[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 72 to 79

                         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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                            Table of Contents



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

  Title 40:
          Chapter I--Environmental Protection Agency 
          (Continued)                                                3
  Finding Aids:
      Table of CFR Titles and Chapters........................     605
      Alphabetical List of Agencies Appearing in the CFR......     625
      List of CFR Sections Affected...........................     635

[[Page iv]]





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

                     Cite this Code: CFR
                     To cite the regulations in 
                       this volume use title, 
                       part and section number. 
                       Thus, 40 CFR 72.1 refers 
                       to title 40, part 72, 
                       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 
issues of the Federal Register. These two publications must be used 
together to determine the latest version of any given rule.
    To determine whether a Code volume has been amended since its 
revision date (in this case, July 1, 2016), consult the ``List of CFR 
Sections Affected (LSA),'' which is issued monthly, and the ``Cumulative 
List of Parts Affected,'' which appears in the Reader Aids section of 
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Register page number of the latest amendment of any given rule.

EFFECTIVE AND EXPIRATION DATES

    Each volume of the Code contains amendments published in the Federal 
Register since the last revision of that volume of the Code. Source 
citations for the regulations are referred to by volume number and page 
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Code a note has been inserted to reflect the future effective date. In 
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inserted following the text.

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 
amendments to existing regulations in the CFR. These OMB numbers are 
placed as close as possible to the applicable recordkeeping or reporting 
requirements.

PAST PROVISIONS OF THE CODE

    Provisions of the Code that are no longer in force and effect as of 
the revision date stated on the cover of each volume are not carried. 
Code users may find the text of provisions in effect on any given date 
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the Code prior to the LSA listings at the end of the volume, consult 
previous annual editions of the LSA. For changes to the Code prior to 
2001, consult the List of CFR Sections Affected compilations, published 
for 1949-1963, 1964-1972, 1973-1985, and 1986-2000.

``[RESERVED]'' TERMINOLOGY

    The term ``[Reserved]'' is used as a place holder within the Code of 
Federal Regulations. An agency may add regulatory information at a 
``[Reserved]'' location at any time. Occasionally ``[Reserved]'' is used 
editorially to indicate that a portion of the CFR was left vacant and 
not accidentally dropped due to a printing or computer error.

INCORPORATION BY REFERENCE

    What is incorporation by reference? Incorporation by reference was 
established by statute and allows Federal agencies to meet the 
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This material, like any other properly issued regulation, has the force 
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    What is a proper incorporation by reference? The Director of the 
Federal Register will approve an incorporation by reference only when 
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    (a) The incorporation will substantially reduce the volume of 
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    (b) The matter incorporated is in fact available to the extent 
necessary to afford fairness and uniformity in the administrative 
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    (c) The incorporating document is drafted and submitted for 
publication in accordance with 1 CFR part 51.
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alphabetical list of agencies publishing in the CFR are also included in 
this volume.

[[Page vii]]

    An index to the text of ``Title 3--The President'' is carried within 
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the revision dates of the 50 CFR titles.

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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 72 to 79)

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

chapter i--Environmental Protection Agency (Continued)......          72

[[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
72              Permits regulation..........................           5
73              Sulfur dioxide allowance system.............          91
74              Sulfur dioxide opt-ins......................         177
75              Continuous emission monitoring..............         204
76              Acid rain nitrogen oxides emission reduction 
                    program.................................         460
77              Excess emissions............................         485
78              Appeal procedures...........................         491
79              Registration of fuels and fuel additives....         506

[[Page 5]]



                  SUBCHAPTER C_AIR PROGRAMS (CONTINUED)





PART 72_PERMITS REGULATION--Table of Contents



             Subpart A_Acid Rain Program General Provisions

Sec.
72.1 Purpose and scope.
72.2 Definitions.
72.3 Measurements, abbreviations, and acronyms.
72.4 Federal authority.
72.5 State authority.
72.6 Applicability.
72.7 New units exemption.
72.8 Retired units exemption.
72.9 Standard requirements.
72.10 Availability of information.
72.11 Computation of time.
72.12 Administrative appeals.
72.13 Incorporation by reference.

                   Subpart B_Designated Representative

72.20 Authorization and responsibilities of the designated 
          representative.
72.21 Submissions.
72.22 Alternate designated representative.
72.23 Changing the designated representative, alternate designated 
          representative; changes in the owners and operators.
72.24 Certificate of representation.
72.25 Objections.
72.26 Delegation by designated representative and alternate designated 
          representative.

                 Subpart C_Acid Rain Permit Applications

72.30 Requirement to apply.
72.31 Information requirements for Acid Rain permit applications.
72.32 Permit application shield and binding effect of permit 
          application.
72.33 Identification of dispatch system.

       Subpart D_Acid Rain Compliance Plan and Compliance Options

72.40 General.
72.41 Phase I substitution plans.
72.42 Phase I extension plans.
72.43 Phase I reduced utilization plans.
72.44 Phase II repowering extensions.

                   Subpart E_Acid Rain Permit Contents

72.50 General.
72.51 Permit shield.

         Subpart F_Federal Acid Rain Permit Issuance Procedures

72.60 General.
72.61 Completeness.
72.62 Draft permit.
72.63 Administrative record.
72.64 Statement of basis.
72.65 Public notice of opportunities for public comment.
72.66 Public comments.
72.67 Opportunity for public hearing.
72.68 Response to comments.
72.69 Issuance and effective date of acid rain permits.

               Subpart G_Acid Rain Phase II Implementation

72.70 Relationship to title V operating permit program.
72.71 Acceptance of State Acid Rain programs--general.
72.72 Criteria for State operating permit program.
72.73 State issuance of Phase II permits.
72.74 Federal issuance of Phase II permits.

                       Subpart H_Permit Revisions

72.80 General.
72.81 Permit modifications.
72.82 Fast-track modifications.
72.83 Administrative permit amendment.
72.84 Automatic permit amendment.
72.85 Permit reopenings.

                   Subpart I_Compliance Certification

72.90 Annual compliance certification report.
72.91 Phase I unit adjusted utilization.
72.92 Phase I unit allowance surrender.
72.93 Units with Phase I extension plans.
72.94 Units with repowering extension plans.
72.95 Allowance deduction formula.
72.96 Administrator's action on compliance certifications.

Appendix A to Part 72--Methodology for Annualization of Emissions Limits
Appendix B to Part 72--Methodology for Conversion of Emissions Limits
Appendix C to Part 72--Actual 1985 Yearly SO2 Emissions 
          Calculation
Appendix D to Part 72--Calculation of Potential Electric Output Capacity

    Authority: 42 U.S.C. 7401, 7403, 7410, 7411, 7426, 7601, et seq.

    Source: 58 FR 3650, Jan. 11, 1993, unless otherwise noted.

[[Page 6]]



             Subpart A_Acid Rain Program General Provisions



Sec. 72.1  Purpose and scope.

    (a) Purpose. The purpose of this part is to establish certain 
general provisions and the operating permit program requirements for 
affected sources and affected units under the Acid Rain Program, 
pursuant to title IV of the Clean Air Act, 42 U.S.C. 7401, et seq., as 
amended by Public Law 101-549 (November 15, 1990).
    (b) Scope. The regulations under this part set forth certain 
generally applicable provisions under the Acid Rain Program. The 
regulations also set forth requirements for obtaining three types of 
Acid Rain permits, during Phases I and II, for which an affected source 
may apply: Acid Rain permits issued by the United States Environmental 
Protection Agency during Phase I; the Acid Rain portion of an operating 
permit issued by a State permitting authority during Phase II; and the 
Acid Rain portion of an operating permit issued by EPA when it is the 
permitting authority during Phase II. The requirements under this part 
supplement, and in some cases modify, the requirements under parts 70 
and 71 of this chapter and other regulations implementing title V for 
approving and implementing State operating permit programs and for 
Federal issuance of operating permits under title V, as such 
requirements apply to affected sources under the Acid Rain Program.

[58 FR 3650, Jan. 11, 1993, as amended at 62 FR 55475, Oct. 24, 1997]



Sec. 72.2  Definitions.

    The terms used in this part, in parts 73, 74, 75, 76, 77 and 78 of 
this chapter shall have the meanings set forth in the Act, including 
sections 302 and 402 of the Act, and in this section as follows:
    Account number means the identification number given by the 
Administrator to each Allowance Tracking System account pursuant to 
Sec. 73.31(d) of this chapter.
    Acid Rain compliance option means one of the methods of compliance 
used by an affected unit under the Acid Rain Program as described in a 
compliance plan submitted and approved in accordance with subpart D of 
this part, part 74 of this chapter or part 76 of this chapter.
    Acid Rain emissions limitation means:
    (1) For purposes of sulfur dioxide emissions:
    (i) The tonnage equivalent of the allowances authorized to be 
allocated to the affected units at a source for use in a calendar year 
under section 404(a)(1), (a)(3), and (h) of the Act, or the basic Phase 
II allowance allocations authorized to be allocated to an affected unit 
for use in a calendar year, or the allowances authorized to be allocated 
to an opt-in source under section 410 of the Act for use in a calendar 
year;
    (ii) As adjusted:
    (A) By allowances allocated by the Administrator pursuant to section 
403, section 405 (a)(2), (a)(3), (b)(2), (c)(4), (d)(3), and (h)(2), and 
section 406 of the Act;
    (B) By allowances allocated by the Administrator pursuant to subpart 
D of this part; and thereafter
    (C) By allowance transfers to or from the compliance account for 
that source that were recorded or properly submitted for recordation by 
the allowance transfer deadline as provided in Sec. 73.35 of this 
chapter, after deductions and other adjustments are made pursuant to 
Sec. 73.34(c) of this chapter; and
    (2) For purposes of nitrogen oxides emissions, the applicable 
limitation under part 76 of this chapter.
    Acid Rain emissions reduction requirement means a requirement under 
the Acid Rain Program to reduce the emissions of sulfur dioxide or 
nitrogen oxides from a unit to a specified level or by a specified 
percentage.
    Acid Rain permit or permit means the legally binding written 
document or portion of such document, including any permit revisions, 
that is issued by a permitting authority under this part and specifies 
the Acid Rain Program requirements applicable to an affected source and 
to the owners and operators and the designated representative of the 
affected source or the affected unit.
    Acid Rain Program means the national sulfur dioxide and nitrogen 
oxides air pollution control and emissions reduction program established 
in accordance with title IV of the Act, this

[[Page 7]]

part, and parts 73, 74, 75, 76, 77, and 78 of this chapter.
    Act means the Clean Air Act, 42 U.S.C. 7401, et seq. as amended by 
Public Law No. 101-549 (November 15, 1990).
    Actual SO2 emissions rate means the annual average sulfur dioxide 
emissions rate for the unit (expressed in lb/mmBtu), for the specified 
calendar year; provided that, if the unit is listed in the NADB, the 
``1985 actual SO2 emissions rate'' for the unit shall be the 
rate specified by the Administrator in the NADB under the data field 
``SO2RTE.''
    Add-on control means a pollution reduction control technology that 
operates independent of the combustion process.
    Additional advance auction means the auction of advance allowances 
that were offered the previous year for sale in an advance sale.
    Administrator means the Administrator of the United States 
Environmental Protection Agency or the Administrator's duly authorized 
representative.
    Advance allowance means an allowance that may be used for purposes 
of compliance with a source Acid Rain sulfur dioxide emissions 
limitation requirements beginning no earlier than seven years following 
the year in which the allowance is first offered for sale.
    Advance auction means an auction of advance allowances.
    Advance sale means a sale of advance allowances.
    Affected source means a source that includes one or more affected 
units.
    Affected States means any affected States as defined in part 71 of 
this chapter.
    Affected unit means a unit that is subject to any Acid Rain 
emissions reduction requirement or Acid Rain emissions limitation under 
Sec. 72.6 or part 74 of this chapter.
    Affiliate shall have the meaning set forth in section 2(a)(11) of 
the Public Utility Holding Company Act of 1935, 15 U.S.C. 79b(a)(11), as 
of November 15, 1990.
    Air Emission Testing Body (AETB) means a company or other entity 
that provides to the owner or operator the certification required by 
section 6.1.2(b) of appendix A to part 75 of this chapter.
    Allocate or allocation means the initial crediting of an allowance 
by the Administrator to an Allowance Tracking System compliance account 
or general account.
    Allowable SO2 emissions rate means the most stringent federally 
enforceable emissions limitation for sulfur dioxide (in lb/mmBtu) 
applicable to the unit or combustion source for the specified calendar 
year, or for such subsequent year as determined by the Administrator 
where such a limitation does not exist for the specified year; provided 
that, if a Phase I or Phase II unit is listed in the NADB, the ``1985 
allowable SO2 emissions rate'' for the Phase I or Phase II 
unit shall be the rate specified by the Administrator in the NADB under 
the data field ``1985 annualized boiler SO2 emission limit.''
    Allowance means an authorization by the Administrator under the Acid 
Rain Program to emit up to one ton of sulfur dioxide during or after a 
specified calendar year.
    Allowance deduction, or deduct when referring to allowances, means 
the permanent withdrawal of allowances by the Administrator from an 
Allowance Tracking System compliance account to account for the number 
of tons of SO2 emissions from the affected units at an 
affected source for the calendar year, for tonnage emissions estimates 
calculated for periods of missing data as provided in part 75 of this 
chapter, or for any other allowance surrender obligations of the Acid 
Rain Program.
    Allowances held or hold allowances means the allowances recorded by 
the Administrator, or submitted to the Administrator for recordation in 
accordance with Sec. 73.50 of this chapter, in an Allowance Tracking 
System account.
    Allowance reserve means any bank of allowances established by the 
Administrator in the Allowance Tracking System pursuant to sections 
404(a)(2) (Phase I extension reserve), 404(g) (energy conservation and 
renewable energy reserve), or 416(b) (special allowance reserve) of the 
Act, and implemented in accordance with part 73, subpart B of this 
chapter.
    Allowance Tracking System or ATS means the Acid Rain Program system

[[Page 8]]

by which the Administrator allocates, records, deducts, and tracks 
allowances.
    Allowance Tracking System account means an account in the Allowance 
Tracking System established by the Administrator for purposes of 
allocating, holding, transferring, and using allowances.
    Allowance transfer deadline means midnight of March 1 (or February 
29 in any leap year) or, if such day is not a business day, midnight of 
the first business day thereafter and is the deadline by which 
allowances may be submitted for recordation in an affected source's 
compliance account for the purposes of meeting the source's Acid Rain 
emissions limitation requirements for sulfur dioxide for the previous 
calendar year.
    Alternative monitoring system means a system or a component of a 
system designed to provide direct or indirect data of mass emissions per 
time period, pollutant concentrations, or volumetric flow, that is 
demonstrated to the Administrator as having the same precision, 
reliability, accessibility, and timeliness as the data provided by a 
certified CEMS or certified CEMS component in accordance with part 75 of 
this chapter.
    As-fired means the taking of a fuel sample just prior to its 
introduction into the unit for combustion.
    Auction subaccount means a subaccount in the Special Allowance 
Reserve, as specified in section 416(b) of the Act, which contains 
allowances to be sold at auction in the amount of 150,000 per year from 
calendar year 1995 through 1999, inclusive, and 200,000 per year for 
each year begnning in calendar year 2000, subject to the adjustments 
noted in the regulations in part 73, subpart E of this chapter.
    Authorized account representative means a responsible natural person 
who is authorized, in accordance with part 73 of this chapter, to 
transfer and otherwise dispose of allowances held in an Allowance 
Tracking System general account; or, in the case of a compliance 
account, the designated representative of the owners and operators of 
the affected source and the affected units at the source.
    Automated data acquisition and handling system means that component 
of the CEMS, COMS, or other emissions monitoring system approved by the 
Administrator for use in the Acid Rain Program, designed to interpret 
and convert individual output signals from pollutant concentration 
monitors, flow monitors, diluent gas monitors, moisture monitors, 
opacity monitors, and other component parts of the monitoring system to 
produce a continuous record of the measured parameters in the 
measurement units required by part 75 of this chapter.
    Award means the conditional set-aside by the Administrator, based on 
the submission of an early ranking application pursuant to subpart D of 
this part, of an allowance from the Phase I extension reserve, for 
possible future allocation to a Phase I extension applicant's Allowance 
Tracking System unit account.
    Backup fuel means a fuel for a unit where: (1) For purposes of the 
requirements of the monitoring exception of appendix E of part 75 of 
this chapter, the fuel provides less than 10.0 percent of the heat input 
to a unit during the three calendar years prior to certification testing 
for the primary fuel and the fuel provides less than 15.0 percent of the 
heat input to a unit in each of those three calendar years; or the 
Administrator approves the fuel as a backup fuel; and (2) For all other 
purposes under the Acid Rain Program, a fuel that is not the primary 
fuel (expressed in mmBtu) consumed by an affected unit for the 
applicable calendar year.
    Baseline means the annual average quantity of fossil fuel consumed 
by a unit, measured in millions of British Thermal Units (expressed in 
mmBtu) for calendar years 1985 through 1987; provided that in the event 
that a unit is listed in the NADB, the baseline will be calculated for 
each unit-generator pair that includes the unit, and the unit's baseline 
will be the sum of such unit-generator baselines. The unit-generator 
baseline will be as provided in the NADB under the data field 
``BASE8587'', as adjusted by the outage hours listed in the NADB under 
the data field ``OUTAGEHR'' in accordance with the following equation:


[[Page 9]]



Baseline = BASE8587 x {26280 / (26280 - OUTAGEHR){time}  x {36 / (36 - 
months not on line){time}  x 10\6\

    ``Months not on line'' is the number of months during January 1985 
through December 1987 prior to the commencement of firing for units that 
commenced firing in that period, i.e., the number of months, in that 
period, prior to the on-line month listed under the data field 
``BLRMNONL'' and the on-line year listed in the data field ``BLRYRONL'' 
in the NADB.
    Basic Phase II allowance allocations means:
    (1) For calendar years 2000 through 2009 inclusive, allocations of 
allowances made by the Administrator pursuant to section 403 and section 
405 (b)(1), (3), and (4); (c)(1), (2), (3), and (5); (d)(1), (2), (4), 
and (5); (e); (f); (g)(1), (2), (3), (4), and (5); (h)(1); (i); and (j).
    (2) For each calendar year beginning in 2010, allocations of 
allowances made by the Administrator pursuant to section 403 and section 
405 (b)(1), (3), and (4); (c)(1), (2), (3), and (5); (d)(1), (2), (4), 
and (5); (e); (f); (g)(1), (2), (3), (4), and (5); (h)(1) and (3); (i); 
and (j).
    Bias means systematic error, resulting in measurements that will be 
either consistently low or high relative to the reference value.
    Boiler means an enclosed fossil or other fuel-fired combustion 
device used to produce heat and to transfer heat to recirculating water, 
steam, or any other medium.
    Bypass operating quarter means a calendar quarter during which 
emissions pass through a stack, duct or flue that bypasses add-on 
emission controls.
    Bypass stack means any duct, stack, or conduit through which 
emissions from an affected unit may or do pass to the atmosphere, which 
either augments or substitutes for the principal stack exhaust system or 
ductwork during any portion of the unit's operation.
    Calibration error means the difference between:
    (1) The response of a gaseous monitor to a calibration gas and the 
known concentration of the calibration gas;
    (2) The response of a flow monitor to a reference signal and the 
known value of the reference signal; or
    (3) The response of a continuous opacity monitoring system to an 
attenuation filter and the known value of the filter after a stated 
period of operation during which no unscheduled maintenance, repair, or 
adjustment took place.
    Calibration gas means:
    (1) A standard reference material;
    (2) A standard reference material-equivalent compressed gas primary 
reference material;
    (3) A NIST traceable reference material;
    (4) NIST/EPA-approved certified reference materials;
    (5) A gas manufacturer's intermediate standard;
    (6) An EPA protocol gas;
    (7) Zero air material; or
    (8) A research gas mixture.
    Capacity factor means either:
    (1) The ratio of a unit's actual annual electric output (expressed 
in MWe/hr) to the unit's nameplate capacity (or maximum observed hourly 
gross load (in MWe/hr) if greater than the nameplate capacity) times 
8760 hours; or
    (2) The ratio of a unit's annual heat input (in million British 
thermal units or equivalent units of measure) to the unit's maximum 
rated hourly heat input rate (in million British thermal units per hour 
or equivalent units of measure) times 8,760 hours.
    CEMS precision or precision as applied to the monitoring 
requirements of part 75 of this chapter, means the closeness of a 
measurement to the actual measured value expressed as the uncertainty 
associated with repeated measurements of the same sample or of different 
samples from the same process (e.g., the random error associated with 
simultaneous measurements of a process made by more than one 
instrument). A measurement technique is determined to have increasing 
``precision'' as the variation among the repeated measurements 
decreases.
    Centroidal area means a representational concentric area that is 
geometrically similar to the stack or duct cross section, and is not 
greater than 1 percent of the stack or duct cross-sectional area.
    Certificate of representation means the completed and signed 
submission required by Sec. 72.20, for certifying the appointment of a 
designated representative for an affected source or a group of

[[Page 10]]

identified affected sources authorized to represent the owners and 
operators of such source(s) and of the affected units at such source(s) 
with regard to matters under the Acid Rain Program.
    Certifying official, for purposes of part 73 of this chapter, means:
    (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 partnership or sole proprietorship, a general partner or the 
proprietor, respectively; and
    (3) For a local government entity or State, Federal, or other public 
agency, either a principal executive officer or ranking elected 
official.
    Coal means all solid fuels classified as anthracite, bituminous, 
subbituminous, or lignite by the American Society for Testing and 
Materials Designation ASTM D388-92 ``Standard Classification of Coals by 
Rank'' (as incorporated by reference in Sec. 72.13).
    Coal-derived fuel means any fuel, whether in a solid, liquid, or 
gaseous state, produced by the mechanical, thermal, or chemical 
processing of coal (e.g., pulverized coal, coal refuse, liquified or 
gasified coal, washed coal, chemically cleaned coal, coal-oil mixtures, 
and coke).
    Coal-fired means the combustion of fuel consisting of coal or any 
coal-derived fuel (except a coal-derived gaseous fuel that meets the 
definition of ``very low sulfur fuel'' in this section), alone or in 
combination with any other fuel, where:
    (1) For purposes of the requirements of part 75 of this chapter, a 
unit is ``coal-fired'' independent of the percentage of coal or coal-
derived fuel consumed in any calendar year (expressed in mmBtu); and
    (2) For all other purposes under the Acid Rain Program, except for 
purposes of applying part 76 of this chapter, a unit is ``coal-fired'' 
if it uses coal or coal-derived fuel as its primary fuel (expressed in 
mmBtu); provided that, if the unit is listed in the NADB, the primary 
fuel is the fuel listed in the NADB under the data field ``PRIMEFUEL''.
    Cogeneration unit means a unit that has equipment used to produce 
electric energy and forms of useful thermal energy (such as heat or 
steam) for industrial, commercial, heating, or cooling purposes, through 
sequential use of energy.
    Combustion source means a stationary fossil fuel fired boiler, 
turbine, or internal combustion engine that has submitted or intends to 
submit an opt-in permit application under Sec. 74.14 of this chapter to 
enter the Opt-in Program.
    Commence commercial operation means to have begun to generate 
electricity for sale, including the sale of test generation.
    Commence construction means that an owner or operator has either 
undertaken a continuous program of construction or has entered into a 
contractual obligation to undertake and complete, within a reasonable 
time, a continuous program of construction.
    Commence operation means to have begun any mechanical, chemical, or 
electronic process, including start-up of an emissions control 
technology or emissions monitor or of a unit's combustion chamber.
    Common pipe means an oil or gas supply line through which the same 
type of fuel is distributed to two or more affected units.
    Common pipe operating time means the portion of a clock hour during 
which fuel flows through a common pipe. The common pipe operating time, 
in hours, is expressed as a decimal fraction, with valid values ranging 
from 0.00 to 1.00.
    Common stack means the exhaust of emissions from two or more units 
through a single flue.
    Compensating unit means an affected unit that is not otherwise 
subject to Acid Rain emissions limitation or Acid Rain emissions 
reduction requirements during Phase I and that is designated as a Phase 
I unit in a reduced utilization plan under Sec. 72.43; provided that an 
opt-in source shall not be a compensating unit.
    Compliance account means an Allowance Tracking System account, 
established by the Administrator under Sec. 73.31(a) or (b) of this 
chapter or Sec. 74.40(a) of this chapter for an affected source and for 
each affected unit at the source.

[[Page 11]]

    Compliance certification means a submission to the Administrator or 
permitting authority, as appropriate, that is required by this part, by 
part 73, 74, 75, 76, 77, or 78 of this chapter, to report an affected 
source or an affected unit's compliance or non-compliance with a 
provision of the Acid Rain Program and that is signed and verified by 
the designated representative in accordance with subparts B and I of 
this part and the Acid Rain Program regulations generally.
    Compliance plan, for the purposes of the Acid Rain Program, means 
the document submitted for an affected source in accordance with subpart 
C of this part or subpart E of part 74 of this chapter, or part 76 of 
this chapter, specifying the method(s) (including one or more Acid Rain 
compliance options as provided under subpart D of this part or subpart E 
of part 74 of this chapter, or part 76 of this chapter) by which each 
affected unit at the source will meet the applicable Acid Rain emissions 
limitation and Acid Rain emissions reduction requirements.
    Compliance use date means the first calendar year for which an 
allowance may be used for purposes of meeting a source's Acid Rain 
emissions limitation for sulfur dioxide.
    Conditionally valid data means data from a continuous monitoring 
system that are not quality-assured, but which may become quality-
assured if certain conditions are met. Examples of data that may qualify 
as conditionally valid are: data recorded by an uncertified monitoring 
system prior to its initial certification; or data recorded by a 
certified monitoring system following a significant change to the system 
that may affect its ability to accurately measure and record emissions. 
A monitoring system must pass a probationary calibration error test, in 
accordance with section 2.1.1 of appendix B to part 75 of this chapter, 
to initiate the conditionally valid data status. In order for 
conditionally valid emission data to become quality-assured, one or more 
quality assurance tests or diagnostic tests must be passed within a 
specified time period in accordance with Sec. 75.20(b)(3).
    Conservation Verification Protocol means a methodology developed by 
the Administrator for calculating the kilowatt hour savings from energy 
conservation measures and improved unit efficiency measures for the 
purposes of title IV of the Act.
    Construction means fabrication, erection, or installation of a unit 
or any portion of a unit.
    Consumer Price Index or CPI means, for purposes of the Acid Rain 
Program, the U.S. Department of Labor, Bureau of Labor Statistics 
unadjusted Consumer Price Index for All Urban Consumers for the U.S. 
city average, for All Items on the latest reference base, or if such 
index is no longer published, such other index as the Administrator in 
his or her discretion determines meets the requirements of the Clean Air 
Act Amendments of 1990.
    (1) CPI (1990) means the CPI for all urban consumers for the month 
of August 1989. The ``CPI (1990)'' is 124.6 (with 1982-1984 = 100). 
Beginning in the month for which a new reference base is established, 
``CPI (1990)'' will be the CPI value for August 1989 on the new 
reference base.
    (2) CPI (year) means the CPI for all urban consumers for the month 
of August of the previous year.
    Continuous emission monitoring system or CEMS means the equipment 
required by part 75 of this chapter used 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 SO2, NOX, or 
CO2 emissions or stack gas volumetric flow rate. The 
following are the principal types of continuous emission monitoring 
systems required under part 75 of this chapter. Sections 75.10 through 
75.18, and Sec. 75.71(a) of this chapter indicate which type(s) of CEMS 
is required for specific applications:
    (1) A sulfur dioxide monitoring system, consisting of an 
SO2 pollutant concentration monitor and an automated DAHS. An 
SO2 monitoring system provides a permanent, continuous record 
of SO2 emissions in units of parts per million (ppm);
    (2) A flow monitoring system, consisting of a stack flow rate 
monitor and an automated DAHS. A flow monitoring system provides a 
permanent,

[[Page 12]]

continuous record of stack gas volumetric flow rate, in units of 
standard cubic feet per hour (scfh);
    (3) A nitrogen oxides (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 DAHS. A 
NOX-diluent 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 (% O2 or CO2), and 
NOX emission rate in units of pounds per million British 
thermal units (lb/mmBtu);
    (4) 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). This type of CEMS is used only in conjunction with a flow 
monitoring system to determine NOX mass emissions (in lb/hr) 
under subpart H of part 75 of this chapter;
    (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 the automated DAHS. A carbon dioxide 
monitoring system provides a permanent, continuous record of 
CO2 emissions in units of percent CO2 (% 
CO2); and
    (6) 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 (% H2O)
    Continuous opacity monitoring system or COMS means the equipment 
required by part 75 of this chapter to sample, measure, analyze, and 
provide, with readings taken at least once every 6 minutes, a permanent 
record of opacity or transmittance. The following components are 
included in a continuous opacity monitoring system:
    (1) Opacity monitor; and
    (2) An automated data acquisition and handling system.
    Control unit means a unit employing a qualifying Phase I technology 
in accordance with a Phase I extension plan under Sec. 72.42.
    Coverage Factor k means, in general, a value chosen on the basis of 
the desired level of confidence to be associated with the interval 
defined by U = kuc. Typically, k is in the range 2 to 3. When 
the normal distribution applies and uc is a reliable estimate 
of the standard deviation of y, U = 2 uc (i.e., k = 2) 
defines an interval having a level of confidence of approximately 95%, 
and U = 3 uc (i.e., k = 3) defines an interval having a level 
of confidence greater than 99%.
    Customer means a purchaser of electricity not for the purposes of 
retransmission or resale. For generating rural electrical cooperatives, 
the customers of the distribution cooperatives served by the generating 
cooperative will be considered customers of the generating cooperative.
    Decisional body means any EPA employee who is or may reasonably be 
expected to act in a decision-making role in a proceeding under part 78 
of this chapter, including the Administrator, a member of the 
Environmental Appeals Board, and a Presiding Officer, and any staff of 
any such person who are participating in the decisional process.
    Demand-side measure means a measure:
    (1) To improve the efficiency of consumption of electricity from a 
utility by customers of the utility; or
    (2) To reduce the amount of consumption of electricity from a 
utility by customers of the utility without increasing the use by the 
customer of fuel other than: Biomass (i.e., combustible energy-producing 
materials from biological sources, which include wood, plant residues, 
biological wastes, landfill gas, energy crops, and eligible components 
of municipal solid waste), solar, geothermal, or wind resources; or 
industrial waste gases where the party making the submission involved 
certifies that there is no net increase in sulfur dioxide emissions from 
the use of such gases. ``Demand-side measure'' includes the measures 
listed in part 73, appendix A, section 1 of this chapter.
    Designated representative means a responsible natural person 
authorized by the owners and operators of an affected

[[Page 13]]

source and of all affected units at the source or by the owners and 
operators of a combustion source or process source, as evidenced by a 
certificate of representation submitted in accordance with subpart B of 
this part, to represent and legally bind each owner and operator, as a 
matter of Federal law, in matters pertaining to the Acid Rain Program. 
Whenever the term ``responsible official'' is used in part 70 of this 
chapter, in any other regulations implementing title V of the Act, or in 
a State operating permit program, it shall be deemed to refer to the 
``designated representative'' with regard to all matters under the Acid 
Rain Program.
    Desulfurization refers to various procedures whereby sulfur is 
removed from petroleum during or apart from the refining process. 
``Desulfurization'' does not include such processes as dilution or 
blending of low sulfur content diesel fuel with high sulfur content 
diesel fuel from a diesel refinery not eligible under 40 CFR part 73, 
subpart G.
    Diesel-fired unit means, for the purposes of part 75 of this 
chapter, an oil-fired unit that combusts diesel fuel as its fuel oil, 
where the supplementary fuel, if any, shall be limited to natural gas or 
gaseous fuels containing no more sulfur than natural gas.
    Diesel fuel means a low sulfur fuel oil of grades 1-D or 2-D, as 
defined by the American Society for Testing and Materials standard ASTM 
D975-91, ``Standard Specification for Diesel Fuel Oils,'' grades 1-GT or 
2-GT, as defined by ASTM D2880-90a, ``Standard Specification for Gas 
Turbine Fuel Oils,'' or grades 1 or 2, as defined by ASTM D396-90a, 
``Standard Specification for Fuel Oils'' (incorporated by reference in 
Sec. 72.13).
    Diesel reciprocating engine unit means an internal combustion engine 
that combusts only diesel fuel and that thereby generates electricity 
through the operation of pistons, rather than by heating steam or water.
    Diluent cap value means a default value of percent CO2 or 
O2 which may be used to calculate the hourly NOX 
emission rate, when the measured hourly average percent CO2 
is below the default value or when the measured hourly average percent 
O2 is above the default value. The diluent cap values for 
boilers are 5.0 percent CO2 and 14.0 percent O2. 
For combustion turbines, the diluent cap values are 1.0 percent 
CO2 and 19.0 percent O2.
    Diluent gas means a major gaseous constituent in a gaseous pollutant 
mixture, which in the case of emissions from fossil fuel-fired units are 
carbon dioxide and oxygen.
    Diluent gas monitor means that component of the continuous emission 
monitoring system that measures the diluent gas concentration in a 
unit's flue gas.
    Direct public utility ownership means direct ownership of equipment 
and facilities by one or more corporations, the principal business of 
which is sale of electricity to the public at retail. Percentage 
ownership of such equipment and facilities shall be measured on the 
basis of book value.
    Dispatch means the assignment within a dispatch system of generating 
levels to specific units and generators to effect the reliable and 
economical supply of electricity, as customer demand rises or falls, and 
includes:
    (1) The operation of high-voltage lines, substations, and related 
equipment; and
    (2) The scheduling of generation for the purpose of supplying 
electricity to other utilities over interconnecting transmission lines.
    Draft Acid Rain permit or draft permit means the version of the Acid 
Rain permit, or the Acid Rain portion of an operating permit, that a 
permitting authority offers for public comment.
    Dual-fuel reciprocating engine unit means an internal combustion 
engine that combusts any combination of natural gas and diesel fuel and 
that thereby generates electricity through the operation of pistons, 
rather than by heating steam or water.
    Eligible Indian tribe means any eligible Indian tribe as defined in 
part 71 of this chapter.
    Emergency fuel means either:
    (1) For purposes of the requirements for a fuel flowmeter used in an 
excepted monitoring system under appendix D or E of part 75 of this 
chapter, the fuel identified by the designated representative in the 
unit's monitoring plan as the fuel which is combusted

[[Page 14]]

only during emergencies where the primary fuel is not available; or
    (2) For purposes of the requirement for stack testing for an 
excepted monitoring system under appendix E of part 75 of this chapter, 
the fuel identified in a federally-enforceable permit for a plant and 
identified by the designated representative in the unit's monitoring 
plan as the fuel which is combusted only during emergencies where the 
primary fuel is not available.
    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 determined by the Administrator, 
in accordance with the emissions monitoring requirements of part 75 of 
this chapter.
    Environmental Appeals Board means the three-member board established 
pursuant to Sec. 1.25(e) of this chapter and authorized to hear appeals 
pursuant to part 78 of this chapter.
    EPA means the United States Environmental Protection Agency.
    EPA Protocol Gas means a calibration gas mixture prepared and 
analyzed according to section 2 of the ``EPA Traceability Protocol for 
Assay and Certification of Gaseous Calibration Standards,'' September 
1997, as amended August 25, 1999, EPA-600/R-97/121 (incorporated by 
reference, see Sec. 72.13) or such revised procedure as approved by the 
Administrator.
    EPA Protocol Gas Production Site means a site that produces or 
blends calibration gas mixtures prepared and analyzed according to 
section 2 of the ``EPA Traceability Protocol for Assay and Certification 
of Gaseous Calibration Standards,'' September 1997, as amended August 
25, 1999, EPA-600/R-97/121 (incorporated by reference, see Sec. 72.13) 
or such revised procedure as approved by the Administrator.
    EPA Protocol Gas Verification Program or PGVP means a calibration 
gas audit program described in Sec. 75.21(g) of this chapter and 
implemented by EPA in cooperation with the National Institute of 
Standards and Technology (NIST).
    EPA trial staff means an employee of EPA, whether temporary or 
permanent, who has been designated by the Administrator to investigate, 
litigate, and present evidence, arguments, and positions of EPA in any 
evidentiary hearing under part 78 of this chapter. Any EPA or permitting 
authority employee, consultant, or contractor who is called as a witness 
in the evidentiary hearing by EPA trial staff shall be deemed to be 
``EPA trial staff''.
    Equivalent diameter means a value, calculated using the Equation 1-1 
in section 12.2 of Method 1 in part 60, appendix A of this chapter, and 
used to determine the upstream and downstream distances for locating 
CEMS or CEMS components in flues or stacks with rectangular cross 
sections.
    Ex parte communication means any communication, written or oral, 
relating to the merits of an adjudicatory proceeding under part 78 of 
this chapter, that was not originally included or stated in the 
administrative record, in a pleading, or in an evidentiary hearing or 
oral argument under part 78 of this chapter, between the decisional body 
and any interested person outside EPA or any EPA trial staff. Ex parte 
communication shall not include:
    (1) Communication between EPA employees other than between EPA trial 
staff and a member of the decisional body; or
    (2) Communication between the decisional body and interested persons 
outside the Agency, or EPA trial staff, where all parties to the 
proceeding have received prior written notice of the proposed 
communication and are given an opportunity to be present and to 
participate therein.
    Excepted monitoring system means a monitoring system that follows 
the procedures and requirements of Sec. 75.15 of this chapter, Sec. 
75.19 of this chapter, Sec. 75.81(b) of this chapter or of appendix D, 
or E to part 75 for approved exceptions to the use of continuous 
emission monitoring systems.
    Excess emissions means:
    (1) Any tonnage of sulfur dioxide emitted by the affected units at 
an affected source during a calendar year that exceeds the Acid Rain 
emissions limitation for sulfur dioxide for the source; and
    (2) Any tonnage of nitrogen oxide emitted by an affected unit during 
a calendar year that exceeds the annual

[[Page 15]]

tonnage equivalent of the Acid Rain emissions limitation for nitrogen 
oxides applicable to the affected unit taking into account the unit's 
heat input for the year.
    Existing unit means a unit (including a unit subject to section 111 
of the Act) that commenced commercial operation before November 15, 1990 
and that on or after November 15, 1990 served a generator with nameplate 
capacity of greater than 25 MWe. ``Existing unit'' does not include 
simple combustion turbines or any unit that on or after November 15, 
1990 served only generators with a nameplate capacity of 25 MWe or less. 
Any ``existing unit'' that is modified, reconstructed, or repowered 
after November 15, 1990 shall continue to be an ``existing unit.''
    Expanded uncertainty means a measure of uncertainty that defines an 
interval about the measurement result y within which the value of the 
measurand Y can be confidently asserted to lie. Although the combined 
standard uncertainty uc is used to express the uncertainty of 
many measurement results, for some commercial, industrial, and 
regulatory applications (e.g., when health and safety are concerned), 
what is often required is an expanded uncertainty, suggested symbol U, 
and is obtained by multiplying uc(y) by a coverage factor, 
suggested symbol k. Thus U = kuc(y) and it is confidently 
believed that Y is greater than or equal to y - U, and is less than or 
equal to y + U, which is commonly written as Y = y [ U.
    Facility means any institutional, commercial, or industrial 
structure, installation, plant, source, or building.
    File means to send or transmit a document, information, or 
correspondence to the official custody of the person specified to take 
possession in accordance with the applicable regulation. Compliance with 
any ``filing'' deadline shall be determined by the date that person 
receives the document, information, or correspondence.
    Flow meter accuracy means the closeness of the measurement made by a 
flow meter to the reference value of the fuel flow being measured, 
expressed as the difference between the measurement and the reference 
value.
    Flow monitor means a component of the continuous emission monitoring 
system that measures the volumetric flow of exhaust gas.
    Flue means a conduit or duct through which gases or other matter are 
exhausted to the atmosphere.
    Flue gas desulfurization system means a type of add-on emission 
control used to remove sulfur dioxide from flue gas, commonly referred 
to as a ``scrubber.''
    Forced outage means the removal of a unit from service due to an 
unplanned component failure or other unplanned condition that requires 
such removal immediately or within 7 days from the onset of the 
unplanned component failure or condition. For purposes of Sec. Sec. 
72.43, 72.91, and 72.92, ``forced outage'' also includes a partial 
reduction in the heat input or electrical output due to an unplanned 
component failure or other unplanned condition that requires such 
reduction immediately or within 7 days from the onset of the unplanned 
component failure or condition.
    Fossil fuel means natural gas, petroleum, coal, or any form of 
solid, liquid, or gaseous fuel derived from such material.
    Fossil fuel-fired means the combustion of fossil fuel or any 
derivative of fossil fuel, alone or in combination with any other fuel, 
independent of the percentage of fossil fuel consumed in any calendar 
year (expressed in mmBtu).
    Fuel flowmeter QA operating quarter means a unit operating quarter 
in which the unit combusts the fuel measured by the fuel flowmeter for 
at least 168 unit operating hours (as defined in this section).
    Fuel flowmeter system means an excepted monitoring system (as 
defined in this section) which provides a continuous record of the flow 
rate of fuel oil or gaseous fuel, in accordance with appendix D to part 
75 of this chapter. A fuel flowmeter system consists of one or more fuel 
flowmeter components, all necessary auxiliary components (e.g., 
transmitters, transducers, etc.), and a data acquisition and handling 
system (DAHS).
    Fuel oil means any petroleum-based fuel (including diesel fuel or 
petroleum derivatives such as oil tar) as defined by the American 
Society for Testing

[[Page 16]]

and Materials in ASTM D396-90a, ``Standard Specification for Fuel Oils'' 
(incorporated by reference in Sec. 72.13), and any recycled or blended 
petroleum products or petroleum by-products used as a fuel whether in a 
liquid, solid or gaseous state; provided that for purposes of the 
monitoring requirements of part 75 of this chapter, ``fuel oil'' shall 
be limited to the petroleum-based fuels for which applicable ASTM 
methods are specified in Appendices D, E, or F of part 75 of this 
chapter.
    Fuel supply agreement means a legally binding agreement between a 
new IPP or a firm associated with a new IPP and a fuel supplier that 
establishes the terms and conditions under which the fuel supplier 
commits to provide fuel to be delivered to the new IPP.
    Fuel usage time means the portion of a clock hour during which a 
unit combusts a particular type of fuel. The fuel usage time, in hours, 
is expressed as a decimal fraction, with valid values ranging from 0.00 
to 1.00.
    Gas-fired means:
    (1) For all purposes under the Acid Rain Program, except for part 75 
of this chapter, the combustion of:
    (i) Natural gas or other gaseous fuel (including coal-derived 
gaseous fuel), for at least 90.0 percent of the unit's average annual 
heat input during the previous three calendar years and for at least 
85.0 percent of the annual heat input in each of those calendar years; 
and
    (ii) Any fuel, except coal or solid or liquid coal-derived fuel, for 
the remaining heat input, if any.
    (2) For purposes of part 75 of this chapter, the combustion of:
    (i) Natural gas or other gaseous fuel (including coal-derived 
gaseous fuel) for at least 90.0 percent of the unit's average annual 
heat input during the previous three calendar years and for at least 
85.0 percent of the annual heat input in each of those calendar years; 
and
    (ii) Fuel oil, for the remaining heat input, if any.
    (3) For purposes of part 75 of this chapter, a unit may initially 
qualify as gas-fired if the designated representative demonstrates to 
the satisfaction of the Administrator that the requirements of paragraph 
(2) of this definition are met, or will in the future be met, through 
one of the following submissions:
    (i) For a unit for which a monitoring plan has not been submitted 
under Sec. 75.62 of this chapter, the designated representative submits 
either:
    (A) Fuel usage data for the unit for the three calendar years 
immediately preceding the date of initial submission of the monitoring 
plan for the unit under Sec. 75.62; or
    (B) If a unit does not have fuel usage data for one or more of the 
three calendar years immediately preceding the date of initial 
submission of the monitoring plan for the unit under Sec. 75.62, the 
unit's designated fuel usage; all available fuel usage data (including 
the percentage of the unit's heat input derived from the combustion of 
gaseous fuels), beginning with the date on which the unit commenced 
commercial operation; and the unit's projected fuel usage.
    (ii) For a unit for which a monitoring plan has already been 
submitted under Sec. 75.62, that has not qualified as gas-fired under 
paragraph (3)(i) of this definition, and whose fuel usage changes, the 
designated representative submits either:
    (A) Three calendar years of data following the change in the unit's 
fuel usage, showing that no less than 90.0 percent of the unit's average 
annual heat input during the previous three calendar years, and no less 
than 85.0 percent of the unit's annual heat input during any one of the 
previous three calendar years, is from the combustion of gaseous fuels 
and the remaining heat input is from the combustion of fuel oil; or
    (B) A minimum of 720 hours of unit operating data following the 
change in the unit's fuel usage, showing that no less than 90.0 percent 
of the unit's heat input is from the combustion of gaseous fuels and the 
remaining heat input is from the combustion of fuel oil, and a statement 
that this changed pattern of fuel usage is considered permanent and is 
projected to continue for the foreseeable future.
    (iii) If a unit qualifies as gas-fired under paragraph (3)(i) or 
(ii) of this definition, the unit is classified as gas-

[[Page 17]]

fired as of the date of the submission under such paragraph.
    (4) For purposes of part 75 of this chapter, a unit that initially 
qualifies as gas-fired under paragraph (3)(i) or (ii) of this definition 
must meet the criteria in paragraph (2) of this definition each year in 
order to continue to qualify as gas-fired. If such a unit combusts only 
gaseous fuel and fuel oil but fails to meet such criteria for a given 
year, the unit no longer qualifies as gas-fired starting January 1 of 
the year after the first year for which the criteria are not met. If 
such a unit combusts fuel other than gaseous fuel or fuel oil and fails 
to meet such criteria in a given year, the unit no longer qualifies as 
gas-fired starting the day after the first day for which the criteria 
are not met. If a unit failing to meet the criteria in paragraph (2) of 
this definition initially qualified as a gas-fired unit under paragraph 
(3) of this definition, the unit may qualify as a gas-fired unit for a 
subsequent year only if the designated representative submits the data 
specified in paragraph (3)(ii)(A) of this definition.
    Gas manufacturer's intermediate standard (GMIS) means a compressed 
gas calibration standard that has been assayed and certified by direct 
comparison to a standard reference material (SRM), an SRM-equivalent 
PRM, a NIST/EPA-approved certified reference material (CRM), or a NIST 
traceable reference material (NTRM), in accordance with section 2.1.2.1 
of the ``EPA Traceability Protocol for Assay and Certification of 
Gaseous Calibration Standards,'' September 1997, EPA-600/R-97/121.
    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.
    General account means an Allowance Tracking System account that is 
not a compliance account.
    Generator means a device that produces electricity and was or would 
have been required to be reported as a generating unit pursuant to the 
United States Department of Energy Form 860 (1990 edition).
    Generator Output capacity means the full-load continuous rating of a 
generator under specific conditions as designed by the manufacturer.
    Hearing clerk means an EPA employee designated by the Administrator 
to establish a repository for all books, records, documents, and other 
materials relating to proceedings under part 78 of this chapter.
    Heat input rate means the product (expressed in mmBtu/hr) of the 
gross calorific value of the fuel (expressed in mmBtu/mass of fuel) and 
the fuel feed rate into the combustion device (expressed in mass of 
fuel/hr) and does not include the heat derived from preheated combustion 
air, recirculated flue gases, or exhaust from other sources.
    Hour before and hour after means, for purposes of the missing data 
substitution procedures of part 75 of this chapter, the quality-assured 
hourly SO2 or CO2 concentration, hourly flow rate, 
hourly NOX concentration, hourly moisture, hourly 
O2 concentration, or hourly NOX emission rate (as 
applicable) recorded by a certified monitor during the unit or stack 
operating hour immediately before and the unit or stack operating hour 
immediately after a missing data period.
    Hybrid generation facility means a plant that generates electrical 
energy derived from a combination of qualified renewable energy (wind, 
solar, biomass, or geothermal) and one or more other energy resources.
    Independent auditor means a professional engineer who is not an 
employee or agent of the source being audited.
    Independent Power Production Facility (IPP) means a source that:
    (1) Is nonrecourse project financed, as defined by the Secretary of 
Energy at 10 CFR part 715;
    (2) Is used for the generation of electricity, eighty percent or 
more of which is sold at wholesale; and
    (3) Is a new unit required to hold allowances under Title IV of the 
Clean Air Act; but only if direct public utility ownership of the 
equipment comprising the facility does not exceed 50 percent.
    Investor-owned utility means a utility that is organized as a tax-
paying for-profit business.

[[Page 18]]

    Kilowatthour saved or savings means the net savings in electricity 
use (expressed in Kwh) that result directly from a utility's energy 
conservation measures or programs.
    Least-cost plan or least-cost planning process means an energy 
conservation and electric power planning methodology meeting the 
requirements of Sec. 73.82(a)(4) of this chapter.
    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 generating 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 
was 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.
    Long-term cold storage means the complete shutdown of a unit 
intended to last for an extended period of time (at least two calendar 
years) where notice for long-term cold storage is provided under Sec. 
75.61(a)(7).
    Low mass emissions unit means an affected unit that is ``gas-fired'' 
or ``oil-fired'' (as defined in this section), and that qualifies to use 
the low mass emissions excepted methodology in Sec. 75.19 of this 
chapter.
    Mail or serve by mail means to submit or serve by means other than 
personal service.
    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 
flow rate and either the maximum carbon dioxide concentration (in 
percent CO2) or the minimum oxygen concentration (in percent 
O2).
    Maximum potential NOX emission rate or MER means the emission rate 
of nitrogen oxides (in lb/mmBtu) calculated in accordance with section 3 
of appendix F to part 75 of this chapter, using the maximum potential 
nitrogen oxides concentration (MPC), as defined in section 2.1.2.1 of 
appendix A to 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. The diluent 
cap value, as defined in this section, may be used in lieu of the 
maximum O2 or minimum CO2 concentration to 
calculate the MER. As a second alternative, when the NOX MPC 
is determined from emission test results or from historical CEM data, as 
described in section 2.1.2.1 of appendix A to part 75 of this chapter, 
quality-assured diluent gas (i.e., O2 or CO2) data 
recorded concurrently with the MPC may be used to calculate the MER. For 
the purposes of Sec. Sec. 75.4(f), 75.19(b)(3), and 75.33(c)(7) in part 
75 of this chapter and section 2.5 in appendix E to part 75 of this 
chapter, the MER is specific to the type of fuel combusted in the unit.
    Maximum rated hourly heat input rate means a unit-specific maximum 
hourly heat input rate (mmBtu/hr) which is the higher of the 
manufacturer's maximum rated hourly heat input rate or the highest 
observed hourly heat input rate.
    Missing data period means the total number of consecutive hours 
during which any certified CEMS or approved alternative monitoring 
system is not providing quality-assured data, regardless of the reason.
    Monitor accuracy means the closeness of the measurement made by a 
CEMS to the reference value of the emissions

[[Page 19]]

or volumetric flow being measured, expressed as the difference between 
the measurement and the reference value.
    Monitor operating hour means any unit operating hour or portion 
thereof over which a CEMS, or other monitoring system approved by the 
Administrator under part 75 of this chapter is operating, regardless of 
the number of measurements (i.e., data points) collected during the hour 
or portion of an hour.
    Most stringent federally enforceable emissions limitation means the 
most stringent emissions limitation for a given pollutant applicable to 
the unit, which has been approved by the Administrator under the Act, 
whether in a State implementation plan approved pursuant to title I of 
the Act, a new source performance standard, or otherwise. To determine 
the most stringent emissions limitation for sulfur dioxide, each 
limitation shall be converted to lbs/mmBtu, using the appropriate 
conversion factors in appendix B of this part; provided that for 
determining the most stringent emissions limitation for sulfur dioxide 
for 1985, each limitation shall also be annualized, using the 
appropriate annualization factors in appendix A of this part.
    Multi-header generator means a generator served by ductwork from 
more than one unit.
    Multi-header unit means a unit with ductwork serving more than one 
generator.
    Multiple stack configuration refers to an exhaust configuration in 
which the flue gases from a particular unit discharge to the atmosphere 
through two or more stacks. The term also refers to a unit for which 
emissions are monitored in two or more ducts leading to the exhaust 
stack, in lieu of monitoring at the stack.
    Nameplate capacity means the maximum electrical generating output 
(expressed in MWe) that a generator can sustain over a specified period 
of time when not restricted by seasonal or other deratings, as listed in 
the NADB under the data field ``NAMECAP'' if the generator is listed in 
the NADB or as measured in accordance with the United States Department 
of Energy standards if the generator is not listed in the NADB.
    National Allowance Data Base or NADB means the data base established 
by the Administrator under section 402(4)(C) of the Act.
    Natural gas means a naturally occurring fluid mixture of 
hydrocarbons (e.g., methane, ethane, or propane) produced in geological 
formations beneath the Earth's surface that maintains a gaseous state at 
standard atmospheric temperature and pressure under ordinary conditions. 
Natural gas contains 20.0 grains or less of total sulfur per 100 
standard cubic feet. Additionally, natural gas must either be composed 
of at least 70 percent methane by volume or have a gross calorific value 
between 950 and 1100 Btu per standard cubic foot. Natural gas does not 
include the following gaseous fuels: landfill gas, digester gas, 
refinery gas, sour gas, blast furnace gas, coal-derived gas, producer 
gas, coke oven gas, or any gaseous fuel produced in a process which 
might result in highly variable sulfur content or heating value.
    NERC region means the North American Electric Reliability Council 
region or, if any, subregion.
    Net income neutrality means, in the case of energy conservation 
measures undertaken by an investor-owned utility whose rates are 
regulated by a State utility regulatory authority, rates and charges 
established by the State utility regulatory authority that ensure that 
the net income earned by the utility on its State-jurisdictional equity 
investment will be no lower as a consequence of its expenditures on 
cost-effective qualified energy conservation measures and any associated 
lost sales than it would have been had the utility not made such 
expenditures, or that the State utility regulatory authority has 
implemented a ratemaking approach designed to meet this objective.
    New independent power production facility or new IPP means a unit 
that:
    (1) Commences commercial operation on or after November 15, 1990;
    (2) Is nonrecourse project-financed, as defined in 10 CFR part 715;
    (3) Sells 80% of electricity generated at wholesale; and
    (4) Does not sell electricity to any affiliate or, if it does, 
demonstrates it

[[Page 20]]

cannot obtain the required allowances from such an affiliate.
    New unit means a unit that commences commercial operation on or 
after November 15, 1990, including any such unit that serves a generator 
with a nameplate capacity of 25 MWe or less or that is a simple 
combustion turbine.
    Ninetieth (90th) percentile means a value that would divide an 
ordered set of increasing values so that at least 90 percent are less 
than or equal to the value and at least 10 percent are greater than or 
equal to the value.
    Ninety-fifth (95th) percentile means a value that would divide an 
ordered set of increasing values so that at least 95 percent of the set 
are less than or equal to the value and at least 5 percent are greater 
than or equal to the value.
    NIST/EPA-approved certified reference material or NIST/EPA-approved 
CRM means a calibration gas mixture that has been approved by EPA and 
the National Institutes of Standards and Technologies (NIST) as having 
specific known chemical or physical property values certified by a 
technically valid procedure as evidenced by a certificate or other 
documentation issued by a certifying standard-setting body.
    NIST traceable reference material (NTRM) means a calibration gas 
mixture tested by and certified by the National Institutes of Standards 
and Technologies (NIST) to have a certain specified concentration of 
gases. NTRMs may have different concentrations from those of standard 
reference materials.
    Offset plan means a plan pursuant to part 77 of this chapter for 
offsetting excess emissions of sulfur dioxide that have occurred at an 
affected source in any calendar year.
    Oil-fired means:
    (1) For all purposes under the Acid Rain Program, except part 75 of 
this chapter, the combustion of:
    (i) Fuel oil for more than 10.0 percent of the average annual heat 
input during the previous three calendar years or for more than 15.0 
percent of the annual heat input during any one of those calendar years; 
and
    (ii) Any solid, liquid or gaseous fuel (including coal-derived 
gaseous fuel), other than coal or any other coal-derived solid or liquid 
fuel, for the remaining heat input, if any.
    (2) For purposes of part 75 of this chapter, combustion of only fuel 
oil and gaseous fuels, provided that the unit involved does not meet the 
definition of gas-fired.
    Opacity means the degree to which emissions reduce the transmission 
of light and obscure the view of an object in the background.
    Operating when referring to a combustion or process source seeking 
entry into the Opt-in Program, means that the source had documented 
consumption of fuel input for more than 876 hours in the 6 months 
immediately preceding the submission of a combustion source's opt-in 
application under Sec. 74.16(a) of this chapter.
    Operating permit means a permit issued under part 70 of this chapter 
and any other regulations implementing title V of the Act.
    Opt in or opt into means to elect to become an affected unit under 
the Acid Rain Program through the issuance of the final effective opt-in 
permit under Sec. 74.14 of this chapter.
    Opt-in permit means the legally binding written document that is 
contained within the Acid Rain permit and sets forth the requirements 
under part 74 of this chapter for a combustion source or a process 
source that opts into the Acid Rain Program.
    Opt-in source means a combustion source or process source that has 
elected to become an affected unit under the Acid Rain Program and whose 
opt-in permit has been issued and is in effect.
    Out-of-control period means any period:
    (1) Beginning with the hour corresponding to the completion of a 
daily calibration error, linearity check, or quality assurance audit 
that indicates that the instrument is not measuring and recording within 
the applicable performance specifications; and
    (2) Ending with the hour corresponding to the completion of an 
additional calibration error, linearity check, or quality assurance 
audit following corrective action that demonstrates that the instrument 
is measuring and recording within the applicable performance 
specifications.

[[Page 21]]

    Oversubscription payment deadline means 30 calendar days prior to 
the allowance transfer deadline.
    Owner means any of the following persons:
    (1) Any holder of any portion of the legal or equitable title in an 
affected unit or in a combustion source or process source; or
    (2) Any holder of a leasehold interest in an affected unit or in a 
combustion source or process source; or
    (3) Any purchaser of power from an affected unit or from a 
combustion source or process source under a life-of-the-unit, firm power 
contractual arrangement as the term is defined herein and used in 
section 408(i) of the Act. 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 affected unit; or
    (4) With respect to any Allowance Tracking System general account, 
any person identified in the submission required by Sec. 73.31(c) of 
this chapter that is subject to the binding agreement for the authorized 
account representative to represent that person's ownership interest 
with respect to allowances.
    Owner or operator means any person who is an owner or who operates, 
controls, or supervises an affected unit, affected source, combustion 
source, or process source and shall include, but not be limited to, any 
holding company, utility system, or plant manager of an affected unit, 
affected source, combustion source, or process source.
    Ozone nonattainment area means an area designated as a nonattainment 
area for ozone under subpart C of part 81 of this chapter.
    Ozone season means the period of time beginning May 1 of a year and 
ending on September 30 of the same year, inclusive.
    Ozone transport region means the ozone transport region designated 
under Section 184 of the Act.
    Peaking unit means:
    (1) A unit that has:
    (i) An average capacity factor of no more than 10.0 percent during 
the previous three calendar years and
    (ii) A capacity factor of no more than 20.0 percent in each of those 
calendar years.
    (2) For purposes of part 75 of this chapter, a unit may initially 
qualify as a peaking unit if the designated representative demonstrates 
to the satisfaction of the Administrator that the requirements of 
paragraph (1) of this definition are met, or will in the future be met, 
through one of the following submissions:
    (i) For a unit for which a monitoring plan has not been submitted 
under Sec. 75.62, the designated representative submits either:
    (A) Capacity factor data for the unit for the three calendar years 
immediately preceding the date of initial submission of the monitoring 
plan for the unit under Sec. 75.62; or
    (B) If a unit does not have capacity factor data for one or more of 
the three calendar years immediately preceding the date of initial 
submission of the monitoring plan for the unit under Sec. 75.62, all 
available capacity factor data, beginning with the date on which the 
unit commenced commercial operation; and projected capacity factor data.
    (ii) For a unit for which a monitoring plan has already been 
submitted under Sec. 75.62, that has not qualified as a peaking unit 
under paragraph (2)(i) of this definition, and where capacity factor 
changes, the designated representative submits either:
    (A) Three calendar years of data following the change in the unit's 
capacity factor showing an average capacity factor of no more than 10.0 
percent during the three previous calendar years and a capacity factor 
of no more than 20.0 percent in each of those calendar years; or
    (B) One calendar year of data following the change in the unit's 
capacity factor showing a capacity factor of no more than 10.0 percent 
and a statement that this changed pattern of operation resulting in a 
capacity factor less than 10.0 percent is considered permanent and is 
projected to continue for the foreseeable future.
    (3) For purposes of part 75 of this chapter, a unit that initially 
qualifies as a peaking unit must meet the criteria in paragraph (1) of 
this definition

[[Page 22]]

each year in order to continue to qualify as a peaking unit. If such a 
unit fails to meet such criteria for a given year, the unit no longer 
qualifies as a peaking unit starting January 1 of the year after the 
year for which the criteria are not met. If a unit failing to meet the 
criteria in paragraph (1) of this definition initially qualified as a 
peaking unit under paragraph (2) of this definition, the unit may 
qualify as a peaking unit for a subsequent year only if the designated 
representative submits the data specified in paragraph (2)(ii)(A) of 
this definition.
    (4) A unit required to comply with the provisions of subpart H of 
part 75 of this chapter, under a State or Federal NOX mass 
emissions reduction program, may, pursuant to Sec. 75.74(c)(11) in part 
75 of this chapter, qualify as a peaking unit on an ozone season basis 
rather than an annual basis, if the owner or operator reports 
NOX mass emissions and heat input data only during the ozone 
season.
    Permit revision means a permit modification, fast track 
modification, administrative permit amendment, or automatic permit 
amendment, as provided in subpart H of this part.
    Permitting authority means either:
    (1) When the Administrator is responsible for administering Acid 
Rain permits under subpart G of this part, the Administrator or a 
delegatee agency authorized by the Administrator; or
    (2) The State air pollution control agency, local agency, other 
State agency, or other agency authorized by the Administrator to 
administer Acid Rain permits under subpart G of this part and part 70 of 
this chapter.
    Person includes an individual, corporation, partnership, 
association, State, municipality, political subdivision of a State, any 
agency, department, or instrumentality of the United States, and any 
officer, agent, or employee thereof.
    Phase I means the Acid Rain Program period beginning January 1, 1995 
and ending December 31, 1999.
    Phase I unit means any affected unit, except an affected unit under 
part 74 of this chapter, that is subject to an Acid Rain emissions 
reduction requirement or Acid Rain emissions limitation beginning in 
Phase I; or any unit exempt under Sec. 72.8 that, but for such 
exemption, would be subject to an Acid Rain emissions reduction 
requirement or Acid Rain emissions limitation beginning in Phase I.
    Phase II means the Acid Rain Program period beginning January 1, 
2000, and continuing into the future thereafter.
    Phase II unit means any affected unit, except an affected unit under 
part 74 of this chapter, that is subject to an Acid Rain emissions 
reduction requirement or Acid Rain emissions limitation during Phase II 
only.
    Pipeline natural gas means a naturally occurring fluid mixture of 
hydrocarbons (e.g., methane, ethane, or propane) produced in geological 
formations beneath the Earth's surface that maintains a gaseous state at 
standard atmospheric temperature and pressure under ordinary conditions, 
and which is provided by a supplier through a pipeline. Pipeline natural 
gas contains 0.5 grains or less of total sulfur per 100 standard cubic 
feet. Additionally, pipeline natural gas must either be composed of at 
least 70 percent methane by volume or have a gross calorific value 
between 950 and 1100 Btu per standard cubic foot.
    Pollutant concentration monitor means that component of the 
continuous emission monitoring system that measures the concentration of 
a pollutant in a unit's flue gas.
    Potential electrical output capacity means the MWe capacity rating 
for the units which shall be equal to 33 percent of the maximum design 
heat input capacity of the steam generating unit, as calculated 
according to appendix D of part 72.
    Power distribution system means the portion of an electricity grid 
owned or operated by a utility that is dedicated to delivering electric 
energy to customers.
    Power purchase commitment means a commitment or obligation of a 
utility to purchase electric power from a facility pursuant to:
    (1) A power sales agreement;
    (2) A state regulatory authority order requiring a utility to:
    (i) Enter into a power sales agreement with the facility;
    (ii) Purchase from the facility; or

[[Page 23]]

    (iii) Enter into arbitration concerning the facility for the purpose 
of establishing terms and conditions of the utility's purchase of power;
    (3) A letter of intent or similar instrument committing to purchase 
power (actual electrical output or generator output capacity) from the 
source at a previously offered or lower price and a power sales 
agreement applicable to the source is executed within the time frame 
established by the terms of the letter of intent but no later than 
November 15, 1993 or, where the letter of intent does not specify a time 
frame, a power sale agreement applicable to the source is executed on or 
before November 15, 1993; or
    (4) A utility competitive bid solicitation that has resulted in the 
selection of the qualifying facility or independent power production 
facility as the winning bidder.
    Power sales agreement is a legally binding agreement between a QF, 
IPP, new IPP, or firm associated with such facility and a regulated 
electric utility that establishes the terms and conditions for the sale 
of power from the facility to the utility.
    Presiding Officer means an Administrative Law Judge appointed under 
5 U.S.C. 3105 and designated to preside at a hearing in an appeal under 
part 78 of this chapter or an EPA lawyer designated to preside at any 
such hearing under Sec. 78.6(b)(3)(ii) of this chapter.
    Primary fuel or primary fuel supply means the main fuel type 
(expressed in mmBtu) consumed by an affected unit for the applicable 
calendar year.
    Probationary calibration error test means an on-line calibration 
error test performed in accordance with section 2.1.1 of appendix B to 
part 75 of this chapter that is used to initiate a conditionally valid 
data period.
    Proposed Acid Rain permit or proposed permit means, in the case of a 
State operating permit program, the version of an Acid Rain permit that 
the permitting authority submits to the Administrator after the public 
comment period, but prior to completion of the EPA permit review period, 
as provided for in part 70 of this chapter.
    QA operating quarter means a calendar quarter in which there are at 
least 168 unit operating hours (as defined in this section) or, for a 
common stack or bypass stack, a calendar quarter in which there are at 
least 168 stack operating hours (as defined in this section).
    Qualified individual (QI) means an individual who is identified by 
an AETB as meeting the requirements described in ASTM D 7036-04 
``Standard Practice for Competence of Air Emission Testing Bodies'' 
(incorporated by reference, see Sec. 72.13), as of the date of testing.
    Qualifying facility (QF) means a ``qualifying small power production 
facility'' within the meaning of section 3(17)(C) of the Federal Power 
Act or a ``qualifying cogeneration facility'' within the meaning of 
section 3(18)(B) of the Federal Power Act.
    Qualifying Phase I technology means a technological system of 
continuous emission reduction that is demonstrated to achieve a ninety 
(90) percent (or greater) reduction in emissions of sulfur dioxide from 
the emissions that would have resulted from the use of fossil fuels that 
were not subject to treatment prior to combustion, as provided in Sec. 
72.42.
    Qualifying power purchase commitment means a power purchase 
commitment in effect as of November 15, 1990 without regard to changes 
to that commitment so long as:
    (1) The identity of the electric output purchaser; or
    (2) The identity of the steam purchaser and the location of the 
facility, remain unchanged as of the date the facility commences 
commercial operation; and
    (3) The terms and conditions of the power purchase commitment are 
not changed in such a way as to allow the costs of compliance with the 
Acid Rain Program to be shifted to the purchaser.
    Qualifying repowering technology means:
    (1) Replacement of an existing coal-fired boiler with one of the 
following clean coal technologies: Atmospheric or pressurized fluidized 
bed combustion, integrated gasification combined cycle, 
magnetohydrodynamics, direct and indirect coal-fired turbines, 
integrated gasification fuel cells, or as determined by the 
Administrator, in consultation with the Secretary of Energy, a 
derivative of one or more of these

[[Page 24]]

technologies, and any other 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 the 
date of enactment of the Clean Air Act Amendments of 1990; or
    (2) Any oil- or gas-fired unit that has been awarded clean coal 
technology demonstration funding as of January 1, 1991, by the 
Department of Energy.
    Quality-assured monitor operating hour means any unit operating hour 
or portion thereof over which a certified CEMS, or other monitoring 
system approved by the Administrator under part 75 of this chapter, is 
operating:
    (1) Within the performance specifications set forth in part 75, 
appendix A of this chapter and the quality assurance/quality control 
procedures set forth in part 75, appendix B of this chapter, without 
unscheduled maintenance, repair, or adjustment; and
    (2) In accordance with Sec. 75.10(d), (e), and (f) of this chapter.
    Receive or receipt of means the date the Administrator or a 
permitting authority comes into possession of information or 
correspondence (whether sent in writing or by authorized electronic 
transmission), as indicated in an official log, or by a notation made on 
the information or correspondence, by the Administrator or the 
permitting authority in the regular course of business.
    Recordation, record, or recorded means, with regard to allowances, 
the transfer of allowances by the Administrator from one Allowance 
Tracking System account to another.
    Reduced utilization means a reduction, during any calendar year in 
Phase I, in the heat input (expressed in mmBtu for the calendar year) at 
a Phase I unit below the unit's baseline, where such reduction subjects 
the unit to the requirement to submit a reduced utilization plan under 
Sec. 72.43; or, in the case of an opt-in source, means a reduction in 
the average utilization, as specified in Sec. 74.44 of this chapter, of 
an opt-in source below the opt-in source's baseline.
    Reference method means any direct test method of sampling and 
analyzing for an air pollutant as specified in part 60, appendix A of 
this chapter.
    Reference value or reference signal means the known concentration of 
a calibration gas, the known value of an electronic calibration signal, 
or the known value of any other measurement standard approved by the 
Administrator, assumed to be the true value for the pollutant or diluent 
concentration or volumetric flow being measured.
    Relative accuracy means a statistic designed to provide a measure of 
the systematic and random errors associated with data from continuous 
emission monitoring systems, and is expressed as the absolute mean 
difference between the pollutant or moisture concentration or volumetric 
flow measured by the pollutant concentration or flow monitor or moisture 
monitor and the value determined by the applicable reference method(s) 
plus the 2.5 percent error confidence coefficient of a series of tests 
divided by the mean of the reference method tests in accordance with 
part 75 of this chapter.
    Replacement unit means an affected unit replacing the thermal energy 
provided by an opt-in source, where both the affected unit and the opt-
in source are governed by a thermal energy plan.
    Research gas mixture (RGM) means a calibration gas mixture developed 
by agreement of a requestor and NIST that NIST analyzes and certifies as 
``NIST traceable.'' RGMs may have concentrations different from those of 
standard reference materials.
    Schedule of compliance means an enforceable sequence of actions, 
measures, or operations designed to achieve or maintain compliance, or 
correct non-compliance, with an applicable requirement of the Acid Rain 
Program, including any applicable Acid Rain permit requirement.
    Secretary of Energy means the Secretary of the United States 
Department of Energy or the Secretary's duly authorized representative.
    Serial number means, when referring to allowances, the unique 
identification number assigned to each allowance by the Administrator, 
pursuant to Sec. 73.34(d) of this chapter.

[[Page 25]]

    Simple combustion turbine means a unit that is a rotary engine 
driven by a gas under pressure that is created by the combustion of any 
fuel. This term includes combined cycle units without auxiliary firing. 
This term excludes combined cycle units with auxiliary firing, unless 
the unit did not use the auxiliary firing from 1985 through 1987 and 
does not use auxiliary firing at any time after November 15, 1990.
    Site lease, as used in part 73, subpart E of this chapter, means a 
legally-binding agreement signed between a new IPP or a firm associated 
with a new IPP and a site owner that establishes the terms and 
conditions under which the new IPP or the firm associated with the new 
IPP has the binding right to utilize a specific site for the purposes of 
operating or constructing the new IPP.
    Small diesel refinery means a domestic motor diesel fuel refinery or 
portion of a refinery that, as an annual average of calendar years 1988 
through 1990 and as reported to the Department of Energy on Form 810, 
had bona fide crude oil throughput less than 18,250,000 barrels per 
year, and the refinery or portion of a refinery is owned or controlled 
by a refiner with a total combined bona fide crude oil throughput of 
less than 50,187,500 barrels per year.
    Solid waste incinerator means a source as defined in section 
129(g)(1) of the Act.
    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 
Act, provided that one or more combustion or process sources that have, 
under Sec. 74.4(c) of this chapter, a different designated 
representative than the designated representative for one or more 
affected utility units at a source shall be treated as being included in 
a separate source from the source that includes such utility units for 
purposes of parts 72 through 78 of this chapter, but shall be treated as 
being included in the same source as the source that includes such 
utility units for purposes of section 502(c) of the Act. For purposes of 
section 502(c) of the Act, a ``source'', including a ``source'' with 
multiple units, shall be considered a single ``facility.''
    Span means the highest pollutant or diluent concentration or flow 
rate that a monitor component is required to be capable of measuring 
under part 75 of this chapter.
    Specialty Gas Company means an organization that wholly or partially 
owns or operates one or more EPA Protocol gas production sites.
    Spot allowance means an allowance that may be used for purposes of 
compliance with a source's Acid Rain sulfur dioxide emissions limitation 
requirements beginning in the year in which the allowance is offered for 
sale.
    Spot auction means an auction of a spot allowance.
    Spot sale means a sale of a spot allowance.
    Stack means a structure that includes one or more flues and the 
housing for the flues.
    Stack operating hour means a clock hour during which flue gases flow 
through a particular stack or duct (either for the entire hour or for 
part of the hour) while the associated unit(s) are combusting fuel.
    Stack operating time means the portion of a clock hour during which 
flue gases flow through a particular stack or duct while the associated 
unit(s) are combusting fuel. The stack operating time, in hours, is 
expressed as a decimal fraction, with valid values ranging from 0.00 to 
1.00.
    Standard conditions means 68 F at 1 atm (29.92 in. of mercury).
    Standard reference material or SRM means a calibration gas mixture 
issued and certified by NIST as having specific known chemical or 
physical property values.
    Standard reference material-equivalent compressed gas primary 
reference material (SRM-equivalent PRM) means those gas mixtures listed 
in a declaration of equivalence in accordance with section 2.1.2 of the 
``EPA Traceability Protocol for Assay and Certification of Gaseous 
Calibration Standards,'' September 1997, EPA-600/R-97/121.
    State means one of the 48 contiguous States and the District of 
Columbia, any non-federal authorities in or including such States or the 
District of Columbia (including local agencies,

[[Page 26]]

interstate associations, and State-wide agencies), and any eligible 
Indian tribe in an area in such State or the District of Columbia. The 
term ``State'' shall have its conventional meaning where such meaning is 
clear from the context.
    State operating permit program means an operating permit program 
that the Administrator has approved under part 70 of this chapter.
    Stationary gas turbine means a turbine that is not self-propelled 
and that combusts natural gas, other gaseous fuel with a total sulfur 
content no greater than the total sulfur content of natural gas, or fuel 
oil in order to heat inlet combustion air and thereby turn a turbine in 
addition to or instead of producing steam or heating water.
    Steam sales agreement is a legally binding agreement between a QF, 
IPP, new IPP, or firm associated with such facility and an industrial or 
commercial establishment requiring steam that establishes the terms and 
conditions under which the facility will supply steam to the 
establishment.
    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 equivalent 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.
    Substitute data means emissions or volumetric flow data provided to 
assure 100 percent recording and reporting of emissions when all or part 
of the continuous emission monitoring system is not functional or is 
operating outside applicable performance specifications.
    Substitution unit means an affected unit, other than a unit under 
section 410 of the Act, that is designated as a Phase I unit in a 
substitution plan under Sec. 72.41.
    Sulfur-free generation means the generation of electricity by a 
process that does not have any emissions of sulfur dioxide, including 
hydroelectric, nuclear, solar, or wind generation. A ``sulfur-free 
generator'' is a generator that is located in one of the 48 contiguous 
States or the District of Columbia and produces ``sulfur-free 
generation.''
    Supply-side measure means a measure to improve the efficiency of the 
generation, transmission, or distribution of electricity, implemented by 
a utility in connection with its operations or facilities to provide 
electricity to its customers, and includes the measures set forth in 
part 73, appendix A, section 2 of this chapter.
    Thermal energy means the thermal output produced by a combustion 
source used directly as part of a manufacturing process but not used to 
produce electricity.
    Ton or tonnage means any ``short ton'' (i.e., 2,000 pounds). For the 
purpose of determining compliance with the Acid Rain emissions 
limitations and reduction requirements, total tons for a year shall be 
calculated as the sum of all recorded hourly emissions (or the tonnage 
equivalent of the recorded hourly emissions rates) in accordance with 
part 75 of this chapter, 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 not to equal any ton.
    Total planned net output capacity means the planned generator output 
capacity, excluding that portion of the electrical power which is 
designed to be used at the power production facility, as specified under 
one or more qualifying power purchase commitments or contemporaneous 
documents as of November 15, 1990; ``Total installed net output 
capacity'' shall be the generator output capacity, excluding that 
portion of the electrical power actually used at the power production 
facility, as installed.
    Transfer unit means a Phase I unit that transfers all or part of its 
Phase I emission reduction obligations to a control unit designated 
pursuant to a Phase I extension plan under Sec. 72.42.
    Underutilization means a reduction, during any calendar year in 
Phase I, of the heat input (expressed in mmBtu for the calendar year) at 
a Phase I unit below the unit's baseline.

