                   81 FR
                                                                    Page
Chapter I
97.406 Regulation at 79 FR 71672 confirmed.........................13279
97.410 Regulation at 79 FR 71672 confirmed.........................13279
97.411 Regulation at 79 FR 71672 confirmed.........................13279
97.412 Regulation at 79 FR 71672 confirmed.........................13279
97.421 Regulation at 79 FR 71672 confirmed.........................13279
97.425 Regulation at 79 FR 71672 confirmed.........................13279
97.430 Regulation at 79 FR 71672 confirmed.........................13279
97.434 Regulation at 79 FR 71672 confirmed.........................13279
97.506 Regulation at 79 FR 71672 confirmed.........................13279
97.510 Regulation at 79 FR 71672 confirmed.........................13279
97.511 Regulation at 79 FR 71672 confirmed.........................13279
97.512 Regulation at 79 FR 71672 confirmed.........................13279
97.521 Regulation at 79 FR 71672 confirmed.........................13279
97.525 Regulation at 79 FR 71672 confirmed.........................13279
97.530 Regulation at 79 FR 71672 confirmed.........................13279
97.534 Regulation at 79 FR 71672 confirmed.........................13279
97.606 Regulation at 79 FR 71672 confirmed.........................13279
97.610 Regulation at 79 FR 71672 confirmed.........................13279
97.611 Regulation at 79 FR 71672 confirmed.........................13279
97.612 Regulation at 79 FR 71672 confirmed.........................13279
97.621 Regulation at 79 FR 71672 confirmed.........................13279
97.625 Regulation at 79 FR 71672 confirmed.........................13279
97.630 Regulation at 79 FR 71672 confirmed.........................13279
97.634 Regulation at 79 FR 71672 confirmed.........................13279
97.706 Regulation at 79 FR 71672 confirmed.........................13279
97.710 Regulation at 79 FR 71672 confirmed.........................13279
97.711 Regulation at 79 FR 71672 confirmed.........................13279
97.712 Regulation at 79 FR 71672 confirmed.........................13279
97.721 Regulation at 79 FR 71672 confirmed.........................13279
97.725 Regulation at 79 FR 71672 confirmed.........................13279
97.730 Regulation at 79 FR 71672 confirmed.........................13279
97.734 Regulation at 79 FR 71672 confirmed.........................13279


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