[[Page 27]]

    Unit means a fossil fuel-fired combustion device.
    Unit load means the total (i.e., gross) output of a unit or source 
in any calendar year (or other specified time period) produced by 
combusting a given heat input of fuel, expressed in terms of:
    (1) The total electrical generation (MWe) for use within the plant 
and for sale; or
    (2) In the case of a unit or source that uses part of its heat input 
for purposes other than electrical generation, the total steam pressure 
(psia) produced by the unit or source.
    Unit operating day means a calendar day in which a unit combusts any 
fuel.
    Unit operating hour means a clock hour during which a unit combusts 
any fuel, either for part of the hour or for the entire hour.
    Unit operating quarter means a calendar quarter in which a unit 
combusts any fuel.
    Unit operating time means the portion of a clock hour during which a 
unit combusts any fuel. The unit operating time, in hours, is expressed 
as a decimal fraction, with valid values ranging from 0.00 to 1.00.
    Utility means any person that sells electricity.
    Utility competitive bid solicitation is a public request from a 
regulated utility for offers to the utility for meeting future 
generating needs. A qualifying facility, independent power production 
facility, or new IPP may be regarded as having been ``selected'' in such 
solicitation if the utility has named the facility as a project with 
which the utility intends to negotiate a power sales agreement.
    Utility regulatory authority means an authority, board, commission, 
or other entity (limited to the local-, State-, or federal-level, 
whenever so specified) responsible for overseeing the business 
operations of utilities located within its jurisdiction, including, but 
not limited to, utility rates and charges to customers.
    Utility system means all interconnected units and generators 
operated by the same utility operating company.
    Utility unit means a unit owned or operated by a utility:
    (1) That serves a generator in any State that produces electricity 
for sale, or
    (2) That during 1985, served a generator in any State that produced 
electricity for sale.
    (3) Notwithstanding paragraphs (1) and (2) of this definition, a 
unit that was in operation during 1985, but did not serve a generator 
that produced electricity for sale during 1985, and did not commence 
commercial operation on or after November 15, 1990 is not a utility unit 
for purposes of the Acid Rain Program.
    (4) Notwithstanding paragraphs (1) and (2) of this definition, a 
unit that cogenerates steam and electricity is not a utility unit for 
purposes of the Acid Rain Program, unless the unit is constructed for 
the purpose of supplying, or commences construction after November 15, 
1990 and supplies, more than one-third of its potential electrical 
output capacity and more than 25 MWe output to any power distribution 
system for sale.
    Utilization means the heat input (expressed in mmBtu/time) for a 
unit.
    Very low sulfur fuel means either:
    (1) A fuel with a total sulfur content no greater than 0.05 percent 
sulfur by weight;
    (2) Natural gas or pipeline natural gas, as defined in this section; 
or
    (3) Any gaseous fuel with a total sulfur content no greater than 20 
grains of sulfur per 100 standard cubic feet.
    Volumetric flow means the rate of movement of a specified volume of 
gas past a cross-sectional area (e.g., cubic feet per hour).
    Zero air material means either:
    (1) A calibration gas certified by the gas vendor not to contain 
concentrations of SO2, NOX, or total hydrocarbons 
above 0.1 parts per million (ppm), a concentration of CO above 1 ppm, or 
a concentration of CO2 above 400 ppm;
    (2) Ambient air conditioned and purified by a CEMS for which the 
CEMS manufacturer or vendor certifies that the particular CEMS model 
produces conditioned gas that does not contain concentrations of 
SO2, NOX, or total hydrocarbons above 0.1 ppm, a 
concentration of CO above 1 ppm, or a concentration of CO2 
above 400 ppm;

[[Page 28]]

    (3) For dilution-type CEMS, conditioned and purified ambient air 
provided by a conditioning system concurrently supplying dilution air to 
the CEMS; or
    (4) A multicomponent mixture certified by the supplier of the 
mixture that the concentration of the component being zeroed is less 
than or equal to the applicable concentration specified in paragraph (1) 
of this definition, and that the mixture's other components do not 
interfere with the CEM readings.

[58 FR 3650, Jan. 11, 1993]

    Editorial Note: For Federal Register citations affecting Sec. 72.2, 
see the List of CFR Sections Affected, which appears in the Finding Aids 
section of the printed volume and at www.fdsys.gov.



Sec. 72.3  Measurements, abbreviations, and acronyms.

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

acfh--actual cubic feet per hour.
atm--atmosphere.
bbl--barrel.
Btu--British thermal unit.
 C--degree Celsius (centigrade).
CEMS--continuous emission monitoring system.
cfm--cubic feet per minute.
cm--centimeter.
dcf--dry cubic feet.
DOE--Department of Energy.
dscf--dry cubic feet at standard conditions.
dscfh--dry cubic feet per hour at standard conditions.
EIA--Energy Information Administration.
eq--equivalent.
F--degree Fahrenheit.
fps--feet per second.
gal--gallon.
hr--hour.
in--inch.
K--degree Kelvin.
kacfm--thousands of cubic feet per minute at actual conditions.
kscfh--thousands of cubic feet per hour at standard conditions.
Kwh--kilowatt hour.
lb--pounds.
m--meter.
mmBtu--million Btu.
min--minute.
mol. wt.--molecular weight.
MWe--megawatt electrical.
MWge--gross megawatt electrical.
NIST--National Institute of Standards and Technology.
ppm--parts per million.
psi--pounds per square inch.
R--degree Rankine.
RATA--relative accuracy test audit.
scf--cubic feet at standard conditions.
scfh--cubic feet per hour at standard conditions.
sec--second.
std--at standard conditions.
CO2--carbon dioxide.
NOX--nitrogen oxides.
O2--oxygen.
THC--total hydrocarbon content.
SO2--sulfur dioxide.

[58 FR 3650, Jan. 11, 1993, as amended at 64 FR 28588, May 26, 1999]



Sec. 72.4  Federal authority.

    (a) The Administrator reserves all authority under sections 
112(r)(9), 113, 114, 120, 301, 303, 304, 306, and 307(a) of the Act, 
including, but not limited to, the authority to:
    (1) Secure information needed for the purpose of developing, 
revising, or implementing, or of determining whether any person is in 
violation of, any standard, method, requirement, or prohibition of the 
Act, this part, parts 73, 74, 75, 76, 77, and 78 of this chapter;
    (2) Make inspections, conduct tests, examine records, and require an 
owner or operator of an affected unit to submit information reasonably 
required for the purpose of developing, revising, or implementing, or of 
determining whether any person is in violation of, any standard, method, 
requirement, or prohibition of the Act, this part, parts 73, 74, 75, 76, 
77, and 78 of this chapter.
    (3) Issue orders, call witnesses, and compel the production of 
documents.
    (b) The Administrator reserves the right under title IV of the Act 
to take any action necessary to protect the orderly and competitive 
functioning of the allowance system, including actions to prevent fraud 
and misrepresentation.

[58 FR 3650, Jan. 11, 1993, as amended at 60 FR 17113, Apr. 4, 1995]



Sec. 72.5  State authority.

    Consistent with section 116 of the Act, the provisions of the Acid 
Rain Program shall not be construed in any manner to preclude any State 
from adopting and enforcing any other air quality requirement (including 
any continuous emissions monitoring) that is not less stringent than, 
and does not

[[Page 29]]

alter, any requirement applicable to an affected unit or affected source 
under the Acid Rain Program; provided that such State requirement, if 
articulated in an operating permit, is in a portion of the operating 
permit separate from the portion containing the Acid Rain Program 
requirements.



Sec. 72.6  Applicability.

    (a) Each of the following units shall be an affected unit, and any 
source that includes such a unit shall be an affected source, subject to 
the requirements of the Acid Rain Program:
    (1) A unit listed in table 1 of Sec. 73.10(a) of this chapter.
    (2) A unit that is listed in table 2 or 3 of Sec. 73.10 of this 
chapter and any other existing utility unit, except a unit under 
paragraph (b) of this section.
    (3) A utility unit, except a unit under paragraph (b) of this 
section, that:
    (i) Is a new unit; or
    (ii) Did not serve a generator with a nameplate capacity greater 
than 25 MWe on November 15, 1990 but serves such a generator after 
November 15, 1990.
    (iii) Was a simple combustion turbine on November 15, 1990 but adds 
or uses auxiliary firing after November 15, 1990;
    (iv) Was an exempt cogeneration facility under paragraph (b)(4) of 
this section but during any three calendar year period after November 
15, 1990 sold, to a utility power distribution system, an annual average 
of more than one-third of its potential electrical output capacity and 
more than 219,000 MWe-hrs electric output, on a gross basis;
    (v) Was an exempt qualifying facility under paragraph (b)(5) of this 
section but, at any time after the later of November 15, 1990 or the 
date the facility commences commercial operation, fails to meet the 
definition of qualifying facility;
    (vi) Was an exempt IPP under paragraph (b)(6) of this section but, 
at any time after the later of November 15, 1990 or the date the 
facility commences commercial operation, fails to meet the definition of 
independent power production facility; or
    (vii) Was an exempt solid waste incinerator under paragraph (b)(7) 
of this section but during any three calendar year period after November 
15, 1990 consumes 20 percent or more (on a Btu basis) fossil fuel.
    (b) The following types of units are not affected units subject to 
the requirements of the Acid Rain Program:
    (1) A simple combustion turbine that commenced commercial operation 
before November 15, 1990.
    (2) Any unit that commenced commercial operation before November 15, 
1990 and that did not, as of November 15, 1990, and does not currently, 
serve a generator with a nameplate capacity of greater than 25 MWe.
    (3) Any unit that, during 1985, did not serve a generator that 
produced electricity for sale and that did not, as of November 15, 1990, 
and does not currently, serve a generator that produces electricity for 
sale.
    (4) A cogeneration facility which:
    (i) For a unit that commenced construction on or prior to November 
15, 1990, was constructed for the purpose of supplying equal to or less 
than one-third its potential electrical output capacity or equal to or 
less than 219,000 MWe-hrs actual electric output on an annual basis to 
any utility power distribution system for sale (on a gross basis). If 
the purpose of construction is not known, the Administrator will presume 
that actual operation from 1985 through 1987 is consistent with such 
purpose. However, if in any three calendar year period after November 
15, 1990, such unit sells to a utility power distribution system an 
annual average of more than one-third of its potential electrical output 
capacity and more than 219,000 MWe-hrs actual electric output (on a 
gross basis), that unit shall be an affected unit, subject to the 
requirements of the Acid Rain Program; or
    (ii) For units which commenced construction after November 15, 1990, 
supplies equal to or less than one-third its potential electrical output 
capacity or equal to or less than 219,000 MWe-hrs actual electric output 
on an annual basis to any utility power distribution system for sale (on 
a gross basis). However, if in any three calendar year period after 
November 15, 1990, such unit sells to a utility power distribution 
system an annual average of more than

[[Page 30]]

one-third of its potential electrical output capacity and more than 
219,000 MWe-hrs actual electric output (on a gross basis), that unit 
shall be an affected unit, subject to the requirements of the Acid Rain 
Program.
    (5) A qualifying facility that:
    (i) Has, as of November 15, 1990, one or more qualifying power 
purchase commitments to sell at least 15 percent of its total planned 
net output capacity; and
    (ii) Consists of one or more units designated by the owner or 
operator with total installed net output capacity not exceeding 130 
percent of the total planned net output capacity. If the emissions rates 
of the units are not the same, the Administrator may exercise discretion 
to designate which units are exempt.
    (6) An independent power production facility that:
    (i) Has, as of November 15, 1990, one or more qualifying power 
purchase commitments to sell at least 15 percent of its total planned 
net output capacity; and
    (ii) Consists of one or more units designated by the owner or 
operator with total installed net output capacity not exceeding 130 
percent of its total planned net output capacity. If the emissions rates 
of the units are not the same, the Administrator may exercise discretion 
to designate which units are exempt.
    (7) A solid waste incinerator, if more than 80 percent (on a Btu 
basis) of the annual fuel consumed at such incinerator is other than 
fossil fuels. For solid waste incinerators which began operation before 
January 1, 1985, the average annual fuel consumption of non-fossil fuels 
for calendar years 1985 through 1987 must be greater than 80 percent for 
such an incinerator to be exempt. For solid waste incinerators which 
began operation after January 1, 1985, the average annual fuel 
consumption of non-fossil fuels for the first three years of operation 
must be greater than 80 percent for such an incinerator to be exempt. 
If, during any three calendar year period after November 15, 1990, such 
incinerator consumes 20 percent or more (on a Btu basis) fossil fuel, 
such incinerator will be an affected source under the Acid Rain Program.
    (8) A non-utility unit.
    (9) A unit for which an exemption under Sec. 72.7 or Sec. 72.8 is 
in effect. Although such a unit is not an affected unit, the unit shall 
be subject to the requirements of Sec. 72.7 or Sec. 72.8, as 
applicable to the exemption.
    (c) A certifying official of an owner or operator of any unit may 
petition the Administrator for a determination of applicability under 
this section.
    (1) Petition Content. The petition shall be in writing and include 
identification of the unit and relevant facts about the unit. In the 
petition, the certifying official shall certify, by his or her 
signature, the statement set forth at Sec. 72.21(b)(2). Within 10 
business days of receipt of any written determination by the 
Administrator covering the unit, the certifying official shall provide 
each owner or operator of the unit, facility, or source with a copy of 
the petition and a copy of the Administrator's response.
    (2) Timing. The petition may be submitted to the Administrator at 
any time but, if possible, should be submitted prior to the issuance 
(including renewal) of a Phase II Acid Rain permit for the unit.
    (3) Submission. All submittals under this section shall be made by 
the certifying official to the Director, Acid Rain Division, (6204J), 
1200 Pennsylvania Ave., NW., Washington, DC 20460.
    (4) Response. The Administrator will issue a written response based 
upon the factual submittal meeting the requirements of paragraph (c)(1) 
of this section.
    (5) Administrative appeals. The Administrator's determination of 
applicability is a decision appealable under 40 CFR part 78 of this 
chapter.
    (6) Effect of determination. The Administrator's determination of 
applicability shall be binding upon the permitting authority, unless the 
petition is found to have contained significant errors or omissions.

[58 FR 3650, Jan. 11, 1993, as amended at 58 FR 15648, Mar. 23, 1993; 62 
FR 55475, Oct. 24, 1997; 64 FR 28588, May 26, 1999; 66 FR 12978, Mar. 1, 
2001]

[[Page 31]]



Sec. 72.7  New units exemption.

    (a) Applicability. This section applies to any new utility unit that 
has not previously lost an exemption under paragraph (f)(4) of this 
section and that, in each year starting with the first year for which 
the unit is to be exempt under this section:
    (1) Serves during the entire year (except for any period before the 
unit commenced commercial operation) one or more generators with total 
nameplate capacity of 25 MWe or less;
    (2) Burns fuel that does not include any coal or coal-derived fuel 
(except coal-derived gaseous fuel with a total sulfur content no greater 
than natural gas); and
    (3) Burns gaseous fuel with an annual average sulfur content of 0.05 
percent or less by weight (as determined under paragraph (d) of this 
section) and nongaseous fuel with an annual average sulfur content of 
0.05 percent or less by weight (as determined under paragraph (d) of 
this section).
    (b)(1) Any new utility unit that meets the requirements of paragraph 
(a) of this section and that is not allocated any allowances under 
subpart B of part 73 of this chapter shall be exempt from the Acid Rain 
Program, except for the provisions of this section, Sec. Sec. 72.2 
through 72.6, and Sec. Sec. 72.10 through 72.13.
    (2) The exemption under paragraph (b)(1) of this section shall be 
effective on January 1 of the first full calendar year for which the 
unit meets the requirements of paragraph (a) of this section. By 
December 31 of the first year for which the unit is to be exempt under 
this section, a statement signed by the designated representative 
(authorized in accordance with subpart B of this part) or, if no 
designated representative has been authorized, a certifying official of 
each owner of the unit shall be submitted to permitting authority 
otherwise responsible for administering a Phase II Acid Rain permit for 
the unit. If the Administrator is not the permitting authority, a copy 
of the statement shall be submitted to the Administrator. The statement, 
which shall be in a format prescribed by the Administrator, shall 
identify the unit, state the nameplate capacity of each generator served 
by the unit and the fuels currently burned or expected to be burned by 
the unit and their sulfur content by weight, and state that the owners 
and operators of the unit will comply with paragraph (f) of this 
section.
    (3) After receipt of the statement under paragraph (b)(2) of this 
section, the permitting authority shall amend under Sec. 72.83 the 
operating permit covering the source at which the unit is located, if 
the source has such a permit, to add the provisions and requirements of 
the exemption under paragraphs (a), (b)(1), (d), and (f) of this 
section.
    (c)(1) Any new utility unit that meets the requirements of paragraph 
(a) of this section and that is allocated one or more allowances under 
subpart B of part 73 of this chapter shall be exempt from the Acid Rain 
Program, except for the provisions of this section, Sec. Sec. 72.2 
through 72.6, and Sec. Sec. 72.10 through 72.13, if each of the 
following requirements are met:
    (i) The designated representative (authorized in accordance with 
subpart B of this part) or, if no designated representative has been 
authorized, a certifying official of each owner of the unit submits to 
the permitting authority otherwise responsible for administering a Phase 
II Acid Rain permit for the unit a statement (in a format prescribed by 
the Administrator) that:
    (A) Identifies the unit and states the nameplate capacity of each 
generator served by the unit and the fuels currently burned or expected 
to be burned by the unit and their sulfur content by weight;
    (B) States that the owners and operators of the unit will comply 
with paragraph (f) of this section;
    (C) Surrenders allowances equal in number to, and with the same or 
earlier compliance use date as, all of those allocated to the unit under 
subpart B of part 73 of this chapter for the first year that the unit is 
to be exempt under this section and for each subsequent year; and
    (D) Surrenders any proceeds for allowances under paragraph 
(c)(1)(i)(C) or this section withheld from the unit

[[Page 32]]

under Sec. 73.10 of this chapter. If the Administrator is not the 
permitting authority, a copy of the statement shall be submitted to the 
Administrator.
    (ii) The Administrator deducts from the compliance account of the 
source that includes the unit allowances under paragraph (c)(1)(i)(C) of 
this section and receives proceeds under paragraph (c)(1)(i)(D) of this 
section. Within 5 business days of receiving a statement in accordance 
with paragraph (c)(1)(i) of this section, the Administrator shall either 
deduct the allowances under paragraph (c)(1)(i)(C) of this section or 
notify the owners and operators that there are insufficient allowances 
to make such deductions.
    (2) The exemption under paragraph (c)(1) of this section shall be 
effective on January 1 of the first full calendar year for which the 
requirements of paragraphs (a) and (c)(1) of this section are met. After 
notification by the Administrator under the third sentence of paragraph 
(c)(1)(ii) of this section, the permitting authority shall amend under 
Sec. 72.83 the operating permit covering the source at which the unit 
is located, if the source has such a permit, to add the provisions and 
requirements of the exemption under paragraphs (a), (c)(1), (d), and (f) 
of this section.
    (d) Compliance with the requirement that fuel burned during the year 
have an annual average sulfur content of 0.05 percent by weight or less 
shall be determined as follows using a method of determining sulfur 
content that provides information with reasonable precision, 
reliability, accessibility, and timeliness:
    (1) For gaseous fuel burned during the year, if natural gas is the 
only gaseous fuel burned, the requirement is assumed to be met;
    (2) For gaseous fuel burned during the year where other gas in 
addition to or besides natural gas is burned, the requirement is met if 
the annual average sulfur content is equal to or less than 0.05 percent 
by weight. The annual average sulfur content, as a percentage by weight, 
for the gaseous fuel burned shall be calculated as follows:
[GRAPHIC] [TIFF OMITTED] TR24OC97.001

where:

%Sannual = annual average sulfur content of the fuel burned 
          during the year by the unit, as a percentage by weight;
%Sn = sulfur content of the nth sample of the fuel delivered 
          during the year to the unit, as a percentage by weight;
Vn = volume of the fuel in a delivery during the year to the 
          unit of which the nth sample is taken, in standard cubic feet; 
          or, for fuel delivered during the year to the unit 
          continuously by pipeline, volume of the fuel delivered 
          starting from when the nth sample of such fuel is taken until 
          the next sample of such fuel is taken, in standard cubic feet;
dn = density of the nth sample of the fuel delivered during 
          the year to the unit, in lb per standard cubic foot; and
n = each sample taken of the fuel delivered during the year to the unit, 
          taken at least once for each delivery; or, for fuel that is 
          delivered during the year to the unit continuously by 
          pipeline, at least once each quarter during which the fuel is 
          delivered.

    (3) For nongaseous fuel burned during the year, the requirement is 
met if the annual average sulfur content is equal to or less than 0.05 
percent by weight. The annual average sulfur content, as a percentage by 
weight, shall be calculated using the equation in paragraph (d)(2) of 
this section. In lieu of the factor, volume times density (Vn 
dn), in the equation, the factor, mass (Mn), may 
be used, where Mn is: mass of the nongaseous fuel in a 
delivery during the year to the unit of which the nth sample is taken, 
in lb; or, for fuel delivered during the year to the unit continuously 
by pipeline, mass of the nongaseous fuel delivered starting from when 
the nth sample of such fuel is taken until the next sample of such fuel 
is taken, in lb.
    (e)(1) A utility unit that was issued a written exemption under this 
section and that meets the requirements of paragraph (a) of this section 
shall be exempt from the Acid Rain Program, except for the provisions of 
this section, Sec. Sec. 72.2 through 72.6, and Sec. Sec. 72.10 through 
72.13 and shall be subject to the requirements of paragraphs (a), (d),

[[Page 33]]

(e)(2), and (f) of this section in lieu of the requirements set forth in 
the written exemption. The permitting authority shall amend under Sec. 
72.83 the operating permit covering the source at which the unit is 
located, if the source has such a permit, to add the provisions and 
requirements of the exemption under this paragraph (e)(1) and paragraphs 
(a), (d), (e)(2), and (f) of this section.
    (2) If a utility unit under paragraph (e)(1) of this section is 
allocated one or more allowances under subpart B of part 73 of this 
chapter, the designated representative (authorized in accordance with 
subpart B of this part) or, if no designated representative has been 
authorized, a certifying official of each owner of the unit shall submit 
to the permitting authority that issued the written exemption a 
statement (in a format prescribed by the Administrator) meeting the 
requirements of paragraph (c)(1)(i)(C) and (D) of this section. The 
statement shall be submitted by June 31, 1998 and, if the Administrator 
is not the permitting authority, a copy shall be submitted to the 
Administrator.
    (f) Special Provisions. (1) The owners and operators and, to the 
extent applicable, the designated representative of a unit exempt under 
this section shall:
    (i) Comply with the requirements of paragraph (a) of this section 
for all periods for which the unit is exempt under this section; and
    (ii) Comply with the requirements of the Acid Rain 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.
    (2) For any period for which a unit is exempt under this section:
    (i) For purposes of applying parts 70 and 71 of this chapter, the 
unit shall not be treated as an affected unit under the Acid Rain 
Program and shall continue to be subject to any other applicable 
requirements under parts 70 and 71 of this chapter.
    (ii) The unit shall not be eligible to be an opt-in source under 
part 74 of chapter.
    (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 requirements of paragraph (a) of this section are met. 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 Administrator or the 
permitting authority.
    (i) Such records shall include, for each delivery of fuel to the 
unit or for fuel delivered to the unit continuously by pipeline, the 
type of fuel, the sulfur content, and the sulfur content of each sample 
taken.
    (ii) The owners and operators bear the burden of proof that the 
requirements of paragraph (a) of this section are met.
    (4) Loss of exemption. (i) On the earliest of the following dates, a 
unit exempt under paragraphs (b), (c), or (e) of this section shall lose 
its exemption and for purposes of applying parts 70 and 71 of this 
chapter, shall be treated as an affected unit under the Acid Rain 
Program:
    (A) The date on which the unit first serves one or more generators 
with total nameplate capacity in excess of 25 MWe;
    (B) The date on which the unit burns any coal or coal-derived fuel 
except for coal-derived gaseous fuel with a total sulfur content no 
greater than natural gas; or
    (C) January 1 of the year following the year in which the annual 
average sulfur content for gaseous fuel burned at the unit exceeds 0.05 
percent by weight (as determined under paragraph (d) of this section) or 
for nongaseous fuel burned at the unit exceeds 0.05 percent by weight 
(as determined under paragraph (d) of this section).
    (ii) Notwithstanding Sec. 72.30(b) and (c), the designated 
representative for a unit that loses its exemption under this section 
shall submit a complete Acid Rain permit application on the later of 
January 1, 1998 or 60 days after the first date on which the unit is no 
longer exempt.
    (iii) For the purpose of applying monitoring requirements under part 
75 of this chapter, a unit that loses its exemption under this section 
shall be treated as a new unit that commenced

[[Page 34]]

commercial operation on the first date on which the unit is no longer 
exempt.

[62 FR 55476, Oct. 24, 1997, as amended at 71 FR 25377, Apr. 28, 2006; 
70 FR 25334, May 12, 2005]



Sec. 72.8  Retired units exemption.

    (a) This section applies to any affected unit (except for an opt-in 
source) that is permanently retired.
    (b)(1) Any affected unit (except for an opt-in source) that is 
permanently retired shall be exempt from the Acid Rain Program, except 
for the provisions of this section, Sec. Sec. 72.2 through 72.6, 
Sec. Sec. 72.10 through 72.13, and subpart B of part 73 of this 
chapter.
    (2) The exemption under paragraph (b)(1) of this section shall 
become effective on January 1 of the first full calendar year during 
which the unit is permanently retired. By December 31 of the first year 
that the unit is to be exempt under this section, the designated 
representative (authorized in accordance with subpart B of this part), 
or, if no designated representative has been authorized, a certifying 
official of each owner of the unit shall submit a statement to the 
permitting authority otherwise responsible for administering a Phase II 
Acid Rain permit for the unit. If the Administrator is not the 
permitting authority, a copy of the statement shall be submitted to the 
Administrator. The statement shall state (in a format prescribed by the 
Administrator) that the unit is permanently retired and will comply with 
the requirements of paragraph (d) of this section.
    (3) After receipt of the notice under paragraph (b)(2) of this 
section, the permitting authority shall amend under Sec. 72.83 the 
operating permit covering the source at which the unit is located, if 
the source has such a permit, to add the provisions and requirements of 
the exemption under paragraphs (b)(1) and (d) of this section.
    (c) A unit that was issued a written exemption under this section 
and that is permanently retired shall be exempt from the Acid Rain 
Program, except for the provisions of this section, Sec. Sec. 72.2 
through 72.6, Sec. Sec. 72.10 through 72.13, and subpart B of part 73 
of this chapter, and shall be subject to the requirements of paragraph 
(d) of this section in lieu of the requirements set forth in the written 
exemption. The permitting authority shall amend under Sec. 72.83 the 
operating permit covering the source at which the unit is located, if 
the source has such a permit, to add the provisions and requirements of 
the exemption under this paragraph (c) and paragraph (d) of this 
section.
    (d) Special Provisions. (1) A unit exempt under this section shall 
not emit any sulfur dioxide and 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 B of part 73 of 
this chapter. If the unit is a Phase I unit, for each calendar year in 
Phase I, the designated representative of the unit shall submit a Phase 
I permit application in accordance with subparts C and D of this part 72 
and an annual certification report in accordance with Sec. Sec. 72.90 
through 72.92 and is subject to Sec. Sec. 72.95 and 72.96.
    (2) A unit exempt under this section shall not resume operation 
unless the designated representative of the source that includes the 
unit submits a complete Acid Rain permit application under Sec. 72.31 
for the unit not less than 24 months prior to the later of January 1, 
2000 or the date on which the unit is first to resume operation.
    (3) The owners and operators and, to the extent applicable, the 
designated representative of a unit exempt under this section shall 
comply with the requirements of the Acid Rain 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) For any period for which a unit is exempt under this section:
    (i) For purposes of applying parts 70 and 71 of this chapter, the 
unit shall not be treated as an affected unit under the Acid Rain 
Program and shall continue to be subject to any other applicable 
requirements under parts 70 and 71 of this chapter.
    (ii) The unit shall not be eligible to be an opt-in source under 
part 74 of chapter.
    (5) For a period of 5 years from the date the records are created, 
the owners and operators of a unit exempt

[[Page 35]]

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 Administrator or the 
permitting authority. 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) or (c) of this section shall lose its 
exemption and for purposes of applying parts 70 and 71 of this chapter, 
shall be treated as an affected unit under the Acid Rain Program:
    (A) The date on which the designated representative submits an Acid 
Rain permit application under paragraph (d)(2) of this section; or
    (B) The date on which the designated representative is required 
under paragraph (d)(2) of this section to submit an Acid Rain permit 
application.
    (ii) For the purpose of applying monitoring requirements under part 
75 of this chapter, a unit that loses its exemption under this section 
shall be treated as a new unit that commenced commercial operation on 
the first date on which the unit resumes operation.

[62 FR 55477, Oct. 24, 1997; 62 FR 66279, Dec. 18, 1997, as amended at 
71 FR 25377, Apr. 28, 2006]



Sec. 72.9  Standard requirements.

    (a) Permit Requirements. (1) The designated representative of each 
affected source and each affected unit at the source shall:
    (i) Submit a complete Acid Rain permit application (including a 
compliance plan) under this part in accordance with the deadlines 
specified in Sec. 72.30;
    (ii) Submit in a timely manner a complete reduced utilization plan 
if required under Sec. 72.43; and
    (iii) Submit in a timely manner any supplemental information that 
the permitting authority determines is necessary in order to review an 
Acid Rain permit application and issue or deny an Acid Rain permit.
    (2) The owners and operators of each affected source and each 
affected unit at the source shall:
    (i) Operate the unit in compliance with a complete Acid Rain permit 
application or a superseding Acid Rain permit issued by the permitting 
authority; and
    (ii) Have an Acid Rain Permit.
    (b) Monitoring Requirements. (1) The owners and operators and, to 
the extent applicable, designated representative of each affected source 
and each affected unit at the source shall comply with the monitoring 
requirements as provided in part 75 of this chapter.
    (2) The emissions measurements recorded and reported in accordance 
with part 75 of this chapter shall be used to determine compliance by 
the source or unit, as appropriate, with the Acid Rain emissions 
limitations and emissions reduction requirements for sulfur dioxide and 
nitrogen oxides under the Acid Rain Program.
    (3) The requirements of part 75 of this chapter shall not affect the 
responsibility of the owners and operators to monitor emissions of other 
pollutants or other emissions characteristics at the unit under other 
applicable requirements of the Act and other provisions of the operating 
permit for the source.
    (c) Sulfur Dioxide Requirements. (1) The owners and operators of 
each source and each affected unit at the source shall:
    (i) Hold allowances, as of the allowance transfer deadline, in the 
source's compliance account (after deductions under Sec. 73.34(c) of 
this chapter) not less than the total annual emissions of sulfur dioxide 
for the previous calendar year from the affected units at the source; 
and
    (ii) Comply with the applicable Acid Rain emissions limitation for 
sulfur dioxide.
    (2) Each ton of sulfur dioxide emitted in excess of the Acid Rain 
emissions limitations for sulfur dioxide shall constitute a separate 
violation of the Act.
    (3) An affected unit shall be subject to the requirements under 
paragraph (c)(1) of this section as follows:
    (i) Starting January 1, 1995, an affected unit under Sec. 
72.6(a)(1);

[[Page 36]]

    (ii) Starting on or after January 1, 1995 in accordance with 
Sec. Sec. 72.41 and 72.43, an affected unit under Sec. 72.6(a) (2) or 
(3) that is a substitution or compensating unit;
    (iii) Starting January 1, 2000, an affected unit under Sec. 
72.6(a)(2) that is not a substitution or compensating unit; or
    (iv) Starting on the later of January 1, 2000 or the deadline for 
monitor certification under part 75 of this chapter, an affected unit 
under Sec. 72.6(a)(3) that is not a substitution or compensating unit.
    (4) Allowances shall be held in, deducted from, or transferred among 
Allowance Tracking System accounts in accordance with the Acid Rain 
Program.
    (5) An allowance shall not be deducted, in order to comply with the 
requirements under paragraph (c)(1)(i) of this section, prior to the 
calendar year for which the allowance was allocated.
    (6) An allowance allocated by the Administrator under the Acid Rain 
Program is a limited authorization to emit sulfur dioxide in accordance 
with the Acid Rain Program. No provision of the Acid Rain Program, the 
Acid Rain permit application, the Acid Rain permit, or an exemption 
under Sec. Sec. 72.7 or 72.8 and no provision of law shall be construed 
to limit the authority of the United States to terminate or limit such 
authorization.
    (7) An allowance allocated by the Administrator under the Acid Rain 
Program does not constitute a property right.
    (d) Nitrogen Oxides Requirements. The owners and operators of the 
source and each affected unit at the source shall comply with the 
applicable Acid Rain emissions limitation for nitrogen oxides.
    (e) Excess Emissions Requirements. (1) The designated representative 
of an affected source that has excess emissions in any calendar year 
shall submit a proposed offset plan, as required under part 77 of this 
chapter.
    (2) The owners and operators of an affected source that has excess 
emissions in any calendar year shall:
    (i) Pay without demand the penalty required, and pay upon demand the 
interest on that penalty, as required by part 77 of this chapter; and
    (ii) Comply with the terms of an approved offset plan, as required 
by part 77 of this chapter.
    (f) Recordkeeping and Reporting Requirements. (1) Unless otherwise 
provided, the owners and operators of the source and each affected 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 Administrator or permitting authority.
    (i) The certificate of representation for the designated 
representative for the source and each affected unit at the source and 
all documents that demonstrate the truth of the statements in the 
certificate of representation, in accordance with Sec. 72.24; 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 
changing the designated representative.
    (ii) All emissions monitoring information, in accordance with part 
75 of this chapter; provided that to the extent that part 75 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 Acid Rain 
Program.
    (iv) Copies of all documents used to complete an Acid Rain permit 
application and any other submission under the Acid Rain Program or to 
demonstrate compliance with the requirements of the Acid Rain Program.
    (2) The designated representative of an affected source and each 
affected unit at the source shall submit the reports and compliance 
certifications required under the Acid Rain Program, including those 
under subpart I of this part and part 75 of this chapter.
    (g) Liability. (1) Any person who knowingly violates any requirement 
or prohibition of the Acid Rain Program, a complete Acid Rain permit 
application, an Acid Rain permit, or an exemption under Sec. 72.7 or 
Sec. 72.8, including any requirement for the payment of any penalty 
owed to the United States,

[[Page 37]]

shall be subject to enforcement pursuant to section 113(c) of the Act.
    (2) Any person who knowingly makes a false, material statement in 
any record, submission, or report under the Acid Rain Program shall be 
subject to criminal enforcement pursuant to section 113(c) of the Act 
and 18 U.S.C. 1001.
    (3) No permit revision shall excuse any violation of the 
requirements of the Acid Rain Program that occurs prior to the date that 
the revision takes effect.
    (4) Each affected source and each affected unit shall meet the 
requirements of the Acid Rain Program.
    (5) Any provision of the Acid Rain Program that applies to an 
affected source (including a provision applicable to the designated 
representative of an affected source) shall also apply to the owners and 
operators of such source and of the affected units at the source.
    (6) Any provision of the Acid Rain Program that applies to an 
affected unit (including a provision applicable to the designated 
representative of an affected unit) shall also apply to the owners and 
operators of such unit.
    (7) Each violation of a provision of this part, parts 73, 74, 75, 
76, 77, and 78 of this chapter, by an affected source or affected unit, 
or by an owner or operator or designated representative of such source 
or unit, shall be a separate violation of the Act.
    (h) Effect on Other Authorities. No provision of the Acid Rain 
Program, an Acid Rain permit application, an Acid Rain permit, or an 
exemption under Sec. 72.7 or Sec. 72.8 shall be construed as:
    (1) Except as expressly provided in title IV of the Act, exempting 
or excluding the owners and operators and, to the extent applicable, the 
designated representative of an affected source or affected unit from 
compliance with any other provision of the Act, including the provisions 
of title I of the Act relating to applicable National Ambient Air 
Quality Standards or State Implementation Plans.
    (2) Limiting the number of allowances a source can hold; provided, 
that the number of allowances held by the source shall not affect the 
source's obligation to comply with any other provisions of the Act.
    (3) Requiring a change of any kind in any State law regulating 
electric utility rates and charges, affecting any State law regarding 
such State regulation, or limiting such State regulation, including any 
prudence review requirements under such State law.
    (4) Modifying the Federal Power Act or affecting the authority of 
the Federal Energy Regulatory Commission under the Federal Power Act.
    (5) Interfering with or impairing any program for competitive 
bidding for power supply in a State in which such program is 
established.

[58 FR 3650, Jan. 11, 1993, as amended at 60 FR 17113, Apr. 4, 1995; 62 
FR 55478, Oct. 24, 1997; 66 FR 12978, Mar. 1, 2001; 70 FR 25334, May 12, 
2005]



Sec. 72.10  Availability of information.

    The availability to the public of information provided to, or 
otherwise obtained by, the Administrator under the Acid Rain Program 
shall be governed by part 2 of this chapter.



Sec. 72.11  Computation of time.

    (a) Unless otherwise stated, any time period scheduled, under the 
Acid Rain 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 
Acid Rain Program, to begin before the occurrence of an act or event 
shall be computed so that the period ends on the day before the act or 
event occurs.
    (c) Unless otherwise stated, if the final day of any time period, 
under the Acid Rain Program, falls on a weekend or a Federal holiday, 
the time period shall be extended to the next business day.
    (d) Whenever a party or interested person has the right, or is 
required, to act under the Acid Rain Program within a prescribed time 
period after service of notice or other document upon him or her by 
mail, 3 days shall be added to the prescribed time.



Sec. 72.12  Administrative appeals.

    The procedures for appeals of decisions of the Administrator under 
this part are contained in part 78 of this chapter.

[[Page 38]]



Sec. 72.13  Incorporation by reference.

    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 the Federal Register in accordance with 
5 U.S.C. 552(a) and 1 CFR part 51. These materials are incorporated as 
they existed on the date of approval, and a notice of any change in 
these materials will be published in the Federal Register. The materials 
are available for purchase at the corresponding address noted below and 
are available for inspection at the Public Information Reference Unit of 
the U.S. EPA, 401 M St., SW., Washington, DC and at the Library (MD-35), 
U.S. EPA, Research Triangle Park, North Carolina or 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) The following materials are available for purchase from the 
following address: American Society for Testing and Material (ASTM) 
International, 100 Barr Harbor Drive, P.O. Box C700, West Conshohocken, 
Pennsylvania 19428-2959, phone: 610-832-9585, http://www.astm.org/
DIGITAL--LIBRARY/index.shtml.
    (1) ASTM D388-92, Standard Classification of Coals by Rank for Sec. 
72.2 of this chapter.
    (2) ASTM D396-90a, Standard Specification for Fuel Oils, for Sec. 
72.2 of this chapter.
    (3) ASTM D975-91, Standard Specification for Diesel Fuel Oils, for 
Sec. 72.2 of this chapter.
    (4) ASTM D2880-90a, Standard Specification for Gas Turbine Fuel 
Oils, for Sec. 72.2 of this part.
    (5) ASTM D 7036-04, Standard Practice for Competence of Air Emission 
Testing Bodies, for Sec. 72.2.
    (b) A copy of the following material is available from http://
www.epa.gov/ttn/emc/news.html (see postings for Sections 1, 2, 3, 4, 
Appendices, Spreadsheets, and the ``Read before downloading Section 2'' 
revision posted August 27, 1999): EPA-600/R-97/121, EPA Traceability 
Protocol for Assay and Certification of Gaseous Calibration Standards, 
September 1997, as amended August 25, 1999, U.S. Environmental 
Protection Agency, for Sec. 72.2.

[58 FR 3650, Jan. 11, 1993, as amended at 60 FR 26526, May 17, 1995; 62 
FR 55478, Oct. 24, 1997; 76 FR 17306, Mar. 28, 2011]



                   Subpart B_Designated Representative



Sec. 72.20  Authorization and responsibilities of the designated 
representative.

    (a) Except as provided under Sec. 72.22, each affected source, 
including all affected units at the source, shall have one and only one 
designated representative, with regard to all matters under the Acid 
Rain Program concerning the source or any affected unit at the source.
    (b) Upon receipt by the Administrator of a complete certificate of 
representation, the 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 affected source 
represented and each affected unit at the source in all matters 
pertaining to the Acid Rain Program, not withstanding any agreement 
between the designated representative and such owners and operators. The 
owners and operators shall be bound by any order issued to the 
designated representative by the Administrator, the permitting 
authority, or a court.
    (c) The designated representative shall be selected and act in 
accordance with the certifications set forth in Sec. 72.24(a) (4), (5), 
(7), and (9).
    (d) No Acid Rain permit shall be issued to an affected source, nor 
shall any allowance transfer be recorded for an Allowance Tracking 
System account of an affected unit at a source, until the Administrator 
has received a complete certificate of representation for the designated 
representative of the source and the affected units at the source.

[58 FR 3650, Jan. 11, 1993, as amended at 71 FR 25378, Apr. 28, 2006]

[[Page 39]]



Sec. 72.21  Submissions.

    (a) Each submission under the Acid Rain Program shall be submitted, 
signed, and certified by the designated representative for all sources 
on behalf of which the submission is made.
    (b) In each submission under the Acid Rain Program, the designated 
representative shall certify, by his or her signature:
    (1) The following statement, which shall be included verbatim in 
such submission: ``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.''
    (2) The following statement, which shall be included verbatim in 
such submission: ``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.''
    (c) The Administrator and the permitting authority shall accept or 
act on a submission made on behalf of owners or operators of an affected 
source and an affected unit only if the submission has been made, 
signed, and certified in accordance with paragraphs (a) and (b) of this 
section.
    (d)(1) The designated representative of a source shall serve notice 
on each owner and operator of the source and of an affected unit at the 
source:
    (i) By the date of submission, of any Acid Rain Program submissions 
by the designated representative and
    (ii) Within 10 business days of receipt of a determination, of any 
written determination by the Administrator or the permitting authority,
    (iii) Provided that the submission or determination covers the 
source or the unit.
    (2) The designated representative of a source shall provide each 
owner and operator of an affected unit at the source a copy of any 
submission or determination under paragraph (d)(1) of this section, 
unless the owner or operator expressly waives the right to receive such 
a copy.
    (e) The provisions of this section shall apply to a submission made 
under parts 73, 74, 75, 76, 77, and 78 of this chapter only if it is 
made or signed or required to be made or signed, in accordance with 
parts 73, 74, 75, 76, 77, and 78 of this chapter, by:
    (1) The designated representative; or
    (2) The authorized account representative or alternate authorized 
account representative of a compliance account.

[58 FR 3650, Jan. 11, 1993, as amended at 60 FR 17113, Apr. 4, 1995; 70 
FR 25334, May 12, 2005]



Sec. 72.22  Alternate designated representative.

    (a) The certificate of representation may designate 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 the 
owners and operators of the source and affected units at the source to 
authorize the alternate designated representative to act in lieu of the 
designated representative.
    (b) Upon receipt by the Administrator of a complete certificate of 
representation that meets the requirements of Sec. 72.24 (including 
those applicable to the alternate designated representative), any 
representation, action, inaction, or submission by the alternate 
designated representative shall be deemed to be an action, 
representation, or failure to act by the designated representative.
    (c) In the event of a conflict, any action taken by the designated 
representative shall take precedence over any action taken by the 
alternate designated representative if, in the Administrator's 
judgement, the actions are concurrent and conflicting.
    (d) Except in this section, Sec. 72.23, and Sec. 72.24, whenever 
the term ``designated representative'' is used under the Acid Rain 
Program, the term shall be construed to include the alternate designated 
representative.

[[Page 40]]

    (e)(1) Notwithstanding paragraph (a) of this section, the 
certification of representation may designate two alternate designated 
representatives for a unit if:
    (i) The unit and at least one other unit, which are located in two 
or more of the contiguous 48 States or the District of Columbia, each 
have a utility system that is a subsidiary of the same company; and
    (ii) The designated representative for the units under paragraph 
(e)(1)(i) of this section submits a NOX averaging plan under 
Sec. 76.11 of this chapter that covers such units and is approved by 
the permitting authority, provided that the approved plan remains in 
effect.
    (2) Except in this paragraph (e), whenever the term ``alternate 
designated representative'' is used under the Acid Rain Program, the 
term shall be construed to include either of the alternate designated 
representatives authorized under this paragraph (e). Except in this 
section, Sec. 72.23, and Sec. 72.24, whenever the term ``designated 
representative'' is used under the Acid Rain Program, the term shall be 
construed to include either of the alternate designated representatives 
authorized under this paragraph (e).

[58 FR 3650, Jan. 11, 1993, as amended at 62 FR 55480, Oct. 24, 1997; 71 
FR 25378, Apr. 28, 2006]



Sec. 72.23  Changing the designated representative, alternate
designated representative; changes in the owners and operators.

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

[58 FR 3650, Jan. 11, 1993, as amended at 71 FR 25378, Apr. 28, 2006]



Sec. 72.24  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 affected source and each affected 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.

[[Page 41]]

    (2) The name, address, and telephone and facsimile numbers of the 
designated representative and any alternate designated representative.
    (3) A list of the owners and operators of the affected source and of 
each affected unit at the source.
    (4) The following statement: ``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 
affected source and each affected unit at the source.''
    (5) [Reserved]
    (6) The following statement: ``I certify that I have all necessary 
authority to carry out my duties and responsibilities under the Acid 
Rain Program on behalf of the owners and operators of the affected 
source and of each affected unit at the source and that each such owner 
and operator shall be fully bound by my representations, actions, 
inactions, or submissions.''
    (7) [Reserved]
    (8) The following statement: ``I certify that the owners and 
operators of the affected source and of each affected 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.''
    (9) The following statement: ``Where there are multiple holders of a 
legal or equitable title to, or a leasehold interest in, an affected 
unit, or where a utility or industrial customer purchases power from an 
affected unit under a life-of-the-unit, firm power contractual 
arrangement, I certify that:
    (i) ``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 affected source and of each affected unit at the 
source; and
    (ii) ``Allowances and proceeds of transactions involving 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 allowances by contract, that allowances and 
the proceeds of transactions involving allowances will be deemed to be 
held or distributed in accordance with the contract.''
    (10) [Reserved]
    (11) The signature of the designated representative and any 
alternate designated representative who is authorized in the certificate 
of representation and the date signed.
    (b) Unless otherwise required by the Administrator or the permitting 
authority, documents of agreement or notice referred to in the 
certificate of representation shall not be submitted to the 
Administrator or the permitting authority. Neither the Administrator nor 
the permitting authority shall be under any obligation to review or 
evaluate the sufficiency of such documents, if submitted.

[58 FR 3650, Jan. 11, 1993, as amended at 62 FR 55480, Oct. 24, 1997; 71 
FR 25378, Apr. 28, 2006; 70 FR 25334, May 12, 2005; 72 FR 59205, Oct. 
19, 2007]



Sec. 72.25  Objections.

    (a) Once a complete certificate of representation has been submitted 
in accordance with Sec. 72.24, the Administrator will rely on the 
certificate of representation unless and until a superseding complete 
certificate is received by the Administrator.
    (b) Except as provided in Sec. 72.23, no objection or other 
communication submitted to the Administrator or the permitting authority 
concerning the authorization, or any representation, action, inaction, 
or submission, of the designated representative shall affect any 
representation, action, inaction, or submission of the designated 
representative, or the finality of any decision by the Administrator or 
permitting authority, under the Acid Rain Program. In the event of such 
communication, the Administrator and the permitting authority are not 
required to stay any allowance transfer, any submission, or the effect 
of any action or inaction under the Acid Rain Program.

[[Page 42]]

    (c) Neither the Administrator nor any permitting authority will 
adjudicate any private legal dispute concerning the authorization or any 
submission, action, or inaction of any designated representative, 
including private legal disputes concerning the proceeds of allowance 
transfers.

[58 FR 3650, Jan. 11, 1993, as amended at 62 FR 55480, Oct. 24, 1997; 71 
FR 25378, Apr. 28, 2006]



Sec. 72.26  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 (in a 
format prescribed by the Administrator) to the Administrator provided 
for or required under this part and parts 73 through 77 of this chapter.
    (b) An alternate designated representative may delegate, to one or 
more natural persons, his or her authority to make an electronic 
submission (in a format prescribed by the Administrator) to the 
Administrator provided for or required under this part and parts 73 
through 77 of this chapter.
    (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 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 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, as appropriate:
    (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 designated representative or alternate designated 
representative, as appropriate, and before this notice of delegation is 
superseded by another notice of delegation under 40 CFR 72.26(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 72.26(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 72.26 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.

[71 FR 25378, Apr. 28, 2006]



                 Subpart C_Acid Rain Permit Applications



Sec. 72.30  Requirement to apply.

    (a) Duty to apply. The designated representative of any source with 
an affected unit shall submit a complete Acid Rain permit application by 
the

[[Page 43]]

applicable deadline in paragraphs (b) and (c) of this section, and the 
owners and operators of such source and any affected unit at the source 
shall not operate the source or unit without a permit that states its 
Acid Rain program requirements.
    (b) Deadlines--(1) Phase 1. (i) The designated representative shall 
submit a complete Acid Rain permit application governing an affected 
unit during Phase I to the Administrator on or before February 15, 1993 
for:
    (A) Any source with such a unit under Sec. 72.6(a)(1); and
    (B) Any source with such a unit under Sec. 72.6(a) (2) or (3) that 
is designated a substitution or compensating unit in a substitution plan 
or reduced utilization plan submitted to the Administrator for approval 
or conditional approval.
    (ii) Notwithstanding paragraph (b)(1)(i) of this section, if a unit 
at a source not previously permitted is designated a substitution or 
compensating unit in a submission requesting revision of an existing 
Acid Rain permit, the designated representative of the unit shall submit 
a complete Acid Rain permit application on the date that the submission 
requesting the revision is made.
    (2) Phase II. (i) For any source with an existing unit under Sec. 
72.6(a)(2), the designated representative shall submit a complete Acid 
Rain permit application governing such unit during Phase II to the 
permitting authority on or before January 1, 1996.
    (ii) For any source with a new unit under Sec. 72.6(a)(3)(i), the 
designated representative shall submit a complete Acid Rain permit 
application governing such unit to the permitting authority at least 24 
months before the later of January 1, 2000 or the date on which the unit 
commences operation.
    (iii) For any source with a unit under Sec. 72.6(a)(3)(ii), the 
designated representative shall submit a complete Acid Rain permit 
application governing such unit to the permitting authority at least 24 
months before the later of January 1, 2000 or the date on which the unit 
begins to serve a generator with a nameplate capacity greater than 25 
MWe.
    (iv) For any source with a unit under Sec. 72.6(a)(3)(iii), the 
designated representative shall submit a complete Acid Rain permit 
application governing such unit to the permitting authority at least 24 
months before the later of January 1, 2000 or the date on which the 
auxiliary firing commences operation.
    (v) For any source with a unit under Sec. 72.6(a)(3)(iv), the 
designated representative shall submit a complete Acid Rain permit 
application governing such unit to the permitting authority before the 
later of January 1, 1998 or March 1 of the year following the three 
calendar year period in which the unit sold to a utility power 
distribution system an annual average of more than one-third of its 
potential electrical output capacity and more than 219,000 MWe-hrs 
actual electric output (on a gross basis).
    (vi) For any source with a unit under Sec. 72.6(a)(3)(v), the 
designated representative shall submit a complete Acid Rain permit 
application governing such unit to the permitting authority before the 
later of January 1, 1998 or March 1 of the year following the calendar 
year in which the facility fails to meet the definition of qualifying 
facility.
    (vii) For any source with a unit under Sec. 72.6(a)(3)(vi), the 
designated representative shall submit a complete Acid Rain permit 
application governing such unit to the permitting authority before the 
later of January 1, 1998 or March 1 of the year following the calendar 
year in which the facility fails to meet the definition of an 
independent power production facility.
    (viii) For any source with a unit under Sec. 72.6(a)(3)(vii), the 
designated representative shall submit a complete Acid Rain permit 
application governing such unit to the permitting authority before the 
later of January 1, 1998 or March 1 of the year following the three 
calendar year period in which the incinerator consumed 20 percent or 
more fossil fuel (on a Btu basis).
    (c) Duty to reapply. The designated representative shall submit a 
complete Acid Rain permit application for each source with an affected 
unit at least 6 months prior to the expiration of an existing Acid Rain 
permit governing

[[Page 44]]

the unit during Phase II or an opt-in permit governing an opt-in source 
or such longer time as may be approved under part 70 of this chapter 
that ensures that the term of the existing permit will not expire before 
the effective date of the permit for which the application is submitted.
    (d) The original and three copies of all permit applications for 
Phase I and where the Administrator is the permitting authority, for 
Phase II, shall be submitted to the EPA Regional Office for the Region 
where the affected source is located. The original and three copies of 
all permit applications for Phase II, where the Administrator is not the 
permitting authority, shall be submitted to the State permitting 
authority for the State where the affected source is located.
    (e) Where two or more affected units are located at a source, the 
permitting authority may, in its sole discretion, allow the designated 
representative of the source to submit, under paragraph (a) or (c) of 
this section, two or more Acid Rain permit applications covering the 
units at the source, provided that each affected unit is covered by one 
and only one such application.

[58 FR 3650, Jan. 11, 1993, as amended at 58 FR 15649, Mar. 23, 1993; 60 
FR 17113, Apr. 4, 1995; 62 FR 55480, Oct. 24, 1997]



Sec. 72.31  Information requirements for Acid Rain permit applications.

    A complete Acid Rain permit application shall include the following 
elements in a format prescribed by the Administrator:
    (a) Identification of the affected source for which the permit 
application is submitted;
    (b) Identification of each Phase I unit at the source for which the 
permit application is submitted for Phase I or each affected unit 
(except for an opt-in source) at the source for which the permit 
application is submitted for Phase II;
    (c) A complete compliance plan for each unit, in accordance with 
subpart D of this part;
    (d) The standard requirements under Sec. 72.9; and
    (e) If the Acid Rain permit application is for Phase II and the unit 
is a new unit, the date that the unit has commenced or will commence 
operation and the deadline for monitor certification.

[58 FR 3650, Jan. 11, 1993, as amended at 62 FR 55480, Oct. 24, 1997]



Sec. 72.32  Permit application shield and binding effect of permit
application.

    (a) Once a designated representative submits a timely and complete 
Acid Rain permit application, the owners and operators of the affected 
source and the affected units covered by the permit application shall be 
deemed in compliance with the requirement to have an Acid Rain permit 
under Sec. 72.9(a)(2) and Sec. 72.30(a); provided that any delay in 
issuing an Acid Rain permit is not caused by the failure of the 
designated representative to submit in a complete and timely fashion 
supplemental information, as required by the permitting authority, 
necessary to issue a permit.
    (b) Prior to the date on which an Acid Rain permit is issued or 
denied, an affected unit governed by and operated in accordance with the 
terms and requirements of a timely and complete Acid Rain permit 
application shall be deemed to be operating in compliance with the Acid 
Rain Program.
    (c) A complete Acid Rain permit application shall be binding on the 
owners and operators and the designated representative of the affected 
source and the affected units covered by the permit application and 
shall be enforceable as an Acid Rain permit from the date of submission 
of the permit application until the issuance or denial of an Acid Rain 
permit covering the units.
    (d) If agency action concerning a permit is appealed under part 78 
of this chapter, issuance or denial of the permit shall occur when the 
Administrator takes final agency action subject to judicial review.

[58 FR 3650, Jan. 11, 1993, as amended at 62 FR 55480, Oct. 24, 1997]



Sec. 72.33  Identification of dispatch system.

    (a) Every Phase I unit shall be treated as part of a dispatch system 
for purposes of Sec. Sec. 72.91 and 72.92 in accordance with this 
section.

[[Page 45]]

    (b)(1) The designated representatives of all affected units in a 
group of all units and generators that are interconnected and centrally 
dispatched and that are included in the same utility system, holding 
company, or power pool, may jointly submit to the Administrator a 
complete identification of dispatch system.
    (2) Except as provided in paragraph (f) of this section, each unit 
or generator may be included in only one dispatch system.
    (3) Any identification of dispatch system must be submitted by 
January 30 of the first year for which the identification is to be in 
effect. A designated representative may request, and the Administrator 
may grant at his or her discretion, an exemption allowing the submission 
of an identification of dispatch system after the otherwise applicable 
deadline for such submission.
    (c) A complete identification of dispatch system shall include the 
following elements in a format prescribed by the Administrator:
    (1) The name of the dispatch system.
    (2) The list of all units and generators (including sulfur-free 
generators) in the dispatch system.
    (3) The first calendar year for which the identification is to be in 
effect.
    (4) The following statement: ``I certify that, except as otherwise 
required under a petition as approved under 40 CFR 72.33(f), the units 
and generators listed herein are and will continue to be interconnected 
and centrally dispatched, and will be treated as a dispatch system under 
40 CFR 72.91 and 72.92, during the period that this identification of 
dispatch system is in effect. During such period, all information 
concerning these units and generators and contained in any submissions 
under 40 CFR 72.91 and 72.92 by me and the other designated 
representatives of these units shall be consistent and shall conform 
with the data in the dispatch system data reports under 40 CFR 72.92(b). 
I am aware of, and will comply with, the requirements imposed under 40 
CFR 72.33(e)(2).''
    (5) The signatures of the designated representative for each 
affected unit in the dispatch system.
    (d) In order to change a unit's current dispatch system, complete 
identifications of dispatch system shall be submitted for the unit's 
current dispatch system and the unit's new dispatch system, reflecting 
the change.
    (e)(1) Any unit or generator not listed in a complete identification 
of dispatch system that is in effect shall treat its utility system as 
its dispatch system and, if such unit or generator is listed in the 
NADB, shall treat the utility system reported under the data field 
``UTILNAME'' of the NADB as its utility system.
    (2) During the period that the identification of dispatch system is 
in effect all information that concerns the units and generators in a 
given dispatch system and that is contained in any submissions under 
Sec. Sec. 72.91 and 72.92 by designated representative of these units 
shall be consistent and shall conform with the data in the dispatch 
system data reports under Sec. 72.92(b). If this requirement is not 
met, the Administrator may reject all such submissions and require the 
designated representatives to make the submissions under Sec. Sec. 
72.91 and 72.92 (including the dispatch system data report) treating the 
utility system of each unit or generator as its respective dispatch 
system and treating the identification of dispatch system as no longer 
in effect.
    (f)(1) Notwithstanding paragraph (e)(1) of this section or any 
submission of an identification of dispatch system under paragraphs (b) 
or (d) of this section, the designated representative of a Phase I unit 
with two or more owners may petition the Administrator to treat, as the 
dispatch system for an owner's portion of the unit, the dispatch system 
of another unit.
    (i) The owner's portion of the unit shall be based on one of the 
following apportionment methods:
    (A) Owner's share of the unit's capacity in 1985-1987. Under this 
method, the baseline of the owner's portion of the unit shall equal the 
baseline of the unit multiplied by the average of the owner's percentage 
ownership of the capacity of the unit for each year during 1985-1987. 
The actual utilization of the owner's portion of the unit for a year in 
Phase I shall equal the actual utilization of the unit for the year that 
is attributed to the owner.

[[Page 46]]

    (B) Owner's share of the unit's baseline. Under this method, the 
baseline of the owner's portion of the unit shall equal the average of 
the unit's annual utilization in 1985-1987 that is attributed to the 
owner. The actual utilization of the owner's portion of the unit for a 
year in Phase I shall equal the actual utilization of the unit for the 
year that is attributed to the owner.
    (ii) The annual or actual utilization of a unit shall be attributed, 
under paragraph (f)(1)(i) of this section, to an owner of the unit using 
accounting procedures consistent with those used to determine the 
owner's share of the fuel costs in the operation of the unit during the 
period for which the annual or actual utilization is being attributed.
    (iii) Upon submission of the petition, the designated representative 
may not change the election of the apportionment method or the baseline 
of the owner's portion of the unit.

The same apportionment method must be used for all portions of the unit 
for all years in Phase I for which any petition under paragraph (f)(1) 
of this section is approved and in effect.
    (2) The petition under paragraph (f)(1) of this section shall be 
submitted by January 30 of the first year for which the dispatch system 
proposed in the petition will take effect, if approved. A complete 
petition shall include the following elements in a format prescribed by 
the Administrator:
    (i) The election of the apportionment method under paragraph 
(f)(1)(i) of this section.
    (ii) The baseline of the owner's portion of the unit and the 
baseline of any other owner's portion of the unit for which a petition 
under paragraph (f)(1) of this section has been approved or has been 
submitted (and not disapproved) and a demonstration that the sum of such 
baselines and the baseline of any remaining portion of the unit equals 
100 percent of the baseline of the unit. The designated representative 
shall also submit, upon request, either:
    (A) Where the unit is to be apportioned under paragraph (f)(1)(i)(A) 
of this section, documentation of the average of the owner's percentage 
ownership of the capacity of the unit for each year during 1985-1987; or
    (B) Where the unit is to be apportioned under paragraph (f)(1)(i)(B) 
of this section, documentation showing the attribution of the unit's 
utilization in 1985, 1986, and 1987 among the portions of the unit and 
the calculation of the annual average utilization for 1985-1987 for the 
portions of the unit.
    (iii) The name of the proposed dispatch system and a list of all 
units (including portions of units) and generators in that proposed 
dispatch system and, upon request, documentation demonstrating that the 
owner's portion of the unit, along with the other units in the proposed 
dispatch system, are a group of all units and generators that are 
interconnected and centrally dispatched by a single utility company, the 
service company of a single holding company, or a single power pool.
    (iv) The following statement, signed by the designated 
representatives of all units in the proposed dispatch system: ``I 
certify that the units and generators in the dispatch system proposed in 
this petition are and will continue to be interconnected and centrally 
dispatched, and will be treated as a dispatch system under 40 CFR 72.91 
and 72.92, during the period that this petition, as approved, is in 
effect.''
    (v) The following statement, signed by the designated 
representatives of all units in all dispatch systems that will include 
any portion of the unit if the petition is approved: ``During the period 
that this petition, if approved, is in effect, all information that 
concerns the units and generators in any dispatch system including any 
portion of the unit apportioned under the petition and that is contained 
in any submissions under 40 CFR 72.91 and 72.92 by me and the other 
designated representatives of these units shall be consistent and shall 
conform to the data in the dispatch system data reports under 40 CFR 
72.92(b). I am aware of, and will comply with, the requirements imposed 
under 40 CFR 72.33(f) (4) and (5).''
    (3)(i) The Administrator will approve in whole, in part, or with 
changes or conditions, or deny the petition under paragraph (f)(1) of 
this section within 90 days of receipt of the petition. The 
Administrator will treat the petition, as changed or conditioned upon 
approval, as amending any identification

[[Page 47]]

of dispatch system that is submitted prior to the approval and includes 
any portion of the unit for which the petition is approved. Where any 
portion of a unit is not covered by an approved petition, that remaining 
portion of the unit shall continue to be part of the unit's dispatch 
system.
    (ii) In approving the petition, the Administrator will determine, on 
a case-by-case basis, the proper calculation and treatment, for purposes 
of the reports required under Sec. Sec. 72.91 and 72.92, of plan 
reductions and compensating generation provided to other units.
    (4) The designated representative for the unit for which a petition 
is approved under paragraph (f)(3) of this section and the designated 
representatives of all other units included in all dispatch systems that 
include any portion of the unit shall submit all annual compliance 
certification reports, dispatch system data reports, and other reports 
required under Sec. Sec. 72.91 and 72.92 treating, as a separate Phase 
I unit, each portion of the unit for which a petition is approved under 
paragraph (f)(3) of this section and the remaining portion of the unit. 
The reports shall include all required calculations and demonstrations, 
treating each such portion of the unit as a separate Phase I unit. Upon 
request, the designated representatives shall demonstrate that the data 
in all the reports under Sec. Sec. 72.91 and 72.92 has been properly 
attributed or apportioned among the portions of the unit and the 
dispatch systems and that there is no undercounting or double-counting 
with regard to such data.
    (i) The baseline of each portion of the unit for which a petition is 
approved shall be determined under paragraphs (f)(1) (i) and (ii) of 
this section. The baseline of the remaining portion of such unit shall 
equal the baseline of the unit less the sum of the baselines of any 
portions of the unit for which a petition is approved.
    (ii) The actual utilization of each portion of the unit for which a 
petition is approved shall be determined under paragraphs (f)(l) (i) and 
(ii) of this section. The actual utilization of the remaining portion of 
such unit shall equal the actual utilization of the unit less the sum of 
the actual utilizations of any portions of the unit for which a petition 
is approved. Upon request, the designated representative of the unit 
shall demonstrate in the annual compliance certification report that the 
requirements concerning calculation of actual utilization under 
paragraph (f)(1)(ii) and any requirements established under paragraph 
(f)(3) of this section are met.
    (iii) Except as provided in paragraph (f)(5) of this section, the 
designated representative shall surrender for deduction the number of 
allowances calculated using the formula in Sec. 72.92(c) and treating, 
as a separate Phase I unit, each portion of unit for which a petition is 
approved under paragraph (f)(3) of this section and the remaining 
portion of the unit.
    (5) In the event that the designated representatives fail to make 
all the proper attributions, apportionments, calculations, and 
demonstrations under paragraph (f)(4) of this section and Sec. Sec. 
72.91 and 72.92, the Administrator may require that:
    (i) All portions of the unit be treated as part of the dispatch 
system of the unit in accordance with paragraph (e)(1) of this paragraph 
and any identification of dispatch system submitted under paragraph (b) 
or (d) of this section;
    (ii) The designated representatives make all submissions under 
Sec. Sec. 72.91 and 72.92 (including the dispatch system data report), 
treating the entire unit as a single Phase I unit, in accordance with 
paragraph (e)(1) of this paragraph and any identification of dispatch 
system submitted under paragraph (b) or (d) of this section; and
    (iii) The designated representative surrender for deduction the 
number of allowances calculated, consistent with the reports under 
paragraph (f)(5)(ii) of this section and Sec. Sec. 72.91 and 72.92, 
using the formula in Sec. 72.92(c) and treating the entire unit as a 
single Phase I unit.
    (6) The designated representative may submit a notification to 
terminate an approved petition by January 30 of the first year for which 
the termination is to take effect. The notification must be signed and 
certified by the designated representatives of all units included in all 
dispatch systems

[[Page 48]]

that include any portion of the unit apportioned under the petition. 
Upon receipt of the notification meeting the requirements of the prior 
two sentences by the Administrator, the approved petition is no longer 
in effect for that year and the remaining years in Phase I and the 
designated representatives shall make all submissions under Sec. Sec. 
72.91 and 72.92 treating the petition as no longer in effect for all 
such years.
    (7) Except as expressly provided in paragraphs (f)(1) through (6) of 
this section or the Administrator's approval of the petition, all 
provisions of the Acid Rain Program applicable to an affected source or 
an affected unit shall apply to the entire unit regardless of whether a 
petition has been submitted or approved, or reports have been submitted, 
under such paragraphs. Approval of a petition under such paragraphs 
shall not constitute a determination of the percentage ownership in a 
unit under any other provision of the Acid Rain Program and shall not 
change the liability of the owners and operators of an affected unit 
that has excess emissions under Sec. 72.9(e).

[58 FR 3650, Jan. 11, 1993, as amended at 60 FR 18468, Apr. 11, 1995; 62 
FR 55481, Oct. 24, 1997]



       Subpart D_Acid Rain Compliance Plan and Compliance Options



Sec. 72.40  General.

    (a) For each affected unit included in an Acid Rain permit 
application, a complete compliance plan shall:
    (1) For sulfur dioxide emissions, certify that, as of the allowance 
transfer deadline, the designated representative will hold allowances in 
the compliance account of the source where the unit is located (after 
deductions under Sec. 73.34(c) of this chapter) not less than the total 
annual emissions of sulfur dioxide from the affected units at the 
source. The compliance plan may also specify, in accordance with this 
subpart, one or more of the Acid Rain compliance options.
    (2) For nitrogen oxides emissions, certify that the unit will comply 
with the applicable emission limitation under Sec. 76.5, Sec. 76.6, or 
Sec. 76.7 of this chapter or shall specify one or more Acid Rain 
compliance options, in accordance with part 76 of this chapter.
    (b) Multi-unit compliance options. (1) A plan for a compliance 
option, under Sec. 72.41, Sec. 72.42, Sec. 72.43, or Sec. 72.44 of 
this part, under Sec. 74.47 of this chapter, or a NOX 
averaging plan under Sec. 76.11 of this chapter, that includes units at 
more than one affected source shall be complete only if:
    (i) Such plan is signed and certified by the designated 
representative for each source with an affected unit governed by such 
plan; and
    (ii) A complete permit application is submitted covering each unit 
governed by such plan.
    (2) A permitting authority's approval of a plan under paragraph 
(b)(1) of this section that includes units in more than one State shall 
be final only after every permitting authority with jurisdiction over 
any such unit has approved the plan with the same modifications or 
conditions, if any.
    (c) Conditional Approval. In the compliance plan, the designated 
representative of an affected unit may propose, in accordance with this 
subpart, any Acid Rain compliance option for conditional approval, 
except a Phase I extension plan; provided that an Acid Rain compliance 
option under section 407 of the Act may be conditionally proposed only 
to the extent provided in part 76 of this chapter.
    (1) To activate a conditionally-approved Acid Rain compliance 
option, the designated representative shall notify the permitting 
authority in writing that the conditionally-approved compliance option 
will actually be pursued beginning January 1 of a specified year. If the 
conditionally approved compliance option includes a plan described in 
paragraph (b)(1) of this section, the designated representative of each 
source governed by the plan shall sign and certify the notification. 
Such notification shall be subject to the limitations on activation 
under subpart D of this part and part 76 of this chapter.
    (2) The notification under paragraph (c)(1) of this section shall 
specify the first calendar year and the last calendar year for which the 
conditionally approved Acid Rain compliance option

[[Page 49]]

is to be activated. A conditionally approved compliance option shall be 
activated, if at all, before the date of any enforceable milestone 
applicable to the compliance option. The date of activation of the 
compliance option shall not be a defense against failure to meet the 
requirements applicable to that compliance option during each calendar 
year for which the compliance option is activated.
    (3) Upon submission of a notification meeting the requirements of 
paragraphs (c) (1) and (2) of this section, the conditionally-approved 
Acid Rain compliance option becomes binding on the owners and operators 
and the designated representative of any unit governed by the 
conditionally-approved compliance option.
    (4) A notification meeting the requirements of paragraphs (c) (1) 
and (2) of this section will revise the unit's permit in accordance with 
Sec. 72.83 (administrative permit amendment).
    (d) Termination of compliance option. (1) The designated 
representative for a unit may terminate an Acid Rain compliance option 
by notifying the permitting authority in writing that an approved 
compliance option will be terminated beginning January 1 of a specified 
year. If the compliance option includes a plan described in paragraph 
(b)(1) of this section, the designated representative for each source 
governed by the plan shall sign and certify the notification. Such 
notification shall be subject to the limitations on termination under 
subpart D of this part and part 76 of this chapter.
    (2) The notification under paragraph (d)(1) of this section shall 
specify the calendar year for which the termination will take effect.
    (3) Upon submission of a notification meeting the requirements of 
paragraphs (d) (1) and (2) of this section, the termination becomes 
binding on the owners and operators and the designated representative of 
any unit governed by the Acid Rain compliance option to be terminated.
    (4) A notification meeting the requirements of paragraphs (d) (1) 
and (2) of this section will revise the unit's permit in accordance with 
Sec. 72.83 (administrative permit amendment).

[58 FR 3650, Jan. 11, 1993, as amended at 60 FR 17113, Apr. 4, 1995; 62 
FR 55481, Oct. 24, 1997; 64 FR 25842, May 13, 1999; 70 FR 25334, May 12, 
2005]



Sec. 72.41  Phase I substitution plans.

    (a) Applicability. This section shall apply during Phase I to the 
designated representative of:
    (1) Any unit listed in table 1 of Sec. 73.10(a) of this chapter; 
and
    (2) Any other existing utility unit that is an affected unit under 
this part, provided that this section shall not apply to a unit under 
section 410 of the Act.
    (b)(1) The designated representative may include, in the Acid Rain 
permit application for a unit under paragraph (a)(1) of this section, a 
substitution plan under which one or more units under paragraph (a)(2) 
of this section are designated as substitution units, provided that:
    (i) Each unit under paragraph (a)(2) of this section is under the 
control of the owner or operator of each unit under paragraph (a)(1) of 
this section that designates the unit under paragraph (a)(2) of this 
section as a substitution unit; and
    (ii) In accordance with paragraph (c)(3) of this section, the 
emissions reductions achieved under the plan shall be the same or 
greater than would have been achieved by all units governed by the plan 
without such plan.
    (2) The designated representative of each source with a unit 
designated as a substitution unit in any plan submitted under paragraph 
(b)(1) of this section shall incorporate in the permit application each 
such plan.
    (3) The designated representative may submit a substitution plan not 
later than 6 months (or 90 days if submitted in accordance with Sec. 
72.82), or a notification to activate a conditionally approved plan in 
accordance with Sec. 72.40(c) not later than 60 days, before the 
allowance transfer deadline applicable to the first year for which the 
plan is to take effect.
    (c) Contents of a substitution plan. A complete substitution plan 
shall include the following elements in a format prescribed by the 
Administrator:

[[Page 50]]

    (1) Identification of each unit under paragraph (a)(1) of this 
section and each substitution unit to be governed by the substitution 
plan. A unit shall not be a substitution unit in more than one 
substitution plan.
    (2) Except where the designated representative requests conditional 
approval of the plan, the first calendar year and, if known, the last 
calendar year in which the substitution plan is to be in effect. Unless 
the designated representative specifies an earlier calendar year, the 
last calendar year will be deemed to be 1999.
    (3) Demonstration that the total emissions reductions achieved under 
the substitution plan will be equal to or greater than the total 
emissions reductions that would have been achieved without the plan, as 
follows:
    (i) For each substitution unit:
    (A) The unit's baseline.
    (B) Each of the following: the unit's 1985 actual SO2 
emissions rate; the unit's 1985 allowable SO2 emissions rate; 
the unit's 1989 actual SO2 emissions rate; the unit's 1990 
actual SO2 emissions rate; and, as of November 15, 1990, the 
most stringent unit-specific federally enforceable or State enforceable 
SO2 emissions limitation covering the unit for 1995-1999. For 
purposes of determining the most stringent emissions limitation, 
applicable emissions limitations shall be converted to lbs/mmBtu in 
accordance with appendix B of this part. Where the most stringent 
emissions limitation is not the same for every year in 1995-1999, the 
most stringent emissions limitation shall be stated separately for each 
year.
    (C) The lesser of: the unit's 1985 actual SO2 emissions 
rate; the unit's 1985 allowable SO2 emissions rate; the 
greater of the unit's 1989 or 1990 actual SO2 emissions rate; 
or, as of November 15, 1990, the most stringent unit-specific federally 
enforceable or State enforceable SO2 emissions limitation 
covering the unit for 1995-99. Where the most stringent emissions 
limitation is not the same for every year during 1995-1999, the lesser 
of the emissions rates shall be determined separately for each year 
using the most stringent emissions limitation for that year.
    (D) The product of the baseline in paragraph (c)(3)(i)(A) of this 
section and the emissions rate in paragraph (c)(3)(i)(C) of this 
section, divided by 2000 lbs/ton. Where the most stringent emissions 
limitation is not the same for every year during 1995-1999, the product 
in the prior sentence shall be calculated separately for each year using 
the emissions rate determined for that year in paragraph (c)(3)(i)(C) of 
this section.
    (ii)(A) The sum of the amounts in paragraph (c)(3)(i)(D) of this 
section for all substitution units to be governed by the plan. Except as 
provided in paragraph (c)(3)(ii)(B) of this section, this sum is the 
total number of allowances available each year under the substitution 
plan.
    (B) Where the most stringent unit-specific federally enforceable or 
State enforceable SO2 emissions limitation is not the same 
for every year during 1995-1999, the sum in paragraph (c)(3)(ii)(A) of 
this section shall be calculated separately for each year using the 
amounts calculated for that year in paragraph (c)(3)(i)(D) of this 
section. Each separate sum is the total number of allowances available 
for the respective year under the substitution plan.
    (iii) Where, as of November 15, 1990, a non-unit-specific federally 
enforceable or State enforceable SO2 emissions limitation 
covers the unit for any year during 1995-1999, the designated 
representative shall state each such limitation and propose a method for 
applying the unit-specific and non-unit-specific emissions limitations 
under paragraph (d) of this section.
    (4) Distribution of substitution allowances. (i) A statement that 
the allowances in paragraph (c)(3)(ii) of this section are not to be 
distributed to any units under paragraph (a)(1) of this section that are 
to be governed by the plan; or
    (ii) A list showing any annual distribution of the allowances in 
paragraph (c)(3)(ii) of this section from a substitution unit to a unit 
under paragraph (a)(1) of this section that, under the plan, designates 
the substitution unit.
    (5) A demonstration that the substitution plan meets the requirement 
that each unit under paragraph (a)(2) of this section is under the 
control of the owner or operator of each unit under

[[Page 51]]

paragraph (a)(1) of this section that designates the unit under 
paragraph (a)(2) of this section as a substitution unit. The 
demonstration shall be one of the following:
    (i) If the unit under paragraph (a)(1) of this section has one or 
more owners or operators that have an aggregate percentage ownership 
interest of 50 percent or more in the capacity of the unit under 
paragraph (a)(2) of this section or the units have a common operator, a 
statement identifying such owners or operators and their aggregate 
percentage ownership interest in the capacity of the unit under 
paragraph (a)(2) of this section or identifying the units' common 
operator. The designated representative shall submit supporting 
documentation upon request by the Administrator.
    (ii) If the unit under paragraph (a)(1) of this section has one or 
more owners or operators that have an aggregate percentage ownership 
interest of at least 10 percent and less than 50 percent in the capacity 
of the unit under paragraph (a)(2) of this section and the units do not 
have a common operator, a statement identifying such owners or operators 
and their aggregate percentage ownership interest in the capacity of the 
unit under paragraph (a)(2) of this section and stating that each such 
owner or operator has the contractual right to direct the dispatch of 
the electricity that, because of its ownership interest, it has the 
right to receive from the unit under paragraph (a)(2) of this section. 
The fact that the electricity that such owner or operator has the right 
to receive is centrally dispatched through a power pool will not be the 
basis for determining that the owner or operator does not have the 
contractual right to direct the dispatch of such electricity. The 
designated representative shall submit supporting documentation upon 
request by the Administrator.
    (iii) A copy of an agreement that is binding on the owners and 
operators of the unit under paragraph (a)(2) of this section and the 
owners and operators of the unit under paragraph (a)(1) of this section, 
provides each of the following elements, and is supported by 
documentation meeting the requirements of paragraph (c)(6) of this 
section:
    (A) The owners and operators of the unit under paragraph (a)(2) of 
this section must not allow the unit to emit sulfur dioxide in excess of 
a maximum annual average SO2 emissions rate (in lbs/mmBtu), 
specified in the agreement, for each year during the period that the 
substitution plan is in effect.
    (B) The maximum annual average SO2 emissions rate for the 
unit under paragraph (a)(2) of this section shall not exceed 70 percent 
of the lesser of: the unit's 1985 actual SO2 emissions rate; 
the unit's 1985 allowable SO2 emissions rate; the greater of 
the unit's 1989 or 1990 actual SO2 emissions rate; the most 
stringent federally enforceable or State enforceable SO2 
emissions limitation, as of November 15, 1990, applicable to the unit in 
Phase I; or the lesser of the average actual SO2 emissions 
rate or the most stringent federally enforceable or State enforceable 
SO2 emissions limitation for the unit for four consecutive 
quarters that immediately precede the 30-day period ending on the date 
the substitution plan is submitted to the Administrator. If the unit is 
covered by a non-unit-specific federally enforceable or State 
enforceable SO2 emissions limitation in the four consecutive 
quarters or, as of November 15, 1990, in Phase I, the Administrator will 
determine, on a case-by-case basis, how to apply the non-unit-specific 
emissions limitation for purposes of determining whether the maximum 
annual average SO2 emissions rate meets the requirement of 
the prior sentence. If a non-unit-specific federally enforceable 
SO2 emissions limitation is not different from a non-unit-
specific federally enforceable SO2 emissions limitation that 
was effective and applicable to the unit in 1985, the Administrator will 
apply the non-unit-specific SO2 emissions limitation by using 
the 1985 allowable SO2 emissions rate.
    (C) For each year that the actual SO2 emissions rate of 
the unit under paragraph (a)(2) of this section exceeds the maximum 
annual average SO2 emissions rate, the designated 
representative of the unit under paragraph (a)(1) of this section must 
surrender allowances for deduction from the Allowance

[[Page 52]]

Tracking System account of the unit under paragraph (a)(1) of this 
section. The designated representative shall surrender allowances 
authorizing emissions equal to the baseline of the unit under paragraph 
(a)(2) of this section multiplied by the difference between the actual 
SO2 emissions rate of the unit under paragraph (a)(2) of this 
section and the maximum annual average SO2 emissions rate and 
divided by 2000 lbs/ton. The surrender shall be made by the allowance 
transfer deadline of the year of the exceedance, and the surrendered 
allowances shall have the same or an earlier compliance use date as the 
allowances allocated to the unit under paragraph (a)(2) of this section 
for that year. The designated representative may identify the serial 
numbers of the allowances to be deducted. In the absence of such 
identification, allowances will be deducted on a first-in, first-out 
basis under Sec. 73.35(c)(2) of this chapter.
    (D) The unit under paragraph (a)(2) of this section and the unit 
under paragraph (a)(1) of this section shall designate a common 
designated representative during the period that the substitution plan 
is in effect. Having a common alternate designated representative shall 
not satisfy the requirement in the prior sentence.
    (E) Except as provided in paragraph (c)(6)(i) of this section, the 
actual SO2 emissions rate for any year and the average actual 
SO2 emissions rate for any period shall be determined in 
accordance with part 75 of this chapter.
    (6) A demonstration under paragraph (c)(5)(iii) of this section 
shall include the following supporting documentation:
    (i) The calculation of the average actual SO2 emissions 
rate and the most stringent federally enforceable or State enforceable 
SO2 emissions limitation for the unit for the four 
consecutive quarters that immediately preceded the 30-day period ending 
on the date the substitution plan is submitted to the Administrator. To 
the extent that the four consecutive quarters include a quarter prior to 
January 1, 1995, the SO2 emissions rate for the quarter shall 
be determined applying the methodology for calculating SO2 
emissions set forth in appendix C of this part. This methodology shall 
be applied using data submitted for the quarter to the Secretary of 
Energy on United States Department of Energy Form 767 or, if such data 
has not been submitted for the quarter, using the data prepared for such 
submission for the quarter.
    (ii) A description of the actions that will be taken in order for 
the unit under paragraph (a)(2) of this section to comply with the 
maximum annual average SO2 emissions rate under paragraph 
(c)(5)(iii) of this section.
    (iii) A description of any contract for implementing the actions 
described in paragraph (c)(6)(ii) of this section that was executed 
before the date on which the agreement under paragraph (c)(5)(iii) of 
this section is executed. The designated representative shall state the 
execution date of each such contract and state whether the contract is 
expressly contingent on the agreement under paragraph (c)(5)(iii) of 
this section.
    (iv) A showing that the actions described under paragraph (c)(6)(ii) 
of this section will not be implemented during Phase I unless the unit 
is approved as a substitution unit.
    (7) The special provisions in paragraph (e) of this section.
    (d) Administrator's action. (1) If the Administrator approves a 
substitution plan, he or she will allocate allowances to the Allowance 
Tracking System accounts of the units under paragraph (a)(1) of this 
section and substitution units, as provided in the approved plan, upon 
issuance of an Acid Rain permit containing the plan, except that if the 
substitution plan is conditionally approved, the allowances will be 
allocated upon revision of the permit to activate the plan.
    (2) In no event shall allowances be allocated to a substitution 
unit, under an approved substitution plan, for any year in excess of the 
sum calculated and applicable to that year under paragraph (c)(3)(ii) of 
this section, as adjusted by the Administrator in approving the plan.
    (3) Where, as of November 15, 1990, a non-unit-specific federally 
enforceable or State enforceable SO2 emissions limitation 
covers the unit for any year during 1995-1999, the Administrator

[[Page 53]]

will specify on a case-by-case basis a method for using unit-specific 
and non-unit-specific emissions limitations in allocating allowances to 
the substitution unit. The specified method will not treat a non-unit-
specific emissions limitation as a unit-specific emissions limitation 
and will not result in substitution units retaining allowances allocated 
under paragraph (d)(1) of this section for emissions reductions 
necessary to meet a non-unit- specific emissions limitation. Such method 
may require an end-of-year review and the adjustment of the allowances 
allocated to the substitution unit and may require the designated 
representative of the substitution unit to surrender allowances by the 
allowance transfer deadline of the year that is subject to the review. 
Any surrendered allowances shall have the same or an earlier compliance 
use date as the allowances originally allocated for the year, and the 
designated representative may identify the serial numbers of the 
allowances to be deducted. In the absence of such identification, such 
allowances will be deducted on a first-in, first-out basis under Sec. 
73.35(c)(2) of this chapter.
    (e) Special provisions--(1) Emissions Limitations. (i) Each 
substitution unit governed by an approved substitution plan shall become 
a Phase I unit from January 1 of the year for which the plan takes 
effect until January 1 of the year for which the plan is no longer in 
effect or is terminated. The designated representative of a substitution 
unit shall surrender allowances, and the Administrator will deduct 
allowances, in accordance with paragraph (d)(3) of this section.
    (ii) Each unit under paragraph (a)(1) of this section, and each 
substitution unit, governed by an approved substitution plan shall be 
subject to the Acid Rain emissions limitations for nitrogen oxides in 
accordance with part 76 of this chapter.
    (iii) Where an approved substitution plan includes a demonstration 
under paragraphs (c)(5)(iii) and (c)(6) of this section.
    (A) The owners and operators of the substitution unit covered by the 
demonstration shall implement the actions described under paragraph 
(c)(6)(ii) of this section, as adjusted by the Administrator in 
approving the plan or in revising the permit. The designated 
representative may submit proposed permit revisions changing the 
description of the actions to be taken in order for the substitution 
unit to achieve the maximum annual average SO2 emissions rate 
under the approved plan and shall include in any such submission a 
showing that the actions in the changed description will not be 
implemented during Phase I unless the unit remains a substitution unit. 
The permit revision will be treated as an administrative amendment, 
except where the Administrator determines that the change in the 
description alters the fundamental nature of the actions to be taken and 
that public notice and comment will contribute to the decision-making 
process, in which case the permit revision will be treated as a permit 
modification or, at the option of the designated representative, a fast-
track modification.
    (B) The designated representative of the unit under paragraph (a)(1) 
of this section shall surrender allowances, and theAdministrator will 
deduct allowances, in accordance with paragraph (c)(5)(iii)(C) of this 
section. The surrender and deduction of allowances as required under the 
prior sentence shall be the only remedy under the Act for a failure to 
meet the maximum annual average SO2 emissions rate, provided 
that, if such deduction of allowance results in excess emissions, the 
remedies for excess emissions shall be fully applicable.
    (2) Liability. The owners and operators of a unit governed by an 
approved substitution plan shall be liable for any violation of the plan 
or this section at that unit or any other unit that is the first unit's 
substitution unit or for which the first unit is a substitution unit 
under the plan, including liability for fulfilling the obligations 
specified in part 77 of this chapter and section 411 of the Act.
    (3) Termination. (i) A substitution plan shall be in effect only in 
Phase I for the calendar years specified in the plan or until the 
calendar year for which a termination of the plan takes effect, provided 
that no substitution plan shall be terminated, and no unit shall be de-
designated as a substitution

[[Page 54]]

unit, before the end of Phase I if the substitution unit serves as a 
control unit under a Phase I extension plan.
    (ii) To terminate a substitution plan for a given calendar year 
prior to the last year for which the plan was approved:
    (A) A notification to terminate in accordance with Sec. 72.40(d) 
shall be submitted no later than 60 days before the allowance transfer 
deadline applicable to the given year; and
    (B) In the notification to terminate, the designated representative 
of each unit governed by the plan shall state that he or she surrenders 
for deduction from the unit's Allowance Tracking System account 
allowances equal in number to, and with the same or an earlier 
compliance use date as, those allocated under paragraph (d)(1) of this 
section for all calendar years for which the plan is to be terminated. 
The designated representative may identify the serial numbers of the 
allowances to be deducted. In the absence of such identification, 
allowances will be deducted on a first-in, first-out basis under Sec. 
73.35(c)(2) of this chapter.
    (iii) If the requirements of paragraph (e)(3)(ii) of this section 
are met and upon revision of the permit to terminate the substitution 
plan, the Administrator will deduct the allowances specified in 
paragraph (e)(3)(ii)(B) of this section. No substitution plan shall be 
terminated, and no unit shall be de-designated as a Phase I unit, unless 
such deduction is made.
    (iv)(A) If there is a change in the ownership interest of the owners 
or operators of any unit under a substitution plan approved as meeting 
the requirements of paragraph (c)(5)(i) or (ii) of this section or a 
change in such owners' or operators' right to direct dispatch of 
electricity from a substitution unit under such a plan and the 
demonstration under paragraph (c)(5)(i) or (ii) of this section cannot 
be made, then the designated representatives of the units governed by 
this plan shall submit a notification to terminate the plan so that the 
plan will terminate as of January 1 of the calendar year during which 
the change is made.
    (B) Where a substitution plan is approved as meeting the 
requirements of paragraph (c)(5)(iii) of this section, if there is a 
change in the agreement under paragraph (c)(5)(iii) of this section and 
a demonstration that the agreement, as changed, meets the requirements 
of paragraph (c)(5)(iii) cannot be made, then the designated 
representative of the units governed by the plan shall submit a 
notification to terminate the plan so that the plan will terminate as of 
January 1 of the calendar year during which the change is made. Where a 
substitution plan is approved as meeting the requirements of paragraph 
(c)(5)(iii) of this section, if the requirements of the first sentence 
of paragraph (e)(1)(iii)(A) of this section are not met during a 
calendar year, then the designated representative of the units governed 
by the plan shall submit a notification to terminate the plan so that 
the plan will terminate as of January 1 of such calendar year.
    (C) If the plan is not terminated in accordance with paragraphs 
(e)(3)(iv)(A) or (B) of this section, the Administrator, on his or her 
own motion, will terminate the plan and deduct the allowances required 
to be surrendered under paragraph (e)(3)(ii) of this section.
    (D) Where a substitution unit and the Phase I unit designating the 
substitution unit in an approved substitution plan have a common owner, 
operator, or designated representative during a year, the plan shall not 
be terminated under paragraphs (e)(3)(iv)(A), (B), or (C) of this 
section with regard to the substitution unit if the year is as specified 
in paragraph (e)(3)(iv)(D)(1) or (2) of this section and the unit 
received from the Administrator for the year, under the Partial 
Settlement in Environmental Defense Fund v. Carol M. Browner, No. 93-
1203 (D.C. Cir. 1993) (signed May 4, 1993), a total number of allowances 
equal to the unit's baseline multiplied by the lesser of the unit's 1985 
actual SO2 emissions rate or 1985 allowable SO2 
emissions rate.
    (1) Except as provided in paragraph (e)(3)(iv)(D)(2) of this 
section, paragraph (e)(3)(iv)(D) of this section shall apply to the 
first year in Phase I for which the unit is and remains an active 
substitution unit.
    (2) If the unit has a Group 1 boiler under part 76 of this chapter 
and is and

[[Page 55]]

remains an active substitution unit during 1995, paragraph (e)(3)(iv)(D) 
of this section shall apply to 1995 and to the second year in Phase I 
for which the unit is and remains an active substitution unit.
    (3) If there is a change in the owners, operators, or designated 
representative of the substitution unit or the Phase I unit during a 
year under paragraph (e)(3)(iv)(D)(1) or (2) of this section and, with 
the change, the units do not have a common owner, operator, or 
designated representative, then the designated representatives for such 
units shall submit a notification to terminate the plan so that the plan 
will terminate as of January 1 of the calendar year during which the 
change is made. If the plan is not terminated in accordance with the 
prior sentence, the Administrator, on his or her own motion, will 
terminate the plan and deduct the allowances required to be surrendered 
under paragraph (e)(3)(ii) of this section.

[58 FR 3650, Jan. 11, 1993, as amended at 58 FR 40747, July 30, 1993; 59 
FR 60230, 60238, Nov. 22, 1994; 62 FR 55481, Oct. 24, 1997]



Sec. 72.42  Phase I extension plans.

    (a) Applicability. (1) This section shall apply to any designated 
representative seeking a 2-year extension of the deadline for meeting 
Phase I sulfur dioxide emissions reduction requirements at any of the 
following types of units by applying for allowances from the Phase I 
extension reserve:
    (i) A unit listed in table 1 of Sec. 73.10(a) of this chapter;
    (ii) A unit designated as a substitution unit in accordance with 
Sec. 72.41; or
    (iii) A unit designated as a compensating unit in accordance with 
Sec. 72.43, except a compensating unit that is a new unit.
    (2) A unit for which a Phase I extension is sought shall be either:
    (i) A control unit, which shall be a unit under paragraph (a)(1) of 
this section and at which qualifying Phase I technology shall commence 
operation on or after November 15, 1990 but not later than December 31, 
1996; or
    (ii) A transfer unit, which shall be a unit under paragraph 
(a)(1)(i) of this section and whose Phase I emissions reduction 
obligation shall be transferred in whole or in part to one or more 
control units.
    (3) A Phase I extension does not exempt the owner or operator for 
any unit governed by the Phase I extension plan from the requirement to 
comply with such unit's Acid Rain emissions limitations for sulfur 
dioxide.
    (b) To apply for a Phase I extension:
    (1) The designated representative for each source with a control 
unit may submit an early ranking application for a Phase I extension 
plan in person, beginning on the 40th day after publication of this 
subpart in the Federal Register, between the hours of 9 a.m. and 5 p.m. 
Eastern Standard Time at Acid Rain Division, Attn: Early Ranking, U.S. 
Environmental Protection Agency, 501 3rd Street NW., 4th floor, 
Washington, DC; or send the application by regular mail, certified mail, 
or overnight delivery service to Acid Rain Division, Attn: Early 
Ranking, U.S. Environmental Protection Agency, 6204 J, 1200 Pennsylvania 
Ave., NW., Washington, DC 20460.
    (2) By February 15, 1993:
    (i) The designated representative for each source with a control 
unit shall submit a Phase I extension plan as a part of the Acid Rain 
permit application for the source, and
    (ii) The designated representative for each source with a unit 
designated as a transfer unit in any plan submitted under paragraph 
(b)(2)(i) of this section shall incorporate in the Acid Rain permit 
application each such plan.
    (c) Contents of early ranking application. A complete early ranking 
application shall include the following elements in a format prescribed 
by the Administrator:
    (1) Identification of each control unit. All control units in an 
application must be located at the same source. If the control unit is 
not a unit under paragraph (a)(1)(i) of this section, a substitution 
plan or a reduced utilization plan governing the unit shall be submitted 
by the deadline for submitting a Phase I permit application.
    (2) Identification of each transfer unit. A unit shall not be a 
transfer unit in more than one early ranking application.

[[Page 56]]

    (3) For each control and transfer unit, the total tonnage of sulfur 
dioxide emitted in 1988 plus the total tonnage of sulfur dioxide emitted 
in 1989, divided by 2. The 1988 and 1989 tonnage figures shall be 
consistent with the data filed on EIA form 767 for those years and the 
conversion methodology specified in appendix B of this part.
    (4) For each control and transfer unit:
    (i) The projected annual utilization (in mmBtu) for 1995 multiplied 
by the projected uncontrolled emissions rate (i.e., the emissions rate 
in the absence of title IV of the Act) for 1995 (in lbs/mmBtu), divided 
by 2000 lbs/ton.
    (ii) The projected annual utilization (in mmBtu) for 1996 multiplied 
by the projected uncontrolled emissions rate (i.e., the emissions rate 
in the absence of title IV of the Act) for 1996 (in lbs/mmBtu), divided 
by 2000 lbs/ton.
    (5) For each control and transfer unit, the number of Phase I 
extension reserve allowances requested for 1995 and for 1996, not to 
exceed the difference between:
    (i) The lesser of the value for the unit under paragraph (c)(3) of 
this section and the value for the unit for that year under paragraph 
(c)(4) of this section, and
    (ii) Each unit's baseline multiplied by 2.5 lb/mmBtu, divided by 
2000 lbs/ton.
    (6) Documentation that the annual emissions reduction obligations 
transferred from all transfer units to all control units do not exceed 
those authorized under this section, as follows:
    (i) For each control unit, the difference, calculated separately for 
1995 and 1996, between:
    (A) The control unit's allowance allocation in table 1 of Sec. 
73.10(2) of this chapter, the allocation under Sec. 72.41 if the 
control unit is a substitution unit, or the allocation under Sec. 72.43 
if the control unit is a compensating unit; and
    (B) The projected emissions resulting from 90% control after 
installing the qualifying Phase I technology, i.e., 10% of the projected 
uncontrolled emissions for the control unit for the year in accordance 
with paragraph (c)(4) of this section.
    (ii) The sum, by year, of the results under paragraph (c)(6)(i) of 
this section for all control units.
    (iii) The sum, by year, of Phase I extension reserve allowances 
requested for all transfer units.
    (iv) A showing that, for each year, the sum under paragraph 
(c)(6)(ii) of this section is greater than or equal to the sum under 
paragraph (c)(6)(iii) of this section.
    (7) For each control and transfer unit, the projected controlled 
emissions for 1997, for 1998, and for 1999 calculated as follows:
    Projected annual utilization (in mmBtu) multiplied by the projected 
controlled emission rate (in lbs/mmBtu), divided by 2000 lbs/ton. \1\
---------------------------------------------------------------------------

    \1\ In the case of a transfer unit that shares a common stack with a 
unit not listed in table 1 of Sec. 73.10(a) of this chapter and whose 
emissions of sulfur dioxide are not monitored separately or apportioned 
in accordance with part 75 of this chapter, the projected figures for 
the transfer unit under paragraph (c)(7) of this section must be for the 
units combined.
---------------------------------------------------------------------------

    (8) For each control unit, the number of Phase I extension reserve 
allowances requested for 1997, for 1998, and for 1999, calculated as 
follows:
    The unit's baseline multiplied by 1.2 lbs/mmBtu and divided by 2000 
lbs/ton, minus the projected controlled emissions (in tons/yr) under 
paragraph (c)(7) of this section for the given year.
    (9) The total of Phase I extension reserve allowances requested for 
all units in the plan for 1995 through 1999.
    (10) With regard to each executed contract for the design 
engineering and construction of qualifying Phase I technology at each 
control unit governed by the early ranking application, either a copy of 
the contract or a certification that the contract is on site at the 
source and will be submitted to the Administrator upon written request. 
The contract or contracts may be contingent on the Administrator 
approving the Phase I extension plan.
    (11) For each contract for which a certification is submitted under 
paragraph (c)(10) of this section, a binding letter agreement, signed 
and dated by each party and specifying:

[[Page 57]]

    (i) The type of qualifying Phase I technology to which the contract 
applies;
    (ii) The parties to the contract;
    (iii) The date each party executed the contracts;
    (iv) The unit to which the contract applies;
    (v) A brief list identifying each provision of the contract;
    (vi) Any dates to which the parties agree, including construction 
completion date; and
    (vii) The total dollar amount of the contract.
    (12) A vendor certification of the sulfur dioxide removal efficiency 
guaranteed to be achievable by the qualifying Phase I technology for the 
type and range of fossil fuels (before any treatment prior to 
combustion) that will be used at the control unit; provided that a 
vendor certification shall not be a defense against a control unit's 
failure to achieve 90% control of sulfur dioxide.
    (13) The date (not later than December 31, 1996) on which the owners 
and operators plan to commence operation of the qualifying Phase I 
technology.
    (14) The special provisions of paragraph (f) of this section.
    (d) Contents of Phase I extension plan. A complete Phase I extension 
plan shall include the following elements in a format prescribed by the 
Administrator:
    (1) Identification of each unit in the plan.
    (2)(i) A statement that the elements in the Phase I extension plan 
are identical to those in the previously submitted early ranking 
application for the plan and that such early ranking application is 
incorporated by reference; or
    (ii) All elements that are different from those in the previously 
submitted early ranking application for the plan and a statement that 
the early ranking application is incorporated by reference as modified 
by the newly submitted elements; provided that the Phase I extension 
plan shall not add any new control units or increase the total Phase I 
extension allowances requested; or
    (iii) All elements required for an early ranking application and a 
statement that no early ranking application for the plan was submitted.
    (e) Administrator's action--(1) Early ranking applications. (i) The 
Administrator may approve in whole or in part or with changes or 
conditions, as appropriate, or disapprove an early ranking application.
    (ii) The Administrator will act on each early ranking application in 
the order of receipt.
    (iii) The Administrator will determine the order of receipt by the 
following procedures:
    (A) Hand-delivered submissions and mailed submissions will be deemed 
to have been received on the date they are received by the 
Administrator; provided that all submissions received by the 
Administrator prior to the 40th day after publication of this subpart in 
the Federal Register will be deemed received on the 40th day.
    (B) All submissions received by the Administrator on the same day 
will be deemed to have been received simultaneously.
    (C) The order of receipt of all submissions received simultaneously 
will be determined by a public lottery if allocation of Phase I 
extension reserve allowances to each of the simultaneous submissions 
would result in oversubscription of the Phase I extension reserve.
    (iv) Based on the allowances requested under paragraph (c)(9) of 
this section, as adjusted by the Administrator in approving the early 
ranking application, the Administrator will award Phase I extension 
reserve allowances for each complete early ranking application to the 
extent that allowances that have not been awarded remain in the Phase I 
extension reserve at the time the Administrator acts on the application. 
The allowances will be awarded in accordance with the procedures set 
forth the allocation of reserve allowances in paragraph (e)(3) of this 
section.
    (v) The Administrator's action on an early ranking application shall 
be conditional on the Administrator's action on a timely and complete 
Acid Rain permit application that includes a complete Phase I extension 
plan and, where the plan includes a unit under

[[Page 58]]

paragraph (a)(1) (ii) and (iii) of this section, a complete substitution 
plan or reduced utilization plan, as appropriate.
    (vi) Not later than 15 days after receipt of each early ranking 
application, the Administrator will notify, in writing, the designated 
representative of each application of the date that the early ranking 
application was received and one of the following:
    (A) The award of allowances if the application was complete and the 
Phase I extension reserve as not oversubscribed;
    (B) A determination that the application was incomplete and is 
disapproved; or
    (C) If the Phase I extension reserve was oversubscribed, a list of 
the applications received on that date, the number of Phase I extension 
allowances requested in each application, and the date, time, and 
location of a lottery to determine the order of receipt for all 
applications received on that date.
    (vii) The date of a lottery for all applications received on a given 
day will not be earlier than 15 days after the Administrator notifies 
each designated representative whose applications were received on that 
date.
    (viii) Any early ranking application may be withdrawn from the 
lottery if a letter signed by the designated representative of each unit 
governed by the application and requesting withdrawal is received by the 
Administrator before the lottery takes place.
    (2) Phase I extension plans. (i) The Administrator will act on each 
Phase I extension plan in the order that the early ranking application 
for that plan was received or, if no early ranking application was 
received, in the order that the Phase I extension plan was received, as 
determined under paragraph (e)(1)(iii) of this section.
    (ii) Based on the allowances requested under paragraph (c)(9) of 
this section, as adjusted under paragraph (d) of this section and by the 
Administrator in approving the Phase I extension plan, the Administrator 
will allocate Phase I extension reserve allowances to the Allowance 
Tracking System account of each control and transfer unit upon issuance 
of an Acid Rain permit containing the approved Phase I extension plan. 
The allowances will be allocated using the procedures set forth in 
paragraph (e)(3) of this section.
    (iii) The Administrator will not approve a Phase I extension plan, 
even if it meets the requirements of this section, unless unallocated 
allowances remain in the Phase I extension reserve at the time the 
Administrator acts on the plan.
    (3) Allowance allocations. In addition to any allowances allocated 
in accordance with table 1 of Sec. 73.10(a) of this chapter and other 
approved compliance options, the Administrator will allocate Phase I 
extension reserve allowances to each eligible unit in a Phase I 
extension plan in the following order.
    (i) For 1995, to each control unit in the order in which it is 
listed in the plan and then to each transfer unit in the order in which 
it is listed.
    (ii) For 1996, to each control unit in the order in which it is 
listed in the plan and then to each transfer unit in the order in which 
it is listed.
    (iii) For 1997, to each control unit in the order in which it is 
listed in the plan, then likewise for 1998, and then likewise for 1999.
    (iv) The Administrator will allocate any Phase I extension reserve 
allowances returned to the Administrator to the next Phase I extension 
plan, in the rank order established under paragraph (e)(1)(iii) of this 
section, that continues to meet the requirements of this section and 
this part.
    (f) Special provisions--(1) Emissions Limitations--(i) Sulfur 
Dioxide. (A) If a control or transfer unit governed by an approved Phase 
I extension plan emits in 1997, 1998, or 1999 sulfur dioxide in excess 
of the projected controlled emissions for the unit specified for the 
year under paragraph (c)(7) of this section as adjusted under paragraph 
(d) of this section and by the Administrator in approving the Phase I 
extension plan, the Administrator will deduct allowances equal to such 
exceedence from the unit's annual allowance allocation in the following 
calendar year. \2\
---------------------------------------------------------------------------

    \2\ In the case of a transfer unit that shares a common stack with a 
unit not listed in table 1 of Sec. 73.10(a) of this chapter where the 
units are not monitored separately or apportioned in accordance with 
part 75 of this chapter, the combined emissions of both units will be 
deemed to be the transfer unit's emissions for purposes of applying 
paragraph (f)(1)(i) of this section.

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

[[Page 59]]

    (B) Failure to demonstrate at least a 90% reduction of sulfur 
dioxide in 1997, 1998, or 1999 in accordance with part 75 of this 
chapter at a control unit governed by an approved Phase I extension plan 
shall be a violation of this section. In the event of any such 
violation, in addition to any other liability under the Act, the 
Administrator will deduct allowances from the control unit's compliance 
subaccount for the year of the violation. The deduction will be 
---------------------------------------------------------------------------
calculated as follows:

Allowances deducted = (1 - (percent reduction achieved [middot] 90%)) x 
Phase I extension reserve allowances received

where:

``Percent reduction achieved'' is the percent reduction determined in 
          accordance with part 75 of this chapter.
``Phase I extension reserve allowances received'' is the number of Phase 
          I extension reserve allowances allocated for the year under 
          paragraph (e)(2)(ii) of this section.

    (ii) Nitrogen Oxides. (A) Beginning on January 1, 1997, each control 
and transfer unit shall be subject to the Acid Rain emissions 
limitations for nitrogen oxides.
    (B) Notwithstanding paragraph (f)(1)(ii)(A) of this section, a 
transfer unit shall be subject to the Acid Rain emissions limitations 
for nitrogen oxides, under section 407 of the Act and regulations 
implementing section 407 of the Act, beginning on January 1 of any year 
for which a transfer unit is allocated fewer Phase I extension reserve 
allowances than the maximum amount that the designated representative 
could have requested in accordance with paragraph (c)(5) of this section 
(as adjusted under paragraph (d) of this section and by the 
Administrator in approving the Phase I extension plan) unless the 
transfer unit is the last unit allocated Phase I extension reserve 
allowances under the plan.
    (2) Monitoring requirements. Each control unit shall comply with the 
special monitoring requirements for Phase I extension plans in 
accordance with part 75 of this chapter.
    (3) Reporting requirements. Each control and transfer unit shall 
comply with the special reporting requirements for Phase I extension 
plans in accordance with Sec. 72.93.
    (4) Liability. The owners and operators of a control or transfer 
unit governed by an approved Phase I extension plan shall be liable for 
any violation of the plan or this section at that or any other unit 
governed by the plan, including liability for fulfilling the obligations 
specified in part 77 of this chapter and section 411 of the Act.
    (5) Termination. A Phase I extension plan shall be in effect only in 
Phase I, and no Phase I extension plan shall be terminated before the 
end of Phase I. The designated representative may, however, withdraw a 
Phase I extension plan at any time prior to issuance of the Phase I Acid 
Rain permit that includes the Phase I extension plan, as adjusted.



Sec. 72.43  Phase I reduced utilization plans.

    (a) Applicability. This section shall apply to the designated 
representative of:
    (1) Any Phase I unit, including:
    (i) Any unit listed in table 1 of Sec. 73.10(a) of this chapter; 
and
    (ii) Any other unit that becomes a Phase I unit (including any unit 
designated as a compensating unit under this section or a substitution 
unit under Sec. 72.41).
    (2) Any affected unit that:
    (i) Is not otherwise subject to any Acid Rain emissions limitation 
or emissions reduction requirements during Phase I; and
    (ii) Meets the requirement, as set forth in paragraphs (c)(4)(ii) 
and (d) of this section, that for each year for which the unit is to be 
covered by the reduced utilization plan, the unit's baseline divided by 
2,000 lbs/ton and multiplied by the lesser of the unit's 1985 actual 
SO2 emissions rate or 1985 allowable SO2 emissions 
rate does not exceed the sum of
    (A) The lesser of 10 percent of the amount under paragraph 
(a)(2)(ii) of this section or 200 tons, plus
    (B) The unit's baseline divided by 2,000 lbs/ton and multiplied by 
the lesser of: The greater of the unit's 1989 or

[[Page 60]]

1990 actual SO2 emissions rate; or, as of November 15, 1990, 
the most stringent federally enforceable or State enforceable 
SO2 emissions limitation covering the unit for 1995-1999.
    (b)(1) The designated representative of any unit under paragraph 
(a)(1) of this section shall include in the Acid Rain permit application 
for the unit a reduced utilization plan, meeting the requirements of 
this section, when the owners and operators of the unit plan to:
    (i) Reduce utilization of the unit below the unit's baseline to 
achieve compliance, in whole or in part, with the unit's Phase I Acid 
Rain emissions limitations for sulfur dioxide; and
    (ii) Accomplish such reduced utilization through one or more of the 
following:
    (A) Shifting generation of the unit to a unit under paragraph (a)(2) 
of this section or to a sulfur-free generator; or
    (B) Using one or more energy conservation measures or improved unit 
efficiency measures.
    (2)(i) Energy conservation measures shall be either demand-side 
measures implemented after December 31, 1987 in the residence or 
facility of a customer to whom the unit's utility system sells 
electricity or supply-side measures implemented after December 31, 1987 
in facilities of the unit's utility system.
    (ii) The utility system shall pay in whole or in part for the energy 
conservation measures either directly or, in the case of demand-side 
measures, through payment to another person who purchases the measure.
    (iii) Energy conservation measures shall not include:
    (A) Conservation programs that are exclusively informational or 
educational in nature;
    (B) Load management measures that lead to reduction of electric 
energy demands during a utility's peak generating period, unless 
kilowatt hour savings can be verified under Sec. 72.91(b); or
    (C) Utilization of industrial waste gases, unless the designated 
representative certifies that there is no net increase in sulfur dioxide 
emissions from such utilization.
    (iv) For calendar years when the unit's utility system is a 
subsidiary of a holding company and the unit's dispatch system is or 
includes all units that are interconnected and centrally dispatched and 
included in that holding company, then:
    (A) Energy conservation measures shall be either demand-side 
measures implemented in the residence or facility of a customer to whom 
any utility system in the holding company sells electricity or supply-
side measures implemented in facilities of any utility system in the 
holding company. Such utility system shall pay in whole or in part for 
the measures either directly or, in the case of demand-side measures, 
through payment to another person who purchases the measures.
    (B) The limitations in paragraph (b)(2)(iii) of this section shall 
apply.
    (3)(i) Improved unit efficiency measures shall be implemented in the 
unit after December 31, 1987. Such measures include supply-side measures 
listed in appendix A, section 2.1 of part 73 of this chapter.
    (ii) The utility system shall pay in whole or in part for the 
improved unit efficiency measures.
    (4) The requirement to submit a reduced utilization plan shall apply 
in the event that the owners and operators of a Phase I unit decide, at 
any time during any Phase I calendar year, to rely on the method of 
compliance in paragraph (b)(1) of this section. In that case, the 
designated representative shall submit a reduced utilization plan not 
later than 6 months (or 90 days if sumitted in accordance with Sec. 
72.82 or Sec. 72.83), or a notification to activate a conditionally 
approved plan in accordance with Sec. 72.40(c) not later than 60 days, 
before the allowance transfer deadline applicable to the first year for 
which the plan is to take effect.
    (5) The designated representative of each source with a unit 
designated as a compensating unit in any plan submitted under paragraphs 
(b) (1) or (4) of this section shall incorporate by reference in the 
permit application each such plan.
    (c) Contents of reduced utilization plan. A complete reduced 
utilization plan shall include the following elements in a format 
prescribed by the Administrator:

[[Page 61]]

    (1) Identification of each Phase I unit for which the owners and 
operators plan reduced utilization.
    (2) Except where the designated representative requests conditional 
approval of the plan, the first calendar year and, if known, the last 
calendar year in which the reduced utilization plan is to be in effect. 
Unless the designated representative specifies an earlier calendar year, 
the last calendar year shall be deemed to be 1999.
    (3) A statement whether the plan designates a compensating unit or 
relies on sulfur-free generation, any energy conservation measure, or 
any improved unit efficiency measure to account for any amount of 
reduced utilization.
    (4) If the plan designates a compensating unit, or relies on sulfur-
free generation, to account for any amount of reduced utilization:
    (i) Identification of each compensating unit or sulfur-free 
generator.
    (ii) For each compensating unit. (A) Each of the following: The 
unit's 1985 actual SO2 emissions rate; the unit's 1985 
allowable emissions rate; the unit's 1989 actual SO2 
emissions rate; the unit's 1990 actual SO2 emissions rate; 
and, as of November 15, 1990, the most stringent unit-specific federally 
enforceable or State enforceable SO2 emissions limitation 
covering the unit for 1995-1999. For purposes of determining the most 
stringent emissions limitation, applicable emissions limitations shall 
be converted to lbs/mmBtu in accordance with appendix B of this part. 
Where the most stringent emissions limitation is not the same for every 
year in 1995-1999, the most stringent emissions limitation shall be 
stated separately for each year.
    (B) The unit's baseline divided by 2,000 lbs/ton and multiplied by 
the lesser of the unit's 1985 actual SO2 emissions rate or 
1985 allowable SO2 emissions rate.
    (C) The unit's baseline divided by 2000 lbs/ton and multiplied by 
the lesser of: The greater of the unit's 1989 or 1990 actual 
SO2 emissions rate; or, as of November 15, 1990, the most 
stringent unit-specific federally enforceable or State enforceable 
SO2 emissions limitation covering the unit for 1995-1999. 
Where the most stringent emissions limitation is not the same for every 
year in 1995-1999, the calculation in the prior sentence shall be made 
separately for each year.
    (D) The difference between the amount under paragraph (c)(4)(ii)(B) 
of this section and the amount under paragraph (c)(4)(ii)(C) of this 
section. If the difference calculated in the prior sentence for any year 
exceeds the lesser of 10 percent of the amount under paragraph 
(c)(4)(ii)(B) of this section or 200 tons, the unit shall not be 
designated as a compensating unit for the year. Where the most stringent 
unit-specific federally enforceable or State enforceable SO2 
emissions limitation is not the same for every year in 1995-1999, the 
difference shall be calculated separately for each year.
    (E) The allowance allocation calculated as the amount under 
paragraph (c)(4)(ii)(B) of this section. If the compensating unit is a 
new unit, it shall be deemed to have a baseline of zero and shall be 
allocated no allowances.
    (F) Where, as of November 15, 1990, a non-unit-specific federally 
enforceable or State enforceable SO2 emissions limitation 
covers the unit for any year in 1995-1999, the designated representative 
shall state each such limitation and propose a method for applying unit-
specific and non-unit-specific emissions limitations under paragraph (d) 
of this section.
    (iii) For each sulfur-free generator, identification of any other 
Phase I units that designate the same sulfur-free generator in another 
plan submitted under paragraph (b) (1) or (4) of this section.
    (iv) For each compensating unit or sulfur-free generator not in the 
dispatch system of the unit reducing utilization under the plan, the 
system directives or power purchase agreements or other contractual 
agreements governing the acquisition, by the dispatch system, of the 
electrical energy that is generated by the compensating unit or sulfur-
free generator and on which the plan relies to accomplish reduced 
utilization. Such contractual agreements shall identify the specific 
compensating unit or sulfur-free generator from which the dispatch 
system acquires such electrical energy.
    (5) The special provisions in paragraph (f) of this section.

[[Page 62]]

    (d) Administrator's action. (1) If the Administrator approves the 
reduced utilization plan, he or she will allocate allowances, as 
provided in the approved plan, to the Allowance Tracking System account 
for any designated compensating unit upon issuance of an Acid Rain 
permit containing the plan, except that, if the plan is conditionally 
approved, the allowances will be allocated upon revision of the permit 
to activate the plan.
    (2) Where, as of November 15, 1990, a non-unit-specific federally 
enforceable or State enforceable emissions limitation covers the unit 
for any year during 1995-1999, the Administrator will specify on a case-
by-case basis a method for using unit-specific and non-unit specific 
emissions limitations in approving or disapproving the compensating 
unit. The specified method will not treat a non-unit-specific emissions 
limitation as a unit-specific emissions limitation and will not result 
in compensating units retaining allowances allocated under paragraph 
(d)(1) of this section for emissions reductions necessary to meet a non-
unit-specific emissions limitation. Such method may require an end-of-
year review and the disapproval and de-designation, and adjustment of 
the allowances allocated to, the compensating unit and may require the 
designated representative of the compensating unit to surrender 
allowances by the allowance transfer deadline of the year that is 
subject to the review. Any surrendered allowances shall have the same or 
an earlier compliance use date as the allowances originally allocated 
for the year, and the designated representative may identify the serial 
numbers of the allowances to be deducted. In the absence of such 
identification, such allowances will be deducted on a first-in, first-
out basis under Sec. 73.35(c)(2) of this chapter.
    (e) Failure to submit a plan. The designated representative of a 
Phase I unit will be deemed not to violate, during a Phase I calendar 
year, the requirement to submit a reduced utilization plan under 
paragraph (b)(1) or (4) of this section if the designated representative 
complies with the allowance surrender and other requirements of 
Sec. Sec. 72.33, 72.91, and 72.92 of this chapter.
    (f) Special provisions--(1) Emissions limitations. (i) Any 
compensating unit designated under an approved reduced utilization plan 
shall become a Phase I unit from January 1 of the calendar year in which 
the plan takes effect until January 1 of the year for which the plan is 
no longer in effect or is terminated, except that such unit shall not 
become subject to the Acid Rain emissions limitations for nitrogen 
oxides in Phase I under part 76 of this chapter.
    (ii) The designated representative of any Phase I unit (including a 
unit governed by a reduced utilization plan relying on energy 
conservation, improved unit efficiency, sulfur-free generation, or a 
compensating unit) shall surrender allowances, and the Administrator 
will deduct or return allowances, in accordance with paragraph (d)(2) of 
this section and subpart I of this part.
    (2) Reporting requirements. The designated representative of any 
Phase I unit (including a unit governed by a reduced utilization plan 
relying on energy conservation, improved unit efficiency, sulfur-free 
generation, or a compensating unit) shall comply with the special 
reporting requirements under Sec. Sec. 72.91 and 72.92.
    (3) Liability. The owners and operators of a unit governed by an 
approved reduced utilization plan shall be liable for any violation of 
the plan or this section at that or any other unit governed by the plan, 
including liability for fulfilling the obligations specified in part 77 
of this chapter and section 411 of the Act.
    (4) Termination. (i) A reduced utilization plan shall be in effect 
only in Phase I for the calendar years specified in the plan or until 
the calendar year for which a termination of the plan takes effect; 
provided that no reduced utilization plan that designates a compensating 
unit that serves as a control unit under a Phase I extension plan shall 
be terminated, and no such unit shall be de-designated as a compensating 
unit, before the end of Phase I.
    (ii) To terminate a reduced utilization plan for a given calendar 
year prior to its last year for which the plan was approved:

[[Page 63]]

    (A) A notification to terminate in accordance with Sec. 72.40(d) 
shall be submitted no later than 60 days before the allowance transfer 
deadline applicable to the given year; and
    (B) In the notification to terminate, the designated representative 
of any compensating unit governed by the plan shall state that he or she 
surrenders for deduction from the unit's Allowance Tracking System 
account allowances equal in number to, and with the same or an earlier 
compliance use date as, those allocated under paragraph (d) of this 
section to each compensating unit for the calendar years for which the 
plan is to be terminated. The designated representative may identify the 
serial numbers of the allowances to be deducted. In the absence of such 
identification, allowances will be deducted on a first-in, first-out 
basis under Sec. 73.35(c)(2) of this chapter.
    (iii) If the requirements of paragraph (f)(3)(ii) are met and upon 
revision of the permit to terminate the reduced utilization plan, the 
Administrator will deduct the allowances specified in paragraph 
(f)(3)(ii)(B) of this section. No reduced utilization plan shall be 
terminated, and no unit shall be de-designated as a Phase I unit, unless 
such deduction is made.

[58 FR 3650, Jan. 11, 1993, as amended at 59 FR 60230, Nov. 22, 1994; 60 
FR 18470, Apr. 11, 1995; 62 FR 55481, Oct. 24, 1997]



Sec. 72.44  Phase II repowering extensions.

    (a) Applicability. (1) This section shall apply to the designated 
representative of:
    (i) Any existing affected unit that is a coal-fired unit and has a 
1985 actual SO2 emissions rate equal to or greater than 1.2 
lbs/mmBtu.
    (ii) Any new unit that will be a replacement unit, as provided in 
paragraph (b)(2) of this section, for a unit meeting the requirements of 
paragraph (a)(1)(i) of this section.
    (iii) Any oil and/or gas-fired unit that has been awarded clean coal 
technology demonstration funding as of January 1, 1991 by the Secretary 
of Energy.
    (2) A repowering extension does not exempt the owner or operator for 
any unit governed by the repowering plan from the requirement to comply 
with such unit's Acid Rain emissions limitations for sulfur dioxide.
    (b) The designated representative of any unit meeting the 
requirements of paragraph (a)(1)(i) of this section may include in the 
unit's Phase II Acid Rain permit application a repowering extension plan 
that includes a demonstration that:
    (1) The unit will be repowered with a qualifying repowering 
technology in order to comply with the Phase II emissions limitations 
for sulfur dioxide; or
    (2) The unit will be replaced by a new utility unit that has the 
same designated representative and that is located at a different site 
using a qualified repowering technology and the existing unit will be 
permanently retired from service on or before the date on which the new 
utility unit commences commercial operation.
    (c) In order to apply for a repowering extension, the designated 
representative of a unit under paragraph (a) of this section shall:
    (1) Submit to the permitting authority, by January 1, 1996, a 
complete repowering extension plan;
    (2) Submit to the Administrator, before June 1, 1997, a complete 
petition for approval of repowering technology; and
    (3) If the repowering extension plan is submitted for conditional 
approval, submit by December 31, 1997, a notification to activate the 
plan in accordance with Sec. 72.40(c).
    (d) Contents and Review of Petition for Approval of Repowering 
Technology. (1) A complete petition for approval of repowering 
technology shall include the following elements, in a format prescribed 
by the Administrator, concerning the technology to be used in a plan 
under paragraph (b) of this section and may follow the repowering 
technology demonstration protocol issued by the Administrator:
    (i) Identification and description of the technology.
    (ii) Vendor certification of the guaranteed performance 
characteristics of the technology, including:
    (A) Percent removal and emission rate of each pollutant being 
controlled;
    (B) Overall generation efficiency; and

[[Page 64]]

    (C) Information on the state, chemical constituents, and quantities 
of solid waste generated (including information on land-use requirements 
for disposal) and on the availability of a market to which any by-
products may be sold.
    (iii) If the repowering technology is not listed in the definition 
of a qualified repowering technology in Sec. 72.2, a vendor 
certification of the guaranteed performance characteristics that 
demonstrate that the technology meets the criteria specified for non-
listed technologies in Sec. 72.2; provided that the existence of such 
guarantee shall not be a defense against the failure to meet the 
criteria for non-listed technologies.
    (2) The Administrator may request any supplemental information that 
is deemed necessary to review the petition for approval of repowering 
technology.
    (3) The Administrator shall review the petition for approval of 
repowering technology and, in consultation with the Secretary of Energy, 
shall make a conditional determination of whether the technology 
described in the petition is a qualifying repowering technology.
    (4) Based on the petition for approval of repowering technology and 
the information provided under paragraph (d)(2) of this section and 
Sec. 72.94(a), the Administrator will make a final determination of 
whether the technology described in the petition is a qualifying 
repowering technology.
    (e) Contents of repowering extension plan. A complete repowering 
extension plan shall include the following elements in a format 
prescribed by the Administrator:
    (1) Identification of the existing unit governed by the plan.
    (2) The unit's federally-approved State Implementation Plan sulfur 
dioxide emissions limitation.
    (3) The unit's 1995 actual SO2 emissions rate.
    (4) A schedule for construction, installation, and commencement of 
operation of the repowering technology approved or submitted for 
approval under paragraph (d) of this section, with dates for the 
following milestones:
    (i) Completion of design engineering;
    (ii) For a plan under paragraph (b)(1) of this section, removal of 
the existing unit from operation to install the qualified repowering 
technology;
    (iii) Commencement of construction;
    (iv) Completion of construction;
    (v) Start-up testing;
    (vi) For a plan under paragraph (b)(2) of this section, shutdown of 
the existing unit; and
    (vii) Commencement of commercial operation of the repowering 
technology.
    (5) For a plan under paragraph (b)(2) of this section:
    (i) Identification of the new unit. A new unit shall not be included 
in more than one repowering extension plan.
    (ii) Certification that the new unit will replace the existing unit.
    (iii) Certification that the new unit has the same designated 
representative as the existing unit.
    (iv) Certification that the existing unit will be permanently 
retired from service on or before the date the new unit commences 
commercial operation.
    (6) The special provisions of paragraph (h) of this section.
    (f) Permitting authority's action on repowering extension plan. (1) 
The permitting authority shall not approve a repowering extension plan 
until the Administrator makes a conditional determination that the 
technology is a qualified repowering technology, unless the permitting 
authority conditionally approves such plan subject to the conditional 
determination of the Administrator.
    (2) Permit issuance. (i) Upon a conditional determination by the 
Administrator that the technology to be used in the repowering extension 
plan is a qualified repowering technology and a determination by the 
permitting authority that such plan meets the requirements of this 
section, the permitting authority shall issue the Acid Rain portion of 
the operating permit including:
    (A) The approved repowering extension plan; and
    (B) A schedule of compliance with enforceable milestones for 
construction, installation, and commencement of operation of the 
repowering technology and other requirements necessary to

[[Page 65]]

ensure that Phase II emission reduction requirements under this section 
will be met.
    (ii) Except as otherwise provided in paragraph (g) of this section, 
the repowering extension shall be in effect starting January 1, 2000 and 
ending on the day before the date (specified in the Acid Rain permit) on 
which the existing unit will be removed from operation to install the 
qualifying repowering technology or will be permanently removed from 
service for replacement by a new unit with such technology; provided 
that the repowering extension shall end no later than December 31, 2003.
    (iii) The portion of the operating permit specifying the repowering 
extension and other requirements under paragraph (f)(2)(i) of this 
section shall be subject to the Administrator's final determination, 
under paragraph (d)(4) of this section, that the technology to be used 
in the repowering extension plan is a qualifying repowering technology.
    (3) Allowance allocation. The Administrator will allocate allowances 
after issuance of an operating permit containing the repowering 
extension plan (or, if the plan is conditionally approved, after the 
revision of the Acid Rain permit under Sec. 72.40(c)) and of the 
Administrator's final determination, under paragraph (d)(4) of this 
section, that the technology to be used in such plan is a qualifying 
repowering technology. Allowances will be allocated (including a pro 
rata allocation for any fraction of a year), as follows:
    (i) To the existing unit under the approved plan, in accordance with 
Sec. 73.21 of this chapter during the repowering extension under 
paragraph (f)(2)(ii) of this section; and
    (ii) To the existing unit under the approved plan under paragraph 
(b)(1) of this section or, in lieu of any further allocations to the 
existing unit, to the new unit under the approved plan under paragraph 
(b)(2) of this section, in accordance with Sec. 73.21 of this chapter, 
after the repowering extension under paragraph (f)(2)(ii) of this 
section ends.
    (g) Failed repowering projects. (1)(i) If, at any time before the 
end of the repowering extension under paragraph (f)(2)(ii) of this 
section, the designated representative of a unit governed by an approved 
repowering extension plan notifies the Administrator in writing that the 
owners and operators have decided to terminate efforts to properly 
design, construct, and test the repowering technology specified in the 
plan before completion of construction or start-up testing and 
demonstrates, in a requested permit modification, to the Administrator's 
satisfaction that such efforts were in good faith, the unit shall not be 
deemed in violation of the Act because of such a termination. If the 
Administrator is not the permitting authority, a copy of the requested 
permit modification shall be sumitted to the Administrator. Where the 
preceding requirements of this paragraph are met, the permitting 
authority shall revise the operating permit in accordance with this 
paragraph and paragraph (g)(1)(ii) of this section and Sec. 72.81 
(permit modification).
    (ii) Regardless of whether notification under paragraph (g)(1)(i) of 
this section is given, the repowering extension will end beginning on 
the earlier of the date of such notification or the date by which the 
designated representative was required to give such notification under 
Sec. 72.94(d). The Administrator will deduct allowances (including a 
pro rata deduction for any fraction of a year) from the Allowance 
Tracking System account of the existing unit to the extent necessary to 
ensure that, beginning the day after the extension ends, allowances are 
allocated in accordance with Sec. 73.21(c)(1) of this chapter.
    (2) If the designated representative of a unit governed by an 
approved repowering extension plan demonstrates to the satisfaction of 
the Administrator, in a requested permit modification, that the 
repowering technology specified in the plan was properly constructed and 
tested on such unit but was unable to achieve the emissions reduction 
limitations specified in the plan and that it is economically or 
technologically infeasible to modify the technology to achieve such 
limits, the unit shall not be deemed in violation of the Act because of 
such failure to achieve the emissions reduction limitations. If the 
Administrator

[[Page 66]]

is not the permitting authority, a copy of the requested permit 
modification shall be sumitted to the Administrator. In order to be 
properly constructed and tested, the repowering technology shall be 
constructed at least to the extent necessary for direct testing of the 
multiple combustion emissions (including sulfur dioxide and nitrogen 
oxides) from such unit while operating the technology at nameplate 
capacity. Where the preceding requirements of this paragraph are met:
    (i) The permitting authority shall revise the Acid Rain portion of 
the operating permit in accordance with paragraphs (g)(2) (ii) and (iii) 
and Sec. 72.81 (permit modification).
    (ii) The existing unit may be retrofitted or repowered with another 
clean coal or other available control technology.
    (iii) The repowering extension will continue in effect until the 
earlier of the date the existing unit commences commercial operation 
with such control technology or December 31, 2003. The Administrator 
will allocate or deduct allowances as necessary to ensure that 
allowances are allocated in accordance with paragraph (f)(3) of this 
section applying the repowering extension under this paragraph.
    (h) Special provisions--(1) Emissions Limitations. (i) Sulfur 
Dioxide. Allowances allocated during the repowering extension under 
paragraphs (f)(3) and (g)(2)(iii) of this section to a unit governed by 
an approved repowering extension plan shall not be transferred to any 
Allowance Tracking System account other than the unit accounts of other 
units at the same source as that unit.
    (ii) Nitrogen oxides. Any existing unit governed by an approved 
repowering extension plan shall be subject to the Acid Rain emissions 
limitations for nitrogen oxides in accordance with part 76 of this 
chapter beginning on the date that the unit is removed from operation to 
install the repowering technology or is permanently removed from 
service.
    (iii) No existing unit governed by an approved repowering extension 
plan shall be eligible for a waiver under section 111(j) of the Act.
    (iv) No new unit governed by an approved repowering extension plan 
shall receive an exemption from the requirements imposed under section 
111 of the Act.
    (2) Reporting requirements. Each unit governed by an approved 
repowering extension plan shall comply with the special reporting 
requirements of Sec. 72.94.
    (3) Liability. (i) The owners and operators of a unit governed by an 
approved repowering plan shall be liable for any violation of the plan 
or this section at that or any other unit governed by the plan, 
including liability for fulfilling the obligations specified in part 77 
of this chapter and section 411 of the Act.
    (ii) The units governed by the plan under paragraph (b)(2) of this 
section shall continue to have a common designated representative until 
the existing unit is permanently retired under the plan.
    (4) Terminations. Except as provided in paragraph (g) of this 
section, a repowering extension plan shall not be terminated after 
December 31, 1999.

[58 FR 3650, Jan. 11, 1993, as amended at 58 FR 15649, Mar. 23, 1993; 62 
FR 55481, Oct. 24, 1997]



                   Subpart E_Acid Rain Permit Contents



Sec. 72.50  General.

    (a) Each Acid Rain permit (including any draft or proposed Acid Rain 
permit) will contain the following elements in a format prescribed by 
the Administrator:
    (1) All elements required for a complete Acid Rain permit 
application under Sec. 72.31 of this part, as approved or adjusted by 
the permitting authority;
    (2) The applicable Acid Rain emissions limitation for sulfur 
dioxide; and
    (3) The applicable Acid Rain emissions limitation for nitrogen 
oxides.
    (b) Each Acid Rain permit is deemed to incorporate the definitions 
of terms under Sec. 72.2 of this part.



Sec. 72.51  Permit shield.

    Each affected unit operated in accordance with the Acid Rain permit 
that governs the unit and that was issued in compliance with title IV of

[[Page 67]]

the Act, as provided in this part and parts 73, 74, 75, 76, 77, and 78 
of this chapter shall be deemed to be operating in compliance with the 
Acid Rain Program, except as provided in Sec. 72.9(g)(6).

[58 FR 3650, Jan. 11, 1993, as amended at 62 FR 55481, Oct. 24, 1997]



         Subpart F_Federal Acid Rain Permit Issuance Procedures



Sec. 72.60  General.

    (a) Scope. This subpart and parts 74, 76, and 78 of this chapter 
contain the procedures for federal issuance of Acid Rain permits for 
Phase I of the Acid Rain Program and Phase II for sources for which the 
Administrator is the permitting authority under Sec. 72.74.
    (1) Notwithstanding the provisions of part 71 of this chapter, the 
provisions of subparts C, D, E, F, and H of this part and of parts 74, 
76, and 78 of this chapter shall govern the following requirements for 
Acid Rain permit applications and permits: submission, content, and 
effect of permit applications; content and requirements of compliance 
plans and compliance options; content of permits and permit shield; 
procedures for determining completeness of permit applications; issuance 
of draft permits; administrative record; public notice and comment and 
public hearings on draft permits; response to comments on draft permits; 
issuance and effectiveness of permits; permit revisions; and 
administrative appeal procedures. The provisions of part 71 of this 
chapter concerning Indian tribes, delegation of a part 71 program, 
affected State review of draft permits, and public petitions to reopen a 
permit for cause shall apply to Acid Rain permit applications and 
permits.
    (2) The procedures in this subpart do not apply to the issuance of 
Acid Rain permits by State permitting authorities with operating permit 
programs approved under part 70 of this chapter, except as expressly 
provided in subpart G of this part.
    (b) Permit Decision Deadlines. Except as provided in Sec. 
72.74(c)(1)(i), the Administrator will issue or deny an Acid Rain permit 
under Sec. 72.69(a) within 6 months of receipt of a complete Acid Rain 
permit application submitted for a unit, in accordance with Sec. 72.21, 
at the U.S. EPA Regional Office for the Region in which the source is 
located.
    (c) Use of Direct Final Procedures. The Administrator may, in his or 
her discretion, issue, as single document, a draft Acid Rain permit in 
accordance with Sec. 72.62 and an Acid Rain permit in final form and 
may provide public notice of the opportunity for public comment on the 
draft Acid Rain permit in accordance with Sec. 72.65. The Administrator 
may provide that, if no significant, adverse comment on the draft Acid 
Rain permit is timely submitted, the Acid Rain permit will be deemed to 
be issued on a specified date without further notice and, if such 
significant, adverse comment is timely submitted, an Acid Rain permit or 
denial of an Acid Rain permit will be issued in accordance with Sec. 
72.69. Any notice provided under this paragraph (c) will include a 
description of the procedure in the prior sentence.

[62 FR 55481, Oct. 24, 1997]



Sec. 72.61  Completeness.

    (a) Determination of Completeness. The Administrator will determine 
whether the Acid Rain permit application is complete within 60 days of 
receipt by the U.S. EPA Regional Office for the Region in which the 
source is located. The permit application shall be deemed to be complete 
if the Administrator fails to notify the designated representative to 
the contrary within 60 days of receipt.
    (b) Supplemental Information. (1) Regardless of whether the Acid 
Rain permit application is complete under paragraph (a) of this section, 
the Administrator may require submission of any additional information 
that the Administrator determines to be necessary in order to review the 
Acid Rain permit application and issue an Acid Rain permit.
    (2)(i) Within a reasonable period determined by the Administrator, 
the designated representative shall submit the information required 
under paragraph (b)(1) of this section.

[[Page 68]]

    (ii) If the designated representative fails to submit the 
supplemental information within the required time period, the 
Administrator may disapprove that portion of the Acid Rain permit 
application for the review of which the information was necessary and 
may deny the source an Acid Rain permit.
    (3) Any designated representative who fails to submit any relevant 
information or who has submitted incorrect information in a permit 
application shall, upon becoming aware of such failure or incorrect 
submittal, promptly submit such supplementary information or corrected 
information to the Administrator.

[58 FR 3650, Jan. 11, 1993, as amended at 62 FR 55481, Oct. 24, 1997]



Sec. 72.62  Draft permit.

    (a) After the Administrator receives a complete Acid Rain permit 
application and any supplemental information, the Administrator will 
issue a draft permit that incorporates in whole, in part, or with 
changes or conditions as appropriate, the permit application or deny the 
source a draft permit.
    (b) The draft permit will be based on the information submitted by 
the designated representative of the affected source and other relevant 
information.
    (c) The Administrator will serve a copy of the draft permit and the 
statement of basis on the designated representative of the affected 
source.
    (d) The Administrator will provide a 30-day period for public 
comment, and opportunity to request a public hearing, on the draft 
permit or denial of a draft permit, in accordance with the public notice 
required under Sec. 72.65(a)(1)(i) of this part.



Sec. 72.63  Administrative record.

    (a) Contents of the Administrative Record. The Administrator will 
prepare an administrative record for an Acid Rain permit or denial of an 
Acid Rain permit. The administrative record will contain:
    (1) The permit application and any supporting or supplemental data 
submitted by the designated representative;
    (2) The draft permit;
    (3) The statement of basis;
    (4) Copies of any documents cited in the statement of basis and any 
other documents relied on by the Administrator in issuing or denying the 
draft permit (including any records of discussions or conferences with 
owners, operators, or the designated representative of affected units at 
the source or interested persons regarding the draft permit), or, for 
any such documents that are readily available, a statement of their 
location;
    (5) Copies of all written public comments submitted on the draft 
permit or denial of a draft permit;
    (6) The record of any public hearing on the draft permit or denial 
of a draft permit;
    (7) The Acid Rain permit; and
    (8) Any response to public comments submitted on the draft permit or 
denial of a draft permit and copies of any documents cited in the 
response and any other documents relied on by the Administrator to issue 
or deny the Acid Rain permit, or, for any such documents that are 
readily available, a statement of their location.
    (b) [Reserved]



Sec. 72.64  Statement of basis.

    (a) The statement of basis will briefly set forth significant 
factual, legal, and policy considerations on which the Administrator 
relied in issuing or denying the draft permit.
    (b) The statement of basis will include:
    (1) The reasons, and supporting authority, for approval or 
disapproval of any compliance options requested in the permit 
application, including references to applicable statutory or regulatory 
provisions and to the administrative record; and
    (2) The name, address, and telephone, and facsimile numbers of the 
EPA office processing the issuance or denial of the draft permit.



Sec. 72.65  Public notice of opportunities for public comment.

    (a)(1) The Administrator will give public notice of the following:
    (i) The draft permit or denial of a draft permit and the opportunity 
for public review and comment and to request a public hearing; and

[[Page 69]]

    (ii) Date, time, location, and procedures for any scheduled hearing 
on the draft permit or denial of a draft permit.
    (2) Any public notice given under this section may be for the 
issuance or denial of one or more draft permits.
    (b) Methods. The Administrator will give the public notice required 
by this section by:
    (1) Serving written notice on the following persons (except where 
such person has waived his or her right to receive such notice):
    (i) The designated representative;
    (ii) The air pollution control agencies of affected States; and
    (iii) Any interested person.
    (2) Giving notice by publication in the Federal Register and in a 
newspaper of general circulation in the area where the source covered by 
the Acid Rain permit application is located or in a State publication 
designed to give general public notice. Notwithstanding the prior 
sentence, if a draft permit requires the affected units at a source to 
comply with Sec. 72.9(c)(1) and to meet any applicable emission 
limitation for NOX under Sec. Sec. 76.5, 76.6, 76.7, 76.8, 
or 76.11 of this chapter and does not include for any unit a compliance 
option under Sec. 72.44, part 74 of this chapter, or Sec. 76.10 of 
this chapter, the Administrator may, in his or her discretion, provide 
notice of the draft permit by Federal Register publication and may omit 
notice by newspaper or State publication.
    (c) Contents. All public notices issued under this section will 
contain the following information:
    (1) Identification of the EPA office processing the issuance or 
denial of the draft permit for which the notice is being given.
    (2) Identification of the designated representative for the affected 
source.
    (3) Identification of each unit covered by the Acid Rain permit 
application and the draft permit.
    (4) Any compliance options proposed for approval in the draft permit 
or for disapproval and the total allowances (including any under the 
compliance options) allocated to each unit if the Acid Rain permit 
application is approved.
    (5) The address and office hours of a public location where the 
administrative record is available for public inspection and a statement 
that all information submitted by the designated representative and not 
protected as confidential under section 114(c) of the Act is available 
for public inspection as part of the administrative record.
    (6) For public notice under paragraph (a)(1)(i) of this section, a 
brief description of the public comment procedures, including:
    (i) A 30-day period for public comment beginning the date of 
publication of the notice or, in the case of an extension or reopening 
of the public comment period, such period as the Administrator deems 
appropriate;
    (ii) The address where public comments should be sent;
    (iii) Required formats and contents for public comment;
    (iv) An opportunity to request a public hearing to occur not earlier 
than 15 days after public notice is given and the location, date, time, 
and procedures of any scheduled public hearing; and
    (v) Any other means by which the public may participate.
    (d) Extensions and Reopenings of the Public Comment Period. On the 
Administrator's own motion or on the request of any person, the 
Administrator may, at his or her discretion, extend or reopen the public 
comment period where he or she finds that doing so will contribute to 
the decision-making process by clarifying one or more significant issues 
affecting the draft permit or denial of a draft permit. Notice of any 
such extension or reopening shall be given under paragraph (a)(1)(i) of 
this section.

[58 FR 3650, Jan. 11, 1993, as amended at 62 FR 55482, Oct. 24, 1997]



Sec. 72.66  Public comments.

    (a) General. During the public comment period, any person may submit 
written comments on the draft permit or the denial of a draft permit.
    (b) Form. (1) Comments shall be submitted in duplicate.
    (2) The submission shall clearly indicate the draft permit issuance 
or denial to which the comments apply.

[[Page 70]]

    (3) The submission shall clearly indicate the name of the person 
commenting, his or her interest in the matter, and his or her 
affiliation, if any, to owners and operators of any unit covered by the 
Acid Rain permit application.
    (c) Contents. Timely comments on any aspect of the draft permit or 
denial or a draft permit will be considered unless they concern:
    (1) Any standard requirement under Sec. 72.9;
    (2) Issues that are not relevant, such as:
    (i) The environmental effects of acid rain, acid deposition, sulfur 
dioxide, or nitrogen oxides generally; and
    (ii) Permit issuance procedures, or actions on other permit 
applications, that are not relevant to the draft permit issuance or 
denial in question.
    (d) Persons who do not wish to raise issues concerning the issuance 
or denial of the draft permit, but who wish to be notified of any 
subsequent actions concerning such matter may so indicate in writing 
during the public comment period or at any other time. The Administrator 
will place their names on a list of interested persons.



Sec. 72.67  Opportunity for public hearing.

    (a) During the public comment period, any person may request a 
public hearing. A request for a public hearing shall be made in writing 
and shall state the issues proposed to be raised in the hearing.
    (b) On the Administrator's own motion or on the request of any 
person, the Administrator may, at his or her discretion, hold a public 
hearing whenever the Administrator finds that such a hearing will 
contribute to the decision-making process by clarifying one or more 
significant issues affecting the draft permit or denial of a draft 
permit. Public hearings will not be held on issues under Sec. 72.66(c) 
(1) and (2).
    (c) During a public hearing under this section, any person may 
submit oral or written comments concerning the draft permit or denial of 
a draft permit. The Administrator may set reasonable limits on the time 
allowed for oral statements and will require the submission of a written 
summary of each oral statement.
    (d) The Administrator will assure that a record is made of the 
hearing.



Sec. 72.68  Response to comments.

    (a) The Administrator will consider comments on the draft permit or 
denial of a draft permit that are received during the public comment 
period and any public hearing. The Administrator is not required to 
consider comments otherwise received.
    (b) In issuing or denying an Acid Rain permit, the Administrator 
will:
    (1) Identify any permit provision or portion of the statement of 
basis that has been changed and the reasons for the change; and
    (2) Briefly describe and respond to relevant comments under 
paragraph (a) of this section.



Sec. 72.69  Issuance and effective date of acid rain permits.

    (a) After the close of the public comment period, the Administrator 
will issue or deny an Acid Rain permit. The Administrator will serve a 
copy of any Acid Rain permit and the response to comments on the 
designated representative for the source covered by the issuance or 
denial and serve written notice of the issuance or denial on the air 
pollution control agencies of affected States and any interested person. 
The Administrator will also give notice in the Federal Register.
    (b)(1) The term of every Acid Rain permit shall be 5 years 
commencing on its effective date.
    (2) Every Acid Rain permit for Phase I shall take effect on January 
1, 1995.

[58 FR 3650, Jan. 11, 1993, as amended at 62 FR 55482, Oct. 24, 1997]



               Subpart G_Acid Rain Phase II Implementation



Sec. 72.70  Relationship to title V operating permit program.

    (a) Scope. This subpart sets forth criteria for approval of State 
operating permit programs and acceptance of State Acid Rain programs, 
the procedure for including State Acid Rain programs in a title V 
operating permit program, and the requirements with which State 
permitting authorities with accepted programs shall comply,

[[Page 71]]

and with which the Administrator will comply in the absence of an 
accepted State program, to issue Phase II Acid Rain permits.
    (b) Relationship to operating permit program. Each State permitting 
authority with an affected source shall act in accordance with this part 
and parts 70, 74, 76, and 78 of this chapter for the purpose of 
incorporating Acid Rain Program requirements into each affected source's 
operating permit . To the extent that this part or part 74, 76, or 78 of 
this chapter is inconsistent with the requirements of part 70 of this 
chapter, this part and parts 74, 76, and 78 of this chapter shall take 
precedence and shall govern the issuance, denial, revision, reopening, 
renewal, and appeal of the Acid Rain portion of an operating permit.

[62 FR 55482, Oct. 24, 1997, as amended at 66 FR 12978, Mar. 1, 2001]



Sec. 72.71  Acceptance of State Acid Rain programs--general.

    (a) Each State shall submit, to the Administrator for review and 
acceptance, a State Acid Rain program meeting the requirements of 
Sec. Sec. 72.72 and 72.73.
    (b) The Administrator will review each State Acid Rain program or 
portion of a State Acid Rain program and accept, by notice in the 
Federal Register, all or a portion of such program to the extent that it 
meets the requirements of Sec. Sec. 72.72 and 72.73. At his or her 
discretion, the Administrator may accept, with conditions and by notice 
in the Federal Register, all or a portion of such program despite the 
failure to meet requirements of Sec. Sec. 72.72 and 72.73. On the later 
of the date of publication of such notice in the Federal Register or the 
date on which the State operating permit program is approved under part 
70 of this chapter, the State Acid Rain program accepted by the 
Administrator will become a portion of the approved State operating 
permit program. Before accepting or rejecting all or a portion of a 
State Acid Rain Program, the Administrator will provide notice and 
opportunity for public comment on such acceptance or rejection.
    (c)(1) Except as provided in paragraph (c)(2) of this section, the 
Administrator will issue all Acid Rain permits for Phase I. The 
Administrator reserves the right to delegate the remaining 
administration and enforcement of Acid Rain permits for Phase I to 
approved State operating permit programs.
    (2) The State permitting authority will issue an opt-in permit for a 
combustion or process source subject to its jurisdiction if, on the date 
on which the combustion or process source submits an opt-in permit 
application, the State permitting authority has opt-in regulations 
accepted under paragraph (b) of this section and an approved operating 
permits program under part 70 of this chapter.

[62 FR 55482, Oct. 24, 1997]



Sec. 72.72  Criteria for State operating permit program.

    A State operating permit program (including a State Acid Rain 
program) shall meet the following criteria. Any aspect of a State 
operating permits program or any implementation of a State operating 
permit program that fails to meet these criteria shall be grounds for 
nonacceptance or withdrawal of all or part of the Acid Rain portion of 
an approved State operating permit program by the Administrator or for 
disapproval or withdrawal of approval of the State operating permit 
program by the Administrator.
    (a) Non-Interference with Acid Rain Program. The State operating 
permit program shall not include or implement any measures that would 
interfere with the Acid Rain Program. In particular, the State program 
shall not restrict or interfere with allowance trading and shall not 
interfere with the Administrator's decision on an offset plan. Aspects 
and implementation of the State program that would constitute 
interference with the Acid Rain Program, and are thus prohibited, 
include but are not limited to:
    (1) Prohibitions, inconsistent with the Acid Rain Program, on the 
acquisition or transfer of allowances by an affected unit or affected 
source under the jurisdiction of the State permitting authority;
    (2) Restrictions, inconsistent with the Acid Rain Program, on an 
affected unit's or an affected source's ability to

[[Page 72]]

sell or otherwise obligate its allowances;
    (3) Requirements that an affected unit or affected source maintain a 
balance of allowances in excess of the level determined to be prudent by 
any utility regulatory authority with jurisdiction over the owners of 
the affected unit or affected source;
    (4) Failing to notify the Administrator of any State administrative 
or judicial appeals of, or decisions covering, Acid Rain permit 
provisions that might affect Acid Rain Program requirements;
    (5) Issuing an order, inconsistent with the Acid Rain Program, 
interpreting Acid Rain Program requirements as not applicable to an 
affected source or an affected unit in whole or in part or otherwise 
adjusting the requirements;
    (6) Withholding approval of any compliance option that meets the 
requirements of the Acid Rain Program; or
    (7) Any other aspect of implementation that the Administrator 
determines would hinder the operation of the Acid Rain Program.
    (b) The State operating permit program shall require the following 
provisions, which are adopted to the extent that this paragraph (b) is 
incorporated by reference or is otherwise included in the State 
operating permit program.
    (1) Acid Rain Permit Issuance. Issuance or denial of Acid Rain 
permits shall follow the procedures under this part, part 70 of this 
chapter, and, for combustion or process sources, part 74, including:
    (i) Permit application--(A) Requirement to comply. (1) The owners 
and operators and the designated representative for each affected 
source, except for combustion or process sources, under jurisdiction of 
the State permitting authority shall be required to comply with subparts 
B, C, and D of this part.
    (2) The owners and operators and the designated representative for 
each combustion or process source under jurisdiction of the State 
permitting authority shall be required to comply with subpart B of this 
part and subparts B, C, D, and E of part 74 of this chapter.
    (B) Effect of an Acid Rain permit application. A complete Acid Rain 
permit application, except for a permit application for a combustion or 
process source, shall be binding on the owners and operators and the 
designated representative of the affected source, all affected units at 
the source, and any other unit governed by the permit application and 
shall be enforceable as an Acid Rain permit, from the date of submission 
of the permit application until the issuance or denial of the Acid Rain 
permit under paragraph (b)(1)(vii) of this section.
    (ii) Draft Permit. (A) The State permitting authority shall prepare 
the draft Acid Rain permit in accordance with subpart E of this part and 
part 76 of this chapter or, for a combustion or process source, with 
subpart B of part 74 of this chapter, or deny a draft Acid Rain permit.
    (B) Prior to issuance of a draft permit for a combustion or process 
source, the State permitting authority shall provide the designated 
representative of a combustion or process source an opportunity to 
confirm its intention to opt-in, in accordance with Sec. 74.14 of this 
chapter.
    (iii) Public Notice and Comment Period. Public notice of the 
issuance or denial of the draft Acid Rain permit and the opportunity to 
comment and request a public hearing shall be given by publication in a 
newspaper of general circulation in the area where the source is located 
or in a State publication designed to give general public notice. 
Notwithstanding the prior sentence, if a draft permit requires the 
affected units at a source to comply with Sec. 72.9(c)(1) and to meet 
any applicable emission limitation for NOX under Sec. Sec. 
76.5, 76.6, 76.7, 76.8, or 76.11 of this chapter and does not include 
for any unit a compliance option under Sec. 72.44, part 74 of this 
chapter, or Sec. 76.10 of this chapter, the State permitting authority 
may, in its discretion, provide notice by serving notice on persons 
entitled to receive a written notice and may omit notice by newspaper or 
State publication.
    (iv) Proposed permit. The State permitting authority shall 
incorporate all changes necessary and issue a proposed Acid Rain permit 
in accordance with subpart E of this part and part 76 of this chapter 
or, for a combustion or

[[Page 73]]

process source, with subpart B of part 74 of this chapter, or deny a 
proposed Acid Rain permit.
    (v) Direct proposed procedures. The State permitting authority may, 
in its discretion, issue, as a single document, a draft Acid Rain permit 
in accordance with paragraph (b)(1)(ii) of this section and a proposed 
Acid Rain permit and may provide public notice of the opportunity for 
public comment on the draft Acid Rain permit in accordance with 
paragraph (b)(1)(iii) of this section. The State permitting authority 
may provide that, if no significant, adverse comment on the draft Acid 
Rain permit is timely submitted, the proposed Acid Rain permit will be 
deemed to be issued on a specified date without further notice and, if 
such significant, adverse comment is timely submitted, a proposed Acid 
Rain permit or denial of a proposed Acid Rain permit will be issued in 
accordance with paragraph (b)(1)(iv) of this section. Any notice 
provided under this paragraph (b)(1)(v) shall include a description of 
the procedure in the prior sentence.
    (vi) Acid Rain Permit Issuance. Following the Administrator's review 
of the proposed Acid Rain permit, the State permitting authority shall 
or, under part 70 of this chapter, the Administrator will, incorporate 
any required changes and issue or deny the Acid Rain permit in 
accordance with subpart E of this part and part 76 of this chapter or, 
for a combustion or process source, with subpart B of part 74 of this 
chapter.
    (vii) New Owners. An Acid Rain permit shall be binding on any new 
owner or operator or designated representative of any source or unit 
governed by the permit.
    (viii) Each Acid Rain permit (including a draft or proposed permit) 
shall contain all applicable Acid Rain requirements, shall be a complete 
and segregable portion of the operating permit, and shall not 
incorporate information contained in any other documents, other than 
documents that are readily available.
    (ix) No Acid Rain permit (including a draft or proposed permit) 
shall be issued unless the Administrator has received a certificate of 
representation for the designated representative of the source in 
accordance with subpart B of this part.
    (x) Except as provided in Sec. 72.73(b) and, with regard to 
combustion or process sources, in Sec. 74.14(c)(6) of this chapter, the 
State permitting authority shall issue or deny an Acid Rain permit 
within 18 months of receiving a complete Acid Rain permit application 
submitted in accordance with Sec. 72.21 or such lesser time approved 
under part 70 of this chapter.
    (2) Permit Revisions. In acting on any Acid Rain permit revision, 
the State permitting authority shall follow the provisions and 
procedures set forth at subpart H of this part.
    (3) Permit Renewal. The renewal of an Acid Rain permit for an 
affected source shall be subject to all the requirements of this subpart 
pertaining to the issuance of permits.
    (4) Acid Rain Program Forms. In developing the Acid Rain portion of 
the operating permit, the permitting authority shall use the applicable 
forms or other formats prescribed by the Administrator under the Acid 
Rain Program; provided that the Administrator may waive this requirement 
in whole or in part.
    (5) Acid Rain Appeal Procedures. (i) Appeals of the Acid Rain 
portion of an operating permit issued by the State permitting authority 
that do not challenge or involve decisions or actions of the 
Administrator under this part or part 73, 74, 75, 76, 77, or 78 of this 
chapter shall be conducted according to procedures established by the 
State in accordance with part 70 of this chapter. Appeals of the Acid 
Rain portion of such a permit that challenge or involve such decisions 
or actions of the Administrator shall follow the procedures under part 
78 of this chapter and section 307 of the Act. Such decisions or actions 
include, but are not limited to, allowance allocations, determinations 
concerning alternative monitoring systems, and determinations of whether 
a technology is a qualifying repowering technology.
    (ii) [Reserved]
    (iii) The State permitting authority shall serve written notice on 
the Administrator of any State administrative or judicial appeal 
concerning as Acid Rain provision of any operating

[[Page 74]]

permit or denial of an Acid Rain portion of any operating permit within 
30 days of the filing of the appeal.
    (iv) Any State administrative permit appeals procedures shall ensure 
that the Administrator may intervene as a matter of right in any permit 
appeal involving an Acid Rain permit provision or denial of an Acid Rain 
permit.
    (v) The State permitting authority shall serve written notice on the 
Administrator of any determination or order in a State administrative or 
judicial proceeding that interprets, modifies, voids, or otherwise 
relates to any portion of an Acid Rain permit.
    (vi) A failure of the State permitting authority to issue an Acid 
Rain permit in accordance with Sec. 72.73(b)(1) or, with regard to 
combustion or process sources, Sec. 74.14(b)(6) of this chapter shall 
be ground for filing an appeal.

[58 FR 3650, Jan. 11, 1993, as amended at 60 FR 17113, Apr. 4, 1995; 62 
FR 55482, Oct. 24, 1997; 66 FR 12978, Mar. 1, 2001; 70 FR 25334, May 12, 
2005]



Sec. 72.73  State issuance of Phase II permits.

    (a) State Permit Issuance. (1) A State that is authorized to 
administer and enforce an operating permit program under part 70 of this 
chapter and that has a State Acid Rain program accepted by the 
Administrator under Sec. 72.71 shall be responsible for administering 
and enforcing Acid Rain permits effective in Phase II for all affected 
sources:
    (i) That are located in the geographic area covered by the operating 
permits program; and
    (ii) To the extent that the accepted State Acid Rain program is 
applicable.
    (2) In administering and enforcing Acid Rain permits, the State 
permitting authority shall comply with the procedures for issuance, 
revision, renewal, and appeal of Acid Rain permits under this subpart.
    (b) Permit Issuance Deadline. (1) A State, to the extent that it is 
responsible under paragraph (a) of this section as of December 31, 1997 
(or such later date as the Administrator may establish) for 
administering and enforcing Acid Rain permits, shall:
    (i) On or before December 31, 1997, issue an Acid Rain permit for 
Phase II covering the affected units (other than opt-in sources) at each 
source in the geographic area for which the program is approved; 
provided that the designated representative of the source submitted a 
timely and complete Acid Rain permit application in accordance with 
Sec. 72.21.
    (ii) On or before January 1, 1999, for each unit subject to an Acid 
Rain NOX emissions limitation, amend the Acid Rain permit 
under Sec. 72.83 and add any NOX early election plan that 
was approved by the Administrator under Sec. 76.8 of this chapter and 
has not been terminated and reopen the Acid Rain permit and add any 
other Acid Rain Program nitrogen oxides requirements; provided that the 
designated representative of the affected source submitted a timely and 
complete Acid Rain permit application for nitrogen oxides in accordance 
with Sec. 72.21.
    (2) Each Acid Rain permit issued in accordance with this section 
shall have a term of 5 years commencing on its effective date; provided 
that, at the discretion of the permitting authority, an Acid Rain permit 
for Phase II issued to a source may have a term of less than 5 years 
where necessary to coordinate the term of such permit with the term of 
an operating permit to be issued to the source under a State operating 
permit program. Each Acid Rain permit issued in accordance with 
paragraph (b)(1) of this section shall take effect by the later of 
January 1, 2000, or, where the permit governs a unit under Sec. 
72.6(a)(3) of this part, the deadline for monitor certification under 
part 75 of this chapter.

[62 FR 55483, Oct. 24, 1997, as amended at 70 FR 25334, May 12, 2005]



Sec. 72.74  Federal issuance of Phase II permits.

    (a)(1) The Administrator will be responsible for administering and 
enforcing Acid Rain permits for Phase II for any affected sources to the 
extent that a State permitting authority is not responsible, as of 
January 1, 1997 or such later date as the Administrator may establish, 
for administering and enforcing Acid Rain permits for such sources under 
Sec. 72.73(a).
    (2) After and to the extent the State permitting authority becomes 
responsible for administering and enforcing

[[Page 75]]

Acid Rain permits under Sec. 72.73(a), the Administrator will suspend 
federal administration of Acid Rain permits for Phase II for sources and 
units to the extent that they are subject to the accepted State Acid 
Rain program, except as provided in paragraph (b)(4) of this section.
    (b)(1) The Administrator will administer and enforce Acid Rain 
permits effective in Phase II for sources and units during any period 
that the Administrator is administering and enforcing an operating 
permit program under part 71 of this chapter for the geographic area in 
which the sources and units are located.
    (2) The Administrator will administer and enforce Acid Rain permits 
effective in Phase II for sources and units otherwise subject to a State 
Acid Rain program under Sec. 72.73(a) if:
    (i) The Administrator determines that the State permitting authority 
is not adequately administering or enforcing all or a portion of the 
State Acid Rain program, notifies the State permitting authority of such 
determination and the reasons therefore, and publishes such notice in 
the Federal Register;
    (ii) The State permitting authority fails either to correct the 
deficiencies within a reasonable period (established by the 
Administrator in the notice under paragraph (b)(2)(i) of this section) 
after issuance of the notice or to take significant action to assure 
adequate administration and enforcement of the program within a 
reasonable period (established by the Administrator in the notice) after 
issuance of the notice; and
    (iii) The Administrator publishes in the Federal Register a notice 
that he or she will administer and enforce Acid Rain permits effective 
in Phase II for sources and units subject to the State Acid Rain program 
or a portion of the program. The effective date of such notice shall be 
a reasonable period (established by the Administrator in the notice) 
after the issuance of the notice.
    (3) When the Administrator administers and enforces Acid Rain 
permits under paragraph (b)(1) or (b)(2) of this section, the 
Administrator will administer and enforce each Acid Rain permit issued 
under the State Acid Rain program or portion of the program until, and 
except to the extent that, the permit is replaced by a permit issued 
under this section. After the later of the date for publication of a 
notice in the Federal Register that the State operating permit program 
is currently approved by the Administrator or that the State Acid Rain 
program or portion of the program is currently accepted by the 
Administrator, the Administrator will suspend federal administration of 
Acid Rain permits effective in Phase II for sources and units to the 
extent that they are subject to the State Acid Rain program or portion 
of the program, except as provided in paragraph (b)(4) of this section.
    (4) After the State permitting authority becomes responsible for 
administering and enforcing Acid Rain permits effective in Phase II 
under Sec. 72.73(a), the Administrator will continue to administer and 
enforce each Acid Rain permit issued under paragraph (a)(1), (b)(1), or 
(b)(2) of this section until, and except to the extent that, the permit 
is replaced by a permit issued under the State Acid Rain program. The 
State permitting authority may replace an Acid Rain permit issued under 
paragraph (a)(1), (b)(1), or (b)(2) of this section by issuing a permit 
under the State Acid Rain program by the expiration of the permit under 
paragraph (a)(1), (b)(1), or (b)(2) of this section. The Administrator 
may retain jurisdiction over the Acid Rain permits issued under 
paragraph (a)(1), (b)(1), or (b)(2) of this section for which the 
administrative or judicial review process is not complete and will 
address such retention of jurisdiction in a notice in the Federal 
Register.
    (c) Permit Issuance Deadline. (1)(i) On or before January 1, 1998, 
the Administrator will issue an Acid Rain permit for Phase II setting 
forth the Acid Rain Program sulfur dioxide requirements for each 
affected unit (other than opt-in sources) at a source not under the 
jurisdiction of a State permitting authority that is responsible, as of 
January 1, 1997 (or such later date as the Administrator may establish), 
under Sec. 72.73(a) of this section for administering and enforcing 
Acid Rain permits with such requirements; provided

[[Page 76]]

that the designated representative for the source submitted a timely and 
complete Acid Rain permit application in accordance with Sec. 72.21. 
The failure by the Administrator to issue a permit in accordance with 
this paragraph shall be grounds for the filing of an appeal under part 
78 of this chapter.
    (ii) Each Acid Rain permit issued in accordance with this section 
shall have a term of 5 years commencing on its effective date. Each Acid 
Rain permit issued in accordance with paragraph (c)(1)(i) of this 
section shall take effect by the later of January 1, 2000 or, where a 
permit governs a unit under Sec. 72.6(a)(3), the deadline for monitor 
certification under part 75 of this chapter.
    (2) Nitrogen Oxides. Not later than 6 months following submission by 
the designated representative of an Acid Rain permit application for 
nitrogen oxides, the Administrator will amend under Sec. 72.83 the Acid 
Rain permit and add any NOX early election plan that was 
approved under Sec. 76.8 of this chapter and has not been terminated 
and reopen the Acid Rain permit for Phase II and add any other Acid Rain 
Program nitrogen oxides requirements for each affected source not under 
the jurisdiction of a State permitting authority that is responsible, as 
of January 1, 1997 (or such later date as the Administrator may 
establish), under Sec. 72.73(a) for issuing Acid Rain permits with such 
requirements; provided that the designated representative for the source 
submitted a timely and complete Acid Rain permit application for 
nitrogen oxides in accordance with Sec. 72.21.
    (d) Permit Issuance. (1) The Administrator may utilize any or all of 
the provisions of subparts E and F of this part to administer Acid Rain 
permits as authorized under this section or may adopt by rulemaking 
portions of a State Acid Rain program in substitution of or in addition 
to provisions of subparts E and F of this part to administer such 
permits. The provisions of Acid Rain permits for Phase I or Phase II 
issued by the Administrator shall not be applicable requirements under 
part 70 of this chapter.
    (2) The Administrator may delegate all or part of his or her 
responsibility, under this section, for administering and enforcing 
Phase II Acid Rain permits or opt-in permits to a State. Such delegation 
will be made consistent with the requirements of this part and the 
provisions governing delegation of a part 71 program under part 71 of 
this chapter.

[62 FR 55483, Oct. 24, 1997]



                       Subpart H_Permit Revisions



Sec. 72.80  General.

    (a) This subpart shall govern revisions to any Acid Rain permit 
issued by the Administrator and to the Acid Rain portion of any 
operating permit issued by a State permitting authority.
    (b) Notwithstanding the operating permit revision procedures 
specified in parts 70 and 71 of this chapter, the provisions of this 
subpart shall govern revision of any Acid Rain Program permit provision.
    (c) A permit revision may be submitted for approval at any time. No 
permit revision shall affect the term of the Acid Rain permit to be 
revised. No permit revision shall excuse any violation of an Acid Rain 
Program requirement that occurred prior to the effective date of the 
revision.
    (d) The terms of the Acid Rain permit shall apply while the permit 
revision is pending, except as provided in Sec. 72.83 for 
administrative permit amendments.
    (e) The standard requirements of Sec. 72.9 shall not be modified or 
voided by a permit revision.
    (f) Any permit revision involving incorporation of a compliance 
option that was not submitted for approval and comment during the permit 
issuance process or involving a change in a compliance option that was 
previously submitted, shall meet the requirements for applying for such 
compliance option under subpart D of this part and parts 74 and 76 of 
this chapter.
    (g) Any designated representative who fails to submit any relevant 
information or who has submitted incorrect information in a permit 
revision shall, upon becoming aware of such failure or incorrect 
submittal, promptly submit such supplementary information or

[[Page 77]]

corrected information to the permitting authority.
    (h) For permit revisions not described in Sec. Sec. 72.81 and 72.82 
of this part, the permitting authority may, in its discretion, determine 
which of these sections is applicable.

[58 FR 3650, Jan. 11, 1993, as amended at 62 FR 55484, Oct. 24, 1997]



Sec. 72.81  Permit modifications.

    (a) Permit revisions that shall follow the permit modification 
procedures are:
    (1) Relaxation of an excess emission offset requirement after 
approval of the offset plan by the Administrator;
    (2) Incorporation of a final nitrogen oxides alternative emission 
limitation following a demonstration period;
    (3) Determinations concerning failed repowering projects under Sec. 
72.44(g)(1)(i) and (2) of this part.
    (b) The following permit revisions shall follow, at the option of 
the designated representative submitting the permit revision, either the 
permit modification procedures or the fast-track modification procedures 
under Sec. 72.82 of this part:
    (1) Consistent with paragraph (a) of this section, incorporation of 
a compliance option that the designated representative did not submit 
for approval and comment during the permit issuance process; except that 
incorporation of a reduced utilization plan that was not submitted 
during the permit issuance process, that does not designate a 
compensating unit, and that meets the requirements of Sec. 72.43 of 
this part, may use the administrative permit amendment procedures under 
Sec. 72.83 of this part;
    (2) Changes in a substitution plan or reduced utilization plan that 
result in the addition of a new substitution unit or a new compensating 
unit under the plan;
    (3) Addition of a nitrogen oxides averaging plan to a permit;
    (4) Changes in a Phase I extension plan, repowering plan, nitrogen 
oxides averaging plan, or nitrogen oxides compliance deadline extension; 
and
    (5) Changes in a thermal energy plan that result in any addition or 
subtraction of a replacement unit or any change affecting the number of 
allowances transferred for the replacement of thermal energy.
    (c)(1) Permit modifications shall follow the permit issuance 
requirements of:
    (i) Subparts E, F, and G of this part, where the Administrator is 
the permitting authority; or
    (ii) Subpart G of this part, where the State is the permitting 
authority.
    (2) For purposes of applying paragraph (c)(1) of this section, a 
requested permit modification shall be treated as a permit application, 
to the extent consistent with Sec. 72.80 (c) and (d).

[58 FR 3650, Jan. 11, 1993, as amended at 60 FR 17114, Apr. 4, 1995; 62 
FR 55485, Oct. 24, 1997]



Sec. 72.82  Fast-track modifications.

    The following procedures shall apply to all fast-track 
modifications.
    (a) If the Administrator is the permitting authority, the designated 
representative shall serve a copy of the fast-track modification on the 
Administrator and any person entitled to a written notice under Sec. 
72.65(b)(1)(ii) and (iii). If a State is the permitting authority, the 
designated representative shall serve such a copy on the Administrator, 
the permitting authority, and any person entitled to receive a written 
notice of a draft permit under the approved State operating permit 
program. Within 5 business days of serving such copies, the designated 
representative shall also give public notice by publication in a 
newspaper of general circulation in the area where the sources are 
located or in a State publication designed to give general public 
notice.
    (b) The public shall have a period of 30 days, commencing on the 
date of publication of the notice, to comment on the fast-track 
modification. Comments shall be submitted in writing to the permitting 
authority and to the designated representative.
    (c) The designated representative shall submit the fast-track 
modification to the permitting authority on or before commencement of 
the public comment period.
    (d) Within 30 days of the close of the public comment period if the 
Administrator is the permitting authority or within 90 days of the close 
of the public

[[Page 78]]

comment period if a State is the permitting authority, the permitting 
authority shall consider the fast-track modification and the comments 
received and approve, in whole or in part or with changes or conditions 
as appropriate, or disapprove the modification. A fast-track 
modification shall be subject to the same provisions for review by the 
Administrator and affected States as are applicable to a permit 
modification under Sec. 72.81.

[58 FR 3650, Jan. 11, 1993, as amended at 62 FR 55485, Oct. 24, 1997]



Sec. 72.83  Administrative permit amendment.

    (a) Acid Rain permit revisions that shall follow the administrative 
permit amendment procedures are:
    (1) Activation of a compliance option conditionally approved by the 
permitting authority; provided that all requirements for activation 
under subpart D of this part are met;
    (2) Changes in the designated representative or alternative 
designated representative; provided that a new certificate of 
representation is submitted;
    (3) Correction of typographical errors;
    (4) Changes in names, addresses, or telephone or facsimile numbers;
    (5) Changes in the owners or operators; provided that a new 
certificate of representation is submitted within 30 days;
    (6)(i) Termination of a compliance option in the permit; provided 
that all requirements for termination under subpart D of this part are 
met and this procedure shall not be used to terminate a repowering plan 
after December 31, 1999 or a Phase I extension plan;
    (ii) For opt-in sources, termination of a compliance option in the 
permit; provided that all requirements for termination under Sec. 74.47 
of this chapter are met.
    (7) Changes in a substitution or reduced utilization plan that do 
not result in the addition of a new substitution unit or a new 
compensating unit under the plan;
    (8) Changes in the date, specified in a unit's Acid Rain permit, of 
commencement of operation of qualifying Phase I technology, provided 
that they are in accordance with Sec. 72.42 of this part;
    (9) Changes in the date, specified in a new unit's Acid Rain permit, 
of commencement of operation or the deadline for monitor certification, 
provided that they are in accordance with Sec. 72.9 of this part;
    (10) The addition of or change in a nitrogen oxides alternative 
emissions limitation demonstration period, provided that the 
requirements of part 76 of this chapter are met; and
    (11) Changes in a thermal energy plan that do not result in the 
addition or subtraction of a replacement unit or any change affecting 
the number of allowances transferred for the replacement of thermal 
energy.
    (12) The addition of a NOX early election plan that was 
approved by the Administrator under Sec. 76.8 of this chapter;
    (13) The addition of an exemption for which the requirements have 
been met under Sec. 72.7 or Sec. 72.8 and
    (14) Incorporation of changes that the Administrator has determined 
to be similar to those in paragraphs (a)(1) through (13) of this 
section.
    (b)(1) The permitting authority will take final action on an 
administrative permit amendment within 60 days, or, for the addition of 
an alternative emissions limitation demonstration period, within 90 
days, of receipt of the requested amendment and may take such action 
without providing prior public notice. The source may implement any 
changes in the administrative permit amendment immediately upon 
submission of the requested amendment, provided that the requirements of 
paragraph (a) of this section are met.
    (2) The permitting authority may, on its own motion, make an 
administrative permit amendment under paragraph (a)(3), (a)(4), (a)(12), 
or (a)(13) of this section at least 30 days after providing notice to 
the designated representative of the amendment and without providing any 
other prior public notice.
    (c) The permitting authority will designate the permit revision 
under paragraph (b) of this section as having been made as an 
administrative permit amendment. Where a State is the permitting 
authority, the permitting authority shall submit the revised portion of 
the permit to the Administrator.

[[Page 79]]

    (d) An administrative amendment shall not be subject to the 
provisions for review by the Administrator and affected States 
applicable to a permit modification under Sec. 72.81.

[58 FR 3650, Jan. 11, 1993, as amended at 60 FR 17114, Apr. 4, 1995; 62 
FR 55485, Oct. 24, 1997; 66 FR 12978, Mar. 1, 2001]



Sec. 72.84  Automatic permit amendment.

    The following permit revisions shall be deemed to amend 
automatically, and become a part of the affected unit's Acid Rain permit 
by operation of law without any further review:
    (a) Upon recordation by the Administrator under part 73 of this 
chapter, all allowance allocations to, transfers to, and deductions from 
an affected unit's Allowance Tracking System account; and
    (b) Incorporation of an offset plan that has been approved by the 
Administrator under part 77 of this chapter.



Sec. 72.85  Permit reopenings.

    (a) The permitting authority shall reopen an Acid Rain permit for 
cause whenever:
    (1) Any additional requirement under the Acid Rain Program becomes 
applicable to any affected unit governed by the permit;
    (2) The permitting authority determines that the permit contains a 
material mistake or that an inaccurate statement was made in 
establishing the emissions standards or other terms or conditions of the 
permit, unless the mistake or statement is corrected in accordance with 
Sec. 72.83; or
    (3) The permitting authority determines that the permit must be 
revised or revoked to assure compliance with Acid Rain Program 
requirements.
    (b) In reopening an Acid Rain permit for cause, the permitting 
authority shall issue a draft permit changing the provisions, or adding 
the requirements, for which the reopening was necessary. The draft 
permit shall be subject to the requirements of subparts E, F, and G of 
this part.
    (c) As provided in Sec. Sec. 72.73(b)(1) and 72.74(c)(2), the 
permitting authority shall reopen an Acid Rain permit to incorporate 
nitrogen oxides requirements, consistent with part 76 of this chapter.
    (d) Any reopening of an Acid Rain permit shall not affect the term 
of the permit.

[58 FR 3650, Jan. 11, 1993, as amended at 62 FR 55485, Oct. 24, 1997]



                   Subpart I_Compliance Certification



Sec. 72.90  Annual compliance certification report.

    (a) Applicability and deadline. For each calendar year during 1995 
through 2005 in which a unit is subject to the Acid Rain emissions 
limitations, the designated representative of the source at which the 
unit is located shall submit to the Administrator, within 60 days after 
the end of the calendar year, an annual compliance certification report 
for the unit.
    (b) Contents of report. The designated representative shall include 
in the annual compliance certification report under paragraph (a) of 
this section the following elements, in a format prescribed by the 
Administrator, concerning the unit and the calendar year covered by the 
report:
    (1) Identification of the unit;
    (2) For all Phase I units, the information in accordance with 
Sec. Sec. 72.91(a) and 72.92(a) of this part;
    (3) If the unit is governed by an approved Phase I extension plan, 
then the information in accordance with Sec. 72.93 of this part;
    (4) At the designated representative's option, the total number of 
allowances to be deducted for the year, using the formula in Sec. 72.95 
of this part, and the serial numbers of the allowances that are to be 
deducted;
    (5) At the designated representative's option, for units that share 
a common stack and whose emissions of sulfur dioxide are not monitored 
separately or apportioned in accordance with part 75 of this chapter, 
the percentage of the total number of allowances under paragraph (b)(4) 
of this section for all such units that is to be deducted from each 
unit's compliance subaccount; and
    (6) The compliance certification under paragraph (c) of this 
section.
    (c) Annual compliance certification. In the annual compliance 
certification report under paragraph (a) of this section, the designated 
representative

[[Page 80]]

shall certify, based on reasonable inquiry of those persons with primary 
responsibility for operating the source and the affected units at the 
source in compliance with the Acid Rain Program, whether each affected 
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 Acid Rain Program applicable to the unit, including:
    (1) Whether the unit was operated in compliance with the applicable 
Acid Rain emissions limitations, including whether the unit held 
allowances, as of the allowance transfer deadline, in its compliance 
subaccount (after accounting for any allowance deductions under Sec. 
73.34(c) of this chapter) not less than the unit's total sulfur dioxide 
emissions during the calendar year covered by the annual report;
    (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 monitored emissions 
to the unit;
    (3) Whether all the 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 conditionally valid data, as 
defined in Sec. 72.2, were reported in the quarterly report. If 
conditionally valid data were reported, the owner or operator shall 
indicate whether the status of all conditionally valid data has been 
resolved and all necessary quarterly report resubmissions have been 
made.
    (4) Whether the facts that form the basis for certification of each 
monitor at the unit or a group of units (including the unit) using a 
common stack or for using an Acid Rain Program excepted monitoring 
method or approved alternative monitoring method, 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.

[58 FR 3650, Jan. 11, 1993, as amended at 64 FR 28588, May 26, 1999; 70 
FR 25334, May 12, 2005]



Sec. 72.91  Phase I unit adjusted utilization.

    (a) Annual compliance certification report. The designated 
representative for each Phase I unit shall include in the annual 
compliance certification report the unit's adjusted utilization for the 
calendar year in Phase I covered by the report, calculated as follows:

Adjusted utilization = baseline - actual utilization - plan reductions + 
compensating generation provided to other units


where:

    (1) ``Baseline'' is as defined in Sec. 72.2 of this part.
    (2) ``Actual utilization'' is the actual annual heat input (in 
mmBtu) of the unit for the calendar year determined in accordance with 
part 75 of this chapter.
    (3) ``Plan reductions'' are the reductions in actual utilization, 
for the calendar year, below the baseline that are accounted for by an 
approved reduced utilization plan. The designated representative for the 
unit shall calculate the ``plan reductions'' (in mmBtu) using the 
following formula and converting all values in Kwh to mmBtu using the 
actual annual average heat rate (Btu/Kwh) of the unit (determined in 
accordance with part 75 of this chapter) before the employment of any 
improved unit efficiency measures under an approved plan:

Plan reductions = reduction from energy conservation + reduction from 
improved unit efficiency improvements + shifts to designated sulfur-free 
generators + shifts to designated compensating units


where:

    (i) ``Reduction from energy conservation'' is a good faith estimate 
of the expected kilowatt hour savings during the calendar year from all 
conservation measures under the reduced utilization

[[Page 81]]

plan and the corresponding reduction in heat input (in mmBtu) resulting 
from those savings. The verified amount of such reduction shall be 
submitted in accordance with paragraph (b) of this section.
    (ii) ``Reduction from improved unit efficiency'' is a good faith 
estimate of the expected improvement in heat rate during the calendar 
year and the corresponding reduction in heat input (in mmBtu) at the 
Phase I unit as a result of all improved unit efficiency measures under 
the reduced utilization plan. The verified amount of such reduction 
shall be submitted in accordance with paragraph (b) of this section.
    (iii) ``Shifts to designated sulfur-free generators'' is the 
reduction in utilization (in mmBtu), for the calendar year, that is 
accounted for by all sulfur-free generators designated under the reduced 
utilization plan in effect for the calendar year. This term equals the 
sum, for all such generators, of the ``shift to sulfur-free generator.'' 
``Shift to sulfur-free generator'' shall equal the amount, to the extent 
documented under paragraph (a)(6) of this section, calculated for each 
generator using the following formula:

Shift to sulfur-free generator = actual sulfur-free utilization - 
[(average 1985-87 sulfur-free annual utilization) (1 + percentage change 
in dispatch system sales)]


where:

    (A) ``Actual sulfur-free utilization'' is the actual annual 
generation (in Kwh) of the designated sulfur-free generator for the 
calendar year converted to mmBtus.
    (B) ``Average 1985-87 sulfur-free utilization'' is the sum of annual 
generation (in Kwh) for 1985, 1986, and 1987 for the designated sulfur-
free generator, divided by three and converted to mmBtus.
    (C) ``Percentage change in dispatch system sales'' is calculated as 
follows:
[GRAPHIC] [TIFF OMITTED] TC01SE92.000

where:

S = dispatch system sales (in Kwh)
c = calendar year
y = 1985, 1986, or 1987

    If the result of the formula for percentage change in dispatch 
system sales is less than or equal to zero, then percentage change in 
dispatch system sales shall be treated as zero only for purposes of 
paragraph (a)(3)(iii) of this section.

    (D) If the result of the formula for ``shift to sulfur-free 
generator'' is less than or equal to zero, then ``shift to sulfur-free 
generator'' is zero.
    (iv) ``Shifts to designated compensating units'' is the reduction in 
utilization (in mmBtu) for the calendar year that is accounted for by 
increased generation at compensating units designated under the reduced 
utilization plan in effect for the calendar year. This term equals the 
heat rate, under paragraph (a)(3) of this section, of the unit reducing 
utilization multiplied by the sum, for all such compensating units, of 
the ``shift to compensating unit'' for each compensating unit. ``Shift 
to compensating unit'' shall equal the amount of compensating generation 
(in Kwh), to the extent documented under paragraph (a)(6) of this 
section, that the designated representatives of the unit reducing 
utilization and the compensating unit have certified (in their 
respective annual compliance certification reports) as the amount that 
will be converted to mmBtus and used, in accordance with paragraph 
(a)(4) of this section, in calculating the adjusted utilization for the 
compensating unit.
    (4) ``Compensating generation provided to other units'' is the total 
amount of utilization (in mmBtu) necessary to provide the generation (if 
any) that was shifted to the unit as a designated compensating unit 
under any other reduced utilization plans that were in effect for the 
unit and for the calendar year. This term equals the heat rate, under 
paragraph (a)(3) of this

[[Page 82]]

section, of such unit multiplied by the sum of each ``shift to 
compensating unit'' that is attributed to the unit in the annual 
compliance certification reports submitted by the Phase I units under 
such other plans and that is certified under paragraph (a)(3)(iv) of 
this section.
    (5) Notwithstanding paragraphs (a)(3) (i), (ii), and (iii) of this 
section, where two or more Phase I units include in ``plan reductions'', 
in their annual compliance certification reports for the calendar year, 
expected kilowatt hour savings or reduction in heat rate from the same 
specific conservation or improved unit efficiency measures or increased 
utilization of the same sulfur-free generator:
    (i) The designated representatives of all such units shall submit 
with their annual reports a certification signed by all such designated 
representatives. The certification shall apportion the total kilowatt 
hour savings, reduction in heat rate, or increased utilization among 
such units.
    (ii) Each designated representative shall include in the annual 
report only the respective unit's share of the total kilowatt hour 
savings, reduction in heat rate, or increased utilization, in accordance 
with the certification under paragraph (a)(5)(i) of this section.
    (6)(i) Where a unit includes in ``plan reductions'' under paragraph 
(a)(3) of this section the increase in utilization of any sulfur-free 
generator, the designated representative of the unit shall submit, with 
the annual compliance certification report, documentation demonstrating 
that an amount of electrical energy at least equal to the ``shift to 
sulfur-free generator'' attributed to the sulfur-free generator in the 
annual report was actually acquired by the unit's dispatch system from 
the sulfur-free generator.
    (ii) Where a unit includes in ``plan reductions'' under paragraph 
(a)(3) of this section utilization of any compensating unit, the 
designated representative of the unit shall submit with the annual 
compliance certification report, documentation demonstrating that an 
amount of electrical energy at least equal to the ``shift to 
compensating unit'' attributed to the compensating unit in the annual 
report was actually acquired by the unit's dispatch system from the 
compensating unit.
    (7) Notwithstanding paragraphs (a)(3) (i), (ii), (iii), and (iv), 
(a)(4), and (a)(5) of this section, ``plan reductions'' minus 
``compensating generation provided to other units'' shall not exceed 
``baseline'' minus ``actual utilization.''
    (b) Confirmation report. (1) If a unit's annual compliance 
certification report estimates any expected kilowatt hour savings or 
improvement in heat rate from energy conservation or improved unit 
efficiency measures under a reduced utilization plan, the designated 
representative shall submit, by July 1 of the year in which the annual 
report was submitted, a confirmation report. The Administrator may 
grant, for good cause shown, an extension of the time to file the 
confirmation report. The confirmation report shall include the following 
elements in a format prescribed by the Administrator:
    (i) The verified kilowatt hour savings from each such energy 
conservation measure and the verified corresponding reduction in the 
unit's heat input resulting from each measure during the calendar year 
covered by the annual report. For purposes of this paragraph (b), all 
values in Kwh shall be converted to mmBtu using the actual annual heat 
rate (Btu/Kwh) of the unit (determined in accordance with part 75 of 
this chapter) before the employment of any improved unit efficiency 
measures under an approved reduced utilization plan.
    (ii) The verified reduction in the heat rate achieved by each 
improved unit efficiency measure and the verified corresponding 
reduction in the unit's heat input resulting from such measure.
    (iii) For each figure under paragraphs (b)(1) (i) and (ii) of this 
section:
    (A) Documentation (which may follow the EPA Conservation 
Verification Protocol) verifying specified figures to the satisfaction 
of the Administrator; or
    (B) Certification, by a State utility regulatory authority that has 
ratemaking jurisdiction over the utility system that paid for the 
measures in accordance with Sec. 72.43(b)(2) of this part and over 
rates reflecting any of the amount paid for such measures, or that

[[Page 83]]

meets the criteria in Sec. 73.82(c)(1) (i) and (ii) of this chapter, 
that such authority verified specified figures related to demand-side 
measures; and
    (C) Certification, by a utility regulatory authority that has 
ratemaking jurisdiction over the utility system that paid for the 
measures in accordance with Sec. 72.43(b)(2) of this part and over 
rates reflecting any of the amount paid for such measures, that such 
authority verified specified figures related to supply-side measures, 
except measures relating to generation efficiency.
    (iv) The sum of the verified reductions in a unit's heat input from 
all measures implemented at the unit to reduce the unit's heat rate 
(whether the measures are treated as supply-side measures or improved 
unit efficiency measures) shall not exceed the generation (in kwh) 
attributed to the unit for the calendar year times the difference 
between the unit's heat rate for 1987 and the unit's heat rate for the 
calendar year.
    (2) Notwithstanding paragraph (b)(1)(i) of this section, where two 
or more Phase I units include in the confirmation report the verified 
kilowatt hour savings or reduction in heat rate from the same specific 
conservation or improved unit efficiency measures:
    (i) The designated representatives of all such units shall submit 
with their confirmation reports a certification signed by all such 
designated representatives. The certification shall apportion the total 
kilowatt hour savings or reduction in heat rate among such units.
    (ii) Each designated representative shall include in the 
confirmation report only the respective unit's share of the total 
savings or reduction in heat rate in accordance with the certification 
under paragraph (b)(2)(i) of this section.
    (3) If the total, included in the confirmation report, of the 
amounts of verified reduction in the unit's heat input from energy 
conservation and improved unit efficiency measures equals the total 
estimated in the unit's annual compliance certification report from such 
measures for the calendar year, then the designated representatives 
shall include in the confirmation report a statement indicating that is 
true.
    (4) If the total, included in the confirmation report, of the 
amounts of verified reduction in the unit's heat input from energy 
conservation and improved unit efficiency measures is greater than the 
total estimated in the unit's annual compliance certification report 
from such measures for the calendar year, then the designated 
representative shall include in the confirmation report the number of 
allowances to be credited to the unit's compliance subaccount calculated 
using the following formula:

Allowances credited = (verified heat input reduction-estimated heat 
input reduction) x emissions rate [middot] 2000 lbs/ton


where:

    (i) ``Verified heat input reduction'' is the total of the amounts of 
verified reduction in the unit's heat input (in mmBtu) from energy 
conservation and improved unit efficiency measures included in the 
confirmation report.
    (ii) ``Estimated heat input reduction'' is the total of the amounts 
of reduction in the unit's heat input (in mmBtu) accounted for by energy 
conservation and improved efficiency measures as estimated in the unit's 
annual compliance certification report for the calendar year.
    (iii) ``Emissions rate'' is the ``emissions rate'' under Sec. 
72.92(c)(2)(v) of this part.
    (iv) The allowances credited shall not exceed the total number of 
allowances deducted from the unit's compliance subaccount for the 
calendar year in accordance with Sec. Sec. 72.92(a) and (c) and 
73.35(b) of this chapter.
    (5) If the total, included in the confirmation report, of the amount 
of verified reduction in the unit's heat input for energy conservation 
and improved unit efficiency measures is less than the total estimated 
in the unit's annual compliance certification report for such measures 
for the calendar year, then the designated representative shall include 
in the confirmation report the number of allowances to be deducted from 
the unit's compliance subaccount calculated in accordance with this 
paragraph (b)(5).

[[Page 84]]

    (i) If any allowances were deducted from the unit's compliance 
subaccount for the calendar year in accordance with Sec. Sec. 72.92(a) 
and (c) and 73.35(b) of this chapter, then the number of allowances to 
be deducted under paragraph (b)(5) of this section equals the absolute 
value of the result of the formula for allowances credited under 
paragraph (b)(4) of this section (excluding paragraph (b)(4)(iv) of this 
section).
    (ii) If no allowances were deducted from the unit's compliance 
subaccount for the calendar year in accordance with Sec. Sec. 72.92(a) 
and (c) and 73.35(b) of this chapter:
    (A) The designated representative shall recalculate the unit's 
adjusted utilization in accordance with paragraph (a) of this section, 
replacing the amounts for reduction from energy conservation and 
reduction from improved unit efficiency by the amount for verified heat 
input reduction. ``Verified heat input reduction'' is the total of the 
amounts of verified reduction in the unit's heat input (in mmBtu) from 
energy conservation and improved unit efficiency measures included in 
the confirmation report.
    (B) After recalculating the adjusted utilization under paragraph 
(b)(5)(ii)(A) of this section for all Phase I units that are in the 
unit's dispatch system and to which paragraph (b)(5) of this section is 
applicable, the designated representative shall calculate the number of 
allowances to be surrendered in accordance with Sec. 72.92(c)(2) using 
the recalculated adjusted utilizations of such Phase I units.
    (C) The allowances to be deducted under paragraph (b)(5) of this 
section shall equal the amount under paragraph (b)(5)(ii)(B) of this 
section, provided that if the amount calculated under this paragraph 
(b)(5)(ii)(C) is equal to or less than zero, then the amount of 
allowances to be deducted is zero.
    (6) The Administrator will determine the amount of allowances that 
would have been included in the unit's compliance subaccount and the 
amount of excess emissions of sulfur dioxide that would have resulted if 
the deductions made under Sec. 73.35(b) of this chapter had been based 
on the verified, rather than the estimated, reduction in the unit's heat 
input from energy conservation and improved unit efficiency measures.
    (7) The Administrator will determine whether the amount of excess 
emissions of sulfur dioxide under paragraph (b)(6) of this section 
differs from the amount of excess emissions determined under Sec. 
73.35(b) of this chapter based on the annual compliance certification 
report. If the amounts differ, the Administrator will determine: The 
number of allowances that should be deducted to offset any increase in 
excess emissions or returned to account for any decrease in excess 
emissions; and the amount of excess emissions penalty (excluding 
interest) that should be paid or returned to account for the change in 
excess emissions. The Administrator will deduct immediately from the 
unit's compliance subaccount the amount of allowances that he or she 
determines is necessary to offset any increase in excess emissions or 
will return immediately to the unit's compliance subaccount the amount 
of allowances that he or she determines is necessary to account for any 
decrease in excess emissions. The designated representative may identify 
the serial numbers of the allowances to be deducted or returned. In the 
absence of such identification, the deduction will be on a first-in, 
first-out basis under Sec. 73.35(b)(2) of this chapter and the return 
will be at the Administrator's discretion.
    (8) If the designated representative of a unit fails to submit on a 
timely basis a confirmation report (in accordance with paragraph (b) of 
this section) with regard to the estimate of expected kilowatt hour 
savings or improvement in heat rate from any energy conservation or 
improved unit efficiency measure under the reduced utilization plan, 
then the Administrator will reject such estimate and correct it to equal 
zero in the unit's annual compliance certification report that includes 
that estimate. The Administrator will deduct immediately, on a first-in, 
first-out basis under Sec. 73.35(c)(2) of this chapter, the amount of 
allowances that he or she determines is necessary to offset

[[Page 85]]

any increase in excess emissions of sulfur dioxide that results from the 
correction and require the owners and operators to pay an excess 
emission penalty in accordance with part 77 of this chapter.

[58 FR 3650, Jan. 11, 1993, as amended at 58 FR 40747, July 30, 1993; 59 
FR 60231, Nov. 22, 1994; 60 FR 18470, Apr. 11, 1995; 62 FR 55485, Oct. 
24, 1997]



Sec. 72.92  Phase I unit allowance surrender.

    (a) Annual compliance certification report. If a Phase I unit's 
adjusted utilization for the calendar year in Phase I under Sec. 
72.91(a) is greater than zero, then the designated representative shall 
include in the annual compliance certification report the number of 
allowances that shall be surrendered for adjusted utilization using the 
formula in paragraph (c) of this section and the calculations that were 
performed to obtain that number.
    (b) Other submissions. (1) [Reserved]
    (2)(i) If any Phase I unit in a dispatch system is governed during 
the calendar year by an approved reduced utilization plan relying on 
sulfur-free generation, then the designated representatives of all 
affected units in such dispatch system shall jointly submit, within 60 
days of the end of the calendar year, a dispatch system data report that 
includes the following elements in a format prescribed by the 
Administrator:
    (A) The name of the dispatch system as reported under Sec. 72.33;
    (B) The calculation of ``percentage change in dispatch system 
sales'' under Sec. 72.91(a)(3)(iii)(C);
    (C) A certification that each designated representative will use 
this figure, as appropriate, in its annual compliance certification 
report and will submit upon request the data supporting the calculation; 
and
    (D) The signatures of all the designated representatives.
    (ii) If any Phase I unit in a dispatch system has adjusted 
utilization greater than zero for the calendar year, then the designated 
representatives of all Phase I units in such dispatch system shall 
jointly submit, within 60 days of the end of the calendar year, a 
dispatch system data report that includes the following elements in a 
format prescribed by the Administrator:
    (A) The name of the dispatch system as reported under Sec. 72.33;
    (B) The calculation of ``percentage change in dispatch system 
sales'' under Sec. 72.91(a)(3)(iii)(C);
    (C) The calculation of ``dispatch system adjusted utilization'' 
under paragraph (c)(2)(i) of this section;
    (D) The calculation of ``dispatch system aggregate baseline'' under 
paragraph (c)(2)(ii) of this section;
    (E) The calculation of ``fraction of generation within dispatch 
system'' under paragraph (c)(2)(v)(A) of this section;
    (F) The calculation of ``dispatch system emissions rate'' under 
paragraph (c)(2)(v)(B) of this section;
    (G) The calculation of ``fraction of generation from non-utility 
generators'' under paragraph (c)(2)(v)(C) of this section;
    (H) The calculation of ``non-utility generator average emissions 
rate `` under paragraph (c)(2)(v)(F) of this section;
    (I) A certification that each designated representative will use 
these figures, as appropriate, in its annual compliance certification 
report and will submit upon request the data supporting these 
calculations; and
    (J) The signatures of all the designated representatives.
    (c) Allowance surrender formula. (1) As provided under the allowance 
surrender formula in paragraph (c)(2) of this section:
    (i) Allowances are not surrendered for deduction for the portion of 
adjusted utilization accounted for by:
    (A) Shifts in generation from the unit to other Phase I units;
    (B) A dispatch-system-wide sales decline;
    (C) Plan reductions under a reduced utilization plan as calculated 
under Sec. 72.91; and
    (D) Foreign generation.
    (ii) Allowances are surrendered for deduction for the portion of 
adjusted utilization that is not accounted for under paragraph (c)(1)(i) 
of this section.

[[Page 86]]

    (2) The designated representative shall surrender for deduction the 
number of allowances calculated using the following formula:

Allowances surrendered = [dispatch system adjusted utilization + 
(dispatch system aggregate baseline x percentage change in dispatch 
system sales)] x unit's share x emissions rate [middot] 2000 lbs/ton.

    If the result of the formula for ``allowances surrendered'' is less 
than or equal to zero, then no allowances are surrendered.
    (i) Calculating dispatch system adjusted utilization. ``Dispatch 
system adjusted utilization'' (in mmBtu) is the sum of the adjusted 
utilization under Sec. 72.91(a) for all Phase I units in the dispatch 
system. If ``dispatch system adjusted utilization'' is less than or 
equal to zero, then no allowances are surrendered by any unit in that 
dispatch system.
    (ii) Calculating dispatch system aggregate baseline. ``Dispatch 
system aggregate baseline'' is the sum of the baselines (as defined in 
Sec. 72.2 of this chapter) for all Phase I units in the dispatch 
system.
    (iii) Calculating percentage change in dispatch system sales. 
``Percentage change in dispatch system sales'' is the ``percentage 
change in dispatch system sales'' under Sec. 72.91 (a)(3)(iii)(C); 
provided that if result of the formula in Sec. 72.91(a)(3)(iii)(C) is 
greater than or equal to zero, the value shall be treated as zero only 
for purposes of paragraph (c)(2) of this section.
    (iv) Calculating unit's share. ``Unit's share'' is the unit's 
adjusted utilization divided by the sum of the adjusted utilization for 
all Phase I units within the dispatch system that have adjusted 
utilization of greater than zero and is calculated as follows:
[GRAPHIC] [TIFF OMITTED] TC01SE92.001


where:

    (A) Uunit = the unit's adjusted utilization for the 
calendar year;
    (B) Ui = the adjusted utilization of a Phase I unit in 
the dispatch system for the calendar year; and
    (C) m = all Phase I units in the dispatch system having an adjusted 
utilization greater than 0 for the calendar year.
    (v) Calculating emissions rate. ``Emissions rate'' (in lbs/mmBtu) is 
the weighted average emissions rate for sulfur dioxide of all units and 
generators, within and outside the dispatch system, that contributed to 
the dispatch system's electrical output for the year, calculated as 
follows:

Emissions rate = [fraction of generation within dispatch system x 
dispatch system emissions rate] + [fraction of generation from non-
utility generators x non-utility generator average emissions rate] + 
[fraction of generation outside dispatch system x fraction of non-Phase 
1 and non-foreign generation in NERC region x NERC region emissions 
rate]


where:

    (A) ``Fraction of generation within dispatch system'' is the 
fraction of the dispatch system's total sales accounted for by 
generation from units and generators within the dispatch system, other 
than generation from non-utility generators. This term equals the total 
generation (in Kwh) by all units and generators within the dispatch 
system for the calendar year minus the total non-utility generation from 
non-utility generators within the dispatch system for the calendar year 
and divided by the total sales (in Kwh) by the dispatch system for the 
calendar year.
    (B) Dispatch system emissions rate'' is the weighted average rate 
(in lbs/mmBtu) for the dispatch system calculated as follows:
    Dispatch system emissions rate =
    [GRAPHIC] [TIFF OMITTED] TR11AP95.000
    
where:

gi = the difference between a Phase II unit's actual 
          utilization for the calendar year and that Phase II unit's 
          baseline. If that difference is less than or equal to zero, 
          then the difference shall be treated as zero only for purposes 
          of paragraph

[[Page 87]]

          (c)(2)(v) of this section and that unit will be excluded from 
          the calculation of dispatch system emissions rate. 
          Notwithstanding the prior sentence, if the actual utilization 
          of each Phase II unit for the year is equal to or less than 
          the baseline, then gi shall equal a Phase II unit's 
          actual utilization for the year. Notwithstanding any provision 
          in this paragraph (c)(2)(v)(B) to the contrary, if the actual 
          utilization of each Phase II unit in the dispatch system is 
          zero or there are no Phase II units in the dispatch system, 
          then the dispatch system emissions rate shall equal the 
          fraction of non-Phase I and non-foreign generation in the NERC 
          region multiplied by the NERC region emissions rate.
ri = a Phase II unit's emissions rate (in lbs/mmBtu), 
          determined in accordance with part 75 of this chapter, for the 
          calendar year.
k = number of Phase II units in the dispatch system.

    (C) ``Fraction of generation from non-utility generators'' is the 
fraction of the dispatch system's total sales accounted for by 
generation acquired from non-utility generators within or outside the 
dispatch system. This term equals the total non-utility generation from 
non-utility generators (within or outside the dispatch system) for the 
calendar year divided by the total sales (in Kwh) by the dispatch system 
for the calendar year.
    (D) ``Non-utility generator'' is a power production facility (within 
or outside the dispatch system) that is not an affected unit or a 
sulfur-free generator and that has a ``non-utility generator emissions 
rate'' for the calendar year under paragraph (c)(2)(v)(F) of this 
section.
    (E) ``Non-utility generation'' is the generation (in Kwh) that the 
dispatch system acquired from a non-utility generator during the 
calendar year as required by Federal or State law or an order of a 
utility regulatory authority or under a contract awarded as the result 
of a power purchase solicitation required by Federal or State law or an 
order of a utility regulatory authority.
    (F) ``Non-utility generator average emissions rate'' is the weighted 
average rate (in lbs/mmBtu) for the non-utility generators calculated as 
follows:
    Non-utility generator average emissions rate =
    [GRAPHIC] [TIFF OMITTED] TR11AP95.001
    
where:

Ni = non-utility generation from a non-utility generator;
Ri = non-utility generator emissions rate for the calendar 
          year for a non-utility generator, which shall equal the most 
          stringent federally enforceable or State enforceable 
          SO2 emissions limitation applicable for the 
          calendar year to such power production facility, as determined 
          in accordance with paragraphs (c)(2)(v)(F) (1), (2), and (3) 
          of this section; and
n = number of non-utility generators from which the dispatch system 
          acquired non-utility generation. If n equals zero, then the 
          non-utility generator average emissions rate shall be treated 
          as zero only for purposes of paragraph (c)(2)(v) of this 
          section.

    (1) For purposes of determining the most stringent emissions 
limitation, applicable emissions limitations shall be converted to lbs/
mmBtu in accordance with appendix B of this part. If an applicable 
emissions limitation cannot be converted to a unit-specific limitation 
in lbs/mmBtu under appendix B of this part, then the limitation shall 
not be used in determining the most stringent emissions limitation. 
Where the power production facility is subject to different emissions 
limitations depending on the type of fuel it uses during the calendar 
year, the most stringent emissions limitation shall be determined 
separately with regard to each type of fuel and the resulting limitation 
with the highest amount of lbs/mmBtu shall be treated as the facility's 
most stringent federally enforceable or State enforceable emissions 
limitation.
    (2) If there is no applicable emissions limitation that can be used 
in determining the most stringent emissions limitation under paragraph 
(c)(2)(v)(F)(1) of this section, then the power production facility has 
no non-utility generator emissions rate for purposes of paragraphs 
(c)(2)(v) (D) and (F) of this section and the generation from the 
facility shall be treated, for purposes of this paragraph (c)(2)(v) as 
generation from units and generators within the dispatch system if the 
facility is within the dispatch system or as

[[Page 88]]

generation from units and generators outside the dispatch system if the 
facility is outside the dispatch system.
    (3) Notwithstanding paragraphs (c)(2)(v)(F) (1) and (2) of this 
section, if the power production facility is authorized under Federal or 
State law to use only natural gas as fuel, then the most stringent 
emissions limitation for the facility for the calendar year shall be 
deemed to be 0.0006 lbs/mmBtu.
    (G) ``Fraction of generation outside dispatch system'' = 1-fraction 
of generation within dispatch system-fraction of generation from non-
utility generators.
    (H) ``Fraction of non-Phase I and non-foreign generation in NERC 
region'' is the portion of the NERC region's total sales generated by 
units and generators other than Phase I units or foreign sources in the 
unit's NERC region in 1985, as set forth in table 1 of this section.
    (I) ``NERC region emissions rate'' is the weighted average emission 
rate (in lbs/mmBtu) for the unit's NERC region in 1985, as set forth in 
table 1 of this section.

       Table 1--NERC Region Generation and Emissions Rate in 1985
------------------------------------------------------------------------
                                                    Fraction
                                                     of non-      NERC
                                                     phase I    weighted
                                                    and non-    average
                   NERC region                       foreign   emissions
                                                   generation  rate (lbs/
                                                     in NERC     mmBtu)
                                                     region
------------------------------------------------------------------------
WSCC.............................................       0.847      0.466
SPP..............................................       0.948      0.647
SERC.............................................       0.749      1.315
NPCC.............................................       0.423      1.058
MAPP.............................................       0.725      1.171
MAIN.............................................       0.682      1.495
MAAC.............................................       0.750      1.599
ERCOT............................................       1.000      0.491
ECAR.............................................       0.549      1.564
------------------------------------------------------------------------


[58 FR 3650, Jan. 11, 1993, as amended at 58 FR 40747, July 30, 1993; 60 
FR 18470, Apr. 11, 1995]



Sec. 72.93  Units with Phase I extension plans.

    Annual compliance certification report. The designated 
representative for a control unit governed by a Phase I extension plan 
shall include in the unit's annual compliance certification report for 
calendar year 1997, the start-up test results upon which the vendor is 
released from liability under the vendor certification of guaranteed 
sulfur dioxide removal efficiency under Sec. 72.42(c)(12).



Sec. 72.94  Units with repowering extension plans.

    (a) Design and engineering and contract requirements. No later than 
January 1, 2000, the designated representative of a unit governed by an 
approved repowering plan shall submit to the Administrator and the 
permitting authority:
    (1) Satisfactory documentation of a preliminary design and 
engineering effort.
    (2) A binding letter agreement for the executed and binding contract 
(or for each in a series of executed and binding contracts) for the 
majority of the equipment to repower the unit using the technology 
conditionally approved by the Administrator under Sec. 72.44(d)(3).
    (3) The letter agreement under paragraph (a)(2) of this section 
shall be signed and dated by each party and specify:
    (i) The parties to the contract;
    (ii) The date each party executed the contract;
    (iii) The unit to which the contract applies;
    (iv) A brief list identifying each provision of the contract;
    (v) Any dates to which the parties agree, including construction 
completion date;
    (vi) The total dollar amount of the contract; and
    (vii) A statement that a copy of the contract is on site at the 
source and will be submitted upon written request of the Administrator 
or the permitting authority.
    (b) Removal from operation to repower. The designated representative 
of a unit governed by an approved repowering plan shall notify the 
Administrator in writing at least 60 days in advance of the date on 
which the existing unit is to be removed from operation so that the 
qualified repowering technology can be installed, or is to be replaced 
by another unit with the qualified repowering technology, in accordance 
with the plan.

[[Page 89]]

    (c) Commencement of operation. Not later than 60 days after the unit 
repowered under an approved repowering plan commences operation at full 
load, the designated representative of the unit shall submit a report 
comparing the actual hourly emissions and percent removal of each 
pollutant controlled at the unit to the actual hourly emissions and 
percent removal at the existing unit under the plan prior to repowering, 
determined in accordance with part 75 of this chapter.
    (d) Decision to terminate. If at any time before the end of the 
repowering extension the owners and operators decide to terminate good 
faith efforts to design, construct, and test the qualified repowering 
technology on the unit to be repowered under an approved repowering 
plan, then the designated representative shall submit a notice to the 
Administrator by the earlier of the end of the repowering extension or a 
date within 30 days of such decision, stating the date on which the 
decision was made.



Sec. 72.95  Allowance deduction formula.

    The following formula shall be used to determine the total number of 
allowances to be deducted for the calendar year from the allowances held 
in an affected source's compliance account as of the allowance transfer 
deadline applicable to that year:

Total allowances deducted = Tons emitted + Allowances surrendered for 
underutilization + Allowances deducted for Phase I extensions + 
Allowances deducted for substitution or compensating units


where:

    (a) ``Tons emitted'' is the total tons of sulfur dioxide emitted by 
the affected units at the source during the calendar year, as reported 
in accordance with part 75 of this chapter.
    (b) ``Allowances surrendered for underutilization'' is the total 
number of allowances calculated in accordance with Sec. 72.92 (a) and 
(c).
    (c) ``Allowances deducted for Phase I extensions'' is the total 
number of allowances calculated in accordance with Sec. 72.42(f)(1)(i).
    (d) ``Allowances deducted for substitution or compensating units'' 
is the total number of allowances calculated in accordance with the 
surrender requirements specified under Sec. 72.41(d)(3) or 
(e)(1)(iii)(B) or Sec. 72.43(d)(2).

[58 FR 3650, Jan. 11, 1993, as amended at 62 FR 55485, Oct. 24, 1997; 70 
FR 25334, May 12, 2005]



Sec. 72.96  Administrator's action on compliance certifications.

    (a) The Administrator may review, and conduct independent audits 
concerning, any compliance certification and any other submission under 
the Acid Rain Program and make appropriate adjustments of the 
information in the compliance certifications and other submissions.
    (b) The Administrator may deduct allowances from or return 
allowances to a source's compliance account in accordance with part 73 
of this chapter based on the information in the compliance 
certifications and other submissions, as adjusted.

[58 FR 3650, Jan. 11, 1993, as amended at 70 FR 25334, May 12, 2005]



 Sec. Appendix A to Part 72--Methodology for Annualization of
 Emissions Limits

    For the purposes of the Acid Rain Program, 1985 emissions limits 
must be expressed in pounds of SO2 per million British 
Thermal Unit of heat input (lb/mmBtu) and expressed on an annual basis.
    Annualization factors are used to develop annual equivalent 
SO2 limits as required by section 402(18) of the CAA. Many 
emission limits are enforced on a shorter term basis (or averaging 
period) than annually. Because of the variability of sulfur in coal and, 
in some cases, scrubber performance, meeting a particular limit with an 
averaging period of less than a year and at a specified statutory 
emissions level would require a lower annual average SO2 
emission rate (or annual equivalent SO2 limit) than would the 
shorter term statutory limit. EPA has selected a compliance level of one 
exceedance per 10 years. For example, an SO2 emission limit 
of 1.2 lbs/MMBtu, enforced for a scrubbed unit over a 7-day averaging 
period, would result in an annualized SO2 emission limit of 
1.16 lbs/MMBtu. In general, the shorter the averaging period, the lower 
the annual equivalent would be. Thus, the annualization of limits is 
established by multiplying each federally enforceable limit by an 
annualization factor that is determined by the averaging period and 
whether or not it's a scrubbed unit.

[[Page 90]]



   Table A-1--SO2Emission Averaging Periods and Annualization Factors
------------------------------------------------------------------------
                                                    Annualization factor
                                                   ---------------------
                    Definition                       Scrubbed Unscrubbed
                                                   ---------------------
                                                       Unit       Unit
------------------------------------------------------------------------
Oil/gas unit......................................       1.00       1.00
< = 1 day.........................................       0.93       0.89
1 week............................................       0.97       0.92
30 days...........................................       1.00       0.96
90 days...........................................       1.00       1.00
1 year............................................       1.00       1.00
Not specified.....................................       0.93       0.89
At all times......................................       0.93       0.89
Coal unit: No Federal limit or limit unknown......       1.00       1.00
------------------------------------------------------------------------



  Sec. Appendix B to Part 72--Methodology for Conversion of Emissions 
                                 Limits

    For the purposes of the Acid Rain Program, all emissions limits must 
be expressed in pounds of SO2 per million British Thermal 
Unit of heat input (lb/mmBtu).
    The factor for converting pounds of sulfur to pounds of 
SO2 is based on the molecular weights of sulfur (32) and 
SO2 (64). Limits expressed as percentage of sulfur or parts 
per million (ppm) depend on the energy content of the fuel and thus may 
vary, depending on several factors such as fuel heat content and 
atmospheric conditions. Generic conversions for these limits are based 
on the assumed average energy contents listed in table A-2. In addition, 
limits in ppm vary with boiler operation (e.g., load and excess air); 
generic conversions for these limits assume, conservatively, very low 
excess air. The remaining factors are based on site-specific heat rates 
and capacities to develop conversions for Btu per hour. Standard 
conversion factors for residual oil are 42 gal/bbl and 7.88 lbs/gal.

                                          Table B-1--Conversion Factors
                      [Emission limits converted to lbs SO2/MMBtu by multiplying as below]
----------------------------------------------------------------------------------------------------------------
                                                                                 Plant fuel type
                                                               -------------------------------------------------
                       Unit measurement                          Bituminous  Subbituminous  Lignite
                                                                    coal          coal        coal       Oil
----------------------------------------------------------------------------------------------------------------
Lbs sulfur/ MMBtu.............................................          2.0           2.0       2.0          2.0
% sulfur in fuel..............................................         1.66          2.22      2.86         1.07
Ppm SO2.......................................................      0.00287       0.00384   .......      0.00167
Ppm sulfur in fuel............................................  ...........  .............  .......      0.00334
Tons SO2/hour.................................................    2,000,000/(HEATRATE*SUMNDCAP*capacity factor)
                                                                                       \1\
Lbs SO2/hour..................................................    1,000/(HEATRATE*SUMNDCAP*capacity factor) \1\
----------------------------------------------------------------------------------------------------------------
\1\ In these cases, if the limit was specified as the ``site'' limit, the summer net dependable capability for
  the entire plant is used; otherwise, the summer net dependable capability for the unit is used. For units
  listed in the NADB, ``HEATRATE'' shall be that listed in the NADB under that field and ``SUMNDCAP'' shall be
  that listed in the NADB under that field. For units not listed in the NADB, ``HEATRATE'' is the generator net
  full load heat rate reported on Form EIA-860 and ``SUMNDCAP'' is the summer net dependable capability of the
  generator (in MWe) as reported on Form EIA-860.


               Table B-2--Assumed Average Energy Contents
------------------------------------------------------------------------
               Fuel type                       Average heat content
------------------------------------------------------------------------
Bituminous Coal........................  24 MMBtu/ton.
Subbituminous Coal.....................  18 MMBtu/ton.
Lignite Coal...........................  14 MMBtu/ton.
Residual Oil...........................  6.2 MMBtu/bbl.
------------------------------------------------------------------------



Sec. Appendix C to Part 72--Actual 1985 Yearly SO2 Emissions 
                               Calculation

    The equation used to calculate the yearly SO2 emissions 
(SO2) is as follows:

SO2 = (coal SO2 emissions) + (oil SO2 emissions) 
          (in tons)

    If gas is the only fuel, gas emissions are defaulted to 0.
    Each fuel type SO2 emissions is calculated on a yearly 
basis, using the equation:

fuel SO2 emissions (in tons) = (yrly wtd. av. fuel sulfur %) 
          x (AP-42 fact.) x (1-scrb. effic. %/100) x (units conver. 
          fact.) x (yearly fuel burned)

    For coal, the yearly fuel burned is in tons/yr and the AP-42 factor 
(which accounts for the ash retention of sulfur in coal), in lbs 
SO2 ton coal, is by coal type:

------------------------------------------------------------------------
                Coal type                           AP-42 factor
------------------------------------------------------------------------
Bituminous, anthracite...................  39 lbs/ton
Subbituminous............................  35
Lignite..................................  30
------------------------------------------------------------------------

    For oil, the yearly fuel burned is in gal/yr. If it is in bbl/yr, 
convert using 42 gal/bbl oil. The AP-42 factor (which accounts for the 
oil density), in lbs SO2/thousand gal oil, is by oil type:

------------------------------------------------------------------------
               Oil type                           AP-42 factor
------------------------------------------------------------------------
Distillate (light)...................  142 lbs/1,000 gal
Residual (heavy).....................  157
------------------------------------------------------------------------


[[Page 91]]

    For all fuel, the units conversion factor is 1 ton/2000 lbs.



  Sec. Appendix D to Part 72--Calculation of Potential Electric Output 
                                Capacity

    The potential electrical output capacity is calculated from the 
maximum design heat input from the boiler by the following equation:
[GRAPHIC] [TIFF OMITTED] TC10NO91.003

For example:

    (1) Assume a boiler with a maximum design heat input capacity of 340 
million Btu/hr.
    (2) One-third of the maximum design heat input capacity is 113.3 
mmBtu/hr. The one-third factor relates to the thermodynamic efficiency 
of the boiler.
    (3) To express this in MWe, the standards conversion of 3413 Btu to 
1 kw-hr is used: 113.3 x 10\6\ Btu/hr x 1 kw-hr / 3413 Btu x 1 MWe / 
1000 kw = 33.2 MWe

[58 FR 15649, Mar. 23, 1993]



PART 73_SULFUR DIOXIDE ALLOWANCE SYSTEM--Table of Contents



                    Subpart A_Background and Summary

Sec.
73.1 Purpose and scope.
73.2 Applicability.
73.3 General.

                     Subpart B_Allowance Allocations

73.10 Initial allocations for phase I and phase II.
73.11 [Reserved]
73.12 Rounding procedures.
73.13 Procedures for submittals.
73.14-73.17 [Reserved]
73.18 Submittal procedures for units commencing commercial operation 
          during the period from January 1, 1993, through December 31, 
          1995.
73.19 Certain units with declining SO2 rates.
73.20 Phase II early reduction credits.
73.21 Phase II repowering allowances.
73.22-73.24 [Reserved]
73.25 Phase I extension reserve.
73.26 Conservation and renewable energy reserve.
73.27 Special allowance reserve.

                   Subpart C_Allowance Tracking System

73.30 Allowance tracking system accounts.
73.31 Establishment of accounts.
73.32 [Reserved]
73.33 Authorized account representative.
73.34 Recordation in accounts.
73.35 Compliance.
73.36 Banking.
73.37 Account error.
73.38 Closing of accounts.

                      Subpart D_Allowance Transfers

73.50 Scope and submission of transfers.
73.51 [Reserved]
73.52 EPA recordation.
73.53 Notification.

   Subpart E_Auctions, Direct Sales, and Independent Power Producers 
                            Written Guarantee

73.70 Auctions.
73.71 Bidding.
73.72 Direct sales.
73.73 Delegation of auctions and sales and termination of auctions and 
          sales.

       Subpart F_Energy Conservation and Renewable Energy Reserve

73.80 Operation of allowance reserve program for conservation and 
          renewable energy.
73.81 Qualified conservation measures and renewable energy generation.
73.82 Application for allowances from reserve program.
73.83 Secretary of Energy's action on net income neutrality 
          applications.
73.84 Administrator's action on applications.
73.85 Administrator review of the reserve program.
73.86 State regulatory autonomy.

Appendix A to Subpart F of Part 73--List of Qualified Energy 
          Conservation Measures, Qualified Renewable Generation, and 
          Measures Applicable for Reduced Utilization

                    Subpart G_Small Diesel Refineries

73.90 Allowance allocations for small diesel refineries.


[[Page 92]]


    Authority: 42 U.S.C. 7601 and 7651 et seq.



                    Subpart A_Background and Summary

    Source: 58 FR 3687, Jan. 11, 1993, unless otherwise noted.



Sec. 73.1  Purpose and scope.

    The purpose of this part is to establish the requirements and 
procedures for the following:
    (a) The allocation of sulfur dioxide emissions allowances;
    (b) The tracking, holding, and transfer of allowances;
    (c) The deduction of allowances for purposes of compliance and for 
purposes of offsetting excess emissions pursuant to parts 72 and 77 of 
this chapter;
    (d) The sale of allowances through EPA-sponsored auctions and a 
direct sale, including the independent power producers written guarantee 
program; and
    (e) The application for, and distribution of, allowances from the 
Conservation and Renewable Energy Reserve.
    (f) The application for, and distribution of, allowances for 
desulfurization of fuel by small diesel refineries.

[58 FR 3687, Jan. 11, 1993, as amended at 58 FR 15650, Mar. 23, 1993]



Sec. 73.2  Applicability.

    The following parties shall be subject to the provisions of this 
part:
    (a) Owners, operators, and designated representatives of affected 
sources and affected units pursuant to Sec. 72.6 of this chapter;
    (b) Any new independent power producer as defined in section 416 of 
the Act and Sec. 72.2 of this chapter, except as provided in section 
405(g)(6) of the Act;
    (c) Any owner of an affected unit who may apply to receive 
allowances under the Energy Conservation and Renewable Energy Reserve 
Program established in accordance with section 404(f) of the Act;
    (d) Any small diesel refinery as defined in Sec. 72.2 of this 
chapter, and
    (e) Any other person, as defined in Sec. 72.2 of this chapter, who 
chooses to purchase, hold, or transfer allowances as provided in section 
403(b) of the Act.



Sec. 73.3  General.

    Part 72 of this chapter, including Sec. Sec. 72.2 (definitions), 
72.3 (measurements, abbreviations, and acronyms), 72.4 (Federal 
authority), 72.5 (State authority), 72.6 (applicability), 72.7 (new 
units exemption), 72.8 (retired unit exemption), 72.9 (standard 
requirements), 72.10 (availability of information), and 72.11 
(computation of time) of part 72, subpart A of this chapter, shall apply 
to this part. The procedures for appeals of decisions of the 
Administrator under this part are contained in part 78 of this chapter. 
Sections 73.3 (Definitions) and 73.4 (Deadlines), which were previously 
published with subpart E of this part--``Auctions, Direct Sales, and 
Independent Power Producers Written Guarantee'', are codified at 
Sec. Sec. 72.2 and 72.12 of this chapter, respectively.



                     Subpart B_Allowance Allocations

    Source: 58 FR 3687, Jan. 11, 1993, unless otherwise noted.



Sec. 73.10  Initial allocations for phase I and phase II.

    (a) Phase I allowances. The Administrator will allocate allowances 
to the compliance account for each source that includes a unit listed in 
table 1 of this section in the amount listed in column A to be held for 
the years 1995 through 1999.

                                     Table 1--Phase I Allowance Allocations
----------------------------------------------------------------------------------------------------------------
                                                                              Column A final
          State name                      Plant name              Boiler         phase 1        Column B auction
                                                                                allocation     and sales reserve
----------------------------------------------------------------------------------------------------------------
Alabama.......................  Colbert.......................  1                       13213                357
                                                                2                       14907                403
                                                                3                       14995                405
                                                                4                       15005                405
                                                                5                       36202                978
                                E.C. Gaston...................  1                       17624                476
                                                                2                       18052                488
                                                                3                       17828                482

[[Page 93]]

 
                                                                4                       18773                507
                                                                5                       58265               1575
Florida.......................  Big Bend......................  BB01                    27662                748
                                                                BB02                    26387                713
                                                                BB03                    26036                704
                                Crist.........................  6                       18695                505
                                                                7                       30846                834
Georgia.......................  Bowen.........................  1BLR                    54838               1482
                                                                2BLR                    53329               1441
                                                                3BLR                    69862               1888
                                                                4BLR                    69852               1888
                                Hammond.......................  1                        8549                231
                                                                2                        8977                243
                                                                3                        8676                234
                                                                4                       36650                990
                                Jack McDonough................  MB1                     19386                524
                                                                MB2                     20058                542
                                Wansley.......................  1                       68908               1862
                                                                2                       63708               1722
                                Yates.........................  Y1BR                     7020                190
                                                                Y2BR                     6855                185
                                                                Y3BR                     6767                183
                                                                Y4BR                     8676                234
                                                                Y5BR                     9162                248
                                                                Y6BR                    24108                652
                                                                Y7BR                    20915                565
Illinois......................  Baldwin.......................  1                       46052               1245
                                                                2                       48695               1316
                                                                3                       46644               1261
                                Coffeen.......................  01                      12925                349
                                                                02                      39102               1057
                                Grand Tower...................  09                       6479                175
                                Hennepin......................  2                       20182                545
                                Joppa Steam...................  1                       12259                331
                                                                2                       10487                283
                                                                3                       11947                323
                                                                4                       11061                299
                                                                5                       11119                301
                                                                6                       10341                279
                                Kincaid.......................  1                       34564                934
                                                                2                       37063               1002
                                Meredosia.....................  05                      15227                411
                                Vermilion.....................  2                        9735                263
Indiana.......................  Bailly........................  7                       12256                331
                                                                8                       17134                463
                                Breed.........................  1                       20280                548
                                Cayuga........................  1                       36581                989
                                                                2                       37415               1011
                                Clifty Creek..................  1                       19620                530
                                                                2                       19289                521
                                                                3                       19873                537
                                                                4                       19552                528
                                                                5                       18851                509
                                                                6                       19844                536
                                Elmer W. Stout................  50                       4253                115
                                                                60                       5229                141
                                                                70                      25883                699
                                F.B. Culley...................  2                        4703                127
                                                                3                       18603                503
                                Frank E. Ratts................  1SG1                     9131                247
                                                                2SG1                     9296                251
                                Gibson........................  1                       44288               1197
                                                                2                       44956               1215
                                                                3                       45033               1217
                                                                4                       44200               1195
                                H.T. Pritchard................  6                        6325                171
                                Michigan City.................  12                      25553                691
                                Petersburg....................  1                       18011                487
                                                                2                       35496                959
                                R. Gallagher..................  1                        7115                192
                                                                2                        7980                216

[[Page 94]]

 
                                                                3                        7159                193
                                                                4                        8386                227
                                Tanners Creek.................  U4                      27209                735
                                Wabash River..................  1                        4385                118
                                                                2                        3135                 85
                                                                3                        4111                111
                                                                5                        4023                109
                                                                6                       13462                364
                                Warrick.......................  4                       29577                799
Iowa..........................  Burlington....................  1                       10428                282
                                Des Moines....................  11                       2259                 61
                                George Neal...................  1                        2571                 69
                                Milton L. Kapp................  2                       13437                363
                                Prairie Creek.................  4                        7965                215
                                Riverside.....................  9                        3885                105
Kansas........................  Quindaro......................  2                        4109                111
Kentucky......................  Coleman.......................  C1                      10954                296
                                                                C2                      12502                338
                                                                C3                      12015                325
                                Cooper........................  1                        7254                196
                                                                2                       14917                403
                                E.W. Brown....................  1                        6923                187
                                                                2                       10623                287
                                                                3                       25413                687
                                Elmer Smith...................  1                        6348                172
                                                                2                       14031                379
                                Ghent.........................  1                       27662                748
                                Green River...................  5                        7614                206
                                H.L. Spurlock.................  1                       22181                599
                                HMP&L Station 2...............  H1                      12989                351
                                                                H2                      11986                324
                                Paradise......................  3                       57613               1557
                                Shawnee.......................  10                       9902                268
Maryland......................  C.P. Crane....................  1                       10058                272
                                                                2                        8987                243
                                Chalk Point...................  1                       21333                577
                                                                2                       23690                640
                                Morgantown....................  1                       34332                928
                                                                2                       37467               1013
Michigan......................  J.H. Campbell.................  1                       18773                507
                                                                2                       22453                607
Minnesota.....................  High Bridge...................  6                        4158                112
Mississippi...................  Jack Watson...................  4                       17439                471
                                                                5                       35734                966
Missouri......................  Asbury........................  1                       15764                426
                                James River...................  5                        4722                128
                                LaBadie.......................  1                       39055               1055
                                                                2                       36718                992
                                                                3                       39249               1061
                                                                4                       34994                946
                                Montrose......................  1                        7196                194
                                                                2                        7984                216
                                                                3                        9824                266
                                New Madrid....................  1                       27497                743
                                                                2                       31625                855
                                Sibley........................  3                       15170                410
                                Sioux.........................  1                       21976                594
                                                                2                       23067                623
                                Thomas Hill...................  MB1                      9980                270
                                                                MB2                     18880                510
New Hampshire.................  Merrimack.....................  1                        9922                268
                                                                2                       21421                579
New Jersey....................  B.L. England..................  1                        8822                238
                                                                2                       11412                308
New York......................  Dunkirk.......................  3                       12268                332
                                                                4                       13690                370
                                Greenidge.....................  6                        7342                198
                                Milliken......................  1                       10876                294
                                                                2                       12083                327
                                Northport.....................  1                       19289                521
                                                                2                       23476                634

[[Page 95]]

 
                                                                3                       25783                697
                                Port Jefferson................  3                       10194                276
                                                                4                       12006                324
Ohio..........................  Ashtabula.....................  7                       18351                496
                                Avon Lake.....................  11                      12771                345
                                                                12                      33413                903
                                Cardinal......................  1                       37568               1015
                                                                2                       42008               1135
                                Conesville....................  1                        4615                125
                                                                2                        5360                145
                                                                3                        6029                163
                                                                4                       53463               1445
                                Eastlake......................  1                        8551                231
                                                                2                        9471                256
                                                                3                       10984                297
                                                                4                       15906                430
                                                                5                       37349               1009
                                Edgewater.....................  13                       5536                150
                                Gen. J.M. Gavin...............  1                       86690               2343
                                                                2                       88312               2387
                                Kyger Creek...................  1                       18773                507
                                                                2                       18072                488
                                                                3                       17439                471
                                                                4                       18218                492
                                                                5                       18247                493
                                Miami Fort....................  5-1                       417                 11
                                                                5-2                       417                 11
                                                                6                       12475                337
                                                                7                       42216               1141
                                Muskingum River...............  1                       16312                441
                                                                2                       15533                420
                                                                3                       15293                413
                                                                4                       12914                349
                                                                5                       44364               1199
                                Niles.........................  1                        7608                206
                                                                2                        9975                270
                                Picway........................  9                        5404                146
                                R.E. Burger...................  5                        3371                 91
                                                                6                        3371                 91
                                                                7                       11818                319
                                                                8                       13626                368
                                W.H. Sammis...................  5                       26496                716
                                                                6                       43773               1183
                                                                7                       47380               1280
                                Walter C. Beckjord............  5                        9811                265
                                                                6                       25235                682
Pennsylvania..................  Armstrong.....................  1                       14031                379
                                                                2                       15024                406
                                Brunner Island................  1                       27030                730
                                                                2                       30282                818
                                                                3                       52404               1416
                                Cheswick......................  1                       38139               1031
                                Conemaugh.....................  1                       58217               1573
                                                                2                       64701               1749
                                Hatfield's Ferry..............  1                       36835                995
                                                                2                       36338                982
                                                                3                       39210               1060
                                Martins Creek.................  1                       12327                333
                                                                2                       12483                337
                                Portland......................  1                        5784                156
                                                                2                        9961                269
                                Shawville.....................  1                       10048                272
                                                                2                       10048                272
                                                                3                       13846                374
                                                                4                       13700                370
                                Sunbury.......................  3                        8530                230
                                                                4                       11149                301
Tennessee.....................  Allen.........................  1                       14917                403
                                                                2                       16329                441
                                                                3                       15258                412
                                Cumberland....................  1                       84419               2281

[[Page 96]]

 
                                                                2                       92344               2496
                                Gallatin......................  1                       17400                470
                                                                2                       16855                455
                                                                3                       19493                527
                                                                4                       20701                559
                                Johnsonville..................  1                        7585                205
                                                                10                       7351                199
                                                                2                        7828                212
                                                                3                        8189                221
                                                                4                        7780                210
                                                                5                        8023                217
                                                                6                        7682                208
                                                                7                        8744                236
                                                                8                        8471                229
                                                                9                        6894                186
West Virginia.................  Albright......................  3                       11684                316
                                Fort Martin...................  1                       40496               1094
                                                                2                       40116               1084
                                Harrison......................  1                       47341               1279
                                                                2                       44936               1214
                                                                3                       40408               1092
                                Kammer........................  1                       18247                493
                                                                2                       18948                512
                                                                3                       16932                458
                                Mitchell......................  1                       42823               1157
                                                                2                       44312               1198
                                M.T. Storm....................  1                       42570               1150
                                                                2                       34644                936
                                                                3                       41314               1116
Wisconsin.....................  Edgewater.....................  4                       24099                651
                                Genoa.........................  1                       22103                597
                                Nelson Dewey..................  1                        5852                158
                                                                2                        6504                176
                                North Oak Creek...............  1                        5083                137
                                                                2                        5005                135
                                                                3                        5229                141
                                                                4                        6154                166
                                Pulliam.......................  8                        7312                198
                                South Oak Creek...............  5                        9416                254
                                                                6                       11723                317
                                                                7                       15754                426
                                                                8                       15375                415
----------------------------------------------------------------------------------------------------------------

    (b) Phase II allowances. (1) The Administrator will allocate 
allowances to the compliance account for each source that includes a 
unit listed in table 2 of this section in the amount specified in table 
2 column C to be held for the years 2000 through 2009.
    (2) The Administrator will allocate allowances to the compliance 
account for each source that includes a unit listed in table 2 of this 
section in the amount specified in table 2 column F to be held for the 
years 2010 and each year thereafter.

[[Page 97]]

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[GRAPHIC] [TIFF OMITTED] TR28SE98.050

    (3) The owner of each unit listed in the following table shall 
surrender, for each allowance listed in Column A or B of such table, an 
allowance of the same or earlier compliance use date and shall return to 
the Administrator any proceeds received from allowances withheld from 
the unit, as listed in Column C of such table. The allowances shall be 
surrendered and the proceeds shall be returned by December 28, 1998.

----------------------------------------------------------------------------------------------------------------
                                                                  Allowances for  Allowances for
                                                                   2000 through      2010 and
       State              Plant name                Unit            2009 column     thereafter       Proceeds
                                                                        (A)         column (B)
----------------------------------------------------------------------------------------------------------------
CA.................  El Centro...........  2                                 285             272        $2749.48
CO.................  Valmont.............  11                                  4               0            0
FL.................  Lauderdale..........  PFL4                              776             781         7904.74
FL.................  Lauderdale..........  PFL5                              796             802         7904.74
LA.................  R S Nelson..........  1                                  30              34            0
LA.................  R S Nelson..........  2                                  33              32            0
MD.................  R P Smith...........  9                                   0              56          687.37
NM.................  Maddox..............  **3                                85              85          687.37
SD.................  Mobile..............  **2                                17              17            0
VA.................  Chesterfield........  **8B                              409             411         4124.21
WI.................  Blount Street.......  7                                   0              13          343.68
WI.................  Blount Street.......  8                                   0             294         3093.16
WI.................  Blount Street.......  9                                   0             355         3436.84
----------------------------------------------------------------------------------------------------------------


[[Page 147]]


[58 FR 3687, Jan. 11, 1993, as amended at 58 FR 15650, Mar. 23, 1993; 58 
FR 33770, June 21, 1993; 58 FR 40747, July 30, 1993; 62 FR 55486, Oct. 
24, 1997; 63 FR 51714, Sept. 28, 1998; 70 FR 25335, May 12, 2005]



Sec. 73.11  [Reserved]



Sec. 73.12  Rounding Procedures.

    (a) Calculation rounding. All allowances under this part and part 72 
of this chapter shall be allocated as whole allowances. All calculations 
for such allowances shall be rounded down for decimals less than 0.500 
and up for decimals of 0.500 or greater.
    (b) [Reserved]

[58 FR 3687, Jan. 11, 1993, as amended at 63 FR 51765, Sept. 28, 1998]



Sec. 73.13  Procedures for submittals.

    (a) Address for submittal. All submittals under this subpart shall 
be made by the designated representative to the Director, Acid Rain 
Division, (6204J), 1200 Pennsylvania Ave., NW., Washington, DC 20460 and 
shall meet the requirements specified in 40 CFR 72.21.
    (b) Appeals procedures. The designated representative may appeal the 
decision as to eligibility or allocation of allowances under Sec. Sec. 
73.18, 73.19, and 73.20, using the appeals procedures of part 78 of this 
chapter.

[58 FR 15708, Mar. 23, 1993, as amended at 63 FR 51765, Sept. 28, 1998]



Sec. Sec. 73.14-73.17  [Reserved]



Sec. 73.18  Submittal procedures for units commencing commercial
operation during the period from January 1, 1993, through
December 31, 1995.

    (a) Eligibility. To be eligible for allowances under this section, a 
unit shall commence commercial operation between January 1, 1993, and 
December 31, 1995, and have commenced construction before December 31, 
1990.
    (b) Application for allowances. No later than December 31, 1995, the 
designated representative for a unit expected to be eligible under this 
provision must submit a photocopy of a signed contract for the 
construction of the unit.
    (c) Commencement of commercial operation. The Administrator will use 
EIA information submitted by the utility for the boiler on-line date as 
commencement of commercial operation.

[58 FR 15710, Mar. 23, 1993]



Sec. 73.19  Certain units with declining SO [bdi2] rates.

    (a) Eligibility. A unit is eligible for allowance allocations under 
this section if it meets the following requirements:
    (1) It is an existing unit that is a utility unit;
    (2) It serves a generator with nameplate capacity equal to or 
greater than 75 MWe;
    (3) Its 1985 actual SO2 emissions rate was equal to or 
greater than 1.2 lb/mmBtu;
    (4) Its 1990 actual SO2 emissions rate is at least 50 
percent less than the lesser of its 1980 actual or allowable 
SO2 emissions rate;
    (5) Its actual SO2 emission rate is less than 1.2 lb/
mmBtu in any one calendar year from 1996 through 1999, as reported under 
part 75 of this chapter;
    (6) It commenced commercial operation after January 1, 1970;
    (7) It is part of a utility system whose combined commercial and 
industrial kilowatt-hour sales increased more than 20 percent between 
calendar years 1980 and 1990; and
    (8) It is part of a utility system whose company-wide fossil-fuel 
SO2 emissions rate declined 40 percent or more from 1980 to 
1988.
    (b) [Reserved]

[58 FR 15710, Mar. 23, 1993, as amended at 63 FR 51765, Sept. 28, 1998]



Sec. 73.20  Phase II early reduction credits.

    (a) Unit eligibility. Units listed in table 2 or 3 of Sec. 73.10 
are eligible for allowances under this section if:
    (1) The unit is not a unit subject to emissions limitation 
requirements of Phase I and is not a substitution unit (under 40 CFR 
72.41) or a compensating unit (under 40 CFR 72.43);
    (2) The unit is authorized by the Governor of the State in which the 
unit is located;

[[Page 148]]

    (3) The unit is part of a utility system (which, for the purposes of 
this section only, includes all generators operated by a single utility, 
including generators that are not fossil fuel-fired) that has decreased 
its total coal-fired generation, as a percentage of total system 
generation, by more than twenty percent between January 1, 1980, and 
December 31, 1985; and
    (4) The unit is part of a utility system that during calendar years 
1985 through 1987 had a weighted capacity factor for all coal-fired 
units in the system of less than fifty percent. The weighted capacity 
factor is equal to:
[GRAPHIC] [TIFF OMITTED] TC01SE92.073

    (b) Emissions reductions eligibility. Sulfur dioxide emissions 
reductions eligible for allowance credits at units eligible under 
paragraph (a) of this section must meet the following requirements:
    (1) Be made no earlier than calendar year 1995 and no later than 
calendar year 1999; and
    (2) Be due to physical changes to the plant or are a result of a 
change in the method of operating the plant including but not limited to 
changing the type or quality of fuel being burned.
    (c) Initial certification of eligibility. The designated 
representative of a unit that seeks allowances under this section shall 
apply for certification of unit eligibility prior to or accompanying a 
request for allowances under paragraph (d) of this section. A completed 
application for this certification shall be submitted according to Sec. 
73.13 and shall include the following:
    (1) A letter from the Governor of the State in which the unit is 
located authorizing the unit to make reductions in sulfur dioxide 
emissions; and
    (2) A report listing all units in the utility system, each fossil 
fuel-fired unit's fuel consumption and fuel heat content for calendar 
year 1980, and each generator's total electrical generation for calendar 
years 1980 and 1985 (including all generators, whether fossil fuel-
fired, nuclear, hydroelectric or other).
    (d) Request for allowances. (1) The designated representative of the 
requesting unit shall submit the request for allowances according to the 
procedures of Sec. 73.13 and shall include the following information:
    (i) The calendar year for which credits for reductions are requested 
and the actual SO2 emissions and fuel consumption in that 
year;
    (ii) A letter signed by the designated representative stating and 
documenting the specific physical changes to the plant or changes in the 
method of operating the plant (including but not limited to changing the 
type or quality of fuel being burned) which resulted in the reduction of 
emissions; and
    (iii) A letter signed by the designated representative certifying 
that all photocopies are exact copies.
    (2) The designated representative shall submit each request for 
allowances no later than March 1 of the calendar year following the year 
in which the reductions were made.
    (e) Allowance allocation. The Administrator will allocate allowances 
to the eligible unit upon satisfactory submittal of information under 
paragraphs (c) and (d) of this section in the amount calculated by the 
following equations. Such allowances will be allocated to the unit's 
2000 future year subaccount.
    (1) ``Prior year'' means a single calendar year selected by the 
eligible unit from 1995 to 1999 inclusive.
    (2) One ``credit'' equals one ton of eligible SO2 
emissions reductions.
    (3) ``ERC units'' are units eligible for early reduction credits, 
and ``non-ERC units'' are fossil fuel-fired units that are part of the 
same operating system but are not eligible for early reduction credits.
    (4) For any unit that did not operate during 1990, the unit's 1990 
SO2 emission rate will be equal to the weighted average 
emission rate of all of the

[[Page 149]]

other units at the same source that did operate during 1990.
    (5) Early reduction credits will be calculated at the unit level, 
subject to the restrictions in paragraph (e)(6) of this section.
    (6) The number of credits for eligible Phase II units will be 
calculated as follows:
    (i) Comparison of the prior year utilization of ERC units to the 
1990 utilization, as a percentage of system utilization. If, as 
calculated below, system-wide prior year utilization of ERC units 
exceeds systems-wide 1990 utilization of ERC units on a percentage 
basis, then paragraphs (e)(6)(ii) and (iii) of this section apply. If 
not, the ERC units are eligible to receive early reduction credits as 
calculated in paragraph (e)(6)(v)(A) of this section.
[GRAPHIC] [TIFF OMITTED] TC01SE92.074

    (ii) Comparison of the prior year average emission rate of all ERC 
units to the prior year average emission rate of all non-ERC units. If, 
as calculated below, the system-wide average SO2 emission 
rate of ERC units exceeds that of non-ERC units, then a unit's prior 
year utilization will be restricted in accordance with paragraph 
(e)(6)(iv) of this section. If not, then paragraph (iii) of this section 
applies.
[GRAPHIC] [TIFF OMITTED] TC01SE92.075


[[Page 150]]


    (iii) Comparison of the emission rate of the non-ERC units in the 
prior year to the emission rate of the non-ERC units in 1990. If, as 
calculated in paragraph (ii) of this section, the prior year system 
average non-ERC SO2 emission rate increases above the 1990 
system average non-ERC SO2 emission rate, as calculated 
below, then a unit's prior year utilization will be restricted in 
accordance with paragraph (e)(6)(iv) of this section. If not, the ERC 
units are eligible to receive early reduction credits as calculated in 
paragraph (e)(6)(v)(A) of this section.
[GRAPHIC] [TIFF OMITTED] TC01SE92.076

    (iv) Calculation of the utilization limit for restricted units. The 
limit on utilization for each unit eligible for early reduction credits 
subject to paragraphs (e)(6) (ii) and (iii) of this section will be 
calculated as follows:
[GRAPHIC] [TIFF OMITTED] TC01SE92.077

    This result, expressed in million Btus, is the restricted 
utilization of the ERC unit to be used in the calculation of early 
reduction credits in paragraph (e)(6)(v)(B) of this section.
    (v)(A) Calculation of the unit's early reduction credits where the 
unit's prior year utilization is not restricted.
[GRAPHIC] [TIFF OMITTED] TC01SE92.078

    (B) Calculation of the unit's early reduction credits where the 
unit's prior year utilization is restricted.

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[GRAPHIC] [TIFF OMITTED] TC01SE92.079

    (vi) The Administrator will allocate to the ERC unit allowances 
equal to the lesser of the calculated number of credits in paragraphs 
(e)(6)(v) (A) or (B) of this section and the following limitation:
[GRAPHIC] [TIFF OMITTED] TC01SE92.080

    (f) Allowance loan program--(1) Eligibility. Units eligible for 
Phase II early reduction credits under paragraph (a) of this section are 
eligible for allowances under this paragraph (f) if the weighted average 
emission rate (based on heat input) for the prior year for all of the 
affected units in the unit's dispatch system was less than the system-
wide weighted average emission rate for 1990. The weighted average 
emission rate shall be calculated as follows:
[GRAPHIC] [TIFF OMITTED] TR24JN97.000

    For the purposes of this calculation, the unit's dispatch system 
will be the dispatch system as it existed as of November 15, 1990.
    (2) Allowance Calculation. Allowances under this paragraph (f) shall 
be calculated as follows:
[GRAPHIC] [TIFF OMITTED] TR24JN97.001

    (3) Allowance Loan. (i) The number of allowances calculated under 
paragraph (f)(2) of this section shall be allocated to the unit's year 
2000 subaccount.
    (ii) The number of allowances calculated under paragraph (f)(2) of 
this section shall be deducted, contemporaneously with the allocation 
under paragraph (f)(3)(i) of this section, from the unit's year 2015 
subaccount.
    (iii) Notwithstanding paragraph (f)(3)(ii) of this section, if the 
number of allowances to be deducted exceeds the amount of allowances 
allocated to the unit for the year 2015, allowances in the year 2015 
subaccount equal to the amount of allowances allocated to the unit for 
the year 2015 shall be deducted. In addition to the deduction from the 
year 2015 subaccount, a sufficient amount of allowances in the year

[[Page 152]]

2016 subaccount (up to the amount of allowances allocated to the unit 
for the year 2016) shall be deducted contemporaneously, such that the 
sum of the allowances deducted from the subaccounts equals the number of 
allowances required to be deducted under paragraph (f)(3)(ii) of this 
section.
    (iv) Notwithstanding paragraph (f)(3)(ii) of this section, the 
procedure in paragraph (f)(3)(iii) shall be applied as follows to each 
year after 2015 (year-by-year in numerical order) for which the number 
of allowances to be deducted from that year's subaccount exceeds the 
number allocated to the unit for that year: allowances equal to the 
number allocated for that year shall be deducted from that year's 
subaccount and the remainder (up to the amount allocated) necessary to 
equal the number of allowances required to be deducted under paragraph 
(f)(3)(ii) of this section shall be deducted from the next year's 
subaccount.
    (v) The owners and operators of the unit shall ensure that 
sufficient allowances are available to make the full deductions required 
under paragraphs (f)(3)(ii), (iii), and (iv) of this section. The 
designated representative may specify the serial number of each 
allowance to be deducted.
    (4) ERC Units. Any unit to which allowances are allocated under 
paragraph (f)(3)(i) of this section shall be considered an ERC unit for 
purposes of applying the restrictions in paragraph (e)(6) of this 
section.

[58 FR 15711, Mar. 23, 1993, as amended at 62 FR 34150, June 24, 1997]



Sec. 73.21  Phase II repowering allowances.

    (a) Repowering allowances. In addition to allowances allocated under 
Sec. 73.10(b), the Administrator will allocate, to each existing unit 
(under Sec. 72.44(b)(1) of this chapter) with an approved repowering 
extension plan, allowances for use during the repowering extension 
period approved under Sec. 72.44(f)(2)(ii) of this chapter (including a 
prorated allocation for any fraction of a year) equal to:
[GRAPHIC] [TIFF OMITTED] TC01SE92.081

where:

1995 SIP = Most stringent federally enforceable State implementation 
          plan SO2 emissions limitation for 1995.
1995 Actual Rate = 1995 actual SO2 emissions rate
Unit's Adjusted Basic Allowances are as listed in the following table

------------------------------------------------------------------------
                                                              Year 2000
                                                               adjusted
                            Unit                                basic
                                                              allowances
------------------------------------------------------------------------
RE Burger 1................................................         1273
RE Burger 2................................................         1245
RE Burger 3................................................         1286
RE Burger 4................................................         1316
RE Burger 5................................................         1336
RE Burger 6................................................         1332
New Castle 1...............................................         1334
New Castle 2...............................................         1485
New Castle 3...............................................         2935
New Castle 4...............................................         2686
New Castle 5...............................................         5481
------------------------------------------------------------------------

    (b) Upon commencement of commercial operation of a new unit (under 
Sec. 72.44(b)(2) of this chapter) with an approved repowering extension 
plan, allowances for use during the repowering extension period approved 
will end and allocations under Sec. 73.10(b) for the existing unit will 
be transferred to the subaccounts for the new unit.
    (c)(1) If the designated representative for a repowering unit 
terminates the repowering extension plan in accordance with Sec. 
72.44(g)(1) of this chapter, the repowering allowances allocated to that 
unit by paragraph (a) of this section will be terminated and any 
necessary allowances from that unit's account forfeited, calculated in 
the following manner:

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[GRAPHIC] [TIFF OMITTED] TC01SE92.082

where:

Forfeiture Period = difference (as a portion of a year) between the end 
          of the approved repowering extension and the end of the 
          repowering extension under Sec. 72.44(g)(1)(ii)
1995 SIP = Most stringent federally enforceable State implementation 
          plan SO2 emissions limitation for 1995.
1995 Actual Rate = 1995 actual SO2 emissions rate
Unit's Adjusted Basic Allowances are as listed in the table in paragraph 
          (a) of this section.

    (c)(2) The Administrator will reallocate any allowances forfeited in 
paragraph (c)(1) of this section with a compliance use date of 2000 or 
any allowances remaining in the repowering reserve to all Table 2 units' 
years 2000 through 2009 subaccounts in the following manner:
[GRAPHIC] [TIFF OMITTED] TR28SE98.051


[53 FR 15713, Mar. 23, 1993, as amended at 63 FR 51765, Sept. 28, 1998]



Sec. Sec. 73.22-73.24  [Reserved]



Sec. 73.25  Phase I extension reserve.

    The Administrator will initially allocate 3.5 million allowances to 
the Phase I Extension Reserve account of the Allowance Tracking System. 
Allowances from this Reserve will be allocated to units under Sec. 
72.42 of this chapter. Allowances remaining in the Phase I Extension 
Reserve account following allocation of all extension allowances under 
Sec. 72.42 of this chapter will remain in the Reserve.

[58 FR 3687, Jan. 11, 1993]



Sec. 73.26  Conservation and renewable energy reserve.

    The Administrator will allocate 300,000 allowances to the 
Conservation and Renewable Energy Reserve subaccount of the Acid Rain 
Data System. Allowances from this Reserve will be allocated to units 
under subpart F of this part. Termination of this Reserve and 
reallocation of allowances will be made under Sec. 73.80(c).

[53 FR 15714, Mar. 23, 1993]



Sec. 73.27  Special allowance reserve.

    (a) Establishment of Reserve. (1) The Administrator will allocate 
150,000 allowances annually for calendar years 1995 through 1999 to the 
Auction Subaccount of the Special Allowance Reserve.
    (2) The Administrator will allocate 250,000 allowances annually for 
calendar year 2000 and each year thereafter to the Auction Subaccount of 
the Special Allowance Reserve.
    (b) Distribution of proceeds. (1) Monetary proceeds from the 
auctions and sales of allowances from the Special Allowance Reserve 
(under subpart E of this part) for use in calendar years 1995 through 
1999 will be distributed to the designated representative of the unit 
according to the following equation:

unit proceeds = (Column B of table 1 of section 73.10/150,000) x total 
proceeds

    (2) Until June 1, 1998, monetary proceeds from the auctions of 
allowances from the Special Allowance Reserve (under subpart E of this 
part) for use in calendar years 2000 through 2009 will be distributed to 
the designated representative of each unit listed in Table 2 according 
to the following equation:

[[Page 154]]

[GRAPHIC] [TIFF OMITTED] TR28SE98.052

    (3) On or after June 1, 1998, monetary proceeds from the auctions of 
allowances from the Special Allowance Reserve (under subpart E of this 
part) for use in calendar years 2000 through 2009 will be distributed to 
the designated representative of each unit listed in Table 2 according 
to the following equation:
[GRAPHIC] [TIFF OMITTED] TR28SE98.053

    (4) Monetary proceeds from the auctions of allowances from the 
Special Allowance Reserve (under subpart E of this part) from years of 
purchase from 1993 through 1998, remaining in the U.S. Treasury as a 
result of the surrender of allowances and return of proceeds under Sec. 
73.10(b)(3), will be distributed to the designated representative of 
each unit listed in Table 2 according to the following equation:
[GRAPHIC] [TIFF OMITTED] TR28SE98.054

    (5) Monetary proceeds from the auctions of allowances from the 
Special Allowance Reserve (under subpart E of this part) for use in 
calendar years 2010 and thereafter will be distributed to the designated 
representative of each unit listed in Table 2 according to the following 
equation:
[GRAPHIC] [TIFF OMITTED] TR28SE98.055

    (c) Reallocation of allowances. (1) Allowances remaining in the 
Special Allowance Reserve following the annual auctions and sales (under 
subpart E of this part) for use in calendar years 1995 through 1999 will 
be reallocated to the unit's Allowance Tracking System Account according 
to the following equation:

unit allowances = (Column B of table 1 of section 73.10/150,000) x 
Allowances remaining

    (2) Until June 1, 1998, allowances, for use in calendar years 2000 
through 2009, remaining in the Special Allowance Reserve at the end of 
each year, following that year's auction (under subpart E of this part), 
will be reallocated to the unit's Allowance Tracking System account 
according to the following equation:

[[Page 155]]

[GRAPHIC] [TIFF OMITTED] TR28SE98.056

    (3) On or after June 1, 1998, allowances, for use in calendar years 
2000 through 2009, remaining in the Special Allowance Reserve at the end 
of each year, following that year's auction (under subpart E of this 
part), will be reallocated to the compliance account of the source that 
includes the unit according to the following equation:
[GRAPHIC] [TIFF OMITTED] TR28SE98.057

    (4) [Reserved]
    (5) Allowances, for use in calendar years 2010 and thereafter, 
remaining in the Special Allowance Reserve at the end of each year, 
following that year's auction (under subpart E of this part), will be 
reallocated to the compliance account of the source that includes the 
unit according to the following equation:
[GRAPHIC] [TIFF OMITTED] TR28SE98.058

    (d) Calculation rounding. All proceeds under this section shall be 
distributed as whole dollars. All calculations for such allowances shall 
be rounded down for decimals less than .5 and up for decimals of .5 or 
greater.
    (e) Achieving exact totals. (1) If the sum of the proceeds to be 
distributed under paragraph (b) of this section exceeds the total 
proceeds or the allowances to be reallocated under paragraph (c) of this 
section exceeds the allowances remaining, then the Administrator will 
withdraw one dollar or allowance from each unit, beginning with the unit 
receiving the largest number of dollars or allowances, in descending 
order, until the distribution balances with the proceeds and the 
reallocated allowances balance with the remaining allowances.
    (2) If the sum of the proceeds to be distributed under paragraph (b) 
of this section is less than the total proceeds or the allowances to be 
reallocated under paragraph (c) of this section is less than the 
allowances remaining, then EPA will distribute one dollar or allowance 
for each unit, beginning with the unit receiving the largest number of 
dollars or allowances, in descending order, until the distribution 
balances with the proceeds and the reallocated allowances balance with 
the remaining allowances.

[58 FR 3687, Jan. 11, 1993, as amended at 58 FR 15714, Mar. 23, 1993; 63 
FR 51765, Sept. 28, 1998; 70 FR 25335, May 12, 2005]



                   Subpart C_Allowance Tracking System

    Source: 58 FR 3691, Jan. 11, 1993, unless otherwise noted.



Sec. 73.30  Allowance tracking system accounts.

    (a) Nature and function of unit accounts. The Administrator will 
establish compliance accounts for all affected sources pursuant to Sec. 
73.31 (a) and (b). All allocations of allowances pursuant to subparts B, 
E, and F of this

[[Page 156]]

part and part 72 of this chapter, transfers of allowances made pursuant 
to subparts C and D, and deductions of allowances made for purposes of 
offsetting emissions pursuant to Sec. 73.35 (b) and (d) and parts 72, 
75, and 77 of this chapter will be recorded in the source's compliance 
account.
    (b) Nature and function of general accounts. Transfers of allowances 
held for any person other than an affected source, made pursuant to 
subparts C, D, E, F, and G of this part will be recorded in that 
person's general account established pursuant to Sec. 73.31(c).

[58 FR 3687, Jan. 11, 1993; 58 FR 40747, July 30, 1993, as amended at 70 
FR 25335, May 12, 2005]



Sec. 73.31  Establishment of accounts.

    (a) Existing affected units. The Administrator will establish a 
compliance account and allocate allowances for each source that includes 
a unit that is, or will become, an existing affected unit pursuant to 
sections 404(a) or 405 of the Act and Sec. 72.6 of this chapter.
    (b) New units. Upon receipt of a complete certificate of 
representation for the designated representative for a new unit pursuant 
to part 72, subpart B of this chapter, the Administrator will establish 
a compliance account for the source that includes the unit, unless the 
source already has a compliance account.
    (c) General accounts. (1) Any person may apply to open an Allowance 
Tracking System account for the purpose of holding and transferring 
allowances. Such application shall be submitted to the Administrator in 
a format to be specified by the Administrator by means of the Allowance 
Account Information Form, or by providing the following information in a 
similar format:
    (i) Name and title of the authorized account representative and 
alternate authorized account representative (if any) pursuant to Sec. 
73.33;
    (ii) Mailing address, telephone number and facsimile transmission 
number (if any) of the authorized account representative and alternate 
authorized account representative (if any);
    (iii) Organization or company name (if applicable) and type of 
organization (if applicable);
    (iv) A list of all persons subject to a binding agreement for the 
authorized account representative to represent their ownership interest 
with respect to the allowances held in the general account and which 
shall be amended and resubmitted within 30 days following any 
transaction giving rise to any change of the list of persons subject to 
the binding agreement;
    (v) A certification statement by the authorized account 
representative and alternate authorized account representative (if any) 
that reads ``I certify that I was selected under the terms of 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 necessary authority to carry out my duties and responsibilities 
on behalf of the persons with an ownership interest and that they shall 
be fully bound by my representations, actions, inactions, or submissions 
under 40 CFR part 73. I am authorized to make this submission on behalf 
of the persons with an ownership interest for whom this submission is 
made. I certify under penalty of law that I have personally examined and 
am familiar with the 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 
information is to the best of my knowledge and belief true, accurate, 
and complete. I am aware that there are significant penalties for 
submitting false material information, or omitting material information, 
including the possibility of fine or imprisonment for violations.'';
    (vi) The signature of the authorized account representative and the 
alternate authorized account representative (if any); and
    (vii) The date of the signature of the authorized account 
representative and the alternate authorized account representative (if 
any).
    (2) Upon receipt of such complete application, the Administrator 
will establish an Allowance Tracking System account for the person or 
persons identified in the application.
    (3) No allowance transfers will be recorded for a general account 
until the

[[Page 157]]

Administrator has established the new account.
    (d) Account identification. The Administrator will assign a unique 
identifying number to each account established pursuant to this section.

[58 FR 3687, Jan. 11, 1993; 58 FR 40747, July 30, 1993, as amended at 71 
FR 25378, Apr. 28, 2006; 70 FR 25335, May 12, 2005]



Sec. 73.32  [Reserved]



Sec. 73.33  Authorized account representative.

    (a) Following the establishment of an Allowance Tracking System 
account, all matters pertaining to the account, including, but not 
limited to, the deduction and transfer of allowances in the account, 
shall be undertaken only by the authorized account representative.
    (b)-(c) [Reserved]
    (d) General account alternate authorized account representative. Any 
application for opening a general account may designate one alternate 
authorized account representative to act on behalf of the certifying 
authorized account representative, in the event the authorized account 
representative is absent or otherwise not available to perform actions 
and duties under this part. The alternate shall be a natural person and 
shall be authorized, provided that the conditions and procedures 
specified in Sec. 73.31(c)(1) are met.
    (1) The alternate authorized account representative may be changed 
at any time by the authorized account representative upon receipt by the 
Administrator of a new complete application as required in Sec. 
73.31(c);
    (2) The alternate authorized account representative shall be subject 
to the provisions of this part applicable to authorized account 
representatives;
    (3) Whenever the term ``authorized account representative'' is used 
in this part it shall be construed to include the alternate authorized 
account representative, unless such a construction would be illogical 
from the context; and
    (4) Any representation, action, inaction, or submission by the 
alternate authorized account representative when acting in that capacity 
shall be deemed to be a representation, action, inaction, or submission 
of the authorized account representative, with all the rights, duties, 
and responsibilities pertaining thereto.
    (e) Changes to the general account authorized account 
representative. An authorized account representative for a general 
account may be succeeded by any person who submits an application 
pursuant to Sec. 73.31(c). The representations, actions, inactions, or 
submissions of an authorized account representative for a general 
account shall be binding on any successor.
    (f) Objections to the authorized account representative. Except for 
a certification pursuant to paragraph (e) of this section, no objection 
or other communication submitted to the Administrator concerning any 
representation, action, inaction, or submission to the Administrator by 
the authorized account representative shall affect any representation, 
action, inaction, or submission of the authorized account representative 
pursuant to subpart D of this part. Neither the United States, the 
Administrator, nor any permitting authority will adjudicate any dispute 
between and among persons concerning any submission to the Administrator 
by the authorized account representative; any actions of the authorized 
account representative; or any other matter arising directly or 
indirectly from the certification, actions or representations of the 
authorized account representative.
    (g) Delegation by authorized account representative and alternate 
authorized account representative. (1) An authorized account 
representative may delegate, to one or more natural persons, his or her 
authority to make an electronic submission (in a format prescribed by 
the Administrator) to the Administrator provided for or required under 
this part.
    (2) An alternate authorized account representative may delegate, to 
one or more natural persons, his or her authority to make an electronic 
submission (in a format prescribed by the Administrator) to the 
Administrator provided for or required under this part.
    (3) In order to delegate authority to make an electronic submission 
to the Administrator in accordance with paragraph (g)(1) or (2) of this 
section,

[[Page 158]]

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:
    (i) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of such authorized account 
representative or alternate authorized account representative;
    (ii) The name, address, e-mail address, telephone number, and, 
facsimile transmission number (if any) of each such natural person 
(referred to as an ``agent'');
    (iii) For each such natural person, a list of the type or types of 
electronic submissions under paragraph (g)(1) or (2) of this section for 
which authority is delegated to him or her;
    (iv) The following certification statements by such authorized 
account representative or alternate authorized account 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 for such agent in this notice of delegation and that is made 
when I am a 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 73.33(g)(4) 
shall be deemed to be an electronic submission by me.''
    (B) ``Until this notice of delegation is superseded by another 
notice of delegation under 40 CFR 73.33(g)(4), 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 73.33(g) is eliminated.''
    (4) A notice of delegation submitted under paragraph (g)(3) 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.
    (5) Any electronic submission covered by the certification in 
paragraph (g)(3)(iv)(A) of this section and made in accordance with a 
notice of delegation effective under paragraph (g)(4) of this section 
shall be deemed to be an electronic submission by the designated 
representative or alternate designated representative submitting such 
notice of delegation.

[58 FR 3691, Jan. 11, 1993, as amended at 71 FR 25378, Apr. 28, 2006]



Sec. 73.34  Recordation in accounts.

    (a) After a compliance account is established under Sec. 73.31(a) 
or (b), the Administrator will record in the compliance account any 
allowance allocated to any affected unit at the source for 30 years 
starting with the later of 1995 or the year in which the compliance 
account is established and any allowance allocated for 30 years starting 
with the later of 1995 or the year in which the compliance account is 
established and transferred to the source with the transfer submitted in 
accordance with Sec. 73.50. In 1996 and each year thereafter, after 
Administrator has completed the deductions pursuant to Sec. 73.35(b), 
the Administrator will record in the compliance account any allowance 
allocated to any affected 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 made) and any allowance allocated for the new 30th year 
and transferred to the source with the transfer submitted in accordance 
with Sec. 73.50.
    (b) After a general account is established under Sec. 73.31(c), the 
Administrator will record in the general account any allowance allocated 
for 30 years starting with the later of 1995 or the year in which the 
general account is established and transferred to the general account 
with the transfer submitted in accordance with Sec. 73.50. In 1996 and 
each year thereafter, after the Administrator has completed the 
deductions pursuant to Sec. 73.35(b), the Administrator will record in 
the general

[[Page 159]]

account any allowance allocated for the new 30th year (i.e., the year 
that is 30 years after the calendar year for which such deductions are 
made) and transferred to the general account with the transfer submitted 
in accordance with Sec. 73.50.
    (c) Allowances in each compliance account and general account 
subaccounts will reflect:
    (1) All allowances allocated or deducted for the unit for the year 
pursuant to subpart B of this part;
    (2) All allowances allocated or deducted pursuant to Sec. Sec. 
72.41, 72.42, 72.43, and 72.44 and part 74 of this chapter;
    (3) All allowances allocated pursuant to subparts F and G of this 
part;
    (4) All allowances recorded as a result of purchases or returns from 
the annual auctions;
    (5) All allowances recorded or deducted as a result of allowance 
transfers recorded pursuant to subpart D of this part; and
    (6) All allowances deducted or returned pursuant to Sec. Sec. 
73.35(d), 72.91 and 72.92, part 74, and part 77 of this chapter.
    (d) Serial numbers for allocated allowances. Upon the allocation of 
allowances to an account, including allowances contained in reserves as 
provided in subpart B of this part, the Administrator will assign each 
allowance a unique identification number that will include digits 
identifying the allowance's compliance use date.

[58 FR 3691, Jan. 11, 1993, as amended at 60 FR 17114, Apr. 4, 1995; 63 
FR 68404, Dec. 11, 1998; 70 FR 25335, May 12, 2005]



Sec. 73.35  Compliance.

    (a) Allowance transfer deadline. No allowance shall be deducted for 
purposes of compliance with an affected source's sulfur dioxide Acid 
Rain emissions limitation requirements pursuant to title IV of the Act 
and paragraph (b) of this section unless:
    (1) The compliance use date of the allowance is no later than the 
year in which the source's SO2 emissions occurred; and
    (2) The allowance is:
    (i) Recorded in the source's compliance account; or
    (ii) Transferred to the source's compliance account, with the 
transfer submitted correctly pursuant to subpart D of this part for 
recordation in the source's compliance account by not later than the 
allowance transfer deadline in the calendar year following the year for 
which compliance is being established; and
    (3) The allowance was not previously deducted by the Administrator 
in accordance with a State SO2 mass emissions reduction 
program under Sec. 51.124(o) of this chapter or otherwise permanently 
retired in accordance with Sec. 51.124(p) of this chapter.
    (b) Deductions for compliance. (1) Except as provided in paragraph 
(d) of this section, following the recordation of transfers submitted 
correctly for recordation in the compliance account pursuant to 
paragraph (a) of this section and subpart D of this part, the 
Administrator will deduct allowances available for deduction under 
paragraph (a) of this section from each affected source's compliance 
account in accordance with the allowance deduction formula in Sec. 
72.95 of this chapter, or, for opt-in sources, the allowance deduction 
formula in Sec. 74.49 of this chapter, and any correction made under 
Sec. 72.96 of this chapter.
    (2) The Administrator will make deductions until either the number 
of allowances deducted is equal to the amount calculated in accordance 
with Sec. 72.95 of this chapter, or, for opt-in sources, in accordance 
with Sec. 74.49 of this chapter, as modified under Sec. 72.96 of this 
chapter or until no more allowances available for deduction under 
paragraph (a) of this section remain in the compliance account.
    (c)(1) Identification of allowances by serial number. The authorized 
account representative for a source's compliance account may request 
that specific allowances, identified by serial number, in the compliance 
account be deducted for a calendar year 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 year and 
include, in a format prescribed by the Administrator, the identification 
of the source and the appropriate serial numbers.
    (2) First-in, first-out. In the absence of an identification or in 
the case of a

[[Page 160]]

partial identification of allowances by serial number, as provided for 
in paragraph (b)(1) or (d) of this section, the Administrator will 
deduct allowances on a first-in, first-out (FIFO) accounting basis 
beginning with those allowances with the earliest compliance use date 
originally allocated for the units at the source and recorded in the 
source's compliance account. Following the deduction of all originally 
allocated allowances from the compliance account, the Administrator will 
deduct those allowances that were transferred and recorded in the 
source's compliance account pursuant to subpart D of this part, 
beginning with those with the earliest date of recordation.
    (d) Deductions for excess emissions. Pursuant to Sec. 77.4 of this 
chapter, and following the process of recordation set forth in Sec. 
73.34(a) of this part, the Administrator will deduct allowances for each 
source with excess emissions for the preceding calendar year in an 
amount equal to the source's excess emissions tonnage.

[58 FR 3691, Jan. 11, 1993, as amended at 60 FR 17114, Apr. 4, 1995; 64 
FR 25842, May 13, 1999; 70 FR 25335, May 12, 2005]



Sec. 73.36  Banking.

    (a) Compliance accounts. Any allowance in a compliance account not 
deducted pursuant to Sec. 73.35 will remain in the compliance account.
    (b) General accounts. In the case of a general account, any 
allowances in the general account not transferred pursuant to subpart D 
to another Allowance Tracking System account will remain in the general 
account.

[58 FR 3691, Jan. 11, 1993, as amended at 70 FR 25336, May 12, 2005]



Sec. 73.37  Account error.

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

[70 FR 25336, May 12, 2005]



Sec. 73.38  Closing of accounts.

    (a) General account. The authorized account representative of a 
general account may instruct the Administrator to close the general 
account by submitting an allowance transfer, pursuant to Sec. 73.50 and 
Sec. 73.52, requesting the transfer of all allowances held in the 
account to one or more other accounts in the Allowance Tracking System, 
and by submitting in writing, with the signature of the authorized 
account representative, a request to close the general account.
    (b) Inactive accounts. If a general account shows no activity for a 
12-month period or longer and does not contain any allowances, the 
Administrator may notify the account's authorized account representative 
that the account will be closed following 20 business days from the date 
the notice is sent. The account will be closed following the 20-day 
period, unless the Administrator receives and records a request for the 
transfer of allowances into the account pursuant to Sec. 73.52 before 
the end of the 20-day period, or the authorized account representative 
submits, in writing, demonstration of good cause as to why the inactive 
account should not be closed.

[58 FR 3691, Jan. 11, 1993, as amended at 70 FR 25336, May 12, 2005]



                      Subpart D_Allowance Transfers

    Source: 58 FR 3694, Jan. 11, 1993, unless otherwise noted.



Sec. 73.50  Scope and submission of transfers.

    (a) Scope of transfers. Except as provided in Sec. 73.51 and Sec. 
73.52, the Administrator will record transfers of an allowance to and 
from Allowance Tracking System accounts.
    (b) Submission of transfers. (1) Authorized account representatives 
seeking recordation of an allowance transfer shall request such transfer 
by submitting to the Administrator, in a format to be specified by the 
Administrator, an Allowance Transfer Form. To be considered correctly 
submitted the request for transfer shall include:
    (i) The numbers identifying both the transferror and transferee 
accounts;

[[Page 161]]

    (ii) A specification by serial number of each allowance to be 
transferred;
    (iii) Signatures of the authorized account representatives of both 
the transferror and transferee accounts;
    (iv) The dates of the signatures of the authorized account 
representatives;
    (v) The numbers identifying the authorized account representatives 
for both the transferror and transferee account; and
    (vi) Where the transferee account has not been established, 
information as required pursuant to Sec. 73.31 (b) or (c).
    (2)(i) The authorized account representative for the transferee 
account can meet the requirements in paragraphs (b)(1)(iii) and (iv) of 
this section by submitting, in a format prescribed by the Administrator, 
a statement signed by the 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 
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 in a 
format prescribed by the Administrator and signed by the authorized 
account representative retracting the authorization for the account.
    (ii) The statement under paragraph (b)(2)(i) 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 authorized account representative for such account unless 
and until a statement signed by the authorized account representative 
retracting this authorization for the account is received by the 
Administrator.''

[58 FR 3694, Jan. 11, 1993, as amended at 63 FR 68404, Dec. 11, 1998; 70 
FR 25336, May 12, 2005]



Sec. 73.51  [Reserved]



Sec. 73.52  EPA recordation.

    (a) General recordation. Except as provided in this paragraph (a), 
the Administrator will record an allowance transfer by no later than 
five business days (or longer as necessary to perform a transfer in 
perpetuity of allowances allocated to a unit) following receipt of an 
allowance transfer request pursuant to Sec. 73.50, by moving each 
allowance from the transferror account to the transferee account as 
specified by the request pursuant to Sec. 73.50, provided that:
    (1) The transfer is correctly submitted under Sec. 73.50;
    (2) The transferor account includes each allowance identified by 
serial number in the transfer; and
    (3) If the allowances identified by serial number specified pursuant 
to Sec. 73.50(b)(1)(ii) are subject to the limitation on transfer 
imposed pursuant to Sec. 72.44(h)(1)(i) of this chapter, Sec. 74.42 of 
this chapter, or Sec. 74.47(c) of this chapter, the transfer is in 
accordance with such limitation.
    (b) To the extent an allowance transfer submitted for recordation 
after the allowance transfer deadline includes allowances allocated for 
any year before the year in which the allowance transfer deadline 
occurs, the transfer of such allowance will not be recorded until after 
completion of the deductions pursuant to Sec. 73.35(b) for year before 
the year in which the allowance transfer deadline occurs.
    (c) Where an allowance transfer submitted for recordation fails to 
meet the requirements of paragraph (a) of this section, the 
Administrator will not record such transfer.

[58 FR 3694, Jan. 11, 1993, as amended at 60 FR 17114, Apr. 4, 1995; 70 
FR 25336, May 12, 2005]



Sec. 73.53  Notification.

    (a) Notification of recordation. The Administrator will notify each 
party to an allowance transfer within five business days following the 
recordation of the transfer. Notice will be given in writing or in a 
format to be specified by the Administrator, to the authorized account 
representatives of both

[[Page 162]]

the transferror and transferee accounts.
    (b) Notification of non-recordation. By no later than five business 
days following receipt of an allowance transfer request by the 
Administrator, the Administrator will notify, in writing or in a format 
to be specified by the Administrator, the authorized account 
representatives of the accounts subject to the allowance transfer 
request submitted for recordation 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 an 
allowance transfer request for recordation following notification of 
non-recordation.



   Subpart E_Auctions, Direct Sales, and Independent Power Producers 
                            Written Guarantee

    Source: 56 FR 65601, Dec. 17, 1991, unless otherwise noted.



Sec. 73.70  Auctions.

    (a) Allowances to be auctioned. Every year the Administrator will 
auction allowances from the Auction Subaccount, established pursuant to 
subpart B of this part, according to the following schedule:

                Table I--Allowance Schedule for Auctions
------------------------------------------------------------------------
                                             Spot     Advance    Advance
             Year of purchase               auction   auction   auction*
------------------------------------------------------------------------
1993.....................................    50,000    100,000
                                                \a\        \b\
1994.....................................    50,000    100,000    25,000
                                                \a\        \b\       \c\
1995.....................................    50,000    100,000    25,000
                                                \a\        \b\       \c\
1996.....................................   150,000    100,000    25,000
                                                           \b\       \c\
1997.....................................   150,000    125,000    25,000
                                                           \b\       \c\
1998.....................................   150,000    125,000
                                                           \b\
1999.....................................   150,000    125,000
                                                           \b\
2000 and after...........................   125,000    125,000
                                                           \b\
------------------------------------------------------------------------
\a\ Not usable until 1995.
\b\ Not usable until 7 years after purchase.
\c\ Not usable until 6 years after purchase.
*These are unsold advance allowances from the direct sale program for
  1993, 1994, 1995, and 1996 respectively.


In addition to the allowances listed above, the Administrator will 
auction allowances pursuant to paragraph (c) of this section and Sec. 
73.72(q) in the amounts and at the times provided for therein.
    (b) Timing of the auctions. The spot auction and the advance auction 
will be held on the same day, selected each year by the Administrator, 
but no later than March 31 of each year. The Administrator will conduct 
one spot auction and one advance auction in each calendar year.
    (c) Submittal for other allowances for auction. Authorized account 
representatives may offer allowances for sale at auction, provided that 
allowances are dated for the year in which they are offered or for any 
previous year or for seven years following the year in which they are 
offered. Such authorized account representatives may specify a minimum 
price for the allowances offered at the auctions. The authorized account 
representative must notify the Administrator fifteen business days prior 
to the auctions, using the SO2 Allowance Offer Form published 
by the Administrator, or by means of electronic communication if the 
Administrator, following public notice, so requires or permits at some 
future time. The notification shall include:
    (1) The compliance use date of the allowances offered;
    (2) The number of allowances to be sold and any other information 
identifying the allowances offered that may be required by subpart C of 
this part;
    (3) Any minimum price; and
    (4) Whether the authorized account representative is willing to sell 
fewer allowances than the number stated in paragraph (c)(2) of this 
section, if the full amount cannot be sold. After notification, the 
Administrator will deduct allowances from the appropriate Allowance 
Tracking System account from which allowances are being offered and 
place them in a separate subaccount for such allowances.
    (d) Conduct of the auctions. (1) The Administrator will rank all 
bids in descending order of bid price starting with the highest. 
Allowances will be sold from the Auction Subaccount in this order at the 
amounts specified in the bids until there are no allowances in the 
subaccount. If all allowances are sold from the Auction Subaccount, 
including unsold allowances transferred from the preceding year's direct 
sale, and if bids still remain, the Administrator will sell allowances 
offered by the authorized account representatives, beginning with those 
offered at

[[Page 163]]

the lowest minimum price. Allowances offered at the lowest minimum price 
will be matched with the highest bid remaining after the Auction 
Subaccount is exhausted. Sales of offered allowances, including, but not 
limited to, allowances offered by more than one offeror at the same 
minimum bid price, will continue in ascending order of minimum price, 
starting with the lowest, and descending order of remaining bids, 
starting with the highest, until:
    (i) All allowances are sold,
    (ii) No bids remain, or
    (iii) Prices of remaining bids do not meet minimum prices required 
in remaining offers.
    (2) In the event that there is more than one bid submitting the same 
price and the total number of allowances requested in all such bids 
exceeds the number of allowances remaining, the Administrator will award 
the remaining allowances by lottery to such bidders.
    (3) In the event that there are more offers of sale at the minimum 
price than there are bids meeting that price, allowances from all such 
offers will be sold to cover the bids, according to each such offeror's 
pro rata share of all allowances so offered.
    (4) In the event that fewer allowances remain than are requested in 
a bid, the Administrator will sell such remaining allowances to the 
bidder provided that, pursuant to Sec. 73.71(b)(4), the bid states the 
bidder's willingness to purchase fewer allowances than requested in the 
bid.
    (5) In the event that fewer than all allowances included in an offer 
for sale would be sold to remaining bids based on price, the 
Administrator will sell such allowances to the bidder(s), provided that, 
pursuant to Sec. 73.70(c)(4), the offer states the offeror's 
willingness to sell fewer allowances than were offered for sale.
    (e) Announcement of results. Following each auction, the 
Administrator will publish the names of winning bidders and their bids, 
the amounts of losing bids, and the lowest price at which allowances are 
sold.
    (f) Transfer of allowances. Allowances will be transferred from the 
Auction Subaccount and from the Allowance Tracking System account for 
allowances offered by authorized account representatives to the 
Allowance Tracking System accounts of successful bidders as soon as 
payment is collected by the Administrator.
    (g) Return of unsuccessful bids. The Administrator will return 
payment to unsuccessful bidders and to bidders unwilling to purchase 
fewer allowances than requested following the conclusion of each 
auction.
    (h) Transfer of proceeds. The Administrator will return all proceeds 
from the auction as follows:
    (1) Allowances auctioned from the Auction Subaccount. Not later than 
90 days following each auction, the Administrator will pay a pro rata 
share of the proceeds of each auction to the authorized account 
representative of each unit from whose annual allowance allocation 
allowances were withheld for the purposes of establishing the Auction 
Subaccount. Each unit's pro rata share will be calculated pursuant to 
regulations to be promulgated under subpart B.
    (2) Allowances contributed from others. Not later than 90 days 
following each auction, the Administrator will transfer the full amount 
of the proceeds of each sale of allowances offered by authorized account 
representatives to such representatives. Proceeds from the sale of 
allowances that were offered with the same specified minimum price will 
be distributed according to each such offeror's pro rata share of the 
sale of such allowances.
    (3) The Administrator will pay no interest on any payment made 
pursuant to paragraphs (h) (1) and (2) of this section.
    (i) Return of unsold allowances. The Administrator will return all 
unsold allowances from the auction as follows:
    (1) Allowances in the Auction Subaccount. At the conclusion of each 
auction, the Administrator will transfer to the Allowance Tracking 
System account of each source that includes a unit specified in 
paragraph (h)(1) of this section its pro rata share of any allowances 
remaining in the Auction Subaccount. Each unit's pro rata share will be 
calculated pursuant to regulations to be promulgated under subpart B.

[[Page 164]]

    (2) Allowances contributed from others. At the conclusion of each 
auction, the Administrator will return unsold allowances to the 
appropriate offerors' Allowance Tracking System accounts. Any unsold 
allowances that were offered with the same specified minimum price will 
be distributed according to each such offeror's pro rata share of all 
such allowances offered.

[56 FR 65601, Dec. 17, 1991, as amended at 61 FR 28763, June 6, 1996; 63 
FR 5735, Feb. 4, 1998; 63 FR 51766, Sept. 28, 1998; 70 FR 25336, May 12, 
2005]



Sec. 73.71  Bidding.

    (a) Who may participate in the auctions. Any person may participate 
in the auctions by submitting a bid or bids pursuant to this section.
    (b) Bidding. Sealed bids shall be sent to the Administrator using 
the Bid Form for SO2 Allowance Auctions, or some method of 
electronic transfer if the Administrator, following public notice, so 
requires or permits at some future time. The bid form shall state:
    (1) The number of allowances sought and the price;
    (2) Whether spot or advance allowances are sought;
    (3) Allowance Tracking System account number;
    (4) Whether the bidder is willing to purchase fewer allowances than 
the number of allowances stated in (b)(1) of this section if the full 
amount is not available. Where the bidder holds no Allowance Tracking 
System account, a New Account/New Authorized Account Representative Form 
must accompany the bid. New account information shall include at a 
minimum: Name, address, telephone number, facsimile number, organization 
or company name (if applicable), type of organization, and the 
authorized account representative for purposes of the account.
    (c) Payment. Each bid must include a certified check or letter of 
credit for the total bid price, or may specify a method of electronic 
transfer or other method of payment, if the Administrator, following 
public notice, so requires or permits at some future time. The certified 
check should be made payable to the U.S. EPA. To meet the requirements 
of this paragraph bidders must submit a completed SO2 
Allowance Auction Letter of Credit Form. If such Form is used, the 
Administrator must receive full payment for allowances awarded at the 
auctions, either by wire transfer or certified check, no later than 2 
business days after the results of the auction are announced in the 
Allowance Tracking System.
    (d) Bid amount and number of bids. Bidders may request any number of 
allowances up to the amount of allowances available for auction. Any 
person may submit more than one bid in each auction, provided that each 
bid meets the requirements of this section.
    (e) Submission of bids. The Administrator will publish in the 
Federal Register and in the Commerce Business Daily the address of where 
to submit bids and payment not later than 60 calendar days before each 
auction.
    (f) Deadline for bids. All bids must be revised by the Administrator 
no later than 3 business days prior to the date of the auctions.



Sec. 73.72  Direct sales.

    Allowances that were formerly part of the direct sale program, which 
has been terminated under Sec. 73.73(b), will be included in the annual 
allowance auctions in accordance with Sec. 73.70(a).

[61 FR 28763, June 6, 1996]



Sec. 73.73  Delegation of auctions and sales and termination of
auctions and sales.

    (a) Delegation. The Administrator may, in the Administrator's 
discretion, by delegation or contract provide for the conduct of sales 
or auctions under the Administrator's supervision by other departments 
or agencies of the United States Government or by nongovernmental 
agencies, groups, or organizations.
    (b) Termination of sales. If the Administrator determines that, 
during any period of 2 consecutive calendar years, fewer than 20 percent 
of the allowances available in the subaccount for direct sales have been 
purchased, the Administrator shall terminate the Direct Sale Subaccount 
and transfer such allowances to the Auction Subaccount.
    (c) Termination of auctions. The Administrator may, in the 
Administrator's discretion, terminate the withholding of allowances and 
the auctions

[[Page 165]]

if the Administrator determines, that, during any period of 3 
consecutive years after 2002, fewer than 20 percent of the allowances 
available in the Auction Subaccount have been purchased.



       Subpart F_Energy Conservation and Renewable Energy Reserve

    Source: 58 FR 3695, Jan. 11, 1993, unless otherwise noted.



Sec. 73.80  Operation of allowance reserve program for conservation
and renewable energy.

    (a) General. The Administrator will allocate allowances from the 
Conservation and Renewable Energy Reserve (the ``Reserve'') established 
under subpart B based on verified kilowatt hours saved through the use 
of one or more qualified energy conservation measures or based on 
kilowatt hours generated by qualified renewable energy generation. 
Allowances will be allocated to applicants that meet the requirements of 
this subpart according to the formulas specified in Sec. 73.82(d), and 
in the order in which applications are received, except where provided 
for in Sec. 73.84 and Sec. 73.85, until a total of 300,000 allowances 
have been allocated.
    (b) Period of applicability. Allowances will be allocated under this 
subpart for qualified energy conservation measures or renewable energy 
generation sources that are operational on or after January 1, 1992, and 
before the date on which any unit owned or operated by the applicant 
becomes a Phase I unit or a Phase II unit.
    (c) Termination of the Reserve. The Administrator will reallocate 
any allowances remaining in the Reserve after January 2, 2010 to the 
affected units from whom allowances were withheld by the Administrator, 
in accordance with section 404(g), for purposes of establishing the 
Reserve. Each unit's allocation under this paragraph will be calculated 
as follows:
[GRAPHIC] [TIFF OMITTED] TC10NO91.004

(Allowances will be rounded to the nearest allowance)

[58 FR 3695, Jan. 11, 1993; 58 FR 40747, July 30, 1993]



Sec. 73.81  Qualified conservation measures and renewable energy
generation.

    (a) Qualified energy conservation measures. A qualified energy 
conservation measure is a demand-side measure not operational until the 
period of applicability, implemented in the residence or facility of a 
customer to whom the utility sells electricity, that:
    (1) Is specified in appendix A(1) of this subpart; or
    (2) In the case of a device or material that is not included in 
appendix A(1) of this subpart,
    (i) Is a cost-effective demand-side measure consistent with an 
applicable least-cost plan or least-cost planning process that increases 
the efficiency of the customer's use of electricity (as measured in 
accordance with Sec. 73.82(c)) without increasing the use by the 
customer of any fuel other than qualified renewable energy, industrial 
waste heat, or, pursuant to paragraph (b)(5) of this section, industrial 
waste gases;
    (ii) Is implemented pursuant to a conservation program approved by 
the utility regulatory authority, which certifies that it meets the 
requirements of paragraph (a)(2)(i) of this section and is not excluded 
by paragraph (b) of this section; and
    (iii) Is reported by the applicant in its application to the 
Reserve.
    (b) Non-qualified energy conservation measures. The following energy 
conservation measures shall not qualify for Allowance Reserve 
allocations:
    (1) Demand-side measures that were operational before January 1, 
1992;
    (2) Supply-side measures;
    (3) Conservation programs that are exclusively informational or 
educational in nature;
    (4) Load management measures that lead to economic reduction of 
electric energy demand during a utility's peak generating periods, 
unless kilowatt hour savings can be verified by the utility pursuant to 
Sec. 73.82(c); or
    (5) Utilization of industrial waste gases, unless the applicant has 
certified that there is no net increase in

[[Page 166]]

sulfur dioxide emissions from such utilization.
    (c) Qualified renewable energy generation. Qualified renewable 
energy generation is electrical energy generation, not operational until 
the period of applicability, that:
    (1) Is specified in appendix A(3) of this subpart; or
    (2) In the case of renewable energy generation that is not included 
in appendix A(3) of this subpart is:
    (i) Consistent with a least cost plan or a least cost planning 
process and derived from biomass (i.e., combustible energy-producing 
materials from biological sources which include wood, plant residues, 
biological wastes, landfill gas, energy crops, and eligible components 
of municipal solid waste), solar, geothermal, or wind resources;
    (ii) Implemented pursuant to approval by the utility regulatory 
authority, which certifies that it meets the requirements of paragraphs 
(c)(2)(i) and (c)(2)(ii) of this section and is not excluded by 
paragraph (d) of this section; and
    (iii) Is reported by the applicant in its application to the 
Reserve.
    (d) Non-qualified renewable energy generation. The following 
renewable energy generation shall not qualify for Allowance Reserve 
allocations:
    (1) Renewable energy generation that was operational before January 
1, 1992;
    (2) Measures that reduce electricity demand for a utility's 
customers without providing electric generation directly for sale to 
customers; and
    (3) Measures that appear on the list of qualified energy 
conservation measures in appendix A(1) of this subpart.

[58 FR 3695, Jan. 11, 1993; 58 FR 40747, July 30, 1993]



Sec. 73.82  Application for allowances from reserve program.

    (a) Application Requirements. Each application for Conservation and 
Renewable Energy Reserve allowances, shall:
    (1) Certify that the applicant is a utility;
    (2) Demonstrate that the applicant, any subsidiary of the applicant, 
or any subsidiary of the applicant's holding company, is an owner or 
operator, in whole or in part, of at least one Phase I or Phase II unit 
by including in the application the name and Allowance Tracking System 
account number of a Phase I or Phase II unit which it owns or operates 
and for which it is listed as an owner or operator on the certificate of 
representation submitted by the designated representative for the unit 
pursuant to Sec. 72.20 of this chapter;
    (3) Through certification, demonstrate that the applicant is paying 
in whole or in part for one or more qualified energy conservation 
measures or qualified renewable energy generation (that became 
operational during the period of applicability) either directly or 
through payment to another person that purchases the qualified energy 
conservation measure or qualified renewable energy generation;
    (4) Demonstrate that the applicant is subject to a least cost plan 
or a least cost planning process that:
    (i) provides an opportunity for public notice and comment or other 
public participation processes;
    (ii) evaluates the full range of existing and incremental resources 
in order to meet expected future demand at lowest system cost;
    (iii) treats demand-side resources and supply-side resources on a 
consistent and integrated basis;
    (iv) takes into account necessary features for system operation such 
as diversity, reliability, dispatchability, and other factors of risk;
    (v) may take into account other factors, including the social and 
environmental costs and benefits of resource investments; and
    (vi) is being implemented by the applicant to the maximum extent 
practicable.
    (5) Demonstrate that the qualified energy conservation measure 
adopted or qualified renewable energy generated, or both, are consistent 
with the least cost plan or least cost planning process;
    (6) If the applicant is subject to the rate-making jurisdiction of a 
State or local utility regulatory authority, its least cost plan or 
least cost planning process has been approved or accepted by the utility 
regulatory authority in the State or locality in which the qualified 
conservation measure(s) are adopted or in which the qualified renewable 
energy generation is utilized,

[[Page 167]]

and such State or local utility regulatory authority certifies that the 
least-cost plan or least-cost planning process meets the requirements of 
paragraph (a)(4) of this section;
    (7) If the applicant is not subject to the rate-making jurisdiction 
of a State or local regulatory authority, its least cost plan or least 
cost planning process has been approved or has been accepted by the 
utility regulatory authority with rate-making jurisdiction over the 
applicant, and such utility regulatory authority certifies that the 
least cost plan or least cost planning process meets the requirements of 
paragraph (a)(4) of this section;
    (8) If the applicant is an independent power production facility 
that sells qualified renewable energy generation to another utility, the 
applicant has enclosed documentation that such qualified renewable 
energy generation was purchased pursuant to the purchasing utility's 
least cost plan or least cost planning process, which has been approved 
or accepted by the purchasing utility's utility regulatory authority.
    (9)(i) If the applicant is an investor-owner utility subject to the 
ratemaking jurisdiction of a State utility regulatory authority and is 
submitting an application on the basis of one or more qualified energy 
conservation measures, such State utility regulatory authority has 
established a procedure for determining rates and charges ensuring net 
income neutrality, as defined in Sec. 72.2 of this chapter, including a 
provision that the utility's net income is compensated in full 
(considering factors such as risk) for lost sales attributable to the 
utility's conservation programs, which may include:
    (A) General ratemaking for formulas that decouple utility profits 
from actual utility sales;
    (B) Specific rate adjustment formulas that allow a utility to 
recover in its retail rates the full costs of conservation measures plus 
any associated net revenues lost as a result of reduced sales resulting 
from conservation initiatives; or
    (C) Conservation incentive mechanisms designed to provide positive 
financial rewards to a utility to encourage implementation of cost-
effective measures;
    (ii) Provided that the existence of any one of the categories of 
ratemaking or rate adjustment formulas or conservation incentive 
mechanisms specified in paragraph (a)(9)(i) of this section shall not 
necessarily constitute fulfillment of the net income neutrality 
requirement unless, pursuant to Sec. 73.83, the Secretary of Energy has 
certified the establishment of such net income neutrality;
    (10) Demonstrate that the applicant has implemented the qualified 
energy conservation measures or used the qualified renewable energy 
generation specified in the application during the period of 
applicability;
    (11) Demonstrate the extent to which installation of the qualified 
conservation measure(s) has achieved actual energy savings, by stating, 
on the basis of the performance of the measure(s) following 
installation:
    (i) The amount of kilowatt hour savings resulting from the 
measure(s) in the given year(s);
    (ii) Pursuant to paragraph (c) of this section, the methodology used 
to calculate the kilowatt hour savings; and
    (iii) The name, address, and phone number of the person who 
performed the calculation of kilowatt hour savings;
    (12) Report the type and amount of yearly qualified renewable energy 
generation, by stating (and submitting documentation, including copies 
of plant operation records, supporting such statements) the kilowatt 
hours of qualified renewable energy generated during a previous calendar 
year or years; and
    (13) Report the extent to which qualified renewable energy 
generation was produced in combination with other energy sources 
(hereafter ``hybrid generation'') by stating (and submitting 
documentation, including copies of plant operation records, supporting 
such statements) the heat input and heat rate of the non-qualified 
renewable generation, the total annual kilowatt hours generated, and the 
kilowatt hours that can be attributed to qualified renewable energy 
generation;
    (14) Demonstrate the extent to which the implementation of qualified 
energy

[[Page 168]]

conservation measures or the use of qualified renewable energy 
generation has resulted in avoided tons of sulfur dioxide emissions by 
the utility during the period of applicability, pursuant to paragraph 
(d) of this section.
    (b) Application to the Secretary of Energy. For purposes of 
paragraph (a)(9) of this section, the applicant shall fulfill the 
following requirements:
    (1) If a utility applying for allowances from the Reserve has not 
received certification of net income neutrality from the Secretary of 
Energy or such certification is no longer applicable, the applicant 
shall submit to the Secretary of Energy:
    (i) A copy of the relevant State utility regulatory authority's 
final order or decision setting forth the approved ratemaking mechanisms 
that ensure that a utility's net income will be at least as high upon 
implementation of energy conservation measures as such net income would 
have been if the energy conservation measures has not been implemented;
    (ii) A description of how the State utility regulatory authority's 
order or decision meets the definition of net income neutrality as 
defined in Sec. 72.2; and
    (iii) Any additional information necessary for Secretary of Energy 
to certify that the State regulatory authority has established rates and 
charges that ensure net income neutrality.
    (2) If a utility applying for allowances from the Reserve has 
already received certification of net income neutrality from the 
Secretary of Energy in connection with a previous application for 
allowances, and the ratemaking methods or procedures that ensure net 
income neutrality have not been altered, the applicant shall certify 
that the ratemaking methods and procedures that led to the original 
certification are still in place.
    (c) Verification of energy savings methodology. For the purposes of 
paragraph (a)(11) of this section:
    (1) Applicants subject to the ratemaking jurisdiction of a State 
utility regulatory authority shall use the energy conservation 
verification methodology approved by such authority in support of energy 
conservation applications under this subpart and part 72 of this 
chapter, provided that
    (i) The authority in question uses this methodology to determine the 
applicant's entitlement to performance-based rate adjustments, which 
permit a utility's rates to be adjusted for additional kilowatt hours 
saved due to the utility's energy conservation programs;
    (ii) Such performance based rate adjustments are subject to 
modification either prospectively or retrospectively to reflect periodic 
evaluations of energy savings secured by the applicant; and
    (iii) The applicant has provided the Administrator with a 
description of the State utility regulatory authority's verification 
methodology and documentation that the requirements of this paragraph 
(e) have been met.
    (2) All other applicants, including applicants whose rates are not 
subject to the ratemaking jurisdiction of a State utility regulatory 
authority shall demonstrate to the satisfaction of the Administrator 
through submission of documentation that savings have been achieved and 
may use the EPA Conservation Verification Protocol.
    (3) All records of verification of energy savings shall be kept on 
file by the applicant for a period of 3 years. The Administrator may 
extend this period for cause at any time prior to the end of 3 years by 
notifying the applicant in writing.
    (4) The Administrator reserves the right to conduct independent 
reviews, analyses, or audits to ascertain that the verification is valid 
and correct. If the Administrator determines that the verification is 
not valid or correct, the Administrator may revise the allocation of 
allowances to an applicant or require the surrender of allowances from 
the applicant's Allowance Tracking System account.
    (d) Calculation of allowances to be allocated. (1) In the case of an 
application submitted on the basis of qualified energy conservation 
measures, the sulfur dioxide emissions tonnage deemed avoided for any 
calendar year shall be equal to the product of:

[[Page 169]]

[GRAPHIC] [TIFF OMITTED] TC10NO91.005

                      (Rounded to the nearest ton)

where:

    (A) = the kilowatt hours that were not, but would otherwise have 
been, supplied by the utility during such year in the absence of such 
qualified energy conservation measures.
    (B) = 0.004 1bs. of sulfur dioxide per kilowatt hour.
    (2) In the case of an application submitted on the basis of 
qualified renewable energy generation, the sulfur dioxide emissions 
tonnage deemed avoided for any calendar year shall be equal to the 
product of:
[GRAPHIC] [TIFF OMITTED] TC10NO91.006

                      (Rounded to the nearest ton)

where:

    (A) = the actual kilowatt hours of qualified renewable energy 
generated or purchased by the applicant (based on the qualified 
renewable energy generation portion for hybrid generation).
    (B) = 0.004 lbs. of sulfur dioxide per kilowatt hour.
    (e) Certification by Applicant's Certifying Official. (1) 
Certification of all application requirements, including the net income 
neutrality requirements, shall be made by a certifying official of the 
applicant upon such official's verification of all information and 
documentation submitted.
    (2) The applicant shall submit a certification statement signed by 
the applicant's certifying official that reads ``I certify under penalty 
of law that I have personally examined and am familiar with the 
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 information is to the best 
of my knowledge and belief true, accurate, and complete. I am aware that 
there are significant penalties for submitting false material 
information, or omitting material information, including the possibility 
of fine or imprisonment for violations.''
    (f) Certification by State Utility Regulatory Authority. Applicants 
subject to the ratemaking jurisdiction of a State utility regulatory 
authority shall include in their applications a certification by the 
State utility regulatory authority's certifying official that it has 
reviewed the application, including supporting documentation, and finds 
it to be accurate, complete, and consistent with all applicable 
requirements of this subpart.
    (g) Time period to apply. (1) Beginning no earlier than July 1, 
1993, and no earlier than July 1 of each subsequent year, applicants may 
apply to the Administrator for allowances from the Reserve for emissions 
avoided in a previous year or years by use of qualified energy 
conservation measures or qualified renewable energy generation that 
became operational during the period of applicability; and
    (2) Beginning no earlier than January 1, 1993, any applicant may 
apply to the Secretary of Energy for the Secretary's certification of 
net income neutrality where the application is based on the use of one 
or more qualified energy conservation measures.
    (3) Applications will be received by the Administrator and the 
Secretary of Energy until January 2, 2010, pursuant to Sec. 73.80(c), 
or until no allowances remain in the Reserve.
    (h) Submittal location. Applicants shall submit one copy of the 
completed Reserve application, not including the net income neutrality 
application, via registered mail to the Administrator at an address to 
be specified in later guidance. Applicants shall submit 10 copies of the 
net income neutrality application via registered mail to the Department 
of Energy at the following address: Department of Energy, Office of 
Conservation and Renewable Energy, Mail Stop CE-10, Room 6c-036, 1000 
Independence Avenue, SW., Washington, DC 20585, Attn: Net Income 
Neutrality Certification.

[58 FR 3695, Jan. 11, 1993; 58 FR 40747, July 30, 1993]

[[Page 170]]



Sec. 73.83  Secretary of Energy's action on net income neutrality
applications.

    (a) First come, first served. The Secretary of Energy will process 
and certify net income neutrality applications on a ``first-come, first 
served'' basis, according to the order, by date and time, in which they 
are received from either the applicant or, in the case of an application 
submitted to the Administrator and then forwarded to the Secretary, from 
the Administrator.
    (b) Deficient applications. If the Secretary of Energy determines 
that the net income neutrality certification application does not meet 
the requirements of Sec. 73.82 (a)(9) and (b), the Secretary will 
notify the applicant and the Administrator in writing of the deficiency. 
The applicant may then supply additional information or a new revised 
application as necessary for the Secretary to make a determination that 
the applicant meets the requirements of Sec. 73.28(a)(9) and (b). 
Additional information or revised applications will be processed 
according to the date of receipt of such information or revisions.
    (c) Notification of approval. The Secretary of Energy will review 
the net income neutrality application to determine whether it meets the 
requirements of Sec. 73.82 (a)(9) and (b) and will certify this finding 
in writing to the applicant and to the Administrator within 60 calendar 
days of receipt of the net income neutrality application or a revised 
application, except that the Secretary may specify a later date for 
certification.



Sec. 73.84  Administrator's action on applications.

    (a) First come, first served. The Administrator will process and 
approve Allowance Reserve applications, in whole or in part, on a 
``first-come, first-served'' basis as established by the order of date 
of receipt, provided that the Administrator shall not allocate more than 
a total of 30,000 allowances in connection with applications based on 
any one of the four categories of qualified renewable energy generation 
enumerated in Sec. 73.81(c)(2)(i) and appendix A(3.1-3.4).
    (b) Deficient applications. An application is deficient and will be 
returned by the Administrator if it fails to meet the requirements set 
forth in this subpart, including those set forth in Sec. 73.82. A 
revised application that is submitted after being returned for failure 
to meet the requirements of this subpart will be processed according to 
the date of receipt of the revised application.
    (c) Notification of approval. Applications that the Administrator 
determines to be complete and correct will be conditionally approved, 
subject to notification to EPA of a net income neutrality certification 
from the Department of Energy, within 120 calendar days of receipt. 
Allowances from the Reserve will be awarded subject to the Department of 
Energy certification, or, if a DOE certification has already been issued 
to the applicant, allocated to applicants from such applications 
depending on the availability of allowances in the Reserve. In the event 
the initial application approval is conditioned upon the Secretary of 
Energy's certification, final approval will be granted upon notification 
of certification by the Secretary of Energy pursuant to Sec. 73.83. The 
Administrator will notify applicants of final approval in writing.
    (d) Allocation of allowances. Beginning in 1995, the Administrator 
will allocate allowances from the Reserve for each approved application 
into the applicant's account or accounts in the Allowance Tracking 
System. If the applicant does not have an account in the Allowance 
Tracking System, or wishes to open a new account for the allowances from 
the Reserve, an application pursuant to Sec. 73.31(c) must accompany 
the application for Reserve allowances.
    (e) Partial fulfillment of requests. (1) In the event that the 
allowances available in the Reserve are less than the number that could 
otherwise be allocated to an approved applicant's account under the 
application as approved, the applicant will receive the allowances 
remaining in the Reserve.
    (2) In the event that a subaccount is established by EPA, pursuant 
to Sec. 73.85, and the applicant is making a request for allowances not 
included in the subaccount, the Allowance Reserve allocations for the 
approved applicant will be made, in addition to any that may be 
allocated pursuant to paragraph (f)(3)

[[Page 171]]

of this section, from any allowances remaining in the Reserve that are 
not contained in the subaccount.
    (f) Oversubscription of the Reserve. (1) In the event that the 
Reserve becomes oversubscribed by more than one applicant on a single 
day, the allowances remaining in the Reserve will be distributed on a 
pro rata basis to applicants meeting the requirements of Sec. 73.82.
    (2) If Reserve applications are received by the Administrator after 
all allowances from the Reserve have been allocated, the Administrator 
will so notify the applicant within 5 business days after receipt of the 
application.
    (3) In the event that applications meeting the requirements pursuant 
to Sec. 73.82 are received by the Administrator prior to February 1, 
1998, and
    (i) All remaining allowances in the Reserve have been placed in a 
subaccount pursuant to Sec. 73.85; and
    (ii) The applicant is not eligible for an allocation of allowances 
from the subaccount; the application will be placed on a waiting list in 
order of receipt.
    (iii) The Administrator will notify the applicant of such action 
within 5 business days after receipt of the application.
    (4) If any allowances are returned to the Reserve after February 1, 
1998 pursuant to Sec. 73.85(c), the Administrator will review the wait-
listed applications in order of receipt and allocate any remaining 
allowances to the approved applicants in the order of their receipt 
until no more allowances remain in the Reserve.
    (g) Applications for allowances based on the same avoided emissions 
from the same energy conservation measures or renewable energy 
generation. (1) The Administrator will not award allowances to more than 
one applicant for the same avoided emissions from the same energy 
conservation measure or the same qualified renewable energy generation, 
and will process and act on such duplicative applications on a ``first-
come, first-serve'' basis as determined by the order of date of receipt.
    (2) Any allowances awarded pursuant to two or more applications 
received on the same date based on the same avoided emissions from the 
same energy conservation measure or the same renewable electric 
generation will be divided equally between all such applicants unless 
the Administrator is otherwise directed by all such applicants.



Sec. 73.85  Administrator review of the reserve program.

    (a) Administrator review of the Reserve and creation of a 
subaccount. In the event that an allocation of allowances from the 
Reserve pursuant to a pending application would bring the total number 
of allowances allocated to a number greater than 240,000, the 
Administrator will review the distribution of all allowances allocated 
as follows:
    (1) If at least 60,000 allowances have been allocated from the 
Reserve for each of
    (i) Qualified energy conservation measures, and
    (ii) Qualified renewable energy generation, allocations of 
allowances will continue pursuant to Sec. 73.82, until no more 
allowances remain in the Reserve.
    (2) If fewer than 60,000 allowances have been allocated for either 
qualified energy conservation measures or qualified renewable energy 
generation, the Administrator will establish a subaccount for the 
allocation of allowances for applications based on the category for 
which fewer than 60,000 allowances have been allocated. The subaccount 
will contain allowances equal to 60,000 less the number of allowances 
previously allocated for such category.
    (b) Allocation of allowances from the subaccount. The Administrator 
will allocate allowances from the subaccount established pursuant to 
paragraph (a) of this section to approved and DOE certified applicants 
that fulfill the requirements of this subpart, including Sec. 73.82 and 
Sec. 73.83, on a ``first-come, first-served basis'', pursuant to Sec. 
73.84(a), until the subaccount is depleted or closed pursuant to 
paragraph (c) of this section.
    (c) Closure of the subaccount. Unless all allowances in the 
subaccount have been previously allocated, the Administrator will 
terminate the subaccount not later than February 1, 1998 and return any 
allowances remaining in the subaccount to the general account of the 
Reserve. After all Reserve allocations have been made to applicants

[[Page 172]]

with approved and DOE certified applications subject to Sec. 
73.84(f)(3), the Administrator will allocate any remaining allowances to 
any applicants that meet the requirements of this subpart, including 
Sec. 73.82 and Sec. 73.83, on a ``first-come, first-served'' basis, 
pursuant to Sec. 73.84.



Sec. 73.86  State regulatory autonomy.

    Nothing in this subpart shall preclude a State or State regulatory 
authority from providing additional incentives to utilities to encourage 
investment in any conservation measures or renewable energy generation.



   Sec. Appendix A to Subpart F of Part 73--List of Qualified Energy 
  Conservation Measures, Qualified Renewable Generation, and Measures 
                   Applicable for Reduced Utilization

 1. Demand-side Measures Applicable for the Conservation and Renewable 
              Energy Reserve Program or Reduced Utilization

    The following listed measures are approved as ``qualified energy 
conservation measures'' for purposes of the Conservation and Renewable 
Energy Reserve Program or reduced utilization qualified energy 
conservation plans under Sec. 72.43 of this chapter. Measures not 
appearing on the list may also be qualified conservation measures if 
they meet the requirements specified in Sec. 73.81(a) of this part.

                             1.1 Residential

                        1.1.1 Space Conditioning

     Electric furnace improvements (intermittent ignition, automatic 
vent dampers, and heating element change-outs)
     Air conditioner (central and room) upgrades/replacements
     Heat pump (ground source, solar assisted, and conventional) 
upgrades/replacements
     Cycling of air conditioners and heat pumps
     Natural ventilation
     Heat recovery ventilation
     Clock thermostats
     Setback thermostats
     Geothermal steam direct use
     Improved equipment controls
     Solar assisted space conditioning (ventilation, air-conditioning, 
and desiccant cooling)
     Passive solar designs
     Air conditioner and heat pump clean and tune-up
     Heat pipes
     Whole house fans
     High efficiency fans and motors
     Hydronic pump insulation
     Register relocation
     Register size and blade configuration
     Return air location
     Duct sizing
     Duct insulation
     Duct sealing
     Duct cleaning
     Shade tree planting

                           1.1.2 Water Heating

     Electric water heater upgrades/replacements
     Electric water heater tank wraps/blankets
     Low-flow showerheads and fittings
     Solar heating and pre-heat units
     Geothermal heating and pre-heat units
     Heat traps
     Water heater heat pumps
     Recirculation pumps
     Setback thermostats
     Water heater cycling control
     Solar heating for swimming pools
     Pipe wrap insulation

                             1.1.3 Lighting

     Lamp replacement
     Dimmers
     Motion detectors and occupancy sensors
     Photovoltaic lighting
     Fixture replacement
     Outdoor lighting controls

                         1.1.4 Building Envelope

     Attic, basement, ceiling, and wall insulation
     Passive solar building systems
     Exterior roof insulation
     Exterior wall insulation
     Exterior wall insulation bordering unheated space (e.g., a garage)
     Knee wall insulation in attic
     Floor insulation
     Perimeter insulation
     Storm windows/doors
     Caulking/weatherstripping
     Multi-glazed inserts for sliding glass doors
     Sliding door replacements
     Installation of French doors
     Hollow core door replacement
     Radiant barriers
     Window vent conversions
     Window replacement
     Window shade screens
     Low-e windows
     Window reduction
     Attic ventilation
     Whole house fan
     Passive solar design

                         1.1.5 Other Appliances

     Refrigerator replacements
     Freezer replacements

[[Page 173]]

     Oven/range replacements
     Dishwasher replacements
     Clothes washer replacements
     Clothes dryer replacements
     Customer located power generation based on photovoltaic, solar 
thermal, biomass, wind or geothermal resources
     Swimming pool pump replacements
     Gasket replacements
     Maintenance/coil cleaning

                             1.2 Commercial

            1.2.1 Heating/Ventilation/Air Conditioning (HVAC)

     Heat pump replacement
     Fan motor efficiency
     Resizing of chillers
     Heat pipe retrofits in air conditioning units
     Dehumidifiers
     Steam trap insulation
     Radiator thermostatic valves
     Variable speed drive on fan motor
     Solar assisted HVAC including ventilation, chillers, heat pumps, 
and desiccants
     HVAC piping insulation
     HVAC ductwork insulation
     Boiler insulation
     Automatic night setback
     Automatic economizer cooling
     Outside air control
     Hot and cold deck automatic reset
     Reheat system primary air optimization
     Process heat recovery
     Deadband thermostat
     Timeclocks on circulating pumps
     Chiller system
     Increase condensing unit efficiency
     Separate make-up air for exhaust hoods
     Variable air volume system
     Direct tower cooling (chiller strainer cycle)
     Multiple chiller control
     Radiant heating
     Evaporative roof surface cooling
     Cooling tower flow control
     Ceiling fans
     Evaporative cooling
     Direct expansion cooling system
     Heat recovery ventilation (water and air-source)
     Set-back controls for heating/cooling
     Make-up air control
     Manual fan switches
     Energy saving exhaust hood
     Night flushing
     Spot radiant heating
     Terminal regulated air volume control scheme
     Variable speed motors for HVAC system
     Waterside economizers
     Airside economizer
     Gray water systems
     Well water for cooling

                         1.2.2 Building envelope

     Insulation
     Wall insulation
     Floor/slab insulation
     Roof insulation
     Window and door upgrades, replacements, and films (to reduce solar 
heat gains)
     Passive solar design
     Earth berming
     Shading devices and tree planting
     High reflectivity roof coating
     Evaporative cooling
     Infiltration reduction
     Weatherstripping
     Caulking
     Low-e windows
     Multi-glazed windows
     Replace glazing with insulated walls
     Thermal break window frames
     Tinted glazing
     Vapor barrier
     Vestibule entry

                             1.2.3 Lighting

     Electronic ballast replacements
     Delamping
     Reflectors
     Occupancy sensors
     Daylighting with controls
     Photovoltaic lighting
     Efficient exterior lighting
     Manual selective switching
     Efficient exit signs
     Daylighting construction
     Cathode cutout ballasts
     High intensity discharge luminaries
     Outdoor light timeclock and photocell

                           1.2.4 Refrigeration

     Refrigerator replacement
     Freezer replacement
     Optimize heat gains to refrigerated space
     Optimize defrost control
     Refrigeration pressure optimization control
     High efficiency compressors
     Anti-condensate heater control
     Floating head pressure
     Hot gas defrost
     Parallel unequal compressors
     Variable speed compressors
     Water cooler controls
     Waste heat utilization
     Air doors on refrigeration equipment

                           1.2.5 Water Heating

     Electric water heating upgrades/replacements
     Electric water heater wraps/blankets
     Pipe insulation
     Solar heating and/or pre-heat units
     Geothermal heating and/or pre-heat units
     Circulating pump control
     Point-of-use water heater
     Heat recovery domestic water heater (DWH) system

[[Page 174]]

     Chemical dishwashing system
     End-use reduction using low-flow fittings

                 1.2.6 Other end-uses and miscellaneous

     Energy management control systems for building operations
     Customer located power based on photovoltaic, solar thermal, 
biomass, wind, and geothermal resources
     Energy efficient office equipment
     Customer-owned transformer upgrades and proper sizing

                              1.3 Industial

                              1.3.1 Motors

     Retire inefficient motors and replace with energy efficient 
motors, including the use of electronic adjustable speed or variable 
frequency drives
     Rebuild motors to operate more efficiently through greater 
contamination protection and improved magnetic materials
     Install self-starters
     Replace improperly sized motors

                             1.3.2 Lighting

     Electronic ballast replacement/improvement
     Electromagnetic ballast upgrade
     Installation of reflectors
     Substitution of lamps with built-in automatic cathode cut-out 
switches
     Modify ballast circuits with additional impedance devices
     Metal halide and high pressure sodium lamp retrofits
     High pressure sodium retrofits
     Daylighting with controls
     Occupancy sensors
     Delamping
     Photovoltaic lighting
     Two step and dimmable high intensity discharge ballast

            1.3.3 Heating/Ventilation/Air Conditioning (HVAC)

     Heat pump replacement/upgrade
     Furnace upgrade/replacement
     Fan motor efficiency
     Resizing of chillers
     Heat pipe retrofits on air conditioners
     Variable speed drive on fan motor
     Solar assisted HVAC including ventilation, chillers, heat pumps 
and desiccants

                       1.3.4 Industrial Processes

     Upgrades in heat transfer equipment
     Insulation and burner upgrades for industrial furnaces/ovens/
boilers to reduce electricity loads on motors and fans
     Insulation and redesign of piping
     Upgrades/retrofits in condenser/evaporation equipment
     Process air and water filtration for improved efficiency
     Upgrades of catalytic combustors
     Solar process heat
     Customer located power based on photovoltaic, solar thermal, 
biomass, wind, and geothermal resources
     Power factor controllers
     Utilization of waste gas fuels
     Steam line and steam trap repairs/upgrades
     Compressed air system improvements/repairs
     Industrial process heat pump
     Optimization of equipment lubrication or maintenance
     Resizing of process equipment for optimal energy efficiency
     Use of unique thermodynamic power cycles

                         1.3.5 Building Envelope

     Insulation of ceiling, walls, and ducts
     Window and door replacement/upgrade, including thermal energy 
barriers
     Caulking/weatherstripping

                           1.3.6 Water Heating

     Electric water heater upgrades/replacements
     Electric water heater wraps/blankets
     Pipe insulation
     Low-flow showerheads and fittings
     Solar heating and pre-heat units
     Geothermal heating and pre-heat units

                 1.3.7 Other End-uses and miscellaneous

     Refrigeration system retrofit/replacement
     Energy management control systems and end use metering
     Customer-owned transformer retrofits/replacements and proper 
sizing

                            1.4 Agricultural

                        1.4.1 Space Conditioning

     Building envelope measures
     Efficient HVAC equipment
     Heat pipe retrofit on air conditioners
     System and control measures
     Solar assisted HVAC including ventilation, chillers, heat pumps, 
and desiccants
     Air-source and geothermal heat pumps replacement/upgrades

                           1.4.2 Water heating

     Upgrades/replacements
     Water heater wraps/blankets
     Pipe insulation
     Low-flow showerheads and fittings
     Solart heating and/or pre-hear units
     Geothermal heating and/or pre-heat units

                             1.4.3 Lighting

     Electronic ballast replacements
     Delamping
     Reflectors

[[Page 175]]

     Occupancy sensors
     Daylighting with controls
     Photovoltaic lighting
     Outdoor lighting controls

                        1.4.4 Pumping/Irrigation

     Pump upgrades/retrofits
     Computerized pump control systems
     Irrigation load management strategies
     Irrigation pumping plants
     Computer irrigation control
     Surge irrigation
     Computerized scheduling of irrigation
     Drip irrigation systems

                              1.4.5 Motors

     Retire inefficient motors and replace with energy efficient 
motors, including the use of electronic adjustable speed and variable 
frequency drives
     Rebuild motors to operate more efficiently through greater 
contamination protection and improved magnetic materials
     Install self-starters
     Replace improperly sized motors

                          1.4.6 Other end uses

     Ventilation fans
     Cooling and refrigeration system upgrades
     Grain drying using unheated air
     Grain drying using low temperature electric
     Customer-owned transformer retrofits/replacements and proper 
sizing
     Programmable controllers for electrical farm equipment
     Controlled livestock ventilation
     Water heating for production agriculture
     Milk cooler heat exchangers
     Direct expansion/ice bank milk cooling
     Low energy precision application systems
     Heat pump crop drying

                     1.5 Government Services Sector

                          1.5.1 Streetlighting

     Replace incandescent and mercury vapor lamps with high pressure 
sodium and metal halide

                               1.5.2 Other

     Energy efficiency improvements in motors, pumps, and controls for 
water supply and waste water treatment
     District heating and cooling measures derived for cogeneration 
that result in electricity savings

       2. Supply-side Measures Applicable for Reduced Utilization

    Supply-side measures that may be approved for purposes of reduced 
utilization plans under Sec. 72.43 include the following:

                        2.1 Generation efficiency

     Heat rate improvement programs
     Availability improvement programs
     Coal cleaning measures that improve boiler efficiency
     Turbine improvements
     Boiler improvements
     Control improvements, including artificial intelligence and expert 
systems
     Distributed control--local (real-time) versus central (delayed)
     Equipment monitoring
     Performance monitoring
     Preventive maintenance
     Additional or improved heat recovery
     Sliding/variable pressure operations
     Adjustable speed drives
     Improved personnel training to improve man/machine interface

              2.2 Transmission and distribution efficiency

     High efficiency transformer switchouts using amorphous core and 
silicon steel technologies
     Low-loss windings
     Innovative cable insulation
     Reactive power dispatch optimization
     Power factor control
     Primary feeder reconfiguration
     Primary distribution voltage upgrades
     High efficiency substation transformers
     Controllable series capacitors
     Real-time distribution data acquisition analysis and control 
systems
     Conservation voltage regulation

3. Renewable Energy Generation Measures Applicable for the Conservation 
                  and Renewable Energy Reserve Program

    The following listed measures are approved as ``qualified renewable 
energy generation'' for purposes of the Conservation and Renewable 
Energy Reserve Program. Measures not appearing on the list may also be 
qualified renewable energy generation measures if they meet the 
requirements specified in Sec. 73.81.

                          3.1 Biomass resources

     Combustible energy-producing materials from biological sources 
which include: wood, plant residues, biological wastes, landfill gas, 
energy crops, and eligible components of municipal solid waste.

                           3.2 Solar resources

     Solar thermal systems and the non-fossil fuel portion of solar 
thermal hybrid systems
     Grid and non-grid connected photovoltaic systems, including 
systems added for voltage or capacity augmentation of a distribution 
grid.

[[Page 176]]

                        3.4 Geothermal resources

     Hydrothermal or geopressurized resources used for dry steam, flash 
steam, or binary cycle generation of electricity.

                           3.5 Wind resources

     Grid-connected and non-grid-connected wind farms
     Individual wind-driven electrical generating turbines



                    Subpart G_Small Diesel Refineries



Sec. 73.90  Allowance allocations for small diesel refineries.

    (a) Initial certification of eligibility. The certifying official of 
a refinery that seeks allowances under this section shall apply for 
certification of its facility eligibility prior to or accompanying a 
request for allowances under paragraph (d) of this section. A completed 
application for certification, submitted to the address in Sec. 73.13 
of this chapter, shall include the following:
    (1) Photocopies of Form EIA-810 for each month of calendar years 
1988 through 1990 for the refinery;
    (2) Photocopies of Form EIA-810 for each month of calendar years 
1988 through 1990 for each refinery owned or controlled by the refiner 
that owns or controls the refinery seeking certification; and
    (3) A letter certified by the certifying official that the submitted 
photocopies are exact duplicates of those forms filed with the 
Department of Energy for 1988 through 1990.
    (b) Request for allowances. (1) In addition to the application for 
certification, prior to, or accompanying, the request for allowances, 
the certifying official for the refinery shall submit an Allowance 
Tracking System New Account/New Authorized Account Representative Form.
    (2) The request for allowances shall be submitted to the address in 
Sec. 72.13 and shall include the following information:
    (i) Certification that all motor fuel produced by the refinery for 
which allowances are claimed meets the requirements of subsection 211(i) 
of the Clean Air Act;
    (ii) For calendar year 1993 desulfurized diesel fuel, photocopies of 
Form 810 for October, November and December 1993;
    (iii) For calendar years 1994 through 1999, inclusive, photocopies 
of Form 810 for each month in the respective calendar year.
    (3) For joint ventures, each eligible refinery shall submit a 
separate application under paragraph (b)(2) of this section. Each 
application must include the diesel fuel throughput applicable to the 
joint agreement and the requested distribution of allowances that would 
be allocated to the joint agreement. If the applications for refineries 
involved in the joint agreement are inconsistent as to the throughput of 
diesel fuel applicable to the joint agreement or as to the distribution 
of the allowances, all involved applications will be considered void for 
purposes of the joint agreement.
    (4) The certifying official shall submit all requests for allowances 
by April 1 of the calendar year following the year in which the diesel 
fuel was desulfurized to the Director, Acid Rain Division, under the 
procedures set forth in Sec. 73.13 of this part.
    (c) Allowance allocation. The Administrator will allocate allowances 
to the eligible refinery upon satisfactory submittal of information 
under paragraphs (a) and (b) of this section in the amount calculated 
according to the following equations. Such allowances will be allocated 
to the refinery's non-unit subaccount for the calendar year in which the 
application is made.
    (1) Allowances allocated under this section to any eligible refinery 
will be limited to the tons of SO2 attributable to the 
desulfurization of diesel fuel at the refinery. (2) The refinery will be 
allocated allowances for a calendar year and, in the case of 1993, for 
the period October 1 through December 31, calculated according to the 
following equation, but not to exceed 1500 for any calendar year:

[[Page 177]]

[GRAPHIC] [TIFF OMITTED] TC01SE92.092

where:

a = diesel fuel in barrels for the year (or for October 1 through 
          December 31 for 1993)
b = lbs per barrel of diesel
c = lbs of sulfur per lbs of diesel
d = lbs of SO2 per lbs of sulfur
e = lbs per short ton

    (3) If applications for a given year request, in the aggregate, more 
than 35,000 allowances, the Administrator will allocate allowances to 
each refinery in the amount equal to the lesser of 1500 or:
[GRAPHIC] [TIFF OMITTED] TR24OC97.000


[58 FR 15716, Mar. 23, 1993; 58 FR 33770, June 21, 1993; 62 FR 55486, 
Oct. 24, 1997]



PART 74_SULFUR DIOXIDE OPT-INS--Table of Contents



                    Subpart A_Background and Summary

Sec.
74.1 Purpose and scope.
74.2 Applicability.
74.3 Relationship to the Acid Rain program requirements.
74.4 Designated representative.

                     Subpart B_Permitting Procedures

74.10 Roles--EPA and permitting authority.
74.12 Opt-in permit contents.
74.14 Opt-in permit process.
74.16 Application requirements for combustion sources.
74.17 Application requirements for process sources. [Reserved]
74.18 Withdrawal.
74.19 Revision and renewal of opt-in permit.

         Subpart C_Allowance Calculations for Combustion Sources

74.20 Data for baseline and alternative baseline.
74.22 Actual SO2 emissions rate.
74.23 1985 Allowable SO2 emissions rate.
74.24 Current allowable SO2 emissions rate.
74.25 Current promulgated SO2 emissions limit.
74.26 Allocation formula.
74.28 Allowance allocation for combustion sources becoming opt-in 
          sources on a date other than January 1.

Subpart D--Allowance Calculations for Process Sources [Reserved]

  Subpart E_Allowance Tracking and Transfer and End of Year Compliance

74.40 Establishment of opt-in source allowance accounts.
74.41 Identifying allowances.
74.42 Limitation on transfers.
74.43 Annual compliance certification report.
74.44 Reduced utilization for combustion sources.
74.45 Reduced utilization for process sources. [Reserved]
74.46 Opt-in source permanent shutdown, reconstruction, or change in 
          affected status.
74.47 Transfer of allowances from the replacement of thermal energy--
          combustion sources.
74.48 Transfer of allowances from the replacement of thermal energy--
          process sources. [Reserved]
74.49 Calculation for deducting allowances.
74.50 Deducting opt-in source allowances from ATS accounts.

[[Page 178]]

           Subpart F_Monitoring Emissions: Combustion Sources

74.60 Monitoring requirements.
74.61 Monitoring plan.

Subpart G--Monitoring Emissions: Process Sources [Reserved]

    Authority: 42 U.S.C. 7601 and 7651 et seq.

    Source: 60 FR 17115, Apr. 4, 1995, unless otherwise noted.



                    Subpart A_Background and Summary



Sec. 74.1  Purpose and scope.

    The purpose of this part is to establish the requirements and 
procedures for:
    (a) The election of a combustion or process source that emits sulfur 
dioxide to become an affected unit under the Acid Rain Program, pursuant 
to section 410 of title IV of the Clean Air Act, 42 U.S.C. 7401, et 
seq., as amended by Public Law 101-549 (November 15, 1990); and
    (b) Issuing and modifying operating permits; certifying monitors; 
and allocating, tracking, transferring, surrendering and deducting 
allowances for combustion or process sources electing to become affected 
units.



Sec. 74.2  Applicability.

    Combustion or process sources that are not affected units under 
Sec. 72.6 of this chapter and that are operating and are located in the 
48 contiguous States or the District of Columbia may submit an opt-in 
permit application to become opt-in sources upon issuance of an opt-in 
permit. Units for which an exemption under Sec. 72.7 or Sec. 72.8 of 
this chapter is in effect and combustion or process sources that are not 
operating are not eligible to submit an opt-in permit application to 
become opt-in sources.

[60 FR 17115, Apr. 4, 1995, as amended at 62 FR 55487, Oct. 24, 1997; 66 
FR 12978, Mar. 1, 2001]



Sec. 74.3  Relationship to the Acid Rain program requirements.

    (a) General. (1) For purposes of applying parts 72, 73, 75, 77 and 
78, each opt-in source shall be treated as an affected unit.
    (2) Subpart A, B, G, and H of part 72 of this chapter, including 
Sec. Sec. 72.2 (definitions), 72.3 (measurements, abbreviations, and 
acronyms), 72.4 (Federal authority), 72.5 (State authority), 72.6 
(applicability), 72.7 (New units exemption), 72.8 (Retired units 
exemption), 72.9 (Standard Requirements), 72.10 (availability of 
information), and 72.11 (computation of time), shall apply to this part.
    (b) Permits. The permitting authority shall act in accordance with 
this part and parts 70, 71, and 72 of this chapter in issuing or denying 
an opt-in permit and incorporating it into a combustion or process 
source's operating permit. To the extent that any requirements of this 
part, part 72, and part 78 of this chapter are inconsistent with the 
requirements of parts 70 and 71 of this chapter, the requirements of 
this part, part 72, and part 78 of this chapter shall take precedence 
and shall govern the issuance, denials, revision, reopening, renewal, 
and appeal of the opt-in permit.
    (c) Appeals. The procedures for appeals of decisions of the 
Administrator under this part are contained in part 78 of this chapter.
    (d) Allowances. A combustion or process source that becomes an 
affected unit under this part shall be subject to all the requirements 
of subparts C and D of part 73 of this chapter, consistent with subpart 
E of this part.
    (e) Excess emissions. A combustion or process source that becomes an 
affected unit under this part shall be subject to the requirements of 
part 77 of this chapter applicable to excess emissions of sulfur dioxide 
and shall not be subject to the requirements of part 77 of this chapter 
applicable to excess emissions of nitrogen oxides.
    (f) Monitoring. A combustion or process source that becomes an 
affected unit under this part shall be subject to all the requirements 
of part 75, consistent with subparts F and G of this part.

[60 FR 17115, Apr. 4, 1995, as amended at 63 FR 18841, Apr. 16, 1998]

[[Page 179]]



Sec. 74.4  Designated representative.

    (a) The provisions of subpart B of part 72 of this chapter shall 
apply to the designated representative of an opt-in source.
    (b) If a combustion or process source is located at the same source 
as one or more affected units, the combustion or process source shall 
have the same designated representative as the other affected units at 
the source.

[60 FR 17115, Apr. 4, 1995, as amended at 63 FR 18841, Apr. 16, 1998; 71 
FR 25379, Apr. 28, 2006]



                     Subpart B_Permitting Procedures



Sec. 74.10  Roles--EPA and permitting authority.

    (a) Administrator responsibilities. The Administrator shall be 
responsible for the following activities under the opt-in provisions of 
the Acid Rain Program:
    (1) Calculating the baseline or alternative baseline and allowance 
allocation, and allocating allowances for combustion or process sources 
that become affected units under this part;
    (2) Certifying or recertifying monitoring systems for combustion or 
process sources as provided under Sec. 74.20 of this chapter;
    (3) Establishing allowance accounts, tracking allowances, assessing 
end-of-year compliance, determining reduced utilization, approving 
thermal energy transfer and accounting for the replacement of thermal 
energy, closing accounts for opt-in sources that shut down, are 
reconstructed, become affected under Sec. 72.6 of this chapter, or fail 
to renew their opt-in permit, and deducting allowances as provided under 
subpart E of this part; and
    (4) Ensuring that the opt-in source meets all withdrawal conditions 
prior to withdrawal from the Acid Rain Program as provided under Sec. 
74.18; and
    (5) Approving and disapproving the request to withdraw from the Acid 
Rain Program.
    (b) Permitting authority responsibilities. The permitting authority 
shall be responsible for the following activities:
    (1) Issuing the draft and final opt-in permit;
    (2) Revising and renewing the opt-in permit; and
    (3) Terminating the opt-in permit for an opt-in source as provided 
in Sec. 74.18 (withdrawal), Sec. 74.46 (shutdown, reconstruction or 
change in affected status) and Sec. 74.50 (deducting allowances).

[60 FR 17115, Apr. 4, 1995, as amended at 63 FR 18841, Apr. 16, 1998]



Sec. 74.12  Opt-in permit contents.

    (a) The opt-in permit shall be included in the Acid Rain permit.
    (b) Scope. The opt-in permit provisions shall apply only to the opt-
in source and not to any other affected units.
    (c) Contents. Each opt-in permit, including any draft or proposed 
opt-in permit, shall contain the following elements in a format 
specified by the Administrator:
    (1) All elements required for a complete opt-in permit application 
as provided under Sec. 74.16 for combustion sources or under Sec. 
74.17 for process sources or, if applicable, all elements required for a 
complete opt-in permit renewal application as provided in Sec. 74.19 
for combustion sources or under Sec. 74.17 for process sources;
    (2) The allowance allocation for the opt-in source as determined by 
the Administrator under subpart C of this part for combustion sources or 
subpart D of this part for process sources;
    (3) The standard permit requirements as provided under Sec. 72.9 of 
this chapter, except that the provisions in Sec. 72.9(d) of this 
chapter shall not be included in the opt-in permit; and
    (4) Termination. The provision that participation of a combustion or 
process source in the Acid Rain Program may be terminated only in 
accordance with Sec. 74.18 (withdrawal), Sec. 74.46 (shutdown, 
reconstruction, or change in affected status), and Sec. 74.50 
(deducting allowances).
    (d) Each opt-in permit is deemed to incorporate the definitions of 
terms under Sec. 72.2 of this chapter.
    (e) Permit shield. Each opt-in source operated in accordance with 
the opt-in permit that governs the opt-in source and that was issued in 
compliance with title IV of the Act, as provided in this part and parts 
72, 73, 75, 77, and 78 of

[[Page 180]]

this chapter, shall be deemed to be operating in compliance with the 
Acid Rain Program, except as provided in Sec. 72.9(g)(6) of this 
chapter.
    (f) Term of opt-in permit. An opt-in permit shall be issued for a 
period of 5 years and may be renewed in accordance with Sec. 74.19; 
provided
    (1) If an opt-in permit is issued prior to January 1, 2000, then the 
opt-in permit may, at the option of the permitting authority, expire on 
December 31, 1999; and
    (2) If an affected unit with an Acid Rain permit is located at the 
same source as the combustion source, the combustion source's opt-in 
permit may, at the option of the permitting authority, expire on the 
same date as the affected unit's Acid Rain permit expires.



Sec. 74.14  Opt-in permit process.

    (a) Submission. The designated representative of a combustion or 
process source may submit an opt-in permit application and a monitoring 
plan to the Administrator at any time for any combustion or process 
source that is operating.
    (b) Issuance or denial of opt-in permits. The permitting authority 
shall issue or deny opt-in permits or revisions of opt-in permits in 
accordance with the procedures in parts 70 and 71 of this chapter and 
subparts F and G of part 72 of this chapter, except as provided in this 
section.
    (1) Supplemental information. Regardless of whether the opt-in 
permit application is complete, the Administrator or the permitting 
authority may request submission of any additional information that the 
Administrator or the permitting authority determines to be necessary in 
order to review the opt-in permit application or to issue an opt-in 
permit.
    (2) Interim review of monitoring plan. The Administrator will 
determine, on an interim basis, the sufficiency of the monitoring plan, 
accompanying the opt-in permit application. A monitoring plan is 
sufficient, for purposes of interim review, if the plan appears to 
contain information demonstrating that all SO2 emissions, 
NOX emissions, CO2 emissions, and opacity of the 
combustion or process source are monitored and reported in accordance 
with part 75 of this chapter. This interim review of sufficiency shall 
not be construed as the approval or disapproval of the combustion or 
process source's monitoring system.
    (3) Issuance of draft opt-in permit. After the Administrator 
determines whether the combustion or process source's monitoring plan is 
sufficient under paragraph (b)(2) of this section, the permitting 
authority shall serve the draft opt-in permit or the denial of a draft 
permit or the draft opt-in permit revisions or the denial of draft opt-
in permit revisions on the designated representative of the combustion 
or process source submitting an opt-in permit application. A draft 
permit or draft opt-in permit revision shall not be served or issued if 
the monitoring plan is determined not to be sufficient.
    (4) Confirmation by source of intention to opt-in. Within 21 
calendar days from the date of service of the draft opt-in permit or the 
denial of the draft opt-in permit, the designated representative of a 
combustion or process source submitting an opt-in permit application 
must submit to the Administrator, in writing, a confirmation or recision 
of the source's intention to become an opt-in source under this part. 
The Administrator shall treat the failure to make a timely submission as 
a recision of the source's intention to become an opt-in source and as a 
withdrawal of the opt-in permit application.
    (5) Issuance of draft opt-in permit. If the designated 
representative confirms the combustion or process source's intention to 
opt in under paragraph (b)(4) of this section, the permitting authority 
will give notice of the draft opt-in permit or denial of the draft opt-
in permit and an opportunity for public comment, as provided under Sec. 
72.65 of this chapter with regard to a draft permit or denial of a draft 
permit if the Administrator is the permitting authority or as provided 
in accordance with part 70 of this chapter with regard to a draft permit 
or the denial of a draft permit if the State is the permitting 
authority.
    (6) Permit decision deadlines. (i) If the Administrator is the 
permitting authority, an opt-in permit will be issued

[[Page 181]]

or denied within 12 months of receipt of a complete opt-in permit 
application.
    (ii) If the State is the permitting authority, an opt-in permit will 
be issued or denied within 18 months of receipt of a complete opt-in 
permit application or such lesser time approved for operating permits 
under part 70 of this chapter.
    (7) Withdrawal of opt-in permit application. A combustion or process 
source may withdraw its opt-in permit application at any time prior to 
the issuance of the final opt-in permit. Once a combustion or process 
source withdraws its application, in order to re-apply, it must submit a 
new opt-in permit application in accordance with Sec. 74.16 for 
combustion sources or Sec. 74.17 for process sources.
    (c) [Reserved]
    (d) Entry into Acid Rain Program--(1) Effective date. The effective 
date of the opt-in permit shall be the January 1, April 1, July 1, or 
October 1 for a combustion or process source providing monthly data 
under Sec. 74.20, or January 1 for a combustion or process source 
providing annual data under Sec. 74.20, following the later of the 
issuance of the opt-in permit by the permitting authority or the 
completion of monitoring system certification, as provided in subpart F 
of this part for combustion sources or subpart G of this part for 
process sources. The combustion or process source shall become an opt-in 
source and an affected unit as of the effective date of the opt-in 
permit.
    (2) Allowance allocation. After the opt-in permit becomes effective, 
the Administrator will allocate allowances to the opt-in source as 
provided in Sec. 74.40. If the effective date of the opt-in permit is 
not January 1, allowances for the first year shall be pro-rated as 
provided in Sec. 74.28.
    (e) Expiration of opt-in permit. An opt-in permit that is issued 
before the completion of monitoring system certification under subpart F 
of this part for combustion sources or under subpart G of this part for 
process sources shall expire 180 days after the permitting authority 
serves the opt-in permit on the designated representative of the 
combustion or process source governed by the opt-in permit, unless such 
monitoring system certification is complete. The designated 
representative may petition the Administrator to extend this time period 
in which an opt-in permit expires and must explain in the petition why 
such an extension should be granted. The designated representative of a 
combustion source governed by an expired opt-in permit and that seeks to 
become an opt-in source must submit a new opt-in permit application.

[60 FR 17115, Apr. 4, 1995, as amended at 63 FR 18841, Apr. 16, 1998]



Sec. 74.16  Application requirements for combustion sources.

    (a) Opt-in permit application. Each complete opt-in permit 
application for a combustion source shall contain the following elements 
in a format prescribed by the Administrator:
    (1) Identification of the combustion source, including company name, 
plant name, plant site address, mailing address, description of the 
combustion source, and information and diagrams on the combustion 
source's configuration;
    (2) Identification of the designated representative, including name, 
address, telephone number, and facsimile number;
    (3) The year and month the combustion source commenced operation;
    (4) The number of hours the combustion source operated in the six 
months preceding the opt-in permit application and supporting 
documentation;
    (5) The baseline or alternative baseline data under Sec. 74.20;
    (6) The actual SO2 emissions rate under Sec. 74.22;
    (7) The allowable 1985 SO2 emissions rate under Sec. 
74.23;
    (8) The current allowable SO2 emissions rate under Sec. 
74.24;
    (9) The current promulgated SO2 emissions rate under 
Sec. 74.25;
    (10) If the combustion source seeks to qualify for a transfer of 
allowances from the replacement of thermal energy, a thermal energy plan 
as provided in Sec. 74.47 for combustion sources; and
    (11) A statement whether the combustion source was previously an 
affected unit under this part;
    (12) A statement that the combustion source is not an affected unit 
under Sec. 72.6 of this chapter and does not have

[[Page 182]]

an exemption under Sec. 72.7, Sec. 72.8, or Sec. 72.14 of this 
chapter;
    (13) A complete compliance plan for SO2 under Sec. 72.40 
of this chapter; and
    (14) The following statement signed by the designated representative 
of the combustion source: ``I certify that the data submitted under 
subpart C of part 74 reflects actual operations of the combustion source 
and has not been adjusted in any way.''
    (b) Accompanying documents. The designated representative of the 
combustion source shall submit a monitoring plan in accordance with 
Sec. 74.61.

[60 FR 17115, Apr. 4, 1995, as amended at 63 FR 18841, Apr. 16, 1998]



Sec. 74.17  Application requirements for process sources. [Reserved]



Sec. 74.18  Withdrawal.

    (a) Withdrawal through administrative amendment. An opt-in source 
may request to withdraw from the Acid Rain Program by submitting an 
administrative amendment under Sec. 72.83 of this chapter; provided 
that the amendment will be treated as received by the permitting 
authority upon issuance of the notification of the acceptance of the 
request to withdraw under paragraph (f)(1) of this section.
    (b) Requesting withdrawal. To withdraw from the Acid Rain Program, 
the designated representative of an opt-in source shall submit to the 
Administrator and the permitting authority a request to withdraw 
effective January 1 of the year after the year in which the submission 
is made. The submission shall be made no later than December 1 of the 
calendar year preceding the effective date of withdrawal.
    (c) Conditions for withdrawal. In order for an opt-in source to 
withdraw, the following conditions must be met:
    (1) By no later than January 30 of the first calendar year in which 
the withdrawal is to be effective, the designated representative must 
submit to the Administrator an annual compliance certification report 
pursuant to Sec. 74.43.
    (2) If the opt-in source has excess emissions in the calendar year 
before the year for which the withdrawal is to be in effect, the 
designated representative must submit an offset plan for excess 
emissions, pursuant to part 77 of this chapter, that provides for 
immediate deduction of allowances.
    (d) Administrator's action on withdrawal. After the opt-in source 
meets the requirements for withdrawal under paragraphs (b) and (c) of 
this section, the Administrator will deduct allowances required to be 
deducted under Sec. 73.35 of this chapter and part 77 of this chapter 
and allowances equal in number to and with the same or earlier 
compliance use date as those allocated under Sec. 74.40 for the first 
year for which the withdrawal is to be effective and all subsequent 
years.
    (e) Opt-in source's prior violations. An opt-in source that 
withdraws from the Acid Rain Program shall comply with all requirements 
under the Acid Rain Program concerning all years for which the opt-in 
source was an affected unit, even if such requirements arise, or must be 
complied with after the withdrawal takes effect.
    (f) Notification. (1) After the requirements for withdrawal under 
paragraphs (b) and (c) of this section are met and after the 
Administrator's action on withdrawal under paragraph (d) of this section 
is complete, the Administrator will issue a notification to the 
permitting authority and the designated representative of the opt-in 
source of the acceptance of the opt-in source's request to withdraw.
    (2) If the requirements for withdrawal under paragraphs (b) and (c) 
of this section are not met or the Administrator's action under 
paragraph (d) of this section cannot be completed, the Administrator 
will issue a notification to the permitting authority and the designated 
representative of the opt-in source that the opt-in source's request to 
withdraw is denied. If the opt-in source's request to withdraw is 
denied, the opt-in source shall remain in the Opt-in Program and shall 
remain subject to the requirements for opt-in sources contained in this 
part.
    (g) Permit amendment. (1) After the Administrator issues a 
notification under paragraph (f)(1) of this section that the 
requirements for withdrawal have been met (including the deduction of 
the full amount of allowances as required under paragraph (d) of this 
section), the permitting authority shall

[[Page 183]]

amend, in accordance with Sec. Sec. 72.80 and 72.83 (administrative 
amendment) of this chapter, the opt-in source's Acid Rain permit to 
terminate the opt-in permit, not later than 60 days from the issuance of 
the notification under paragraph (f) of this section.
    (2) The termination of the opt-in permit under paragraph (g)(1) of 
this section will be effective on January 1 of the year for which the 
withdrawal is requested. An opt-in source shall continue to be an 
affected unit until the effective date of the termination.
    (h) Reapplication upon failure to meet conditions of withdrawal. If 
the Administrator denies the opt-in source's request to withdraw, the 
designated representative may submit another request to withdraw in 
accordance with paragraphs (b) and (c) of this section.
    (i) Ability to return to the Acid Rain Program. Once a combustion or 
process source withdraws from the Acid Rain Program and its opt-in 
permit is terminated, a new opt-in permit application for the combustion 
or process source may not be submitted prior to the date that is four 
years after the date on which the opt-in permit became effective.

[60 FR 17115, Apr. 4, 1995, as amended at 63 FR 18841, Apr. 16, 1998; 70 
FR 25336, May 12, 2005]



Sec. 74.19  Revision and renewal of opt-in permit.

    (a) The designated representative of an opt-in source may submit 
revisions to its opt-in permit in accordance with subpart H of part 72 
of this chapter.
    (b) The designated representative of an opt-in source may renew its 
opt-in permit by meeting the following requirements:
    (1)(i) In order to renew an opt-in permit if the Administrator is 
the permitting authority for the renewed permit, the designated 
representative of an opt-in source must submit to the Administrator an 
opt-in permit application at least 6 months prior to the expiration of 
an existing opt-in permit.
    (ii) In order to renew an opt-in permit if the State is the 
permitting authority for the renewed permit, the designated 
representative of an opt-in source must submit to the permitting 
authority an opt-in permit application at least 18 months prior to the 
expiration of an existing opt-in permit or such shorter time as may be 
approved for operating permits under part 70 of this chapter.
    (2) Each complete opt-in permit application submitted to renew an 
opt-in permit shall contain the following elements in a format 
prescribed by the Administrator:
    (i) Elements contained in the opt-in source's initial opt-in permit 
application as specified under Sec. 74.16(a)(1), (2), (10), (11), (12), 
and (13).
    (ii) An updated monitoring plan, if applicable under Sec. 75.53(b) 
of this chapter.
    (c)(1) Upon receipt of an opt-in permit application submitted to 
renew an opt-in permit, the permitting authority shall issue or deny an 
opt-in permit in accordance with the requirements under subpart B of 
this part, except as provided in paragraph (c)(2) of this section.
    (2) When issuing a renewed opt-in permit, the permitting authority 
shall not alter an opt-in source's allowance allocation as established, 
under subpart B and subpart C of this part for combustion sources and 
under subpart B and subpart D of this part for process sources, in the 
opt-in permit that is being renewed.



         Subpart C_Allowance Calculations for Combustion Sources



Sec. 74.20  Data for baseline and alternative baseline.

    (a) Acceptable data. (1) The designated representative of a 
combustion source shall submit either the data specified in this 
paragraph or alternative data under paragraph (c) of this section. The 
designated representative shall also submit the calculations under this 
section based on such data.
    (2) The following data shall be submitted for the combustion source 
for the calendar year(s) under paragraph (a)(3) of this section:
    (i) Monthly or annual quantity of each type of fuel consumed, 
expressed in thousands of tons for coal, thousands of barrels for oil, 
and million standard cubic feet (scf) for natural

[[Page 184]]

gas. If other fuels are used, the combustion source must specify units 
of measure.
    (ii) Monthly or annual heat content of fuel consumed for each type 
of fuel consumed, expressed in British thermal units (Btu) per pound for 
coal, Btu per barrel for oil, and Btu per standard cubic foot (scf) for 
natural gas. If other fuels are used, the combustion source must specify 
units of measure.
    (iii) Monthly or annual sulfur content of fuel consumed for each 
type of fuel consumed, expressed as a percentage by weight.
    (3) Calendar Years. (i) For combustion sources that commenced 
operating prior to January 1, 1985, data under this section shall be 
submitted for 1985, 1986, and 1987.
    (ii) For combustion sources that commenced operation after January 
1, 1985, the data under this section shall be submitted for the first 
three consecutive calendar years during which the combustion source 
operated after December 31, 1985.
    (b) Calculation of baseline and alternative baseline. (1) For 
combustion sources that commenced operation prior to January 1, 1985, 
the baseline is the average annual quantity of fuel consumed during 
1985, 1986, and 1987, expressed in mmBtu. The baseline shall be 
calculated as follows:
[GRAPHIC] [TIFF OMITTED] TR04AP95.000


where,

    (i) for a combustion source submitting monthly data,
    [GRAPHIC] [TIFF OMITTED] TR04AP95.001
    

and unit conversion

= 2 for coal
= 0.001 for oil
= 1 for gas


For other fuels, the combustion source must specify unit conversion; or
    (ii) for a combustion source submitting annual data,
    [GRAPHIC] [TIFF OMITTED] TR04AP95.002
    

and unit conversion
    = 2 for coal
    = 0.001 for oil
    = 1 for gas

For other fuels, the combustion source must specify unit conversion.
    (2) For combustion sources that commenced operation after January 1, 
1985, the alternative baseline is the average annual quantity of fuel 
consumed in the first three consecutive calendar years during which the 
combustion source operated after December 31, 1985, expressed in mmBtu. 
The alternative baseline shall be calculated as follows:

[[Page 185]]

[GRAPHIC] [TIFF OMITTED] TR04AP95.003

where,

``annual fuel consumption'' is as defined under paragraph (b)(1)(i) or 
(ii) of this section.

    (c) Alternative data. (1) For combustion sources for which any of 
the data under paragraph (b) of this section is not available due solely 
to a natural catastrophe, data as set forth in paragraph (a)(2) of this 
section for the first three consecutive calendar years for which data is 
available after December 31, 1985, may be submitted. The alternative 
baseline for these combustion sources shall be calculated using the 
equation for alternative baseline in paragraph (b)(2) of this section 
and the definition of annual fuel consumption in paragraphs (b)(1)(i) or 
(ii) of this section.
    (2) Except as provided in paragraph (c)(1) of this section, no 
alternative data may be submitted. A combustion source that cannot 
submit all required data, in accordance with this section, shall not be 
eligible to submit an opt-in permit application.
    (d) Administrator's action. The Administrator may accept in whole or 
in part or with changes as appropriate, request additional information, 
or reject data or alternative data submitted for a combustion source's 
baseline or alternative baseline.



Sec. 74.22  Actual SO [bdi2] emissions rate.

    (a) Data requirements. The designated representative of a combustion 
source shall submit the calculations under this section based on data 
submitted under Sec. 74.20 for the following calendar year:
    (1) For combustion sources that commenced operation prior to January 
1, 1985, the calendar year for calculating the actual SO2 
emissions rate shall be 1985.
    (2) For combustion sources that commenced operation after January 1, 
1985, the calendar year for calculating the actual SO2 
emissions rate shall be the first year of the three consecutive calendar 
years of the alternative baseline under Sec. 74.20(b)(2).
    (3) For combustion sources meeting the requirements of Sec. 
74.20(c), the calendar year for calculating the actual SO2 
emissions rate shall be the first year of the three consecutive calendar 
years to be used as alternative data under Sec. 74.20(c).
    (b) SO2 emissions factor calculation. The SO2 emissions 
factor for each type of fuel consumed during the specified year, 
expressed in pounds per thousand tons for coal, pounds per thousand 
barrels for oil and pounds per million cubic feet (scf) for gas, shall 
be calculated as follows:

SO2 Emissions Factor = (average percent of sulfur by weight) 
x (k),

where,

average percent of sulfur by weight
    = annual average, for a combustion source submitting annual data
    = monthly average, for a combustion source submitting monthly data
k = 39,000 for bituminous coal or anthracite
    = 35,000 for subbituminous coal
    = 30,000 for lignite
    = 5,964 for distillate (light) oil
    = 6,594 for residual (heavy) oil
    = 0.6 for natural gas
For other fuels, the combustion source must specify the SO2 
emissions factor.

    (c) Annual SO2 emissions calculation. Annual SO2 
Emissions for the specified calendar year, expressed in pounds, shall be 
calculated as follows:
    (1) For a combustion source submitting monthly data,

[[Page 186]]

[GRAPHIC] [TIFF OMITTED] TR04AP95.004

    (2) For a combustion source submitting annual data:
    [GRAPHIC] [TIFF OMITTED] TR04AP95.005
    
where,

``quantity of fuel consumed'' is as defined under Sec. 74.20(a)(2)(i);
``SO2 emissions factor'' is as defined under paragraph (b) of 
          this section;
``control system efficiency'' is as defined under Sec. 60.48(a) and 
          part 60, appendix A, method 19 of this chapter, if applicable; 
          and
``fuel pre-treatment efficiency'' is as defined under Sec. 60.48(a) and 
          part 60, appendix A, method 19 of this chapter, if applicable.

    (d) Annual fuel consumption calculation. Annual fuel consumption for 
the specified calendar year, expressed in mmBtu, shall be calculated as 
defined under Sec. 74.20(b)(1) (i) or (ii).
    (e) Actual SO2 emissions rate calculation. The actual SO2 
emissions rate for the specified calendar year, expressed in lbs/mmBtu, 
shall be calculated as follows:
[GRAPHIC] [TIFF OMITTED] TR04AP95.006


[60 FR 17115, Apr. 4, 1995, as amended at 63 FR 18841, Apr. 16, 1998]



Sec. 74.23  1985 Allowable SO [bdi2] emissions rate.

    (a) Data requirements. (1) The designated representative of the 
combustion source shall submit the following data and the calculations 
under paragraph (b) of this section based on the submitted data:
    (i) Allowable SO2 emissions rate of the combustion source 
expressed in lbs/mmBtu as defined under Sec. 72.2 of this chapter for 
the calendar year specified in paragraph (a)(2) of this section. If the 
allowable SO2 emissions rate is not expressed in lbs/mmBtu, 
the allowable emissions rate shall be converted to lbs/mmBtu by 
multiplying the emissions rate by the appropriate factor as specified in 
Table 1 of this section.

                       Table 1--Factors to Convert Emission Limits to Pounds of SO2/mmBtu
----------------------------------------------------------------------------------------------------------------
                                                             Bituminous   Subbituminous   Lignite
                     Unit measurement                           coal           coal         coal         Oil
----------------------------------------------------------------------------------------------------------------
lbs Sulfur/mmBtu..........................................       2.0            2.0           2.0        2.0
% Sulfur in fuel..........................................       1.66           2.22          2.86       1.07
ppm SO2...................................................       0.00287        0.00384  .........       0.00167
ppm Sulfur in fuel........................................  ............  .............  .........       0.00334

[[Page 187]]

 
tons SO2/hour.............................................  2 x 8760/(annual fuel consumption for specified year
                                                                                \1\ x 10\3\)
lbs SO2/hour..............................................  8760/(annual fuel consumption for specified year \1\
                                                                                  x 10\6\)
----------------------------------------------------------------------------------------------------------------
\1\ Annual fuel consumption as defined under Sec. 74.20(b)(1) (i) or (ii); specified calendar year as defined
  under Sec. 74.23(a)(2).

    (ii) Citation of statute, regulations, and any other authority under 
which the allowable emissions rate under paragraph (a)(1) of this 
section is established as applicable to the combustion source;
    (iii) Averaging time associated with the allowable emissions rate 
under paragraph (a)(1) of this section.
    (iv) The annualization factor for the combustion source, based on 
the type of combustion source and the associated averaging time of the 
allowable emissions rate of the combustion source, as set forth in the 
Table 2 of this section:

          Table 2--Annualization Factors for SO2 Emission Rates
------------------------------------------------------------------------
                                                           Annualization
                                            Annualization    factor for
         Type of combustion source            factor for     unscrubbed
                                            scrubbed unit       unit
------------------------------------------------------------------------
Unit Combusting Oil, Gas, or some                   1.00           1.00
 combination..............................
Coal Unit with Averaging Time <= 1 day....          0.93           0.89
Coal Unit with Averaging Time = 1 week....          0.97           0.92
Coal Unit with Averaging Time = 30 days...          1.00           0.96
Coal Unit with Averaging Time = 90 days...          1.00           1.00
Coal Unit with Averaging Time = 1 year....          1.00           1.00
Coal Unit with Federal Limit, but                   0.93           0.89
 Averaging Time Not Specified.............
------------------------------------------------------------------------

    (2) Calendar year. (i) For combustion sources that commenced 
operation prior to January 1, 1985, the calendar year for the allowable 
SO2 emissions rate shall be 1985.
    (ii) For combustion sources that commenced operation after January 
1, 1985, the calendar year for the allowable SO2 emissions 
rate shall be the first year of the three consecutive calendar years of 
the alternative baseline under Sec. 74.20(b)(2).
    (iii) For combustion sources meeting the requirements of Sec. 
74.20(c), the calendar year for calculating the allowable SO2 
emissions rate shall be the first year of the three consecutive calendar 
years to be used as alternative data under Sec. 74.20(c).
    (b) 1985 Allowable SO2 emissions rate calculation. The 
allowable SO2 emissions rate for the specified calendar year 
shall be calculated as follows:

1985 Allowable SO2 Emissions Rate = (Allowable SO2 
Emissions Rate) x (Annualization Factor)



Sec. 74.24  Current allowable SO [bdi2] emissions rate.

    The designated representative shall submit the following data:
    (a) Current allowable SO2 emissions rate of the 
combustion source, expressed in lbs/mmBtu, which shall be the most 
stringent federally enforceable emissions limit in effect as of the date 
of submission of the opt-in application. If the allowable SO2 
emissions rate is not expressed in lbs/mmBtu, the allowable emissions 
rate shall be converted to lbs/mmBtu by multiplying the allowable rate 
by the appropriate factor as specified in Table 1 in Sec. 
74.23(a)(1)(i).
    (b) Citations of statute, regulation, and any other authority under 
which the allowable emissions rate under paragraph (a) of this section 
is established as applicable to the combustion source;
    (c) Averaging time associated with the allowable emissions rate 
under paragraph (a) of this section.

[[Page 188]]



Sec. 74.25  Current promulgated SO [bdi2] emissions limit.

    The designated representative shall submit the following data:
    (a) Current promulgated SO2 emissions limit of the 
combustion source, expressed in lbs/mmBtu, which shall be the most 
stringent federally enforceable emissions limit that has been 
promulgated as of the date of submission of the opt-in permit 
application and that either is in effect on that date or will take 
effect after that date. If the promulgated SO2 emissions 
limit is not expressed in lbs/mmBtu, the limit shall be converted to 
lbs/mmBtu by multiplying the limit by the appropriate factor as 
specified in Table 1 of Sec. 74.23(a)(1)(i).
    (b) Citations of statute, regulation and any other authority under 
which the emissions limit under paragraph (a) of this section is 
established as applicable to the combustion source;
    (c) Averaging time associated with the emissions limit under 
paragraph (a) of this section.
    (d) Effective date of the emissions limit under paragraph (a) of 
this section.



Sec. 74.26  Allocation formula.

    (a) The Administrator will calculate the annual allowance allocation 
for a combustion source based on the data, corrected as necessary, under 
Sec. 74.20 through Sec. 74.25 as follows:
    (1) For combustion sources for which the current promulgated 
SO2 emissions limit under Sec. 74.25 is greater than or 
equal to the current allowable SO2 emissions rate under Sec. 
74.24, the number of allowances allocated for each year equals:
[GRAPHIC] [TIFF OMITTED] TR04AP95.007

    (2) For combustion sources for which the current promulgated 
SO2 emissions limit under Sec. 74.25 is less than the 
current allowable SO2 emissions rate under Sec. 74.24.
    (i) The number of allowances for each year ending prior to the 
effective date of the promulgated SO2 emissions limit equals:
[GRAPHIC] [TIFF OMITTED] TR04AP95.008

    (ii) The number of allowances for the year that includes the 
effective date of the promulgated SO2 emissions limit and for 
each year thereafter equals:

[[Page 189]]

[GRAPHIC] [TIFF OMITTED] TR04AP95.009


[60 FR 17115, Apr. 4, 1995, as amended at 63 FR 18841, Apr. 16, 1998]



Sec. 74.28  Allowance allocation for combustion sources becoming opt-
in sources on a date other than January 1.

    (a) Dates of entry. (1) If an opt-in source provided monthly data 
under Sec. 74.20, the opt-in source's opt-in permit may become 
effective at the beginning of a calendar quarter as of January 1, April 
1, July 1, or October 1.
    (2) If an opt-in source provided annual data under Sec. 74.20, the 
opt-in source's opt-in permit must become effective on January 1.
    (b) Prorating by Calendar Quarter. Where a combustion source's opt-
in permit becomes effective on April 1, July 1, or October 1 of a given 
year, the Administrator will prorate the allowance allocation for that 
first year by the calendar quarters remaining in the year as follows:

Allowances for the first year
[GRAPHIC] [TIFF OMITTED] TR04AP95.010

    (1) For combustion sources that commenced operations before January 
1, 1985,
[GRAPHIC] [TIFF OMITTED] TR04AP95.011

    (2) For combustion sources that commenced operations after January 
1, 1985,
[GRAPHIC] [TIFF OMITTED] TR04AP95.012

    (3) Under paragraphs (b) (1) and (2) of this section,
    (i) ``Remaining calendar quarters'' shall be the calendar quarters 
in the first year for which the opt-in permit will be effective.
    (ii) Fuel consumption for remaining calendar quarters =

[[Page 190]]

[GRAPHIC] [TIFF OMITTED] TR04AP95.013


where unit conversion
    = 2 for coal
    = 0.001 for oil
    = 1 for gas
For other fuels, the combustion source must specify unit conversion;
and where starting month
    = April, if effective date is April 1;
    = July, if effective date is July 1; and
    = October, if effective date is October 1.

Subpart D--Allowance Calculations for Process Sources [Reserved]



  Subpart E_Allowance Tracking and Transfer and End of Year Compliance



Sec. 74.40  Establishment of opt-in source allowance accounts.

    (a) Establishing accounts. Not earlier than the date on which a 
combustion or process source becomes an affected unit under this part 
and upon receipt of a request for a compliance account under paragraph 
(b) of this section, the Administrator will establish a compliance 
account (unless the source that includes the opt-in source already has a 
compliance account or the opt-in source has, under Sec. 74.4(c), a 
different designated representative than the designated representative 
for the source) and allocate allowances in accordance with subpart C of 
this part for combustion sources or subpart D of this part for process 
sources.
    (b) Request for opt-in account. The designated representative of the 
opt-in source shall, on or after the effective date of the opt-in permit 
as specified in Sec. 74.14(d), submit a letter requesting the opening 
of an compliance account (unless the source that includes the opt-in 
source already has a compliance account or the opt-in source has, under 
Sec. 74.4(c), a different designated representative than the designated 
representative for the source)to the Administrator.

[60 FR 17115, Apr. 4, 1995, as amended at 70 FR 25336, May 12, 2005]



Sec. 74.41  Identifying allowances.

    (a) Identifying allowances. Allowances allocated to an opt-in source 
will be assigned a serial number that identifies them as being allocated 
under an opt-in permit.
    (b) Submittal of opt-in allowances for auction. (1) An authorized 
account representative may offer for sale in the spot auction under 
Sec. 73.70 of this chapter allowances that are allocated to opt-in 
sources, if the allowances have a compliance use date earlier than the 
year in which the spot auction is to be held and if the Administrator 
has completed the deductions for compliance under Sec. 73.35(b) for the 
compliance year corresponding to the compliance use date of the offered 
allowances.
    (2) Authorized account representatives may not offer for sale in the 
advance auctions under Sec. 73.70 of this chapter allowances allocated 
to opt-in sources.



Sec. 74.42  Limitation on transfers.

    (a) With regard to a transfer request submitted for recordation 
during the period starting January 1 and ending with the allowance 
transfer deadline in the same year, the Administrator will not record a 
transfer of an opt-in allowance that is allocated to an opt-in source 
for the year in which the transfer request is submitted or a subsequent 
year.
    (b) With regard to a transfer request during the period starting 
with the day after an allowance transfer deadline and ending December 31 
in the same year, the Administrator will not record a transfer of an 
opt-in allowance that is allocated to an opt-in source for a year after 
the year in which the transfer request is submitted.

[70 FR 25336, May 12, 2005]



Sec. 74.43  Annual compliance certification report.

    (a) Applicability and deadline. For each calendar year in which an 
opt-in source is subject to the Acid Rain

[[Page 191]]

emissions limitations, the designated representative of the opt-in 
source shall submit to the Administrator, no later than 60 days after 
the end of the calendar year, an annual compliance certification report 
for the opt-in source.
    (b) Contents of report. The designated representative shall include 
in the annual compliance certification report the following elements, in 
a format prescribed by the Administrator, concerning the opt-in source 
and the calendar year covered by the report:
    (1) Identification of the opt-in source;
    (2) An opt-in utilization report in accordance with Sec. 74.44 for 
combustion sources and Sec. 74.45 for process sources;
    (3) A thermal energy compliance report in accordance with Sec. 
74.47 for combustion sources and Sec. 74.48 for process sources, if 
applicable;
    (4) Shutdown or reconstruction information in accordance with Sec. 
74.46, if applicable;
    (5) A statement that the opt-in source has not become an affected 
unit under Sec. 72.6 of this chapter;
    (6) At the designated representative's option, the total number of 
allowances to be deducted for the year, using the formula in Sec. 
74.49, and the serial numbers of the allowances that are to be deducted; 
and
    (7) In an annual compliance certification report for a year during 
1995 through 2005, at the designated representative's option, for opt-in 
sources that share a common stack and whose emissions of sulfur dioxide 
are not monitored separately or apportioned in accordance with part 75 
of this chapter, the percentage of the total number of allowances under 
paragraph (b)(6) of this section for all such affected units that is to 
be deducted from each affected unit's compliance subaccount; and
    (8) In an annual compliance certification report for a year during 
1995 through 2005, the compliance certification under paragraph (c) of 
this section.
    (c) Annual compliance certification. In the annual compliance 
certification report under paragraph (a) of this section, the designated 
representative shall certify, based on reasonable inquiry of those 
persons with primary responsibility for operating the opt-in source in 
compliance with the Acid Rain Program, whether the opt-in source was 
operated during the calendar year covered by the report in compliance 
with the requirements of the Acid Rain Program applicable to the opt-in 
source, including:
    (1) Whether the opt-in source was operated in compliance with 
applicable Acid Rain emissions limitations, including whether the opt-in 
source held allowances, as of the allowance transfer deadline, in its 
compliance subaccount (after accounting for any allowance deductions or 
other adjustments under Sec. 73.34(c) of this chapter) not less than 
the opt-in source's total sulfur dioxide emissions during the calendar 
year covered by the annual report;
    (2) Whether the monitoring plan that governs the opt-in source has 
been maintained to reflect the actual operation and monitoring of the 
opt-in source and contains all information necessary to attribute 
monitored emissions to the opt-in source;
    (3) Whether all the emissions from the opt-in source or group of 
affected units (including the opt-in source) using a common stack were 
monitored or accounted for through the missing data procedures and 
reported in the quarterly monitoring reports in accordance with part 75 
of this chapter;
    (4) Whether the facts that form the basis for certification of each 
monitor at the opt-in source or group of affected units (including the 
opt-in source) using a common stack or of an opt-in source's 
qualifications for using an Acid Rain Program excepted monitoring method 
or approved alternative monitoring method, if any, have changed;
    (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 monitoring 
recertification; and
    (6) When applicable, whether the opt-in source was operating in 
compliance

[[Page 192]]

with its thermal energy plan as provided in Sec. 74.47 for combustion 
sources and Sec. 74.48 for process sources.

[60 FR 17115, Apr. 4, 1995, as amended at 70 FR 25337, May 12, 2005]



Sec. 74.44  Reduced utilization for combustion sources.

    (a) Calculation of utilization--(1) Annual utilization. (i) Except 
as provided in paragraph (a)(1)(ii) of this section, annual utilization 
for the calendar year shall be calculated as follows:

Annual Utilization = Actual heat input + Reduction from improved 
efficiency


where,

    (A) ``Actual heat input'' shall be the actual annual heat input (in 
mmBtu) of the opt-in source for the calendar year determined in 
accordance with appendix F of part 75 of this chapter.
    (B) ``Reduction from improved efficiency'' shall be the sum of the 
following four elements: Reduction from demand side measures that 
improve the efficiency of electricity consumption; reduction from demand 
side measures that improve the efficiency of steam consumption; 
reduction from improvements in the heat rate at the opt-in source; and 
reduction from improvement in the efficiency of steam production at the 
opt-in source. Qualified demand side measures applicable to the 
calculation of utilization for opt-in sources are listed in appendix A, 
section 1 of part 73 of this chapter.
    (C) ``Reduction from demand side measures that improve the 
efficiency of electricity consumption'' shall be a good faith estimate 
of the expected kilowatt hour savings during the calendar year for such 
measures and the corresponding reduction in heat input (in mmBtu) 
resulting from those measures. The demand side measures shall be 
implemented at the opt-in source, in the residence or facility to which 
the opt-in source delivers electricity for consumption or in the 
residence or facility of a customer to whom the opt-in source's utility 
system sells electricity. The verified amount of such reduction shall be 
submitted in accordance with paragraph (c)(2) of this section.
    (D) ``Reduction from demand side measures that improve the 
efficiency of steam consumption'' shall be a good faith estimate of the 
expected steam savings (in mmBtu) from such measures during the calendar 
year and the corresponding reduction in heat input (in mmBtu) at the 
opt-in source as a result of those measures. The demand side measures 
shall be implemented at the opt-in source or in the facility to which 
the opt-in source delivers steam for consumption. The verified amount of 
such reduction shall be submitted in accordance with paragraph (c)(2) of 
this section.
    (E) ``Reduction from improvements in heat rate'' shall be a good 
faith estimate of the expected reduction in heat rate during the 
calendar year and the corresponding reduction in heat input (in mmBtu) 
at the opt-in source as a result of all improved unit efficiency 
measures at the opt-in source and may include supply-side measures 
listed in appendix A, section 2.1 of part 73 of this chapter. The 
verified amount of such reduction shall be submitted in accordance with 
paragraph (c)(2) of this section.
    (F) ``Reduction from improvement in the efficiency of steam 
production at the opt-in source'' shall be a good faith estimate of the 
expected improvement in the efficiency of steam production at the opt-in 
source during the calendar year and the corresponding reduction in heat 
input (in mmBtu) at the opt-in source as a result of all improved steam 
production efficiency measures. In order to claim improvements in the 
efficiency of steam production, the designated representative of the 
opt-in source must demonstrate to the satisfaction of the Administrator 
that the heat rate of the opt-in source has not increased. The verified 
amount of such reduction shall be submitted in accordance with paragraph 
(c)(2) of this section.
    (G) Notwithstanding paragraph (a)(1)(i)(B) of this section, where 
two or more opt-in sources, or two or more opt-in sources and Phase I 
units, include in their annual compliance certification reports their 
good faith estimate of kilowatt hour savings or steam savings from the 
same specific measures:

[[Page 193]]

    (1) The designated representatives of all such opt-in sources and 
Phase I units shall submit with their annual compliance certification 
reports a certification signed by all such designated representatives. 
The certification shall apportion the total kilowatt hour savings or 
steam savings among such opt-in sources and Phase I units.
    (2) Each designated representative shall include in its annual 
compliance certification report only its share of kilowatt hour savings 
or steam savings.
    (ii) For an opt-in source whose opt-in permit becomes effective on a 
date other than January 1, annual utilization for the first year shall 
be calculated as follows:
[GRAPHIC] [TIFF OMITTED] TR04AP95.014

where ``actual heat input'' and ``reduction from improved efficiency'' 
          are defined as set forth in paragraph (a)(1)(i) of this 
          section but are restricted to data or estimates for the 
          ``remaining calendar quarters'', which are the calendar 
          quarters that begin on or after the date the opt-in permit 
          becomes effective.

    (2) Average utilization. Average utilization for the calendar year 
shall be defined as the average of the annual utilization calculated as 
follows:
    (i) For the first two calendar years after the effective date of an 
opt-in permit taking effect on January 1, average utilization will be 
calculated as follows:
    (A) Average utilization for the first year = annual 
utilizationyear 1

where ``annual utilizationyear 1'' is as calculated under 
paragraph (a)(1)(i) of this section.

    (B) Average utilization for the second year
    [GRAPHIC] [TIFF OMITTED] TR04AP95.015
    
where,

``revised annual utilizationyear 1'' is as submitted for the 
          year under paragraph (c)(2)(i)(B) of this section and adjusted 
          under paragraph (c)(2)(iii) of this section;
``annual utilizationyear 2'' is as calculated under paragraph 
          (a)(1)(i) of this section.

    (ii) For the first three calendar years after the effective date of 
the opt-in permit taking effect on a date other than January 1, average 
utilization will be calculated as follows:

    (A) Average utilization for the first year after opt-in = annual 
utilizationyear 1

where ``annual utilizationyear 1'' is as calculated under 
paragraph (a)(1)(ii) of this section.

    (B) Average utilization for the second year after opt-in


where,

[[Page 194]]

[GRAPHIC] [TIFF OMITTED] TR04AP95.016

``revised annual utilizationyear 1'' is as submitted for the 
          year under paragraph (c)(2)(i)(B) of this section and adjusted 
          under paragraph (c)(2)(iii) of this section; and
``annual utilizationyear 2'' is as calculated under paragraph 
          (a)(1)(ii) of this section.

    (C) Average utilization for the third year after opt-in
    [GRAPHIC] [TIFF OMITTED] TR04AP95.017
    
where,

``revised annual utilizationyear 1'' is as submitted for the 
          year under paragraph (c)(2)(i)(B) of this section and adjusted 
          under paragraph (c)(2)(iii) of this section; and
``revised annual utilizationyear 2'' is as submitted for the 
          year under paragraph (c)(2)(i)(B) of this section and adjusted 
          under paragraph (c)(2)(iii) of this section; and
``annual utilizationyear 3'' is as calculated under paragraph 
          (a)(1)(ii) of this section.

    (iii) Except as provided in paragraphs (a)(2)(i) and (a)(2)(ii) of 
this section, average utilization shall be the sum of annual utilization 
for the calendar year and the revised annual utilization, submitted 
under paragraph (c)(2)(i)(B) of this section and adjusted by the 
Administrator under paragraph (c)(2)(iii) of this section, for the two 
immediately preceding calendar years divided by 3.
    (b) Determination of reduced utilization and calculation of 
allowances--(1) Determination of reduced utilization. For a year during 
which its opt-in permit is effective, an opt-in source has reduced 
utilization if the opt-in source's average utilization for the calendar 
year, as calculated under paragraph (a) of this section, is less than 
its baseline.
    (2) Calculation of allowances deducted for reduced utilization. If 
the Administrator determines that an opt-in source has reduced 
utilization for a calendar year during which the opt-in source's opt-in 
permit is in effect, the Administrator will deduct allowances, as 
calculated under paragraph (b)(2)(i) of this section, from the 
compliance subaccount of the opt-in source's Allowance Tracking System 
account.
    (i) Allowances deducted for reduced utilization =
    [GRAPHIC] [TIFF OMITTED] TR04AP95.018
    

[[Page 195]]


    (ii) The allowances deducted shall have the same or an earlier 
compliance use date as those allocated under subpart C of this part for 
the calendar year for which the opt-in source has reduced utilization.
    (c) Compliance--(1) Opt-in Utilization Report. The designated 
representative for each opt-in source shall submit an opt-in utilization 
report for the calendar year, as part of its annual compliance 
certification report under Sec. 74.43, that shall include the following 
elements in a format prescribed by the Administrator:
    (i) The name, authorized account representative identification 
number, and telephone number of the designated representative of the 
opt-in source;
    (ii) The account identification number in the Allowance Tracking 
System of the source that includes the opt-in source;
    (iii) The opt-in source's annual utilization for the calendar year, 
as defined under paragraph (a)(1) of this section, and the revised 
annual utilization, submitted under paragraph (c)(2)(i)(B) of this 
section and adjusted under paragraph (c)(2)(iii) of this section, for 
the two immediately preceding calendar years;
    (iv) The opt-in source's average utilization for the calendar year, 
as defined under paragraph (a)(2) of this section;
    (v) The difference between the opt-in source's average utilization 
and its baseline;
    (vi) The number of allowances that shall be deducted, if any, using 
the formula in paragraph (b)(2)(i) of this section and the supporting 
calculations;
    (2) Confirmation report. (i) If the annual compliance certification 
report for an opt-in source includes estimates of any reduction in heat 
input resulting from improved efficiency as defined under paragraph 
(a)(1)(i) of this section, the designated representative shall submit, 
by July 1 of the year in which the annual compliance certification 
report was submitted, a confirmation report, concerning the calendar 
year covered by the annual compliance certification report. The 
Administrator may grant, for good cause shown, an extension of the time 
to file the confirmation report. The confirmation report shall include 
the following elements in a format prescribed by the Administrator:
    (A) Verified reduction in heat input. Any verified kwh savings or 
any verified steam savings from demand side measures that improve the 
efficiency of electricity or steam consumption, any verified reduction 
in the heat rate at the opt-in source, or any verified improvement in 
the efficiency of steam production at the opt-in source achieved and the 
verified corresponding reduction in heat input for the calendar year 
that resulted.
    (B) Revised annual utilization. The opt-in source's annual 
utilization for the calendar year as provided under paragraph 
(c)(1)(iii) of this section, recalculated using the verified reduction 
in heat input for the calendar year under paragraph (c)(2)(i)(A) of this 
section.
    (C) Revised average utilization. The opt-in source's average 
utilization as provided under paragraph (c)(1)(iv) of this section, 
recalculated using the verified reduction in heat input for the calendar 
year under paragraph (c)(2)(i)(A) of this section.
    (D) Recalculation of reduced utilization. The difference between the 
opt-in source's recalculated average utilization and its baseline.
    (E) Allowance adjustment. The number of allowances that should be 
credited or deducted using the formulas in paragraphs (c)(2)(iii)(C) and 
(D) of this section and the supporting calculations; and the number of 
adjusted allowances remaining using the formula in paragraph 
(c)(2)(iii)(E) of this section and the supporting calculations.
    (ii) Documentation. (A) For all figures under paragraphs 
(c)(2)(i)(A) of this section, the opt-in source must provide as part of 
the confirmation report, documentation (which may follow the EPA 
Conservation Verification Protocol) verifying the figures to the 
satisfaction of the Administrator.
    (B) Notwithstanding paragraph (c)(2)(i)(A) of this section, where 
two or more opt-in sources, or two or more opt-in sources and Phase I 
units include in the confirmation report under paragraph (c)(2) of this 
section or Sec. 72.91(b) of this chapter the verified kilowatt hour 
savings or steam savings defined under paragraph (c)(2)(i)(A) of

[[Page 196]]

this section, for the calendar year, from the same specific measures:
    (1) The designated representatives of all such opt-in sources and 
Phase I units shall submit with their confirmation reports a 
certification signed by all such designated representatives. The 
certification shall apportion the total kilowatt hour savings or steam 
savings as defined under paragraph (c)(2)(i)(A) of this section for the 
calendar year among such opt-in sources and Phase I units.
    (2) Each designated representative shall include in the opt-in 
source's confirmation report only its share of the verified reduction in 
heat input as defined under paragraph (c)(2)(i)(A) of this section for 
the calendar year under the certification under paragraph 
(c)(2)(ii)(B)(1) of this section.
    (iii) Determination of reduced utilization based on confirmation 
report. (A) If an opt-in source must submit a confirmation report as 
specified under paragraph (c)(2) of this section, the Administrator, 
upon such submittal, will adjust his or her determination of reduced 
utilization for the calendar year for the opt-in source. Such adjustment 
will include the recalculation of both annual utilization and average 
utilization, using verified reduction in heat input as defined under 
paragraph (c)(2)(i)(A) of this section for the calendar year instead of 
the previously estimated values.
    (B) Estimates confirmed. If the total, included in the confirmation 
report, of the amounts of verified reduction in the opt-in source's heat 
input equals the total estimated in the opt-in source's annual 
compliance certification report for the calendar year, then the 
designated representative shall include in the confirmation report a 
statement indicating that is true.
    (C) Underestimate. If the total, included in the confirmation 
report, of the amounts of verified reduction in the opt-in source's heat 
input is greater than the total estimated in the opt-in source's annual 
compliance certification report for the calendar year, then the 
designated representative shall include in the confirmation report the 
number of allowances to be credited to the compliance account of the 
source that includes the opt-in source calculated using the following 
formula:

Allowances credited for the calendar year in which the reduced 
utilization occurred =
[GRAPHIC] [TIFF OMITTED] TR04AP95.019

where,

Average Utilizationestimate = the average utilization of the 
          opt-in source as defined under paragraph (a)(2) of this 
          section, calculated using the estimated reduction in the opt-
          in source's heat input under (a)(1) of this section, and 
          submitted in the annual compliance certification report for 
          the calendar year.
Average Utilizationverified = the average utilization of the 
          opt-in source as defined under paragraph (a)(2) of this 
          section, calculated using the verified reduction in the opt-in 
          source's heat input as submitted under paragraph (c)(2)(i)(A) 
          of this section by the designated representative in the 
          confirmation report.

    (D) Overestimate. If the total of the amounts of verified reduction 
in the opt-in source's heat input included in the confirmation report is 
less than the total estimated in the opt-in source's annual compliance 
certification report for the calendar year, then the designated 
representative shall include in the confirmation report the number of 
allowances to be deducted from the compliance account of the source that 
includes the opt-in source, which equals the absolute value of the 
result of the formula for allowances credited under paragraph 
(c)(2)(iii)(C) of this section.
    (E) Adjusted allowances remaining. Unless paragraph (c)(2)(iii)(B) 
of this section applies, the designated representative shall include in 
the confirmation report the adjusted amount of allowances that would 
have been held in the

[[Page 197]]

compliance account of the source that includes the opt-in source if the 
deductions made under Sec. 73.35(b) of this chapter had been based on 
the verified, rather than the estimated, reduction in the opt-in 
source's heat input, calculated as follows:
[GRAPHIC] [TIFF OMITTED] TR04AP95.020

where:

``Allowances held after deduction'' shall be the amount of allowances 
          held in the compliance account of the source that includes the 
          opt-in source after deduction of allowances was made under 
          Sec. 73.35(b) of this chapter based on the annual compliance 
          certification report.
``Excess emissions'' shall be the amount (if any) of excess emissions 
          determined under Sec. 73.35(d) for the calendar year based on 
          the annual compliance certification report. ``Allowances 
          credited'' shall be the amount of allowances calculated under 
          paragraph (c)(2)(iii)(C) of this section.
``Allowances deducted'' shall be the amount of allowances calculated 
          under paragraph (c)(2)(iii)(D) of this section.

    (1) If the result of the formula for ``adjusted amount of 
allowances'' is negative, the absolute value of the result constitutes 
excess emissions of sulfur dioxide. If the result is positive, there are 
no excess emissions of sulfur dioxide.
    (2) If the amount of excess emissions of sulfur dioxide calculated 
under ``adjusted amount of allowances'' differs from the amount of 
excess emissions of sulfur dioxide determined under Sec. 73.35 of this 
chapter based on the annual compliance certification report, then the 
designated representative shall include in the confirmation report a 
demonstration of:
    (i) The number of allowances that should be deducted to offset any 
increase in excess emissions or returned to the account for any decrease 
in excess emissions; and
    (ii) The amount of the excess emissions penalty (excluding interest) 
that should be paid or returned to the account for the change in excess 
emissions.
    (3) The Administrator will deduct immediately from the compliance 
account of the source that includes the opt-in source the amount of 
allowances that he or she determines is necessary to offset any increase 
in excess emissions or will return immediately to the compliance account 
of the source that includes the opt-in source the amount of allowances 
that he or she determines is necessary to account for any decrease in 
excess emissions.
    (4) The designated representative may identify the serial numbers of 
the allowances to be deducted or returned. In the absence of such 
identification, the deduction will be on a first-in, first-out basis 
under Sec. 73.35(c)(2) of this chapter and the identification of 
allowances returned will be at the Administrator's discretion.
    (5) If the designated representative of an opt-in source fails to 
submit on a timely basis a confirmation report, in accordance with 
paragraph (c)(2) of this section, with regard to the estimate of 
reductions in heat input as defined under paragraph (c)(2)(i)(A) of this 
section, then the Administrator will reject such estimate and correct it 
to equal zero in the opt-in source's annual compliance certification 
report that includes that estimate. The Administrator will deduct 
immediately, on a first-in, first-out basis under Sec. 73.35(c)(2) of 
this chapter, the amount of allowances that he or she determines is 
necessary to offset any increase in excess emissions of sulfur dioxide 
that results from the correction and will require the owners and 
operators of the opt-in source to pay an excess emission penalty in 
accordance with part 77 of this chapter.
    (F) If the opt-in source is governed by an approved thermal energy 
plan under Sec. 74.47 and if the opt-in source must

[[Page 198]]

submit a confirmation report as specified under paragraph (c)(2) of this 
section, the adjusted amount of allowances that should remain in the 
compliance account of the source that includes the opt-in source shall 
be calculated as follows:

Adjusted amount of allowances =
[GRAPHIC] [TIFF OMITTED] TR16AP98.027

where,

``Allowances allocated or acquired'' shall be the number of allowances 
          held in the compliance account of the source that includes the 
          opt-in source at the allowance transfer deadline plus the 
          number of allowances transferred for the previous calendar 
          year to all replacement units under an approved thermal energy 
          plan in accordance with Sec. 74.47(a)(6).
``Tons emitted'' shall be the total tons of sulfur dioxide emitted by 
          the opt-in source during the calendar year, as reported in 
          accordance with subpart F of this part for combustion sources.
``Allowances transferred to all replacement units'' shall be the sum of 
          allowances transferred to all replacement units under an 
          approved thermal energy plan in accordance with Sec. 74.47 
          and adjusted by the Administrator in accordance with Sec. 
          74.47(d)(2).
``Allowances deducted for reduced utilization'' shall be the total 
          number of allowances deducted for reduced utilization as 
          calculated in accordance with this section including any 
          adjustments required under paragraph (c)(iii)(E) of this 
          section.

[60 FR 17115, Apr. 4, 1995, as amended at 63 FR 18841, Apr. 16, 1998; 70 
FR 25337, May 12, 2005]



Sec. 74.45  Reduced utilization for process sources. [Reserved]



Sec. 74.46  Opt-in source permanent shutdown, reconstruction,
or change in affected status.

    (a) Notification. (1) When an opt-in source has permanently shutdown 
during the calendar year, the designated representative shall notify the 
Administrator of the date of shutdown, within 30 days of such shutdown.
    (2) When an opt-in source has undergone a modification that 
qualifies as a reconstruction as defined in Sec. 60.15 of this chapter, 
the designated representative shall notify the Administrator of the date 
of completion of the reconstruction, within 30 days of such completion.
    (3) When an opt-in source becomes an affected unit under Sec. 72.6 
of this chapter, the designated representative shall notify the 
Administrator of such change in the opt-in source's affected status 
within 30 days of such change.
    (b) Administrator's action. (1) The Administrator will terminate the 
opt-in source's opt-in permit and deduct allowances as provided below in 
the following circumstances:
    (i) When an opt-in source has permanently shutdown. The 
Administrator shall deduct allowances equal in number to and with the 
same or earlier compliance use date as those allocated to the opt-in 
source under Sec. 74.40 for the calendar year in which the shut down 
occurs and for all future years following the year in which the shut 
down occurs; or
    (ii) When an opt-in source has undergone a modification that 
qualifies as a reconstruction as defined in Sec. 60.15 of this chapter. 
The Administrator shall deduct allowances equal in number to and with 
the same or earlier compliance use date as those allocated to the opt-in 
source under Sec. 74.40 for the calendar year in which the 
reconstruction is completed and all future years following the year in 
which the reconstruction is completed; or
    (iii) When an opt-in source becomes an affected unit under Sec. 
72.6 of this chapter. The Administrator shall deduct allowances equal in 
number to and with the same or earlier compliance use date as those 
allocated to the

[[Page 199]]

opt-in source under Sec. 74.40 for the calendar year in which the opt-
in source becomes affected under Sec. 72.6 of this chapter and all 
future years following the calendar year in which the opt-in source 
becomes affected under Sec. 72.6; or
    (iv) When an opt-in source does not renew its opt-in permit. The 
Administrator shall deduct allowances equal in number to and with the 
same or earlier compliance use date as those allocated to the opt-in 
source under Sec. 74.40 for the calendar year in which the opt-in 
source's opt-in permit expires and all future years following the year 
in which the opt-in source's opt-in permit expires.
    (2) [Reserved]

[60 FR 17115, Apr. 4, 1995, as amended at 70 FR 25337, May 12, 2005]



Sec. 74.47  Transfer of allowances from the replacement of thermal
energy--combustion sources.

    (a) Thermal energy plan--(1) General provisions. The designated 
representative of an opt-in source that seeks to qualify for the 
transfer of allowances based on the replacement of thermal energy by a 
replacement unit shall submit a thermal energy plan subject to the 
requirements of Sec. 72.40(b) of this chapter for multi-unit compliance 
options and this section. The effective period of the thermal energy 
plan shall begin at the start of the calendar quarter (January 1, April 
1, July 1, or October 1) for which the plan is approved and end December 
31 of the last full calendar year for which the opt-in permit containing 
the plan is in effect.
    (2) Applicability. This section shall apply to any designated 
representative of an opt-in source and any designated representative of 
each replacement unit seeking to transfer allowances based on the 
replacement of thermal energy.
    (3) Contents. Each thermal energy plan shall contain the following 
elements in a format prescribed by the Administrator:
    (i) The calendar year and quarter that the thermal energy plan takes 
effect, which shall be the first year and quarter the replacement 
unit(s) will replace thermal energy of the opt-in source;
    (ii) The name, authorized account representative identification 
number, and telephone number of the designated representative of the 
opt-in source;
    (iii) The name, authorized account representative identification 
number, and telephone number of the designated representative of each 
replacement unit;
    (iv) The account identification number in the Allowance Tracking 
System of the source that includes the opt-in source;
    (v) The account identification number in the Allowance Tracking 
System of each source that includes a replacement unit;
    (vi) The type of fuel used by each replacement unit;
    (vii) The allowable SO2 emissions rate, expressed in lbs/
mmBtu, of each replacement unit for the calendar year for which the plan 
will take effect. When a thermal energy plan is renewed in accordance 
with paragraph (a)(9) of this section, the allowable SO2 
emission rate at each replacement unit will be the most stringent 
federally enforceable allowable SO2 emissions rate applicable 
at the time of renewal for the calendar year for which the renewal will 
take effect. This rate will not be annualized;
    (viii) The estimated annual amount of total thermal energy to be 
reduced at the opt-in source, including all energy flows (steam, gas, or 
hot water) used for any process or in any heating or cooling 
application, and, for a plan starting April 1, July 1, or October 1, 
such estimated amount of total thermal energy to be reduced starting 
April 1, July 1, or October 1 respectively and ending on December 31;
    (ix) The estimated amount of total thermal energy at each 
replacement unit for the calendar year prior to the year for which the 
plan is to take effect, including all energy flows (steam, gas, or hot 
water) used for any process or in any heating or cooling application, 
and, for a plan starting April 1, July 1, or October 1, such estimated 
amount of total thermal energy for the portion of such calendar year 
starting April 1, July 1, or October 1 respectively;

[[Page 200]]

    (x) The estimated annual amount of total thermal energy at each 
replacement unit after replacing thermal energy at the opt-in source, 
including all energy flows (steam, gas, or hot water) used for any 
process or in any heating or cooling application, and, for a plan 
starting April 1, July 1, or October 1, such estimated amount of total 
thermal energy at each replacement unit after replacing thermal energy 
at the opt-in source starting April 1, July 1, or October 1 respectively 
and ending December 31;
    (xi) The estimated annual amount of thermal energy at each 
replacement unit, including all energy flows (steam, gas, or hot water) 
used for any process or in any heating or cooling application, replacing 
thermal energy at the opt-in source, and, for a plan starting April 1, 
July 1, or October 1, such estimated amount of thermal energy replacing 
thermal energy at the opt-in source starting April 1, July 1, or October 
1 respectively and ending December 31;
    (xii) The estimated annual total fuel input at each replacement unit 
after replacing thermal energy at the opt-in source and, for a plan 
starting April 1, July 1, or October 1, such estimated total fuel input 
after replacing thermal energy at the opt-in source starting April 1, 
July 1, or October 1 respectively and ending December 31;
    (xiii) The number of allowances calculated under paragraph (b) of 
this section that the opt-in source will transfer to each replacement 
unit represented in the thermal energy plan.
    (xiv) The estimated number of allowances to be deducted for reduced 
utilization under Sec. 74.44;
    (xv) Certification that each replacement unit has entered into a 
legally binding steam sales agreement to provide the thermal energy, as 
calculated under paragraph (a)(3)(xi) of this section, that it is 
replacing for the opt-in source. The designated representative of each 
replacement unit shall maintain and make available to the Administrator, 
at the Administrator's request, copies of documents demonstrating that 
the replacement unit is replacing the thermal energy at the opt-in 
source.
    (4) Submission. The designated representative of the opt-in source 
seeking to qualify for the transfer of allowances based on the 
replacement of thermal energy shall submit a thermal energy plan to the 
permitting authority by no later than six months prior to the first 
calendar quarter for which the plan is to be in effect. The thermal 
energy plan shall be signed and certified by the designated 
representative of the opt-in source and each replacement unit covered by 
the plan.
    (5) Retirement of opt-in source upon enactment of plan. (i) If the 
opt-in source will be permanently retired as of the effective date of 
the thermal energy plan, the opt-in source shall not be required to 
monitor its emissions upon retirement, consistent with Sec. 75.67 of 
this chapter, provided that the following requirements are met:
    (A) The designated representative of the opt-in source shall include 
in the plan a request for an exemption from the requirements of part 75 
in accordance with Sec. 75.67 of this chapter and shall submit the 
following statement: ``I certify that the opt-in source (``is'' or 
``will be'', as applicable) permanently retired on the date specified in 
this plan and will not emit any sulfur dioxide or nitrogen oxides after 
such date.''
    (B) The opt-in source shall not emit any sulfur dioxide or nitrogen 
oxides after the date specified in the plan.
    (ii) Notwithstanding the monitoring exemption discussed in paragraph 
(a)(5)(i) of this section, the designated representative for the opt-in 
source shall submit the annual compliance certification report provided 
under paragraph (d) of this section.
    (6) Administrator's action. If the permitting authority approves a 
thermal energy plan, the Administrator will annually transfer allowances 
to the compliance account of each source that includes a replacement 
unit, as provided in the approved plan.
    (7) Incorporation, modification and renewal of a thermal energy 
plan. (i) An approved thermal energy plan, including any revised or 
renewed plan that is approved, shall be incorporated into both the opt-
in permit for the opt-in source and the Acid Rain permit for each 
replacement unit governed by the

[[Page 201]]

plan. Upon approval, the thermal energy plan shall be incorporated into 
the Acid Rain permit for each replacement unit pursuant to the 
requirements for administrative permit amendments under Sec. 72.83 of 
this chapter.
    (ii) In order to revise an opt-in permit to add an approved thermal 
energy plan or to change an approved thermal energy plan, the designated 
representative of the opt-in source shall submit a plan or a revised 
plan under paragraph (a)(4) of this section and meet the requirements 
for permit revisions under Sec. 72.80 and either Sec. 72.81 or Sec. 
72.82 of this chapter.
    (8) Termination of plan. (i) A thermal energy plan shall be in 
effect until the earlier of the expiration of the opt-in permit for the 
opt-in source or the year for which a termination of the plan takes 
effect under paragraph (a)(8)(ii) of this section.
    (ii) Termination of plan by opt-in source and replacement units. A 
notification to terminate a thermal energy plan in accordance with Sec. 
72.40(d) of this chapter shall be submitted no later than December 1 of 
the calendar year for which the termination is to take effect.
    (iii) If the requirements of paragraph (a)(8)(ii) of this section 
are met and upon revision of the opt-in permit of the opt-in source and 
the Acid Rain permit of each replacement unit governed by the thermal 
energy plan to terminate the plan pursuant to Sec. 72.83 of this 
chapter, the Administrator will adjust the allowances for the opt-in 
source and the replacement units to reflect the transfer back to the 
opt-in source of the allowances transferred from the opt-in source under 
the plan for the year for which the termination of the plan takes 
effect.
    (9) Renewal of thermal energy plan. The designated representative of 
an opt-in source may renew the thermal energy plan as part of its opt-in 
permit renewal in accordance with Sec. 74.19.
    (b) Calculation of transferable allowances--(1) Qualifying thermal 
energy. The amount of thermal energy credited towards the transfer of 
allowances based on the replacement of thermal energy shall equal the 
qualifying thermal energy and shall be calculated for each replacement 
unit as follows:
[GRAPHIC] [TIFF OMITTED] TR04AP95.022

    (2) Fuel associated with qualifying thermal energy. The fuel 
associated with the qualifying thermal energy at each replacement unit 
shall be calculated as follows:
[GRAPHIC] [TIFF OMITTED] TR04AP95.023

where,

``Qualifying thermal energy'' for the replacement unit is as defined in 
          paragraph (b)(1) of this section;
``Efficiency constant'' for the replacement unit

    = 0.85, where the replacement unit is a boiler
    = 0.80, where the replacement unit is a cogenerator

    (3) Allowances transferable from the opt-in source to each 
replacement unit. The number of allowances transferable from the opt-in 
source to each replacement unit for the replacement of thermal energy is 
calculated as follows:

[[Page 202]]

[GRAPHIC] [TIFF OMITTED] TR04AP95.024

where,

``Allowable SO2 emission rate'' for the replacement unit is 
          as defined in paragraph (a)(3)(vii) of this section;
``Fuel associated with qualifying thermal energy'' is as defined in 
          paragraph (b)(2) of this section;

    (c) Transfer prohibition. The allowances transferred from the opt-in 
source to each replacement unit shall not be transferred from the 
compliance account of the source that includes the replacement unit of 
the replacement unit to any other Allowance Tracking System account.
    (d) Compliance--(1) Annual compliance certification report. (i) As 
required for all opt-in sources, the designated representative of the 
opt-in source covered by a thermal energy plan must submit an opt-in 
utilization report for the calendar year as part of its annual 
compliance certification report under Sec. 74.44(c)(1).
    (ii) The designated representative of an opt-in source must submit a 
thermal energy compliance report for the calendar year as part of the 
annual compliance certification report, which must include the following 
elements in a format prescribed by the Administrator:
    (A) The name, authorized account representative identification 
number, and telephone number of the designated representative of the 
opt-in source;
    (B) The name, authorized account representative identification 
number, and telephone number of the designated representative of each 
replacement unit;
    (C) The account identification number in the Allowance Tracking 
System of the source that includes the opt-in source;
    (D) The account identification number in the Allowance Tracking 
System of each source that includes a replacement unit;
    (E) The actual amount of total thermal energy reduced at the opt-in 
source during the calendar year, including all energy flows (steam, gas, 
or hot water) used for any process or in any heating or cooling 
application;
    (F) The actual amount of thermal energy at each replacement unit, 
including all energy flows (steam, gas, or hot water) used for any 
process or in any heating or cooling application, replacing the thermal 
energy at the opt-in source;
    (G) The actual amount of total thermal energy at each replacement 
unit after replacing thermal energy at the opt-in source, including all 
energy flows (steam, gas, or hot water) used for any process or in any 
heating or cooling application;
    (H) Actual total fuel input at each replacement unit as determined 
in accordance with part 75 of this chapter;
    (I) Calculations of allowance adjustments to be performed by the 
Administrator in accordance with paragraph (d)(2) of this section.
    (2) Allowance adjustments by Administrator. (i) The Administrator 
will adjust the number of allowances in the compliance account for each 
source that includes the opt-in source or a replacement unit to reflect 
any changes between the estimated values submitted in the thermal energy 
plan pursuant to paragraph (a) of this section and the actual values 
submitted in the thermal energy compliance report pursuant to paragraph 
(d) of this section. The values to be considered for this adjustment 
include:
    (A) The number of allowances transferable by the opt-in source to 
each replacement unit, calculated in paragraph (b) of this section using 
the actual, rather than estimated, thermal energy at the replacement 
unit replacing thermal energy at the opt-in source.
    (B) The number of allowances deducted from the compliance account of 
the source that includes the opt-in source, calculated under Sec. 
74.44(b)(2).
    (ii) If the opt-in source includes in the opt-in utilization report 
under Sec. 74.44 estimates for reductions in heat

[[Page 203]]

input, then the Administrator will adjust the number of allowances in 
the compliance account for each source that includes the opt-in source 
or a replacement unit to reflect any differences between the estimated 
values submitted in the opt-in utilization report and the actual values 
submitted in the confirmation report pursuant to Sec. 74.44(c)(2).
    (3) Liability. The owners and operators of an opt-in source or a 
replacement unit governed by an approved thermal energy plan shall be 
liable for any violation of the plan or this section at that opt-in 
source or replacement unit that is governed by the thermal energy plan, 
including liability for fulfilling the obligations specified in part 77 
of this chapter and section 411 of the Act.

[60 FR 17115, Apr. 4, 1995, as amended at 63 FR 18841, 18842, Apr. 16, 
1998; 70 FR 25337, May 12, 2005]



Sec. 74.48  Transfer of allowances from the replacement of thermal 
energy--process sources. [Reserved]



Sec. 74.49  Calculation for deducting allowances.

    (a) Allowance deduction formula. The following formula shall be used 
to determine the total number of allowances to be deducted for the 
calendar year from the allowances held in the compliance account of a 
source that includes an opt-in source as of the allowance transfer 
deadline applicable to that year:

Total allowances deducted = Tons emitted + Allowances deducted for 
reduced utilization where:

    (1)(i) Except as provided in paragraph (a)(1)(ii) of this section, 
``Tons emitted'' shall be the total tons of sulfur dioxide emitted by 
the opt-in source during the calendar year, as reported in accordance 
with subpart F of this part for combustion sources or subpart G of this 
part for process sources.
    (ii) If the effective date of the opt-in source's permit took effect 
on a date other than January 1, ``Tons emitted'' for the first calendar 
year shall be the total tons of sulfur dioxide emitted by the opt-in 
source during the calendar quarters for which the opt-in source's opt-in 
permit is effective, as reported in accordance with subpart F of this 
part for combustion sources or subpart G of this part for process 
sources.
    (2) ``Allowances deducted for reduced utilization'' shall be the 
total number of allowances deducted for reduced utilization as 
calculated in accordance with Sec. 74.44 for combustion sources or 
Sec. 74.45 for process sources.
    (b) [Reserved]

[60 FR 17115, Apr. 4, 1995, as amended at 70 FR 25337, May 12, 2005]



Sec. 74.50  Deducting opt-in source allowances from ATS accounts.

    (a)(1) Deduction of allowances. The Administrator may deduct any 
allowances that were allocated to an opt-in source under Sec. 74.40 by 
removing, from any Allowance Tracking System accounts in which they are 
held, the allowances in an amount specified in paragraph (d) of this 
section, under the following circumstances:
    (i) When the opt-in source has permanently shut down; or
    (ii) When the opt-in source has been reconstructed; or
    (iii) When the opt-in source becomes an affected unit under Sec. 
72.6 of this chapter; or
    (iv) When the opt-in source fails to renew its opt-in permit.
    (2) An opt-in allowance may not be deducted under paragraph (a)(1) 
of this section from any Allowance Tracking System Account other than 
the account of the source that includes opt-in source allocated such 
allowance:
    (i) After the Administrator has completed the process of recordation 
as set forth in Sec. 73.34(a) of this chapter following the deduction 
of allowances from the compliance account of the source that includes 
the opt-in source for the year for which such allowance may first be 
used; or
    (ii) If the opt-in source includes in the annual compliance 
certification report estimates of any reduction in heat input resulting 
from improved efficiency under Sec. 74.44(a)(1)(i), after the 
Administrator has completed action on the confirmation report concerning 
such estimated reduction pursuant to Sec. 74.44(c)(2)(iii)(E)(3), (4), 
and (5) for the year for which such allowance may first be used.

[[Page 204]]

    (b) Method of deduction. The Administrator will deduct allowances 
beginning with those allowances with the latest recorded date of 
transfer out of the compliance account of the source that includes the 
opt-in source.
    (c) Notification of deduction. When allowances are deducted, the 
Administrator will send a written notification to the authorized account 
representative of each Allowance Tracking System account from which 
allowances were deducted. The notification will state:
    (1) The serial numbers of all allowances deducted from the account,
    (2) The reason for deducting the allowances, and
    (3) The date of deduction of the allowances.
    (d) Amount of deduction. The Administrator may deduct allowances in 
accordance with paragraph (a) of this section in an amount required to 
offset any excess emissions in accordance with part 77 of this chapter 
and when the source that includes the opt-in source does not hold 
allowances equal in number to and with the same or earlier compliance 
use date for the calendar years specified under Sec. 74.46(b)(1) (i) 
through (iv) in an amount required to be deducted under Sec. 
74.46(b)(1) (i) through (iv).

[60 FR 17115, Apr. 4, 1995, as amended at 63 FR 18842, Apr. 16, 1998; 70 
FR 25337, May 12, 2005]



           Subpart F_Monitoring Emissions: Combustion Sources



Sec. 74.60  Monitoring requirements.

    (a) Monitoring requirements for combustion sources. The owner or 
operator of each combustion source shall meet all of the requirements 
specified in part 75 of this chapter for the owners and operators of an 
affected unit to install, certify, operate, and maintain a continuous 
emission monitoring system, an excepted monitoring system, or an 
approved alternative monitoring system in accordance with part 75 of 
this chapter.
    (b) Monitoring requirements for opt-in sources. The owner or 
operator of each opt-in source shall install, certify, operate, and 
maintain a continuous emission monitoring system, an excepted monitoring 
system, an approved alternative monitoring system in accordance with 
part 75 of this chapter.



Sec. 74.61  Monitoring plan.

    (a) Monitoring plan. The designated representative of a combustion 
source shall meet all of the requirements specified under part 75 of 
this chapter for a designated representative of an affected unit to 
submit to the Administrator a monitoring plan that includes the 
information required in a monitoring plan under Sec. 75.53 of this 
chapter. This monitoring plan shall be submitted as part of the 
combustion source's opt-in permit application under Sec. 74.14 of this 
part.
    (b) [Reserved]

Subpart G--Monitoring Emissions: Process Sources [Reserved]



PART 75_CONTINUOUS EMISSION MONITORING--Table of Contents



                            Subpart A_General

Sec.
75.1 Purpose and scope.
75.2 Applicability.
75.3 General Acid Rain Program provisions.
75.4 Compliance dates.
75.5 Prohibitions.
75.6 Incorporation by reference.
75.7-75.8 [Reserved]

                     Subpart B_Monitoring Provisions

75.10 General operating requirements.
75.11 Specific provisions for monitoring SO2 emissions.
75.12 Specific provisions for monitoring NOX emission rate.
75.13 Specific provisions for monitoring CO2 emissions.
75.14 Specific provisions for monitoring opacity.
75.15 [Reserved]
75.16 Special provisions for monitoring emissions from common, bypass, 
          and multiple stacks for SO2 emissions and heat 
          input determinations.
75.17 Specific provisions for monitoring emissions from common, bypass, 
          and multiple stacks for NOX emission rate.
75.18 Specific provisions for monitoring emissions from common and by-
          pass stacks for opacity.
75.19 Optional SO2, NOX, and CO2 
          emissions calculation for low mass emissions (LME) units.

[[Page 205]]

            Subpart C_Operation and Maintenance Requirements

75.20 Initial certification and recertification procedures.
75.21 Quality assurance and quality control requirements.
75.22 Reference test methods.
75.23 Alternatives to standards incorporated by reference.
75.24 Out-of-control periods and adjustment for system bias.

             Subpart D_Missing Data Substitution Procedures

75.30 General provisions.
75.31 Initial missing data procedures.
75.32 Determination of monitor data availability for standard missing 
          data procedures.
75.33 Standard missing data procedures for SO2, 
          NOX, and flow rate.
75.34 Units with add-on emission controls.
75.35 Missing data procedures for CO2.
75.36 Missing data procedures for heat input rate determinations.
75.37 Missing data procedures for moisture.
75.38-75.39 [Reserved]

                Subpart E_Alternative Monitoring Systems

75.40 General demonstration requirements.
75.41 Precision criteria.
75.42 Reliability criteria.
75.43 Accessibility criteria.
75.44 Timeliness criteria.
75.45 Daily quality assurance criteria.
75.46 Missing data substitution criteria.
75.47 Criteria for a class of affected units.
75.48 Petition for an alternative monitoring system.

                  Subpart F_Recordkeeping Requirements

75.50-75.52 [Reserved]
75.53 Monitoring plan.
75.54-75.56 [Reserved]
75.57 General recordkeeping provisions.
75.58 General recordkeeping provisions for specific situations.
75.59 Certification, quality assurance, and quality control record 
          provisions.

                    Subpart G_Reporting Requirements

75.60 General provisions.
75.61 Notifications.
75.62 Monitoring plan submittals.
75.63 Initial certification or recertification application.
75.64 Quarterly reports.
75.65 Opacity reports.
75.66 Petitions to the Administrator.
75.67 Retired units petitions.

                 Subpart H_NOX Mass Emissions Provisions

75.70 NOX mass emissions provisions.
75.71 Specific provisions for monitoring NOX and heat input 
          for the purpose of calculating NOX mass emissions.
75.72 Determination of NOX mass emissions for common stack 
          and multiple stack configurations.
75.73 Recordkeeping and reporting.
75.74 Annual and ozone season monitoring and reporting requirements.
75.75 Additional ozone season calculation procedures for special 
          circumstances.

Appendix A to Part 75--Specifications and Test Procedures
Appendix B to Part 75--Quality Assurance and Quality Control Procedures
Appendix C to Part 75--Missing Data Estimation Procedures
Appendix D to Part 75--Optional SO2 Emissions Data Protocol 
          for Gas-Fired and Oil-Fired Units
Appendix E to Part 75--Optional NOX Emissions Estimation 
          Protocol for Gas-Fired Peaking Units and Oil-Fired Peaking 
          Units
Appendix F to Part 75--Conversion Procedures
Appendix G to Part 75--Determination of CO2 Emissions
Appendix H to Part 75--Revised Traceability Protocol No. 1 [Reserved]
Appendix I to Part 75--Optional F--factor/Fuel Flow Method [Reserved]
Appendix J to Part 75--Compliance Dates for Revised Recordkeeping 
          Requirements and Missing Data Procedures [Reserved]

    Authority: 42 U.S.C. 7601 and 7651K, and 7651K note.

    Source: 58 FR 3701, Jan. 11, 1993, unless otherwise noted.

    Editorial Note: Nomenclature changes to part 75 appear at 67 FR 
40476, June 12, 2002.



                            Subpart A_General



Sec. 75.1  Purpose and scope.

    (a) Purpose. The purpose of this part is to establish requirements 
for the monitoring, recordkeeping, and reporting of sulfur dioxide 
(SO2), nitrogen oxides (NOX), and carbon dioxide 
(CO2) emissions, volumetric flow, and opacity data from 
affected units under the Acid Rain Program pursuant to sections 412 and 
821 of the CAA, 42 U.S.C. 7401-7671q as amended by Public Law 101-549 
(November 15, 1990) [the Act]. In addition, this part sets forth 
provisions for the monitoring, recordkeeping, and

[[Page 206]]

reporting of NOX mass emissions with which EPA, individual 
States, or groups of States may require sources to comply in order to 
demonstrate compliance with a NOX mass emission reduction 
program, to the extent these provisions are adopted as requirements 
under such a program.
    (b) Scope. (1) The regulations established under this part include 
general requirements for the installation, certification, operation, and 
maintenance of continuous emission or opacity monitoring systems and 
specific requirements for the monitoring of SO2 emissions, 
volumetric flow, NOX emissions, opacity, CO2 
emissions and SO2 emissions removal by qualifying Phase I 
technologies. Specifications for the installation and performance of 
continuous emission monitoring systems, certification tests and 
procedures, and quality assurance tests and procedures are included in 
appendices A and B to this part. Criteria for alternative monitoring 
systems and provisions to account for missing data from certified 
continuous emission monitoring systems or approved alternative 
monitoring systems are also included in the regulation.
    (2) Statistical estimation procedures for missing data are included 
in appendix C to this part. Optional protocols for estimating 
SO2 mass emissions from gas-fired or oil-fired units and 
NOX emissions from gas-fired peaking or oil-fired peaking 
units are included in appendices D and E, respectively, to this part. 
Requirements for recording and recordkeeping of monitoring data and for 
quarterly electronic reporting also are specified. Procedures for 
conversion of monitoring data into units of the standard are included in 
appendix F to this part. Procedures for the monitoring and calculation 
of CO2 emissions are included in appendix G of this part.

[58 FR 3701, Jan. 11, 1993; 58 FR 34126, June 23, 1993; 58 FR 40747, 
July 30, 1993; 63 FR 57498, Oct. 27, 1999; 67 FR 40421, June 12, 2002]



Sec. 75.2  Applicability.

    (a) Except as provided in paragraphs (b) and (c) of this section, 
the provisions of this part apply to each affected unit subject to Acid 
Rain emission limitations or reduction requirements for SO2 
or NOX.
    (b) The provisions of this part do not apply to:
    (1) A new unit for which a written exemption has been issued under 
Sec. 72.7 of this chapter (any new unit that serves one or more 
generators with total nameplate capacity of 25 MWe or less and burns 
only fuels with a sulfur content of 0.05 percent or less by weight may 
apply to the Administrator for an exemption); or
    (2) Any unit not subject to the requirements of the Acid Rain 
Program due to operation of any paragraph of Sec. 72.6(b) of this 
chapter; or
    (3) An affected unit for which a written exemption has been issued 
under Sec. 72.8 of this chapter and an exception granted under Sec. 
75.67 of this part.
    (c) The provisions of this part apply to sources subject to a State 
or federal NOX mass emission reduction program, to the extent 
these provisions are adopted as requirements under such a program.

[58 FR 3701, Jan. 11, 1993, as amended at 58 FR 15716, Mar. 23, 1993; 60 
FR 26516, May 17, 1995; 63 FR 57499, Oct. 27, 1998; 70 FR 28678, May 18, 
2005; 76 FR 17306, Mar. 28, 2011]



Sec. 75.3  General Acid Rain Program provisions.

    The provisions of part 72, including the following, shall apply to 
this part:
    (a) Sec. 72.2 (Definitions);
    (b) Sec. 72.3 (Measurements, Abbreviations, and Acronyms);
    (c) Sec. 72.4 (Federal Authority);
    (d) Sec. 72.5 (State Authority);
    (e) Sec. 72.6 (Applicability);
    (f) Sec. 72.7 (New Unit Exemption);
    (g) Sec. 72.8 (Retired Units Exemption);
    (h) Sec. 72.9 (Standard Requirements);
    (i) Sec. 72.10 (Availability of Information); and
    (j) Sec. 72.11 (Computation of Time).

In addition, the procedures for appeals of decisions of the 
Administrator under this part are contained in part 78 of this chapter.



Sec. 75.4  Compliance dates.

    (a) The provisions of this part apply to each existing Phase I and 
Phase II unit on February 10, 1993. For substitution or compensating 
units that are

[[Page 207]]

so designated under the Acid Rain permit which governs that unit and 
contains the approved substitution or reduced utilization plan, pursuant 
to Sec. 72.41 or Sec. 72.43 of this chapter, the provisions of this 
part become applicable upon the issuance date of the Acid Rain permit. 
For combustion sources seeking to enter the Opt-in Program in accordance 
with part 74 of this chapter, the provisions of this part become 
applicable upon the submission of an opt-in permit application in 
accordance with Sec. 74.14 of this chapter. The provisions of this part 
for the monitoring, recording, and reporting of NOX mass 
emissions become applicable on the deadlines specified in the applicable 
State or federal NOX mass emission reduction program, to the 
extent these provisions are adopted as requirements under such a 
program. In accordance with Sec. 75.20, the owner or operator of each 
existing affected unit shall ensure that all monitoring systems required 
by this part for monitoring SO2, NOX, 
CO2, opacity, moisture and volumetric flow are installed and 
that all certification tests are completed no later than the following 
dates (except as provided in paragraphs (d) through (i) of this 
section):
    (1) For a unit listed in table 1 of Sec. 73.10(a) of this chapter, 
November 15, 1993.
    (2) For a substitution or a compensating unit that is designated 
under an approved substitution plan or reduced utilization plan pursuant 
to Sec. 72.41 or Sec. 72.43 of this chapter, or for a unit that is 
designated an early election unit under an approved NOX 
compliance plan pursuant to part 76 of this chapter, that is not 
conditionally approved and that is effective for 1995, the earlier of 
the following dates:
    (i) January 1, 1995; or
    (ii) 90 days after the issuance date of the Acid Rain permit (or 
date of approval of permit revision) that governs the unit and contains 
the approved substitution plan, reduced utilization plan, or 
NOX compliance plan.
    (3) For either a Phase II unit, other than a gas-fired unit or an 
oil-fired unit, or a substitution or compensating unit that is not a 
substitution or compensating unit under paragraph (a)(2) of this 
section: January 1, 1995.
    (4) For a gas-fired Phase II unit or an oil-fired Phase II unit, 
January 1, 1995, except that installation and certification tests for 
continuous emission monitoring systems for NOX and 
CO2 or excepted monitoring systems for NOX under 
appendix E or CO2 estimation under appendix G of this part 
shall be completed as follows:
    (i) For an oil-fired Phase II unit or a gas-fired Phase II unit 
located in an ozone nonattainment area or the ozone transport region, 
not later than July 1, 1995; or
    (ii) For an oil-fired Phase II unit or a gas-fired Phase II unit not 
located in an ozone nonattainment area or the ozone transport region, 
not later than January 1, 1996.
    (5) For combustion sources seeking to enter the Opt-in Program in 
accordance with part 74 of this chapter, the expiration date of a 
combustion source's opt-in permit under Sec. 74.14(e) of this chapter.
    (b) In accordance with Sec. 75.20, the owner or operator of each 
new affected unit shall ensure that all monitoring systems required 
under this part for monitoring of SO2, NOX, 
CO2, opacity, and volumetric flow are installed and all 
certification tests are completed on or before the later of the 
following dates:
    (1) January 1, 1995, except that for a gas-fired unit or oil-fired 
unit located in an ozone nonattainment area or the ozone transport 
region, the date for installation and completion of all certification 
tests for NOX and CO2 monitoring systems shall be 
July 1, 1995 and for a gas-fired unit or an oil-fired unit not located 
in an ozone nonattainment area or the ozone transport region, the date 
for installation and completion of all certification tests for 
NOX and CO2 monitoring systems shall be January 1, 
1996; or
    (2) 180 calendar days after the date the unit commences commercial 
operation, notice of which date shall be provided under subpart G of 
this part.
    (c) In accordance with Sec. 75.20, the owner or operator of any 
unit affected under any paragraph of Sec. 72.6(a)(3) (ii) through (vii) 
of this chapter shall ensure that all monitoring systems required under 
this part for monitoring

[[Page 208]]

of SO2, NOX, CO2, opacity, and 
volumetric flow are installed and all certification tests are completed 
on or before the later of the following dates:
    (1) January 1, 1995, except that for a gas-fired unit or oil-fired 
unit located in an ozone nonattainment area or the ozone transport 
region, the date for installation and completion of all certification 
tests for NOX and CO2 monitoring systems shall be 
July 1, 1995 and for a gas-fired unit or an oil-fired unit not located 
in an ozone nonattainment area or the ozone transport region, the date 
for installation and completion of all certification tests for 
NOX and CO2 monitoring systems shall be January 1, 
1996; or
    (2) 180 calendar days after the date on which the unit becomes 
subject to the requirements of the Acid Rain Program, notice of which 
date shall be provided under subpart G of this part.
    (d) This paragraph (d) applies to affected units under the Acid Rain 
Program and to units subject to a State or Federal pollutant mass 
emissions reduction program that adopts the emission monitoring and 
reporting provisions of this part. In accordance with Sec. 75.20, for 
an affected unit which, on the applicable compliance date, is either in 
long-term cold storage (as defined in Sec. 72.2 of this chapter) or is 
shut down as the result of a planned outage or a forced outage, thereby 
preventing the required continuous monitoring system certification tests 
from being completed by the compliance date, the owner or operator shall 
provide notice of such unit storage or outage in accordance with Sec. 
75.61(a)(3) or Sec. 75.61(a)(7), as applicable. For the planned and 
unplanned unit outages described in this paragraph (d), the owner or 
operator shall ensure that all of the continuous monitoring systems for 
SO2, NOX, CO2, opacity, and volumetric 
flow rate required under this part (or under the applicable State or 
Federal mass emissions reduction program) are installed and that all 
required certification tests are completed no later than 90 unit 
operating days or 180 calendar days (whichever occurs first) after the 
date that the unit recommences commercial operation, notice of which 
date shall be provided under Sec. 75.61(a)(3) or Sec. 75.61(a)(7), as 
applicable. The owner or operator shall determine and report 
SO2 concentration, NOX emission rate, 
CO2 concentration, and flow rate data (as applicable) for all 
unit operating hours after the applicable compliance date until all of 
the required certification tests are successfully completed, using 
either:
    (1) The maximum potential concentration of SO2 (as 
defined in section 2.1.1.1 of appendix A to this part), the maximum 
potential NOX emission rate, as defined in Sec. 72.2 of this 
chapter, the maximum potential flow rate, as defined in section 2.1.4.1 
of appendix A to this part, or the maximum potential CO2 
concentration, as defined in section 2.1.3.1 of appendix A to this part; 
or
    (2) The conditional data validation provisions of Sec. 75.20(b)(3); 
or
    (3) Reference methods under Sec. 75.22(b); or
    (4) Another procedure approved by the Administrator pursuant to a 
petition under Sec. 75.66.
    (e) In accordance with Sec. 75.20, if the owner or operator of an 
affected unit completes construction of a new stack or flue, or a flue 
gas desulfurization system or add-on NOX emission controls, 
after the applicable deadline in paragraph (a), (b), or (c) of this 
section:
    (1) Except as otherwise provided in paragraph (e)(3) of this 
section, the owner or operator shall ensure that all required 
certification and/or recertification and/or diagnostic tests of the 
monitoring systems required under this part (i.e., the SO2, 
NOX, CO2, O2, opacity, volumetric flow 
rate, and moisture monitoring systems, as applicable) are completed not 
later than 90 unit operating days or 180 calendar days (whichever occurs 
first) after:
    (i) For the event of construction of a new stack or flue, the date 
that emissions first exit to the atmosphere through the new stack or 
flue, notice of which date shall be provided under subpart G of this 
part; or
    (ii) For the event of installation of a flue gas desulfurization 
system or add-on NOX emission controls, the date that reagent 
is first injected into the flue gas desulfurization system or the

[[Page 209]]

add-on NOX emission controls, as applicable, notice of which 
date shall be provided under subpart G of this part.
    (2) The owner or operator shall determine and report, as applicable, 
SO2 concentration, NOX concentration, 
NOX emission rate, CO2 concentration, 
O2 concentration, volumetric flow rate, and moisture data for 
all unit or stack operating hours after emissions first pass through the 
new stack or flue, or reagent is first injected into the flue gas 
desulfurization system or add-on NOX emission controls, as 
applicable, until all required certification and/or recertification and/
or diagnostic tests are successfully completed, using:
    (i) Quality-assured data recorded by a previously-certified 
monitoring system for which the event requires no additional testing;
    (ii) The applicable missing data substitution procedures under 
Sec. Sec. 75.31 through 75.37;
    (iii) The conditional data validation procedures of Sec. 
75.20(b)(3), except that conditional data validation may, if necessary, 
be used for the entire window of time provided under paragraph (e)(1) of 
this section in lieu of the periods specified in Sec. 75.20(b)(3)(iv);
    (iv) Reference methods under Sec. 75.22(b);
    (v) For the event of installation of a flue gas desulfurization 
system or add-on NOX emission controls, quality-assured data 
recorded on the high measurement scale of the monitor that measures the 
pollutant being removed by the add-on emission controls (i.e., 
SO2 or NOX, as applicable), if, pursuant to 
section 2 of appendix A to this part, two spans and ranges are required 
for that monitor and if the high measurement scale of the monitor has 
been certified according to Sec. 75.20(c), section 6 of appendix A to 
this part, and, if applicable, paragraph (e)(4)(i) of this section. Data 
recorded on the certified high scale that ordinarily would be required 
to be recorded on the low scale, pursuant to section 2.1.1.4(g) or 
2.1.2.4(f) of appendix A to this part, may be reported as quality-
assured for a period not to exceed 60 unit or stack operating days after 
the date and hour that reagent is first injected into the control 
device, after which one or more of the options provided in paragraphs 
(e)(2)(ii), (e)(2)(iii), (e)(2)(iv) and (e)(2)(vi) of this section must 
be used to report SO2 or NOX concentration data 
(as applicable) for each operating hour in which these low emissions 
occur, until certification testing of the low scale of the monitor is 
successfully completed; or
    (vi) Another procedure approved by the Administrator pursuant to a 
petition under Sec. 75.66.
    (3) If a particular project involves both the event of new stack or 
flue construction and the event of installation of a flue gas 
desulfurization system or add-on NOX emission controls, the 
owner or operator shall either:
    (i) Complete all of the monitoring system certification and/or 
recertification and/or diagnostic testing requirements of both events 
within the window of time provided under paragraph (e)(1)(i) of this 
section; or
    (ii) Complete all of the monitoring system certification and/or 
recertification and/or diagnostic testing requirements of each event 
within the separate window of time applicable to such event provided 
under paragraph (e)(1) of this section.
    (4) For the project described in paragraph (e)(3) of this section, 
the emissions data from each CEMS installed on the new stack recorded in 
the interval of time starting on the date and hour on which emissions 
first exit to the atmosphere through the new stack and ending on the 
hour before the date and hour on which reagent is first injected into 
the control device may be reported as quality assured:
    (i) For the CEMS that includes the monitor that measures the 
pollutant being removed by the add-on emission controls (i.e., 
SO2 or NOX, as applicable):
    (A) Only if the relative accuracy test audit (RATA) of the high 
measurement scale of the monitor is successfully completed either prior 
to the date and hour of the first injection of reagent into the emission 
control device, or after that date and hour during a period when the 
control device is not operating, but still within the window of time 
provided under paragraph (e)(1)(i) of this section, and the rest of the 
certification tests required under Sec. 75.20(c) and section 6 of 
appendix A to this part

[[Page 210]]

for the high measurement scale of the monitor are successfully completed 
within the window of time provided under paragraph (e)(1)(i) of this 
section;
    (B) Beginning with:
    (1) The first unit or stack operating hour after successful 
completion of all of the certification tests in accordance with 
paragraph (e)(4)(i)(A) of this section; or
    (2) The hour of the probationary calibration error test (see Sec. 
75.20(b)(3)(ii)), if conditional data validation is used and all of the 
certification tests are successfully completed in accordance with 
paragraph (e)(4)(i)(A) of this section, with no test failures. If any 
required test is failed or aborted or is otherwise not in accordance 
with paragraph (e)(4)(i)(A) of this section, data validation shall be 
done according to Sec. 75.20(b)(3)(vii).
    (ii) For a CEMS other than one addressed in paragraph (e)(4)(i) of 
this section:
    (A) Only if the relative accuracy test audit (RATA) of the CEMS is 
successfully completed either prior to the date and hour of the first 
injection of reagent into the emission control device, or after that 
date and hour during a period when the control device is not operating, 
but still within the window of time provided under paragraph (e)(1)(i) 
of this section, and the rest of the certification tests required under 
Sec. 75.20(c) and section 6 of appendix A to this part for the CEMS are 
successfully completed within the window of time provided under 
paragraph (e)(1)(i) of this section;
    (B) Beginning with:
    (1) The first unit or stack operating hour after successful 
completion of all of the certification tests in accordance with 
paragraph (e)(4)(ii)(A) of this section; or
    (2) The hour of the probationary calibration error test (see Sec. 
75.20(b)(3)(ii)), if conditional data validation is used and all of the 
certification tests are successfully completed in accordance with 
paragraph (e)(4)(ii)(A) of this section, with no test failures. If any 
required test is failed or aborted or is otherwise not in accordance 
with paragraph (e)(4)(ii)(A) of this section, data validation shall be 
done according to Sec. 75.20(b)(3)(vii).
    (f) In accordance with Sec. 75.20, the owner or operator of an 
affected gas-fired or oil-fired peaking unit, if planning to use 
appendix E of this part, shall ensure that the required certification 
tests for excepted monitoring systems under appendix E are completed for 
backup fuel, as defined in Sec. 72.2 of this chapter, no later than 90 
unit operating days or 180 calendar days (whichever occurs first) after 
the date that the unit first combusts the backup fuel following the 
certification testing with the primary fuel. If the required testing is 
completed by this deadline, the appendix E correlation curve derived 
from the test results may be used for reporting data under this part 
beginning with the first date and hour that the backup fuel is 
combusted, provided that the fuel flowmeter for the backup fuel was 
certified as of that date and hour. If the required appendix E testing 
has not been successfully completed by the compliance date in this 
paragraph, then, until the testing is completed, the owner or operator 
shall report NOX emission rate data for all unit operating 
hours that the backup fuel is combusted using either:
    (1) The fuel-specific maximum potential NOX emission 
rate, as defined in Sec. 72.2 of this chapter; or
    (2) Reference methods under Sec. 75.22(b) of this part; or
    (3) Another procedure approved by the Administrator pursuant to a 
petition under Sec. 75.66.
    (g) The provisions of this paragraph shall apply unless an owner or 
operator is exempt from certifying a fuel flowmeter for use during 
combustion of emergency fuel under section 2.1.4.3 of appendix D to this 
part, in which circumstance the provisions of section 2.1.4.3 of 
appendix D shall apply. In accordance with Sec. 75.20, whenever the 
owner or operator of a gas-fired or oil-fired unit uses an excepted 
monitoring system under appendix D or E of this part and combusts 
emergency fuel as defined in Sec. 72.2 of this chapter, then the owner 
or operator shall ensure that a fuel flowmeter measuring emergency

[[Page 211]]

fuel is installed and the required certification tests for excepted 
monitoring systems are completed by no later than 30 unit operating days 
after the first date after January 1, 1995 that the unit combusts 
emergency fuel. For all unit operating hours that the unit combusts 
emergency fuel after January 1, 1995 until the owner or operator 
installs a flowmeter for emergency fuel and successfully completes all 
required certification tests, the owner or operator shall determine and 
report SO2 mass emission data using either:
    (1) The maximum potential fuel flow rate, as described in appendix D 
of this part, and the maximum sulfur content of the fuel, as described 
in section 2.1.1.1 of appendix A of this part;
    (2) Reference methods under Sec. 75.22(b) of this part; or
    (3) Another procedure approved by the Administrator pursuant to a 
petition under Sec. 75.66.
    (h) [Reserved]
    (i) In accordance with Sec. 75.20, the owner or operator of each 
affected unit at which SO2 concentration is measured on a dry 
basis or at which moisture corrections are required to account for 
CO2 emissions, NOX emission rate in lb/mmBtu, heat 
input, or NOX mass emissions for units in a NOX 
mass reduction program, shall ensure that the continuous moisture 
monitoring system required by this part is installed and that all 
applicable initial certification tests required under Sec. 75.20(c)(5), 
(c)(6), or (c)(7) for the continuous moisture monitoring system are 
completed no later than the following dates:
    (1) April 1, 2000, for a unit that is existing and has commenced 
commercial operation by January 2, 2000;
    (2) For a new affected unit which has not commenced commercial 
operation by January 2, 2000, 90 unit operating days or 180 calendar 
days (whichever occurs first) after the date the unit commences 
commercial operation; or
    (3) For an existing unit that is shutdown and is not yet operating 
by April 1, 2000, 90 unit operating days or 180 calendar days (whichever 
occurs first) after the date that the unit recommences commercial 
operation.
    (j) If the certification tests required under paragraph (b) or (c) 
of this section have not been completed by the applicable compliance 
date, the owner or operator shall determine and report SO2 
concentration, NOX emission rate, CO2 
concentration, and flow rate data for all unit operating hours after the 
applicable compliance date in this paragraph until all required 
certification tests are successfully completed using either:
    (1) The maximum potential concentration of SO2, as 
defined in section 2.1.1.1 of appendix A to this part, the maximum 
potential NOX emission rate, as defined in Sec. 72.2 of this 
chapter, the maximum potential flow rate, as defined in section 2.1.4.1 
of appendix A to this part, or the maximum potential CO2 
concentration, as defined in section 2.1.3.1 of appendix A to this part;
    (2) Reference methods under Sec. 75.22(b); or
    (3) Another procedure approved by the Administrator pursuant to a 
petition under Sec. 75.66.

[60 FR 17131, Apr. 4, 1995, as amended at 60 FR 26516, May 17, 1995; 63 
FR 57499, Oct. 27, 1998; 64 FR 28588, May 26, 1999; 67 FR 40421, June 
12, 2002; 73 FR 4340, Jan. 24, 2008; 76 FR 17306, Mar. 28, 2011; 76 FR 
50132, Aug. 12, 2011]



Sec. 75.5  Prohibitions.

    (a) A violation of any applicable regulation in this part by the 
owners or operators or the designated representative of an affected 
source or an affected unit is a violation of the Act.
    (b) No owner or operator of an affected unit shall operate the unit 
without complying with the requirements of Sec. Sec. 75.2 through 75.75 
and appendices A through G to this part.
    (c) No owner or operator of an affected unit shall use any 
alternative monitoring system, alternative reference method, or any 
other alternative for the required continuous emission monitoring system 
without having obtained the Administrator's prior written approval in 
accordance with Sec. Sec. 75.23, 75.48 and 75.66.
    (d) No owner or operator of an affected unit shall operate the unit 
so as to discharge, or allow to be discharged, emissions of 
SO2, NOX or CO2 to the atmosphere 
without accounting for all such emissions in accordance with the 
provisions of Sec. Sec. 75.10 through 75.19.

[[Page 212]]

    (e) No owner or operator of an affected 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, NOX, or CO2 emissions 
discharged to the atmosphere, except for periods of recertification, or 
periods when calibration, quality assurance, or maintenance is performed 
pursuant to Sec. 75.21 and appendix B of this part.
    (f) No owner or operator of an affected unit shall retire or 
permanently discontinue use of the continuous emission monitoring 
system, any component thereof, the continuous opacity monitoring system, 
or any other approved emission monitoring system under this part, except 
under any one of the following circumstances:
    (1) During the period that the unit is covered by an approved 
retired unit exemption under Sec. 72.8 of this chapter that is in 
effect; or
    (2) The owner or operator is monitoring emissions from the unit with 
another certified monitoring system or an excepted methodology approved 
by the Administrator for use at that unit that provides emissions data 
for the same pollutant or parameter as the retired or discontinued 
monitoring system; or
    (3) The designated representative submits notification of the date 
of recertification testing of a replacement monitoring system in 
accordance with Sec. Sec. 75.20 and 75.61, and the owner or operator 
recertifies thereafter a replacement monitoring system in accordance 
with Sec. 75.20.

[58 FR 3701, Jan. 11, 1993, as amended at 58 FR 40747, July 30, 1993; 60 
FR 26517, May 17, 1995; 64 FR 28589, May 26, 1999]



Sec. 75.6  Incorporation by reference.

    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 the Federal Register in accordance with 
5 U.S.C. 552(a) and 1 CFR part 51. These materials are incorporated as 
they existed on the date of approval, and a notice of any change in 
these materials will be published in the Federal Register. The materials 
are available for purchase at the corresponding address noted below and 
are available for inspection at the Public Information Reference Unit of 
the U.S. EPA, 401 M St., SW., Washington, DC and at the Library (MD-35), 
U.S. EPA, Research Triangle Park, North Carolina or 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) The following materials are available for purchase from the 
following address: American Society for Testing and Material (ASTM) 
International, 100 Barr Harbor Drive, P.O. Box C700, West Conshohocken, 
Pennsylvania, 19428-2959, phone: 610-832-9585, http://www.astm.org/
DIGITAL--LIBRARY/index.shtml.
    (1) ASTM D129-00, Standard Test Method for Sulfur in Petroleum 
Products (General Bomb Method), for appendices A and D of this part.
    (2) D240-00, Standard Test Method for Heat of Combustion of Liquid 
Hydrocarbon Fuels by Bomb Calorimeter, for appendices A, D and F of this 
part.
    (3) ASTM D287-92 (Reapproved 2000), Standard Test Method for API 
Gravity of Crude Petroleum and Petroleum Products (Hydrometer Method), 
for appendix D of this part.
    (4) ASTM D388-99, Standard Classification of Coals by Rank, 
incorporation by reference for appendix F of this part.
    (5) [Reserved]
    (6) ASTM D1072-06, Standard Test Method for Total Sulfur in Fuel 
Gases by Combustion and Barium Chloride Titration, for appendix D of 
this part.
    (7) ASTM D1217-993 (Reapproved 1998), Standard Test Method for 
Density and Relative Density (Specific Gravity) of Liquids by Bingham 
Pycnometer, for appendix D of this part.
    (8) ASTM D1250-07 , Standard Guide for Use of the Petroleum 
Measurement Tables, for appendix D of this part.
    (9) ASTM D1298-99, Standard Test Method for Density, Relative 
Density (Specific Gravity) or API Gravity of Crude Petroleum and Liquid 
Petroleum Products by Hydrometer Method, for appendix D of this part.

[[Page 213]]

    (10) ASTM D1480-93 (Reapproved 1997), Standard Test Method for 
Density and Relative Density (Specific Gravity) of Viscous Materials by 
Bingham Pycnometer, for appendix D of this part.
    (11) ASTM D1481-93 (Reapproved 1997), Standard Test Method for 
Density and Relative Density (Specific Gravity) of Viscous Materials by 
Lipkin Bicapillary Pycnometer, for appendix D of this part.
    (12) ASTM D1552-01, Standard Test Method for Sulfur in Petroleum 
Products (High-Temperature Method), for appendices A and D of the part.
    (13) ASTM D1826-94 (Reapproved 1998), Standard Test Method for 
Calorific (Heating) Value of Gases in Natural Gas Range by Continuous 
Recording Calorimeter, for appendices D and F to this part.
    (14) ASTM D1945-96 (Reapproved 2001), Standard Test Method for 
Analysis of Natural Gas by Gas Chromatography, for appendices F and G of 
this part.
    (15) ASTM D1946-90 (Reapproved 2006), Standard Practice for Analysis 
of Reformed Gas by Gas Chromatography, for appendices F and G of this 
part.
    (16) [Reserved]
    (17) ASTM D2013-01, Standard Practice for Preparing Coal Samples for 
Analysis, for appendix F of this part.
    (18) [Reserved]
    (19) ASTM D2234-00, Standard Practice for Collection of a Gross 
Sample of Coal, for appendix F of this part.
    (20) [Reserved]
    (21) ASTM D2502-92 (Reapproved 1996), Standard Test Method for 
Estimation of Molecular Weight (Relative Molecular Mass) of Petroleum 
Oils from Viscosity Measurements, for appendix G of this part.
    (22) ASTM D2503-92 (Reapproved 1997), Standard Test Method for 
Relative Molecular Mass (Molecular Weight) of Hydrocarbons by 
Thermoelectric Measurement of Vapor Pressure, for appendix G of this 
part.
    (23) ASTM D2622-98, Standard Test Method for Sulfur in Petroleum 
Products by Wavelength Dispersive X-ray Fluorescence Spectrometry, for 
appendices A and D of this part.
    (24) ASTM D3174-00, Standard Test Method for Ash in the Analysis 
Sample of Coal and Coke from Coal, for appendix G of this part.
    (25) ASTM D3176-89 (Reapproved 2002), Standard Practice for Ultimate 
Analysis of Coal and Coke, for appendices A and F of this part.
    (26) ASTM D3177-02 (Reapproved 2007), Standard Test Methods for 
Total Sulfur in the Analysis Sample of Coal and Coke, for appendix A of 
this part.
    (27) ASTM D5373-02 (Reapproved 2007) Standard Test Methods for 
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in 
Laboratory Samples of Coal and Coke, for appendix G of this part.
    (28) ASTM D3238-95 (Reapproved 2000), Standard Test Method for 
Calculation of Carbon Distribution and Structural Group Analysis of 
Petroleum Oils by the n-d-M Method, for appendix G of this part.
    (29) ASTM D3246-96, Standard Test Method for Sulfur in Petroleum Gas 
by Oxidative Microcoulometry, for appendix D of this part.
    (30) [Reserved]
    (31) ASTM D3588-98, Standard Practice for Calculating Heat Value, 
Compressibility Factor, and Relative Density of Gaseous Fuels, for 
appendices D and F to this part.
    (32) ASTM D4052-96 (Reapproved 2002), Standard Test Method for 
Density and Relative Density of Liquids by Digital Density Meter, for 
appendix D of this part.
    (33) ASTM D4057-95 (Reapproved 2000), Standard Practice for Manual 
Sampling of Petroleum and Petroleum Products, for appendix D of this 
part.
    (34) ASTM D4177-95 (Reapproved 2000), Standard Practice for 
Automatic Sampling of Petroleum and Petroleum Products, for appendix D 
of this part.
    (35) ASTM D4239-02, Standard Test Methods for Sulfur in the Analysis 
Sample of Coal and Coke Using High-Temperature Tube Furnace Combustion 
Methods, for appendix A of this part.
    (36) ASTM D4294-98, Standard Test Method for Sulfur in Petroleum and 
Petroleum Products by Energy-Dispersive X-ray Fluorescence Spectrometry, 
for appendices A and D of this part.
    (37) ASTM D4468-85 (Reapproved 2006), Standard Test Method for Total

[[Page 214]]

Sulfur in Gaseous Fuels by Hydrogenolysis and Rateometric Colorimetry, 
for appendix D of this part.
    (38) [Reserved]
    (39) ASTM D4891-89 (Reapproved 2006), Standard Test Method for 
Heating Value of Gases in Natural Gas Range by Stoichiometric 
Combustion, for appendices D and F to this part.
    (40) ASTM D5291-02, Standard Test Methods for Instrumental 
Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products 
and Lubricants, for appendices F and G to this part.
    (41) ASTM D5373-02 (Reapproved 2007), ``Standard Test Methods for 
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in 
Laboratory Samples of Coal and Coke,'' for appendix G to this part.
    (42) ASTM D5504-01, Standard Test Method for Determination of Sulfur 
Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography and 
Chemiluminescence, for appendix D of this part.
    (43) [Reserved]
    (44) [Reserved]
    (45) ASTM D6667-04, Standard Test Method for Determination of Total 
Volatile Sulfur in Gaseous Hydrocarbons and Liquefied Petroleum Gases by 
Ultraviolet Fluorescence, for appendix D of this part.
    (46) ASTM D4809-00, Standard Test Method for Heat of Combustion of 
Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method), for 
appendices D and F of this part.
    (47) ASTM D5865-01a, Standard Test Method for Gross Calorific Value 
of Coal and Coke, for appendices A, D, and F of this part.
    (48) ASTM D7036-04, Standard Practice for Competence of Air Emission 
Testing Bodies, for Sec. 75.21, Sec. 75.59, and appendix A to this 
part.
    (49) ASTM D5453-06, Standard Test Method for Determination of Total 
Sulfur in Light Hydrocarbons, Spark Ignition Engine Fuel, Diesel Engine 
Fuel, and Engine Oil by Ultraviolet Fluorescence, for appendix D of this 
part.
    (50) ASTM D5865-10 (Approved January 1, 2010), Standard Test Method 
for Gross Calorific Value of Coal and Coke, for appendices A, D, and F 
of this part.
    (b) The following materials are available for purchase from the 
American Society of Mechanical Engineers (ASME), 22 Law Drive, P.O. Box 
2900, Fairfield, New Jersey 07007-2900:
    (1) ASME MFC-3M-2004 (Revision of ASME MFC-3M-1989 (R1995)), 
Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi, 
for appendix D of this part.
    (2) ASME MFC-4M-1986 (Reaffirmed 1997), Measurement of Gas Flow by 
Turbine Meters, for appendix D of this part.
    (3) ASME-MFC-5M-1985 (Reaffirmed 1994), Measurement of Liquid Flow 
in Closed Conduits Using Transit-Time Ultrasonic Flowmeters, for 
appendix D of this part.
    (4) ASME MFC-6M-1998, Measurement of Fluid Flow in Pipes Using 
Vortex Flowmeters, for appendix D of this part.
    (5) ASME MFC-7M-1987 (Reaffirmed 1992), Measurement of Gas Flow by 
Means of Critical Flow Venturi Nozzles, for appendix D of this part.
    (6) ASME MFC-9M-1988 (Reaffirmed 2001), Measurement of Liquid Flow 
in Closed Conduits by Weighing Method, for appendix D of this part.
    (c) The following materials are available for purchase from the 
American National Standards Institute (ANSI), 25 West 43rd Street, 
Fourth Floor, New York, New York 10036:
    (1) ISO 8316: 1987(E) Measurement of Liquid Flow in closed Conduits-
Method by Collection of the Liquid in a Volumetric Tank, for appendices 
D and E of this part.
    (2) [Reserved]
    (d) The following materials are available for purchase from the 
following address: Gas Processors Association (GPA), 6526 East 60th 
Street, Tulsa, Oklahoma 74143:
    (1) GPA Standard 2172-96, Calculation of Gross Heating Value, 
Relative Density and Compressibility Factor for Natural Gas Mixtures 
from Compositional Analysis, for appendices D, E, and F of this part.
    (2) GPA Standard 2261-00, Analysis for Natural Gas and Similar 
Gaseous Mixtures by Gas Chromatography, for appendices D, F, and G of 
this part.

[[Page 215]]

    (e) The following American Gas Association materials are available 
for purchase from the following address: ILI Infodisk, 610 Winters 
Avenue, Paramus, New Jersey 07652:
    (1) American Gas Association Report No. 3: Orifice Metering of 
Natural Gas and Other Related Hydrocarbon Fluids, Part 1: General 
Equations and Uncertainty Guidelines (October 1990 Edition), Part 2: 
Specification and Installation Requirements (February 1991 Edition) and 
Part 3: Natural Gas Applications (August 1992 Edition), for appendices D 
and E of this part.
    (2) American Gas Association Transmission Measurement Committee 
Report No. 7: Measurement of Gas by Turbine Meters (Second Revision, 
April, 1996), for appendix D to this part.
    (f) The following materials are available for purchase from the 
following address: American Petroleum Institute, Publications 
Department, 1220 L Street NW, Washington, DC 20005-4070.
    (1) American Petroleum Institute (API) Manual of Petroleum 
Measurement Standards, Chapter 3--Tank Gauging, Section 1A, Standard 
Practice for the Manual Gauging of Petroleum and Petroleum Products, 
Second Edition, August 2005; Section 1B--Standard Practice for Level 
Measurement of Liquid Hydrocarbons in Stationary Tanks by Automatic Tank 
Gauging, Second Edition June 2001; Section 2--Standard Practice for 
Gauging Petroleum and Petroleum Products in Tank Cars, First Edition, 
August 1995 (Reaffirmed March 2006); Section 3--Standard Practice for 
Level Measurement of Liquid Hydrocarbons in Stationary Pressurized 
Storage Tanks by Automatic Tank Gauging, First Edition June 1996; 
Section 4--Standard Practice for Level Measurement of Liquid 
Hydrocarbons on Marine Vessels by Automatic Tank Gauging, First Edition 
April 1995 (Reaffirmed, March 2006); and Section 5--Standard Practice 
for Level Measurement of Light Hydrocarbon Liquids Onboard Marine 
Vessels by Automatic Tank Gauging, First Edition March 1997 (Reaffirmed, 
March 2003); for Sec. 75.19.
    (2) Shop Testing of Automatic Liquid Level Gages, Bulletin 2509 B, 
December 1961 (Reaffirmed August 1987, October 1992), for Sec. 75.19.
    (3) American Petroleum Institute (API) Manual of Petroleum 
Measurement Standards, Chapter 4--Proving Systems, Section 2--Pipe 
Provers (Provers Accumulating at Least 10,000 Pulses), Second Edition, 
March 2001, Section 3--Small Volume Provers, First Edition, July 1988, 
Reaffirmed Oct 1993, and Section 5--Master-Meter Provers, Second 
Edition, May 2000, for appendix D to this part.
    (4) American Petroleum Institute (API) Manual of Petroleum 
Measurement Standards, Chapter 22--Testing Protocol, Section 2--
Differential Pressure Flow Measurement Devices (First Edition, August 
2005), for appendix D to this part.
    (g) A copy of the following material is available from http://
www.epa.gov/ttn/emc/news.html (see postings for Sections 1, 2, 3, 4, 
Appendices, Spreadsheets, and the ``Read before downloading Section 2'' 
revision posted August 27, 1999): EPA-600/R-97/121, EPA Traceability 
Protocol for Assay and Certification of Gaseous Calibration Standards, 
September 1997, as amended August 25, 1999, U.S. Environmental 
Protection Agency, for Sec. 75.21, and appendix A to this part.

[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26517, May 17, 1995; 61 
FR 59157, Nov. 20, 1996; 63 FR 57499, Oct. 27, 1998; 64 FR 28589, May 
26, 1999; 67 FR 40422, June 12, 2002; 70 FR 28678, May 18, 2005; 70 FR 
51269, Aug. 30, 2005; 73 FR 4341, Jan. 24, 2008; 76 FR 17307, Mar. 28, 
2011; 77 FR 2460, Jan. 18, 2012]

    Editorial Note: At 70 FR 28678, May 18, 2005, Sec. 75.6 was 
amended, however, certain amendments could not be incorporated due to 
inaccurate amendatory instruction.



Sec. Sec. 75.7-75.8  [Reserved]



                     Subpart B_Monitoring Provisions



Sec. 75.10  General operating requirements.

    (a) Primary Measurement Requirement. The owner or operator shall 
measure opacity, and all SO2, NOX, and 
CO2 emissions for each affected unit as follows:
    (1) To determine SO2 emissions, the owner or operator 
shall install, certify, operate, and maintain, in accordance with all 
the requirements of this part, a SO2 continuous emission 
monitoring

[[Page 216]]

system and a flow monitoring system with an automated data acquisition 
and handling system for measuring and recording SO2 
concentration (in ppm), volumetric gas flow (in scfh), and 
SO2 mass emissions (in lb/hr) discharged to the atmosphere, 
except as provided in Sec. Sec. 75.11 and 75.16 and subpart E of this 
part;
    (2) To determine NOX emissions, the owner or operator 
shall install, certify, operate, and maintain, in accordance with all 
the requirements of this part, a NOX-diluent continuous 
emission monitoring system (consisting of a NOX pollutant 
concentration monitor and an O2 or CO2 diluent gas 
monitor) with an automated data acquisition and handling system for 
measuring and recording NOX concentration (in ppm), 
O2 or CO2 concentration (in percent O2 
or CO2) and NOX emission rate (in lb/mmBtu) 
discharged to the atmosphere, except as provided in Sec. Sec. 75.12 and 
75.17 and subpart E of this part. The owner or operator shall account 
for total NOX emissions, both NO and NO2, either 
by monitoring for both NO and NO2 or by monitoring for NO 
only and adjusting the emissions data to account for NO2;
    (3) The owner or operator shall determine CO2 emissions 
by using one of the following options, except as provided in Sec. 75.13 
and subpart E of this part:
    (i) The owner or operator shall install, certify, operate, and 
maintain, in accordance with all the requirements of this part, a 
CO2 continuous emission monitoring system and a flow 
monitoring system with an automated data acquisition and handling system 
for measuring and recording CO2 concentration (in ppm or 
percent), volumetric gas flow (in scfh), and CO2 mass 
emissions (in tons/hr) discharged to the atmosphere;
    (ii) The owner or operator shall determine CO2 emissions 
based on the measured carbon content of the fuel and the procedures in 
appendix G of this part to estimate CO2 emissions (in ton/
day) discharged to the atmosphere; or
    (iii) The owner or operator shall install, certify, operate, and 
maintain, in accordance with all the requirements of this part, a flow 
monitoring system and a CO2 continuous emission monitoring 
system that uses an O2 concentration monitor to determine 
CO2 emissions (according to the procedures in appendix F of 
this part) with an automated data acquisition and handling system for 
measuring and recording O2 concentration (in percent), 
CO2 concentration (in percent), volumetric gas flow (in 
scfh), and CO2 mass emissions (in tons/hr) discharged to the 
atmosphere;
    (4) The owner or operator shall install, certify, operate, and 
maintain, in accordance with all the requirements in this part, a 
continuous opacity monitoring system with the automated data acquisition 
and handling system for measuring and recording the opacity of emissions 
(in percent opacity) discharged to the atmosphere, except as provided in 
Sec. Sec. 75.14 and 75.18; and
    (5) A single certified flow monitoring system may be used to meet 
the requirements of paragraphs (a)(1) and (a)(3) of this section. A 
single certified diluent monitor may be used to meet the requirements of 
paragraphs (a)(2) and (a)(3) of this section. A single automated data 
acquisition and handling system may be used to meet the requirements of 
paragraphs (a)(1) through (a)(4) of this section.
    (b) Primary Equipment Performance Requirements. The owner or 
operator shall ensure that each continuous emission monitoring system 
required by this part meets the equipment, installation, and performance 
specifications in appendix A to this part; and is maintained according 
to the quality assurance and quality control procedures in appendix B to 
this part; and shall record SO2 and NOX emissions 
in the appropriate units of measurement (i.e., lb/hr for SO2 
and lb/mmBtu for NOX).
    (c) Heat Input Rate Measurement Requirement. The owner or operator 
shall determine and record the heat input rate, in units of mmBtu/hr, to 
each affected unit for every hour or part of an hour any fuel is 
combusted following the procedures in appendix F to this part.
    (d) Primary equipment hourly operating requirements. The owner or 
operator shall ensure that all continuous emission and opacity 
monitoring systems required by this part are in operation and monitoring 
unit emissions or opacity at all times that the affected unit

[[Page 217]]

combusts any fuel except as provided in Sec. 75.11(e) and during 
periods of calibration, quality assurance, or preventive maintenance, 
performed pursuant to Sec. 75.21 and appendix B of this part, periods 
of repair, periods of backups of data from the data acquisition and 
handling system, or recertification performed pursuant to Sec. 75.20. 
The owner or operator shall also ensure, subject to the exceptions above 
in this paragraph, that all continuous opacity monitoring systems 
required by this part are in operation and monitoring opacity during the 
time following combustion when fans are still operating, unless fan 
operation is not required to be included under any other applicable 
Federal, State, or local regulation, or permit. The owner or operator 
shall ensure that the following requirements are met:
    (1) The owner or operator shall ensure that each continuous emission 
monitoring system is capable of completing a minimum of one cycle of 
operation (sampling, analyzing, and data recording) for each successive 
15-min interval. The owner or operator shall reduce all SO2 
concentrations, volumetric flow, SO2 mass emissions, 
CO2 concentration, O2 concentration, 
CO2 mass emissions (if applicable), NOX 
concentration, and NOX emission rate data collected by the 
monitors to hourly averages. Hourly averages shall be computed using at 
least one data point in each fifteen minute quadrant of an hour, where 
the unit combusted fuel during that quadrant of an hour. Notwithstanding 
this requirement, an hourly average may be computed from at least two 
data points separated by a minimum of 15 minutes (where the unit 
operates for more than one quadrant of an hour) if data are unavailable 
as a result of the performance of calibration, quality assurance, or 
preventive maintenance activities pursuant to Sec. 75.21 and appendix B 
of this part, or backups of data from the data acquisition and handling 
system, or recertification, pursuant to Sec. 75.20. The owner or 
operator shall use all valid measurements or data points collected 
during an hour to calculate the hourly averages. All data points 
collected during an hour shall be, to the extent practicable, evenly 
spaced over the hour.
    (2) The owner or operator shall ensure that each continuous opacity 
monitoring system is capable of completing a minimum of one cycle of 
sampling and analyzing for each successive 10-sec period and one cycle 
of data recording for each successive 6-min period. The owner or 
operator shall reduce all opacity data to 6-min averages calculated in 
accordance with the provisions of part 51, appendix M of this chapter, 
except where the applicable State implementation plan or operating 
permit requires a different averaging period, in which case the State 
requirement shall satisfy this Acid Rain Program requirement.
    (3) Failure of an SO2, CO2, or O2 
emissions concentration monitor, NOX concentration monitor, 
flow monitor, moisture monitor, or NOX-diluent continuous 
emission monitoring system to acquire the minimum number of data points 
for calculation of an hourly average in paragraph (d)(1) of this section 
shall result in the failure to obtain a valid hour of data and the loss 
of such component data for the entire hour. For a NOX-diluent 
monitoring system, an hourly average NOX emission rate in lb/
mmBtu is valid only if the minimum number of data points is acquired by 
both the NOX pollutant concentration monitor and the diluent 
monitor (O2 or CO2). For a moisture monitoring 
system consisting of one or more oxygen analyzers capable of measuring 
O2 on a wet-basis and a dry-basis, an hourly average percent 
moisture value is valid only if the minimum number of data points is 
acquired for both the wet-and dry-basis measurements. If a valid hour of 
data is not obtained, the owner or operator shall estimate and record 
emissions, moisture, or flow data for the missing hour by means of the 
automated data acquisition and handling system, in accordance with the 
applicable procedure for missing data substitution in subpart D of this 
part.
    (e) Optional backup monitor requirements. If the owner or operator 
chooses to use two or more continuous emission monitoring systems, each 
of which is capable of monitoring the same stack or duct at a specific 
affected unit, or group of units using a common stack, then the owner or 
operator shall designate one monitoring system as

[[Page 218]]

the primary monitoring system, and shall record this information in the 
monitoring plan, as provided for in Sec. 75.53. The owner or operator 
shall designate the other monitoring system(s) as backup monitoring 
system(s) in the monitoring plan. The backup monitoring system(s) shall 
be designated as redundant backup monitoring system(s), non-redundant 
backup monitoring system(s), or reference method backup system(s), as 
described in Sec. 75.20(d). When the certified primary monitoring 
system is operating and not out-of-control as defined in Sec. 75.24, 
only data from the certified primary monitoring system shall be reported 
as valid, quality-assured data. Thus, data from the backup monitoring 
system may be reported as valid, quality-assured data only when the 
backup is operating and not out-of-control as defined in Sec. 75.24 (or 
in the applicable reference method in appendix A of part 60 of this 
chapter) and when the certified primary monitoring system is not 
operating (or is operating but out-of-control). A particular monitor may 
be designated both as a certified primary monitor for one unit and as a 
certified redundant backup monitor for another unit.
    (f) Minimum measurement capability requirement. The owner or 
operator shall ensure that each continuous emission monitoring system is 
capable of accurately measuring, recording, and reporting data, and 
shall not incur an exceedance of the full scale range, except as 
provided in sections 2.1.1.5, 2.1.2.5, and 2.1.4.3 of appendix A to this 
part.
    (g) Minimum recording and recordkeeping requirements. The owner or 
operator shall record and the designated representative shall report the 
hourly, daily, quarterly, and annual information collected under the 
requirements of this part as specified in subparts F and G of this part.

[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26519, May 17, 1995; 64 
FR 28590, May 26, 1999; 67 FR 40422, June 12, 2002; 70 FR 28678, May 18, 
2005; 76 FR 17308, Mar. 28, 2011]



Sec. 75.11  Specific provisions for monitoring SO[bdi2] emissions.

    (a) Coal-fired units. The owner or operator shall meet the general 
operating requirements in Sec. 75.10 for an SO2 continuous 
emission monitoring system and a flow monitoring system for each 
affected coal-fired unit while the unit is combusting coal and/or any 
other fuel, except as provided in paragraph (e) of this section, in 
Sec. 75.16, and in subpart E of this part. During hours in which only 
gaseous fuel is combusted in the unit, the owner or operator shall 
comply with the applicable provisions of paragraph (e)(1), (e)(2), or 
(e)(3) of this section.
    (b) Moisture correction. Where SO2 concentration is 
measured on a dry basis, the owner or operator shall either:
    (1) Report the appropriate fuel-specific default moisture value for 
each unit operating hour, selected from among the following: 3.0%, for 
anthracite coal; 6.0% for bituminous coal; 8.0% for sub-bituminous coal; 
11.0% for lignite coal; 13.0% for wood and 14.0% for natural gas 
(boilers, only); or
    (2) Install, operate, maintain, and quality assure a continuous 
moisture monitoring system for measuring and recording the moisture 
content of the flue gases, in order to correct the measured hourly 
volumetric flow rates for moisture when calculating SO2 mass 
emissions (in lb/hr) using the procedures in appendix F to this part. 
The following continuous moisture monitoring systems are acceptable: a 
continuous moisture sensor; an oxygen analyzer (or analyzers) capable of 
measuring O2 both on a wet basis and on a dry basis; or a 
stack temperature sensor and a moisture look-up table, i.e., a 
psychrometric chart (for saturated gas streams following wet scrubbers 
or other demonstrably saturated gas streams, only). The moisture 
monitoring system shall include as a component the automated data 
acquisition and handling system (DAHS) for recording and reporting both 
the raw data (e.g., hourly average wet-and dry-basis O2 
values) and the hourly average values of the stack gas moisture content 
derived from those data. When a moisture look-up table is used, the 
moisture monitoring system shall be represented as a single component, 
the certified DAHS, in the monitoring plan for the unit or common stack.
    (c) Unit with no location for a flow monitor meeting siting 
requirements.

[[Page 219]]

Where no location exists that satisfies the minimum physical siting 
criteria in appendix A to this part for installation of a flow monitor 
in either the stack or the ducts serving an affected unit or 
installation of a flow monitor in either the stack or ducts is 
demonstrated to the satisfaction of the Administrator to be technically 
infeasible, either:
    (1) The designated representative shall petition the Administrator 
for an alternative method for monitoring volumetric flow in accordance 
with Sec. 75.66; or
    (2) The owner or operator shall construct a new stack or modify 
existing ductwork to accommodate the installation of a flow monitor, and 
the designated representative shall petition the Administrator for an 
extension of the required certification date given in Sec. 75.4 and 
approval of an interim alternative flow monitoring methodology in 
accordance with Sec. 75.66. The Administrator may grant existing Phase 
I affected units an extension to January 1, 1995, and existing Phase II 
affected units an extension to January 1, 1996 for the submission of the 
certification application for the purpose of constructing a new stack or 
making substantial modifications to ductwork for installation of a flow 
monitor; or
    (3) The owner or operator shall install a flow monitor in any 
existing location in the stack or ducts serving the affected unit at 
which the monitor can achieve the performance specifications of this 
part.
    (d) Gas-fired and oil-fired units. The owner or operator of an 
affected unit that qualifies as a gas-fired or oil-fired unit, as 
defined in Sec. 72.2 of this chapter, based on information submitted by 
the designated representative in the monitoring plan, shall measure and 
record SO2 emissions:
    (1) By meeting the general operating requirements in Sec. 75.10 for 
an SO2 continuous emission monitoring system and flow 
monitoring system. If this option is selected, the owner or operator 
shall comply with the applicable provisions in paragraph (e)(1), (e)(2), 
or (e)(3) of this section during hours in which the unit combusts only 
gaseous fuel;
    (2) By providing other information satisfactory to the Administrator 
using the applicable procedures specified in appendix D to this part for 
estimating hourly SO2 mass emissions; or
    (3) By using the low mass emissions excepted methodology in Sec. 
75.19(c) for estimating hourly SO2 mass emissions if the 
affected unit qualifies as a low mass emissions unit under Sec. 
75.19(a) and (b). If this option is selected for SO2, the LME 
methodology must also be used for NOX and CO2 when 
these parameters are required to be monitored by applicable program(s).
    (e) Special considerations during the combustion of gaseous fuels. 
The owner or operator of an affected unit that uses a certified flow 
monitor and a certified diluent gas (O2 or CO2) 
monitor to measure the unit heat input rate shall, during any hours in 
which the unit combusts only gaseous fuel, determine SO2 
emissions in accordance with paragraph (e)(1) or (e)(3) of this section, 
as applicable.
    (1) If the gaseous fuel qualifies for a default SO2 
emission rate under Section 2.3.1.1, 2.3.2.1.1, or 2.3.6(b) of appendix 
D to this part, the owner or operator may determine SO2 
emissions by using Equation F-23 in appendix F to this part. Substitute 
into Equation F-23 the hourly heat input, calculated using the certified 
flow monitoring system and the certified diluent monitor (according to 
the applicable equation in section 5.2 of appendix F to this part), in 
conjunction with the appropriate default SO2 emission rate 
from section 2.3.1.1, 2.3.2.1.1, or 2.3.6(b) of appendix D to this part. 
When this option is chosen, the owner or operator shall perform the 
necessary data acquisition and handling system tests under Sec. 
75.20(c), and shall meet all quality control and quality assurance 
requirements in appendix B to this part for the flow monitor and the 
diluent monitor; or
    (2) [Reserved]
    (3) The owner or operator may determine SO2 mass 
emissions by using a certified SO2 continuous monitoring 
system, in conjunction with the certified flow rate monitoring system. 
However, if the gaseous fuel is very low sulfur fuel (as defined in 
Sec. 72.2 of this chapter), the SO2 monitoring system

[[Page 220]]

shall meet the following quality assurance provisions when the very low 
sulfur fuel is combusted:
    (i) When conducting the daily calibration error tests of the 
SO2 monitoring system, as required by section 2.1.1 in 
appendix B of this part, the zero-level calibration gas shall have an 
SO2 concentration of 0.0 percent of span. This restriction 
does not apply if gaseous fuel is burned in the affected unit only 
during unit startup.
    (ii) EPA recommends that the calibration response of the 
SO2 monitoring system be adjusted, either automatically or 
manually, in accordance with the procedures for routine calibration 
adjustments in section 2.1.3 of appendix B to this part, whenever the 
zero-level calibration response during a required daily calibration 
error test exceeds the applicable performance specification of the 
instrument in section 3.1 of appendix A to this part (i.e., [2.5 percent 
of the span value or [5 ppm, whichever is less restrictive).
    (iii) Any bias-adjusted hourly average SO2 concentration 
of less than 2.0 ppm recorded by the SO2 monitoring system 
shall be adjusted to a default value of 2.0 ppm, for reporting purposes. 
Such adjusted hourly averages shall be considered to be quality-assured 
data, provided that the monitoring system is operating and is not out-
of-control with respect to any of the quality assurance tests required 
by appendix B of this part (i.e., daily calibration error, linearity and 
relative accuracy test audit).
    (iv) In accordance with the requirements of section 2.1.1.2 of 
appendix A to this part, for units that sometimes burn gaseous fuel that 
is very low sulfur fuel (as defined in Sec. 72.2 of this chapter) and 
at other times burn higher sulfur fuel(s) such as coal or oil, a second 
low-scale SO2 measurement range is not required when the very 
low sulfur gaseous fuel is combusted. For units that burn only gaseous 
fuel that is very low sulfur fuel and burn no other type(s) of fuel(s), 
the owner or operator shall set the span of the SO2 
monitoring system to a value no greater than 200 ppm.
    (4) The provisions in paragraph (e)(1) of this section, may also be 
used for the combustion of a solid or liquid fuel that meets the 
definition of very low sulfur fuel in Sec. 72.2 of this chapter, 
mixtures of such fuels, or combinations of such fuels with gaseous fuel, 
if the owner or operator submits a petition under Sec. 75.66 for a 
default SO2 emission rate for each fuel, mixture or 
combination, and if the Administrator approves the petition.
    (f) Other units. The owner or operator of an affected unit that 
combusts wood, refuse, or other material in addition to oil or gas shall 
comply with the monitoring provisions for coal-fired units specified in 
paragraph (a) of this section, except where the owner or operator has an 
approved petition to use the provisions of paragraph (e)(1) of this 
section.

[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26520, 26566, May 17, 
1995; 61 FR 59157, Nov. 20, 1996; 63 FR 57499, Oct. 27, 1998; 64 FR 
28590, May 26, 1999; 67 FR 40423, June 12, 2002; 73 FR 4342, Jan. 24, 
2008]



Sec. 75.12  Specific provisions for monitoring NOX emission rate.

    (a) Coal-fired units, gas-fired nonpeaking units or oil-fired 
nonpeaking units. The owner or operator shall meet the general operating 
requirements in Sec. 75.10 of this part for a NOX continuous 
emission monitoring system (CEMS) for each affected coal-fired unit, 
gas-fired nonpeaking unit, or oil-fired nonpeaking unit, except as 
provided in paragraph (d) of this section, Sec. 75.17, and subpart E of 
this part. The diluent gas monitor in the NOX-diluent CEMS 
may measure either O2 or CO2 concentration in the 
flue gases.
    (b) Moisture correction. If a correction for the stack gas moisture 
content is needed to properly calculate the NOX emission rate 
in lb/mmBtu, e.g., if the NOX pollutant concentration monitor 
measures on a different moisture basis from the diluent monitor, the 
owner or operator shall either report a fuel-specific default moisture 
value for each unit operating hour, as provided in Sec. 75.11(b)(1), or 
shall install, operate, maintain, and quality assure a continuous 
moisture monitoring system, as defined in Sec. 75.11(b)(2). 
Notwithstanding this requirement, if Equation 19-3, 19-4 or 19-8 in 
Method 19 in appendix A to part 60 of this chapter is used to measure 
NOX emission rate, the following

[[Page 221]]

fuel-specific default moisture percentages shall be used in lieu of the 
default values specified in Sec. 75.11(b)(1): 5.0%, for anthracite 
coal; 8.0% for bituminous coal; 12.0% for sub-bituminous coal; 13.0% for 
lignite coal; 15.0% for wood and 18.0% for natural gas (boilers, only).
    (c) Determination of NOX emission rate. The owner or 
operator shall calculate hourly, quarterly, and annual NOX 
emission rates (in lb/mmBtu) by combining the NOX 
concentration (in ppm), diluent concentration (in percent O2 
or CO2), and percent moisture (if applicable) measurements 
according to the procedures in appendix F to this part.
    (d) Gas-fired peaking units or oil-fired peaking units. The owner or 
operator of an affected unit that qualifies as a gas-fired peaking unit 
or oil-fired peaking unit, as defined in Sec. 72.2 of this chapter, 
based on information submitted by the designated representative in the 
monitoring plan shall comply with one of the following:
    (1) Meet the general operating requirements in Sec. 75.10 for a 
NOX continuous emission monitoring system; or
    (2) Provide information satisfactory to the Administrator using the 
procedure specified in appendix E of this part for estimating hourly 
NOX emission rate. However, if in the years after 
certification of an excepted monitoring system under appendix E of this 
part, a unit's operations exceed a capacity factor of 20 percent in any 
calendar year or exceed a capacity factor of 10.0 percent averaged over 
three years, the owner or operator shall install, certify, and operate a 
NOX-diluent continuous emission monitoring system no later 
than December 31 of the following calendar year. If the required CEMS 
has not been installed and certified by that date, the owner or operator 
shall report the maximum potential NOX emission rate (MER) 
(as defined in Sec. 72.2 of this chapter) for each unit operating hour, 
starting with the first unit operating hour after the deadline and 
continuing until the CEMS has been provisionally certified.
    (e) Low mass emissions units. Notwithstanding the requirements of 
paragraphs (a) and (d) of this section, the owner or operator of an 
affected unit that qualifies as a low mass emissions unit under Sec. 
75.19(a) and (b) shall comply with one of the following:
    (1) Meet the general operating requirements in Sec. 75.10 for a 
NOX continuous emission monitoring system;
    (2) Meet the requirements specified in paragraph (d)(2) of this 
section for using the excepted monitoring procedures in appendix E to 
this part, if applicable; or
    (3) Use the low mass emissions excepted methodology in Sec. 
75.19(c) for estimating hourly NOX emission rate and hourly 
NOX mass emissions, if applicable under Sec. 75.19(a) and 
(b). If this option is selected for NOX, the LME methodology 
must also be used for SO2 and CO2 when these 
parameters are required to be monitored by applicable program(s).
    (f) Other units. The owner or operator of an affected unit that 
combusts wood, refuse, or other material in addition to oil or gas shall 
comply with the monitoring provisions specified in paragraph (a) of this 
section.

[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26520, May 17, 1995; 63 
FR 57499, Oct. 27, 1998; 64 FR 28591, May 26, 1999; 67 FR 40423, June 
12, 2002; 73 FR 4342, Jan. 24, 2008]



Sec. 75.13  Specific provisions for monitoring CO [bdi2] emissions.

    (a) CO2 continuous emission monitoring system. If the owner or 
operator chooses to use the continuous emission monitoring method, then 
the owner or operator shall meet the general operating requirements in 
Sec. 75.10 for a CO2 continuous emission monitoring system 
and flow monitoring system for each affected unit. The owner or operator 
shall comply with the applicable provisions specified in Sec. Sec. 
75.11(a) through (e) or Sec. 75.16, except that the phrase 
``CO2 continuous emission monitoring system'' shall apply 
rather than ``SO2 continuous emission monitoring system,'' 
the phrase ``CO2 concentration'' shall apply rather than 
``SO2 concentration,'' the term ``maximum potential 
concentration of CO2'' shall apply rather than ``maximum 
potential concentration of SO2,'' and the phrase 
``CO2 mass emissions'' shall apply rather than 
``SO2 mass emissions.''
    (b) Determination of CO2 emissions using appendix G to this part. If 
the owner or operator chooses to use the

[[Page 222]]

appendix G method, then the owner or operator shall follow the 
procedures in appendix G to this part for estimating daily 
CO2 mass emissions based on the measured carbon content of 
the fuel and the amount of fuel combusted. For units with wet flue gas 
desulfurization systems or other add-on emissions controls generating 
CO2, the owner or operator shall use the procedures in 
appendix G to this part to estimate both combustion-related emissions 
based on the measured carbon content of the fuel and the amount of fuel 
combusted and sorbent-related emissions based on the amount of sorbent 
injected. The owner or operator shall calculate daily, quarterly, and 
annual CO2 mass emissions (in tons) in accordance with the 
procedures in appendix G to this part.
    (c) Determination of CO2 mass emissions using an O2 monitor 
according to appendix F to this part. If the owner or operator chooses 
to use the appendix F method, then the owner or operator shall determine 
hourly CO2 concentration and mass emissions with a flow 
monitoring system; a continuous O2 concentration monitor; 
fuel F and Fc factors; and, where O2 concentration 
is measured on a dry basis (or where Equation F-14b in appendix F to 
this part is used to determine CO2 concentration), either, a 
continuous moisture monitoring system, as specified in Sec. 
75.11(b)(2), or a fuel-specific default moisture percentage (if 
applicable), as defined in Sec. 75.11(b)(1); and by using the methods 
and procedures specified in appendix F to this part. For units using a 
common stack, multiple stack, or bypass stack, the owner or operator may 
use the provisions of Sec. 75.16, except that the phrase 
``CO2 continuous emission monitoring system'' shall apply 
rather than ``SO2 continuous emission monitoring system,'' 
the term ``maximum potential concentration of CO2'' shall 
apply rather than ``maximum potential concentration of SO2,'' 
and the phrase ``CO2 mass emissions'' shall apply rather than 
``SO2 mass emissions.''
    (d) Determination of CO2 mass emissions from low mass emissions 
units. The owner or operator of a unit that qualifies as a low mass 
emissions unit under Sec. 75.19(a) and (b) shall comply with one of the 
following:
    (1) Meet the general operating requirements in Sec. 75.10 for a 
CO2 continuous emission monitoring system and flow monitoring 
system;
    (2) Meet the requirements specified in paragraph (b) or (c) of this 
section for use of the methods in appendix G or F to this part, 
respectively; or
    (3) Use the low mass emissions excepted methodology in Sec. 
75.19(c) for estimating hourly CO2 mass emissions, if 
applicable under Sec. 75.19(a) and (b). If this option is selected for 
CO2, the LME methodology must also be used for NOX 
and SO2 when these parameters are required to be monitored by 
applicable program(s).

[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26521, May 17, 1995; 63 
FR 57499, Oct. 27, 1998; 64 FR 28591, May 26, 1999; 67 FR 40423, June 
12, 2002; 73 FR 4343, Jan. 24, 2008]



Sec. 75.14  Specific provisions for monitoring opacity.

    (a) Coal-fired units and oil-fired units. The owner or operator 
shall meet the general operating provisions in Sec. 75.10 of this part 
for a continuous opacity monitoring system for each affected coal-fired 
or oil-fired unit, except as provided in paragraphs (b), (c), and (d) of 
this section and in Sec. 75.18. Each continuous opacity monitoring 
system shall meet the design, installation, equipment, and performance 
specifications in Performance Specification 1 in appendix B to part 60 
of this chapter. Any continuous opacity monitoring system previously 
certified to meet Performance Specification 1 shall be deemed certified 
for the purposes of this part.
    (b) Unit with wet flue gas pollution control system. If the owner or 
operator can demonstrate that condensed water is present in the exhaust 
flue gas stream and would impede the accuracy of opacity measurements, 
then the owner or operator of an affected unit equipped with a wet flue 
gas pollution control system for SO2 emissions or 
particulates is exempt from the opacity monitoring requirements of this 
part.
    (c) Gas-fired units. The owner or operator of an affected unit that 
qualifies as gas-fired, as defined in Sec. 72.2 of this

[[Page 223]]

chapter, based on information submitted by the designated representative 
in the monitoring plan is exempt from the opacity monitoring 
requirements of this part. Whenever a unit previously categorized as a 
gas-fired unit is recategorized as another type of unit by changing its 
fuel mix, the owner or operator shall install, operate, and certify a 
continuous opacity monitoring system as required by paragraph (a) of 
this section by December 31 of the following calendar year.
    (d) Diesel-fired units and dual-fuel reciprocating engine units. The 
owner or operator of an affected diesel-fired unit or a dual-fuel 
reciprocating engine unit is exempt from the opacity monitoring 
requirements of this part.
    (e) Unit with a certified particulate matter (PM) monitoring system. 
If, for a particular affected unit, the owner or operator installs, 
certifies, operates, maintains, and quality-assures a continuous 
particulate matter (PM) monitoring system in accordance with Procedure 2 
in appendix F to part 60 of this chapter, the unit shall be exempt from 
the opacity monitoring requirement of this part.

[58 FR 3701, Jan. 11, 1993, as amended at 61 FR 25581, May 22, 1996; 73 
FR 4343, Jan. 24, 2008]



Sec. 75.15  [Reserved]



Sec. 75.16  Special provisions for monitoring emissions from common,
bypass, and multiple stacks for SO [bdi2] emissions and heat input
determinations.

    (a) [Reserved]
    (b) Common stack procedures. The following procedures shall be used 
when more than one unit uses a common stack:
    (1) Unit utilizing common stack with other affected unit(s). When a 
Phase I or Phase II affected unit utilizes a common stack with one or 
more other Phase I or Phase II affected units, but no nonaffected units, 
the owner or operator shall either:
    (i) Install, certify, operate, and maintain an SO2 
continuous emission monitoring system and flow monitoring system in the 
duct to the common stack from each affected unit; or
    (ii) Install, certify, operate, and maintain an SO2 
continuous emission monitoring system and flow monitoring system in the 
common stack and combine emissions for the affected units for 
recordkeeping and compliance purposes.
    (2) Unit utilizing common stack with nonaffected unit(s). When one 
or more Phase I or Phase II affected units utilizes a common stack with 
one or more nonaffected units, the owner or operator shall either:
    (i) Install, certify, operate, and maintain an SO2 
continuous emission monitoring system and flow monitoring system in the 
duct to the common stack from each Phase I and Phase II unit; or
    (ii) Install, certify, operate, and maintain an SO2 
continuous emission monitoring system and flow monitoring system in the 
common stack; and
    (A) Designate the nonaffected units as opt-in units in accordance 
with part 74 of this chapter and combine emissions for recordkeeping and 
compliance purposes; or
    (B) Install, certify, operate, and maintain an SO2 
continuous emission monitoring system and flow monitoring system in the 
duct from each nonaffected unit; determine SO2 mass emissions 
from the affected units as the difference between SO2 mass 
emissions measured in the common stack and SO2 mass emissions 
measured in the ducts of the nonaffected units, not to be reported as an 
hourly average value less than zero; combine emissions for the Phase I 
and Phase II affected units for recordkeeping and compliance purposes; 
and calculate and report SO2 mass emissions from the Phase I 
and Phase II affected units, pursuant to an approach approved by the 
Administrator, such that these emissions are not underestimated; or
    (C) Record the combined emissions from all units as the combined 
SO2 mass emissions for the Phase I and Phase II affected 
units for recordkeeping and compliance purposes; or
    (D) Petition through the designated representative and provide 
information satisfactory to the Administrator on methods for 
apportioning SO2 mass emissions measured in the common stack 
to each of the units using the common stack and on reporting the 
SO2 mass emissions. The Administrator

[[Page 224]]

may approve such demonstrated substitute methods for apportioning and 
reporting SO2 mass emissions measured in a common stack 
whenever the demonstration ensures that there is a complete and accurate 
accounting of all emissions regulated under this part and, in 
particular, that the emissions from any affected unit are not 
underestimated.
    (c) Unit with bypass stack. Whenever any portion of the flue gases 
from an affected unit can be routed through a bypass stack so as to 
avoid the installed SO2 continuous emission monitoring system 
and flow monitoring system, the owner or operator shall either:
    (1) Install, certify, operate, and maintain separate SO2 
continuous emission monitoring systems and flow monitoring systems on 
the main stack and the bypass stack and calculate SO2 mass 
emissions for the unit as the sum of the SO2 mass emissions 
measured at the two stacks; or
    (2) Monitor SO2 mass emissions at the main stack using 
SO2 and flow rate monitoring systems and measure 
SO2 mass emissions at the bypass stack using the reference 
methods in Sec. 75.22(b) for SO2 and flow rate and calculate 
SO2 mass emissions for the unit as the sum of the emissions 
recorded by the installed monitoring systems on the main stack and the 
emissions measured by the reference method monitoring systems; or
    (3) Install, certify, operate, and maintain SO2 and flow 
rate monitoring systems only on the main stack. If this option is 
chosen, report the following values for each hour during which emissions 
pass through the bypass stack: the maximum potential concentration of 
SO2 as determined under section 2.1.1.1 of appendix A to this 
part (or, if available, the SO2 concentration measured by a 
certified monitor located at the control device inlet may be reported 
instead), and the hourly volumetric flow rate value that would be 
substituted for the flow monitor installed on the main stack or flue 
under the missing data procedures in subpart D of this part if data from 
the flow monitor installed on the main stack or flue were missing for 
the hour. The maximum potential SO2 concentration may be 
specific to the type of fuel combusted in the unit during the bypass 
(see Sec. 75.33(b)(5)). The option in this paragraph, (c)(3), may only 
be used if use of the bypass stack is limited to unit startup, emergency 
situations (e.g., malfunction of a flue gas desulfurization system), and 
periods of routine maintenance of the flue gas desulfurization system or 
maintenance on the main stack. If this option is chosen, it is not 
necessary to designate the exhaust configuration as a multiple stack 
configuration in the monitoring plan required under Sec. 75.53, with 
respect to SO2 or any other parameter that is monitored only 
at the main stack. Calculate SO2 mass emissions for the unit 
as the sum of the emissions calculated with the substitute values and 
the emissions recorded by the SO2 and flow monitoring systems 
installed on the main stack.
    (d) Unit with multiple stacks or ducts. When the flue gases from an 
affected unit utilize two or more ducts feeding into two or more stacks 
(that may include flue gases from other affected or nonaffected units), 
or when the flue gases utilize two or more ducts feeding into a single 
stack and the owner or operator chooses to monitor in the ducts rather 
than the stack, the owner or operator shall either:
    (1) Install, certify, operate, and maintain an SO2 
continuous emission monitoring system and flow monitoring system in each 
duct feeding into the stack or stacks and determine SO2 mass 
emissions from each affected unit as the sum of the SO2 mass 
emissions recorded for each duct; or
    (2) Install, certify, operate, and maintain an SO2 
continuous emission monitoring system and flow monitoring system in each 
stack. Determine SO2 mass emissions from each affected unit 
as the sum of the SO2 mass emissions recorded for each stack. 
Notwithstanding the prior sentence, if another unit also exhausts flue 
gases to one or more of the stacks, the owner or operator shall also 
comply with the applicable common stack requirements of this section to 
determine and record SO2 mass emissions from the units using 
that stack and shall calculate and report SO2 mass emissions 
from the affected

[[Page 225]]

units and stacks, pursuant to an approach approved by the Administrator, 
such that these emissions are not underestimated.
    (e) Heat input rate. The owner or operator of an affected unit using 
a common stack, bypass stack, or multiple stacks shall account for heat 
input rate according to the following:
    (1) The owner or operator of an affected unit using a common stack, 
bypass stack, or multiple stack with a diluent monitor and a flow 
monitor on each stack may use the flow rate and diluent monitors to 
determine the heat input rate for the affected unit, using the 
procedures specified in paragraphs (b) through (d) of this section, 
except that the term ``heat input rate'' shall apply rather than 
``SO2 mass emissions'' or ``emissions'' and the phrase ``a 
diluent monitor and a flow monitor'' shall apply rather than 
``SO2 continuous emission monitoring system and flow 
monitoring system.'' The applicable equation in appendix F to this part 
shall be used to calculate the heat input rate from the hourly flow 
rate, diluent monitor measurements, and (if the equation in appendix F 
requires a correction for the stack gas moisture content) hourly 
moisture measurements. Notwithstanding the options for combining heat 
input rate in paragraph (b)(1)(ii) and (b)(2)(ii) of this section, the 
owner or operator of an affected unit with a diluent monitor and a flow 
monitor installed on a common stack to determine the combined heat input 
rate at the common stack shall also determine and report heat input rate 
to each individual unit, according to paragraph (e)(3) of this section.
    (2) In the event that an owner or operator of a unit with a bypass 
stack does not install and certify a diluent monitor and flow monitoring 
system in a bypass stack, the owner or operator shall determine total 
heat input rate to the unit for each unit operating hour during which 
the bypass stack is used according to the missing data provisions for 
heat input rate under Sec. 75.36 or the procedures for calculating heat 
input rate from fuel sampling and analysis in section 5.5 of appendix F 
to this part.
    (3) The owner or operator of an affected unit with a diluent monitor 
and a flow monitor installed on a common stack to determine heat input 
rate at the common stack may choose to apportion the heat input rate 
from the common stack to each affected unit utilizing the common stack 
by using either of the following two methods, provided that all of the 
units utilizing the common stack are combusting fuel with the same F-
factor found in section 3 of appendix F of this part. The heat input 
rate may be apportioned either by using the ratio of load (in MWe) for 
each individual unit to the total load for all units utilizing the 
common stack or by using the ratio of steam load (in 1000 lb/hr or 
mmBtu/hr thermal output) for each individual unit to the total steam 
load for all units utilizing the common stack, in conjunction with the 
appropriate unit and stack operating times. If using either of these 
apportionment methods, the owner or operator shall apportion according 
to section 5.6 of appendix F to this part.
    (4) Notwithstanding paragraph (e)(1) of this section, any affected 
unit that is using the procedures in this part to meet the monitoring 
and reporting requirements of a State or federal NOX mass 
emission reduction program must also meet the requirements for 
monitoring heat input rate in Sec. Sec. 75.71, 75.72 and 75.75.

[60 FR 26522, May 17, 1995, as amended at 61 FR 25582, May 22, 1996; 61 
FR 59158, Nov. 20, 1996; 64 FR 28591, May 26, 1999; 67 FR 40423, June 
12, 2002; 67 FR 53504, Aug. 16, 2002; 73 FR 4343, Jan. 24, 2008]



Sec. 75.17  Specific provisions for monitoring emissions from common,
bypass, and multiple stacks for NOX emission rate.

    Notwithstanding the provisions of paragraphs (a), (b), (c), and (d) 
of this section, the owner or operator of an affected unit that is using 
the procedures in this part to meet the monitoring and reporting 
requirements of a State or federal NOX mass emission 
reduction program must also meet the provisions for monitoring 
NOX emission rate in Sec. Sec. 75.71 and 75.72.
    (a) Unit utilizing common stack with other affected unit(s). When an 
affected unit utilizes a common stack with one

[[Page 226]]

or more affected units, but no nonaffected units, the owner or operator 
shall either:
    (1) Install, certify, operate, and maintain a NOX 
continuous emission monitoring system in the duct to the common stack 
from each affected unit; or
    (2) Install, certify, operate, and maintain a NOX 
continuous emission monitoring system in the common stack and follow the 
appropriate procedure in paragraphs (a)(2) (i) through (iii) of this 
section, depending on whether or not the units are required to comply 
with a NOX emission limitation (in lb/mmBtu, annual average 
basis) pursuant to section 407(b) of the Act (referred to hereafter as 
``NOX emission limitation'').
    (i) When each of the affected units has a NOX emission 
limitation, the designated representative shall submit a compliance plan 
to the Administrator that indicates:
    (A) Each unit will comply with the most stringent NOX 
emission limitation of any unit utilizing the common stack; or
    (B) Each unit will comply with the applicable NOX 
emission limitation by averaging its emissions with the other unit(s) 
utilizing the common stack, pursuant to the emissions averaging plan 
submitted under part 76 of this chapter; or
    (C) Each unit's compliance with the applicable NOX 
emission limit will be determined by a method satisfactory to the 
Administrator for apportioning to each of the units the combined 
NOX emission rate (in lb/mmBtu) measured in the common stack 
and for reporting the NOX emission rate, as provided in a 
petition submitted by the designated representative. The Administrator 
may approve such demonstrated substitute methods for apportioning and 
reporting NOX emission rate measured in a common stack 
whenever the demonstration ensures that there is a complete and accurate 
estimation of all emissions regulated under this part and, in 
particular, that the emissions from any unit with a NOX 
emission limitation are not underestimated.
    (ii) When none of the affected units has a NOX emission 
limitation, the owner or operator and the designated representative have 
no additional obligations pursuant to section 407 of the Act and may 
record and report a combined NOX emission rate (in lb/mmBtu) 
for the affected units utilizing the common stack.
    (iii) When at least one of the affected units has a NOX 
emission limitation and at least one of the affected units does not have 
a NOX emission limitation, the owner or operator shall 
either:
    (A) Install, certify, operate, and maintain NOX and 
diluent monitors in the ducts from the affected units; or
    (B) Develop, demonstrate, and provide information satisfactory to 
the Administrator on methods for apportioning the combined 
NOX emission rate (in lb/mmBtu) measured in the common stack 
on each of the units. The Administrator may approve such demonstrated 
substitute methods for apportioning the combined NOX emission 
rate measured in a common stack whenever the demonstration ensures 
complete and accurate estimation of all emissions regulated under this 
part.
    (b) Unit utilizing common stack with nonaffected unit(s). When one 
or more affected units utilizes a common stack with one or more 
nonaffected units, the owner or operator shall either:
    (1) Install, certify, operate, and maintain a NOX-diluent 
continuous emission monitoring system in the duct from each affected 
unit; or
    (2) Develop, demonstrate, and provide information satisfactory to 
the Administrator on methods for apportioning the combined 
NOX emission rate (in lb/mmBtu) measured in the common stack 
for each of the units. The Administrator may approve such demonstrated 
substitute methods for apportioning the combined NOX emission 
rate measured in a common stack whenever the demonstration ensures 
complete and accurate estimation of all emissions regulated under this 
part.
    (c) Unit with multiple stacks or ducts. When the flue gases from an 
affected unit discharge to the atmosphere through two or more stacks or 
when flue gases from an affected unit utilize two or more ducts feeding 
into a single stack and the owner or operator chooses to monitor in the 
ducts rather than the stack, the owner or operator shall monitor the 
NOX emission rate in a

[[Page 227]]

way that is representative of each affected unit. Where another unit 
also exhausts flue gases to one or more of the stacks where monitoring 
systems are installed, the owner or operator shall also comply with the 
applicable common stack monitoring requirements of this section. The 
owner or operator shall either:
    (1) Install, certify, operate, and maintain a NOX-diluent 
continuous emission monitoring system and a flow monitoring system in 
each stack or duct and determine the NOX emission rate for 
the unit as the Btu-weighted average of the NOX emission 
rates measured in the stacks or ducts using the heat input estimation 
procedures in appendix F to this part. Alternatively, for units that are 
eligible to use the procedures of appendix D to this part, the owner or 
operator may monitor heat input and NOX emission rate at the 
unit level, in lieu of installing flow monitors on each stack or duct. 
If this alternative unit-level monitoring is performed, report, for each 
unit operating hour, the highest emission rate measured by any of the 
NOX-diluent monitoring systems installed on the individual 
stacks or ducts as the hourly NOX emission rate for the unit, 
and report the hourly unit heat input as determined under appendix D to 
this part. Also, when this alternative unit-level monitoring is 
performed, the applicable NOX missing data procedures in 
Sec. Sec. 75.31 or 75.33 shall be used for each unit operating hour in 
which a quality-assured NOX emission rate is not obtained for 
one or more of the individual stacks or ducts; or
    (2) Provided that the products of combustion are well-mixed, 
install, certify, operate, and maintain a NOX continuous 
emission monitoring system in one stack or duct from the affected unit 
and record the monitored value as the NOX emission rate for 
the unit. The owner or operator shall account for NOX 
emissions from the unit during all times when the unit combusts fuel. 
Therefore, this option shall not be used if the monitored stack or duct 
can be bypassed (e.g., by using dampers). Follow the procedure in Sec. 
75.17(d) for units with bypass stacks. Further, this option shall not be 
used unless the monitored NOX emission rate truly represents 
the NOX emissions discharged to the atmosphere (e.g., the 
option is disallowed if there are any additional NOX emission 
controls downstream of the monitored location).
    (d) Unit with a main stack and bypass stack configuration. For an 
affected unit with a discharge configuration consisting of a main stack 
and a bypass stack, the owner or operator shall either:
    (1) Follow the procedures in paragraph (c)(1) of this section; or
    (2) Install, certify, operate, and maintain a NOX-diluent 
CEMS only on the main stack. If this option is chosen, it is not 
necessary to designate the exhaust configuration as a multiple stack 
configuration in the monitoring plan required under Sec. 75.53, with 
respect to NOX or any other parameter that is monitored only 
at the main stack. For each unit operating hour in which the bypass 
stack is used and the emissions are either uncontrolled (or the add-on 
controls are not documented to be operating properly), report the 
maximum potential NOX emission rate (as defined in Sec. 72.2 
of this chapter). The maximum potential NOX emission rate may 
be specific to the type of fuel combusted in the unit during the bypass 
(see Sec. 75.33(c)(8)). Alternatively, for a unit with NOX 
add-on emission controls, for each unit operating hour in which the 
bypass stack is used and the add-on NOX emission controls are 
not bypassed, the owner or operator may report the maximum controlled 
NOX emission rate (MCR) instead of the maximum potential 
NOX emission rate provided that the add-on controls are 
documented to be operating properly, as described in the quality 
assurance/quality control program for the unit, required by section 1 in 
appendix B of this part. To provide the necessary documentation, the 
owner or operator shall record parametric data to verify the proper 
operation of the NOX add-on emission controls as described in 
Sec. 75.34(d). Furthermore, the owner or operator shall calculate the 
MCR using the procedure described in section 2.1.2.1(b) of appendix A to 
this part where the words ``maximum potential NOX emission 
rate (MER)'' shall apply

[[Page 228]]

instead of the words ``maximum controlled NOX emission rate 
(MCR)'' and by using the NOX MEC in the calculations instead 
of the NOX MPC.

[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26523, May 17, 1995; 63 
FR 57499, Oct. 27, 1998; 64 FR 28592, May 26, 1999; 67 FR 40424, June 
12, 2002; 73 FR 4343, Jan. 24, 2008]



Sec. 75.18  Specific provisions for monitoring emissions from common
and by-pass stacks for opacity.

    (a) Unit using common stack. When an affected unit utilizes a common 
stack with other affected units or nonaffected units, the owner or 
operator shall comply with the applicable monitoring provision in this 
paragraph, as determined by existing Federal, State, or local opacity 
regulations.
    (1) Where another regulation requires the installation of a 
continuous opacity monitoring system upon each affected unit, the owner 
or operator shall install, certify, operate, and maintain a continuous 
opacity monitoring system meeting Performance Specification 1 in 
appendix B to part 60 of this chapter (referred to hereafter as a 
``certified continuous opacity monitoring system'') upon each unit.
    (2) Where another regulation does not require the installation of a 
continuous opacity monitoring system upon each affected unit, and where 
the affected source is not subject to any existing Federal, State, or 
local opacity regulations, the owner or operator shall install, certify, 
operate, and maintain a certified continuous opacity monitoring system 
upon each common stack for the combined effluent.
    (b) Unit using bypass stack. Where any portion of the flue gases 
from an affected unit can be routed so as to bypass the installed 
continuous opacity monitoring system, the owner or operator shall 
install, certify, operate, and maintain a certified continuous opacity 
monitoring system on each bypass stack flue, duct, or stack gas stream 
unless either:
    (1) An applicable Federal, State, or local opacity regulation or 
permit exempts the unit from a requirement to install a continuous 
opacity monitoring system in the bypass stack; or
    (2) A continuous opacity monitoring system is already installed and 
certified at the inlet of the add-on emissions controls.
    (3) The owner or operator monitors opacity using method 9 of 
appendix A of part 60 of this chapter whenever emissions pass through 
the bypass stack. Method 9 shall be used in accordance with the 
applicable State regulations.

[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26524, May 17, 1995; 60 
FR 40296, Aug. 8, 1995; 61 FR 59158, Nov. 20, 1996]



Sec. 75.19  Optional SO [bdi2], NO X, and CO [bdi2] emissions
calculation for low mass emissions (LME) units.

    (a) Applicability and qualification. (1) For units that meet the 
requirements of this paragraph (a)(1) and paragraphs (a)(2) and (b) of 
this section, the low mass emissions (LME) excepted methodology in 
paragraph (c) of this section may be used in lieu of continuous emission 
monitoring systems or, if applicable, in lieu of methods under 
appendices D, E, and G to this part, for the purpose of determining unit 
heat input, NOX, SO2, and CO2 mass 
emissions, and NOX emission rate under this part. If the 
owner or operator of a qualifying unit elects to use the LME 
methodology, it must be used for all parameters that are required to be 
monitored by the applicable program(s). For example, for an Acid Rain 
Program LME unit, the methodology must be used to estimate 
SO2, NOX, and CO2 mass emissions, 
NOX emission rate, and unit heat input.
    (i) A low mass emissions unit is an affected unit that is gas-fired, 
or oil-fired (as defined in Sec. 72.2 of this chapter), and for which:
    (A) An initial demonstration is provided, in accordance with 
paragraph (a)(2) of this section, which shows that the unit emits:
    (1) No more than 25 tons of SO2 annually and less than 
100 tons of NOX annually, for Acid Rain Program affected 
units. If the unit is also subject to the provisions of subpart H of 
this part, no more than 50 of the allowable annual tons of 
NOX may be emitted during the ozone season; or
    (2) Less than 100 tons of NOX annually and no more than 
50 tons of NOX during the ozone season, for non-Acid

[[Page 229]]

Rain Program units subject to the provisions of subpart H of this part, 
for which the owner or operator reports emissions data on a year-round 
basis, in accordance with Sec. 75.74(a) or Sec. 75.74(b); or
    (3) No more than 50 tons of NOX per ozone season, for 
non-Acid Rain Program units subject to the provisions of subpart H of 
this part, for which the owner or operator reports emissions data only 
during the ozone season, in accordance with Sec. 75.74(b); and
    (B) An annual demonstration is provided thereafter, using one of the 
allowable methodologies in paragraph (c) of this section, showing that 
the low mass emissions unit continues to emit no more than the 
applicable number of tons of SO2 and/or NOX 
specified in paragraph (a)(1)(i)(A) of this section.
    (C) This paragraph, (a)(1)(i)(C), applies only to a unit that is 
subject to an SO2 emission limitation under the Acid Rain 
Program, and that combusts a gaseous fuel other than pipeline natural 
gas or natural gas (as defined in Sec. 72.2 of this chapter). The owner 
or operator of such a unit must quantify the sulfur content and 
variability of the gaseous fuel by performing the demonstration 
described in section 2.3.6 of appendix D to this part, in order for the 
unit to qualify for LME unit status. If the results of that 
demonstration show that the gaseous fuel qualifies under paragraph (b) 
of section 2.3.6 to use a default SO2 emission rate to report 
SO2 mass emissions under this part, the unit is eligible for 
LME unit status.
    (ii) Each qualifying LME unit must start using the low mass 
emissions excepted methodology as follows:
    (A) For a unit that reports emission data on a year-round basis, 
begin using the methodology in the first unit operating hour in the 
calendar year designated in the certification application as the first 
year that the methodology will be used; or
    (B) For a unit that is subject to Subpart H of this part and that 
reports only during the ozone season according to Sec. 75.74(c), begin 
using the methodology in the first unit operating hour in the ozone 
season designated in the certification application as the first ozone 
season that the methodology will be used.
    (C) For a new or newly-affected unit, see paragraph (b)(4) of this 
section for additional guidance.
    (2) A unit may initially qualify as a low mass emissions unit if the 
designated representative submits a certification application to use the 
LME methodology (as described in Sec. 75.63(a)(1)(ii) and in this 
paragraph, (a)(2)) and the Administrator (or permitting authority, as 
applicable) certifies the use of such methodology. The certification 
application shall be submitted no later than 45 days prior to the date 
on which use of the low mass emissions methodology is expected to 
commence, and the application must contain:
    (i) A statement identifying the projected date on which the LME 
methodology will first be used. The projected commencement date shall be 
consistent with paragraphs (a)(1)(ii) and (b)(4) of this section, as 
applicable; and
    (ii) Either:
    (A) Actual SO2 and/or NOX mass emissions data 
(as applicable) for each of the three calendar years (or ozone seasons) 
prior to the calendar year in which the certification application is 
submitted demonstrating to the satisfaction of the Administrator or (if 
applicable) the permitting authority, that the unit emitted less than 
the applicable number of tons of SO2 and/or NOX 
specified in paragraph (a)(1)(i)(A) of this section. For the purposes of 
this paragraph, (a)(2)(ii)(A), the required actual SO2 or 
NOX mass emissions for each qualifying year or ozone season 
shall be determined using the SO2, NOX and heat 
input data reported to the Administrator in the electronic quarterly 
reports required under Sec. 75.64 or under the Ozone Transport 
Commission (OTC) NOX Budget Trading Program. Notwithstanding 
this requirement, in the absence of such electronic reports, an estimate 
of the actual emissions for each of the previous three years (or ozone 
seasons) shall be provided, using either the maximum rated heat input 
methodology described in paragraph (c)(3)(i) of this section or 
procedures consistent with the long term fuel flow heat input 
methodology described in paragraph (c)(3)(ii) of this section, in

[[Page 230]]

conjunction with the appropriate SO2 or NOX 
emission rate from paragraph (c)(1)(i) of this section for 
SO2, and paragraph (c)(1)(ii) or (c)(1)(iv) of this section 
for NOX. Alternatively, the initial estimate of the 
NOX emission rate may be based on historical emission test 
data that is representative of operation at normal load or historical 
data from a CEMS certified under part 60 of this chapter or under a 
state CEM program; or
    (B) When the three full years (or ozone seasons) of actual 
SO2 and NOX mass emissions data (or reliable 
estimates thereof) described under paragraph (a)(2)(ii)(A) of this 
section do not exist, the designated representative may submit an 
application to use the low mass emissions excepted methodology based 
upon a combination of actual historical SO2 and 
NOX mass emissions data and projected SO2 and 
NOX mass emissions, totaling three years (or ozone seasons). 
Except as provided in paragraph (a)(3) of this section, actual data must 
be used for any years (or ozone seasons) in which such data exists and 
projected data should be used for any remaining future years (or ozone 
seasons) needed to provide emissions data for three consecutive calendar 
years (or ozone seasons). For example, if a unit commenced operation two 
years ago, the designated representative may submit actual, historical 
data for the previous two years and one year of projected emissions for 
the current calendar year or, for a new unit, the designated 
representative may submit three years of projected emissions, beginning 
with the current calendar year. Any actual or projected annual emissions 
must demonstrate to the satisfaction of the Administrator that the unit 
will emit less than the applicable number of tons of SO2 and/
or NOX specified in paragraph (a)(1)(i)(A) of this section. 
Projected emissions shall be calculated using either the appropriate 
default emission rates from paragraphs (c)(1)(i) and (c)(1)(ii) of this 
section (or, alternatively for NOX, a conservative estimate 
of the NOX emission rate, as described in paragraph (a)(4) of 
this section), in conjunction with projections of unit operating hours 
or fuel type and fuel usage, according to one of the allowable 
calculation methodologies in paragraph (c) of this section; and
    (iii) A description of the methodology from paragraph (c) of this 
section that will be used to demonstrate on-going compliance under 
paragraph (b) of this section; and
    (iv) Appropriate documentation demonstrating that the unit is 
eligible to use projected emissions to qualify for LME status under 
paragraph (a)(3) of this section (if applicable).
    (3) In the following circumstances, projected emissions for a future 
year (or years) may be used in lieu of the actual emissions data from 
one (or more) of the three years (or ozone seasons) preceding the year 
of the certification application:
    (i) If the owner or operator takes an enforceable permit restriction 
on the number of annual or ozone season unit operating hours for the 
future year (or years), such that the unit will emit no more than the 
applicable number of tons of SO2 and/or NOX 
specified in paragraph (a)(1)(i)(A) of this section; or
    (ii) If the actual emissions for one (or more) of the three years 
(or ozone seasons) prior to the year of the certification application is 
not representative of the present and expected future emissions from the 
unit, because the owner or operator has recently installed emission 
controls on the unit.
    (4) When the owner or operator elects to demonstrate initial LME 
qualification and on-going compliance using a fuel-and-unit-specific 
NOX emission rate in accordance with paragraph (c)(1)(iv) of 
this section, there will be instances (e.g., for a new or newly-affected 
unit) where it is not possible to determine that NOX emission 
rate prior to submitting the certification application. In such cases, 
if the generic default NOX emission rates in Table LM-2 of 
this section are inappropriately high for the unit, the owner or 
operator may use a more representative, but conservatively high estimate 
of the expected NOX emission rate, for the purposes of the 
initial monitoring plan submittal and to calculate the unit's projected 
annual or ozone season emissions under paragraph (a)(2)(ii)(B) of this 
section. For example, the NOX emission rate could, as 
described in paragraph (a)(2)(ii)(A) of this section,

[[Page 231]]

be estimated using historical CEM data or historical emission test data 
that is representative of operation at normal load. The NOX 
emission limit specified in the operating permit for the unit could also 
be used to estimate the NOX emission rate (except for units 
equipped with SCR or SNCR), or, consistent with paragraph 
(c)(1)(iv)(C)(4) of this section, for a unit that uses SCR or SNCR to 
control NOX emissions, an estimated default NOX 
emission rate of 0.15 lb/mmBtu could be used. However, these estimated 
NOX emission rates may not be used for reporting purposes in 
the time period extending from the first hour in which the LME 
methodology is used to the date and hour on which the fuel-and-unit-
specific NOX emission rate testing is completed. Rather, in 
that interval, the owner or operator shall either report the appropriate 
default NOX emission rate from Table LM-2, or shall report 
the maximum potential NOX emission rate, calculated in 
accordance with Sec. 72.2 of this chapter and section 2.1.2.1 of 
appendix A to this part. Then, beginning with the first unit operating 
hour after completion of the tests, the appropriate default 
NOX emission rate(s) obtained from the fuel-and-unit-specific 
testing shall be used for emissions reporting.
    (b) On-going qualification and disqualification. (1) Once a low mass 
emissions unit has qualified for and has started using the low mass 
emissions excepted methodology, an annual demonstration is required, 
showing that the unit continues to emit no more than the applicable 
number of tons of SO2 and/or NOX specified in 
paragraph (a)(1)(i)(A) of this section. The calculation methodology used 
for the annual demonstration shall be the methodology described in the 
certification application under paragraph (a)(2)(iii) of this section.
    (2) If any low mass emissions unit fails to provide the required 
annual demonstration under paragraph (b)(1) of this section, such that 
the calculated cumulative emissions for the unit exceed the applicable 
number of tons of SO2 and/or NOX specified in 
paragraph (a)(1)(i)(A) of this section at the end of any calendar year 
or ozone season, then:
    (i) The low mass emissions unit shall be disqualified from using the 
low mass emissions excepted methodology; and
    (ii) The owner or operator of the low mass emissions unit shall 
install and certify monitoring systems that meet the requirements of 
Sec. Sec. 75.11, 75.12, and 75.13, and shall report SO2 
(Acid Rain Program units, only), NOX, and CO2 
(Acid Rain Program units, only) emissions data and heat input data from 
such monitoring systems by December 31 of the calendar year following 
the year in which the unit exceeded the number of tons of SO2 
and/or NOX specified in paragraph (a)(1)(i)(A) of this 
section; and
    (iii) If the required monitoring systems have not been installed and 
certified by the applicable deadline in paragraph (b)(2)(ii) of this 
section, the owner or operator shall report the following values for 
each unit operating hour, beginning with the first operating hour after 
the deadline and continuing until the monitoring systems have been 
provisionally certified: the maximum potential hourly heat input for the 
unit, as defined in Sec. 72.2 of this chapter; the SO2 
emissions, in lb/hr, calculated using the applicable default 
SO2 emission rate from paragraph (c)(1)(i) of this section 
and the maximum potential hourly unit heat input; the CO2 
emissions, in tons/hr, calculated using the applicable default 
CO2 emission rate from paragraph (c)(1)(iii) of this section 
and the maximum potential hourly unit heat input; and the maximum 
potential NOX emission rate, as defined in Sec. 72.2 of this 
chapter.
    (3) If a low mass emissions unit that initially qualifies to use the 
low mass emissions excepted methodology under this section changes 
fuels, such that a fuel other than those allowed for use in the low mass 
emissions methodology is combusted in the unit, the unit shall be 
disqualified from using the low mass emissions excepted methodology as 
of the first hour that the new fuel is combusted in the unit. The owner 
or operator shall install and certify SO2 (Acid Rain Program 
units, only), NOX, and CO2 (Acid Rain Program 
units, only) and flow (if necessary) monitoring systems that meet the 
requirements of Sec. Sec. 75.11, 75.12, and 75.13 prior to a change

[[Page 232]]

to such fuel, and shall report emissions data from such monitoring 
systems beginning with the date and hour on which the new fuel is first 
combusted in the unit. If the required monitoring systems are not 
installed and certified prior to the fuel switch, the owner or operator 
shall report (as applicable) the maximum potential concentration of 
SO2, CO2 and NOX, the maximum potential 
NOX emission rate, the maximum potential flowrate, the 
maximum potential hourly heat input and the maximum (or minimum, if 
appropriate) potential moisture percentage, from the date and hour of 
the fuel switch until the monitoring systems are certified or until 
probationary calibration error tests of the monitors are passed and the 
conditional data validation procedures in Sec. 75.20(b)(3) begin to be 
used. All maximum and minimum potential values shall be specific to the 
new fuel and shall be determined in a manner consistent with section 2 
of appendix A to this part and Sec. 72.2 of this chapter. The owner or 
operator must notify the Administrator (or the permitting authority) in 
the case where a unit switches fuels without previously having installed 
and certified a SO2, NOX and CO2 
monitoring system meeting the requirements of Sec. Sec. 75.11, 75.12, 
and 75.13.
    (4) If a new of newly-affected unit initially qualifies to use the 
low mass emissions excepted methodology under this section and the owner 
or operator wants to use the low mass emissions methodology for the 
unit, he or she must:
    (i) Keep the records specified in paragraph (c)(2) of this section, 
beginning with the date and hour of commencement of commercial 
operation, for a new unit subject to an Acid Rain emission limitation, 
and beginning with the date and hour of the commencement of operation, 
for a new unit subject to a NOX mass reduction program under 
subpart H of this part. For newly-affected units, the records in 
paragraph (c)(2) of this section shall be kept as follows:
    (A) For Acid Rain Program units, begin keeping the records as of the 
first hour of commercial operation of the unit following the date on 
which the unit becomes affected; or
    (B) For units subject to a NOX mass reduction program 
under subpart H of this part, begin keeping the records as of the first 
hour of unit operation following the date on which the unit becomes an 
affected unit;
    (ii) Use these records to determine the cumulative heat input and 
SO2, CO2, and/or NOX mass emissions in 
order to continue to qualify as a low mass emissions unit; and
    (iii) Determine the cumulative SO2 and/or NOX 
mass emissions according to paragraph (c) of this section using the same 
procedures used after the certification deadline for the unit, for 
purposes of demonstrating eligibility to use the excepted methodology 
set forth in this section. For example, use the default emission rates 
in Tables LM-1, LM-2, and LM-3 of this section or use the fuel-and-unit-
specific NOX emission rate determined according to paragraph 
(c)(1)(iv) of this section. For Acid Rain Program LME units, the 
Administrator will not count SO2 mass emissions calculated 
for the period between commencement of commercial operation and the 
certification deadline for the unit under Sec. 75.4 against 
SO2 allowances to be held in the unit account.
    (5) A low mass emissions unit that has been disqualified from using 
the low mass emissions excepted methodology may subsequently submit an 
application to qualify again to use the low mass emissions methodology 
under paragraph (a)(2) of this section only if, following the non-
compliant year (or ozone season), at least three full years (or ozone 
seasons) of actual, monitored emissions data is obtained showing that 
the unit emitted no more than the applicable number of tons of 
SO2 and/or NOX specified in paragraph (a)(1)(i)(A) 
of this section. Further, the designated representative or authorized 
account representative must certify in the application that the unit 
operation for the years or ozone seasons for which the emissions were 
monitored are representative of the projected future operation of the 
unit.
    (c) Low mass emissions excepted methodology, calculations, and 
values--(1) Determination of SO2, NOX, and CO2 emission rates.
    (i) If the unit combusts only natural gas and/or fuel oil, use Table 
LM-1 of

[[Page 233]]

this section to determine the appropriate SO2 emission rate 
for use in calculating hourly SO2 mass emissions under this 
section. Alternatively, for fuel oil combustion, a lower, fuel-specific 
SO2 emission factor may be used in lieu of the applicable 
emission factor from Table LM-1, if a federally enforceable permit 
condition is in place that limits the sulfur content of the oil. If this 
alternative is chosen, the fuel-specific SO2 emission rate in 
lb/mmBtu shall be calculated by multiplying the fuel sulfur content 
limit (weight percent sulfur) by 1.01. In addition, the owner or 
operator shall periodically determine the sulfur content of the oil 
combusted in the unit, using one of the oil sampling and analysis 
options described in section 2.2 of appendix D to this part, and shall 
keep records of these fuel sampling results in a format suitable for 
inspection and auditing. Alternatively, the required oil sampling and 
associated recordkeeping may be performed using a consensus standard 
(e.g., ASTM, API, etc.) that is prescribed in the unit's Federally-
enforceable operating permit, in an applicable State regulation, or in 
another applicable Federal regulation. If the unit combusts gaseous 
fuel(s) other than natural gas, the owner or operator shall use the 
procedures in section 2.3.6 of appendix D to this part to document the 
total sulfur content of each such fuel and to determine the appropriate 
default SO2 emission rate for each such fuel.
    (ii) If the unit combusts only natural gas and/or fuel oil, use 
either the appropriate NOX emission factor from Table LM-2 of 
this section, or a fuel-and-unit-specific NOX emission rate 
determined according to paragraph (c)(1)(iv) of this section, to 
calculate hourly NOX mass emissions under this section. If 
the unit combusts a gaseous fuel other than pipeline natural gas or 
natural gas, the owner or operator shall determine a fuel-and-unit-
specific NOX emission rate according to paragraph (c)(1)(iv) 
of this section.
    (iii) If the unit combusts only natural gas and/or fuel oil, use 
Table LM-3 of this section to determine the appropriate CO2 
emission rate for use in calculating hourly CO2 mass 
emissions under this section (Acid Rain Program units, only). If the 
unit combusts a gaseous fuel other than pipeline natural gas or natural 
gas, the owner or operator shall determine a fuel-and-unit-specific 
CO2 emission rate for the fuel, as follows:
    (A) Derive a carbon-based F-factor for the fuel, using fuel sampling 
and analysis, as described in section 3.3.6 of appendix F to this part; 
and
    (B) Use Equation G-4 in appendix G to this part to derive the 
default CO2 emission rate. Rearrange the equation, solving it 
for the ratio of WCO2/H (this ratio will yield an emission 
rate, in units of tons/mmBtu). Then, substitute the carbon-based F-
factor determined in paragraph (c)(1)(iii)(A) of this section into the 
rearranged equation to determine the default CO2 emission 
rate for the unit.
    (iv) In lieu of using the default NOX emission rate from 
Table LM-2 of this section, the owner or operator may, for each fuel 
combusted by a low mass emissions unit, determine a fuel-and-unit-
specific NOX emission rate for the purpose of calculating 
NOX mass emissions under this section. This option may be 
used by any unit which qualifies to use the low mass emission excepted 
methodology under paragraph (a) of this section, and also by groups of 
units which combust fuel from a common source of supply and which use 
the long term fuel flow methodology under paragraph (c)(3)(ii) of this 
section to determine heat input. The testing must be completed in a 
timely manner, such that the test results are reported electronically no 
later than the end of the calendar year or ozone season in which the LME 
methodology is first used. If this option is chosen, the following 
procedures shall be used.
    (A) Except as otherwise provided in paragraphs (c)(1)(iv)(F), 
(c)(1)(iv)(G), and (c)(1)(iv)(I) of this section, determine a fuel-and-
unit-specific NOX emission rate by conducting a four load 
NOX emission rate test procedure as specified in section 2.1 
of appendix E to this part, for each type of fuel combusted in the unit. 
For a group of units sharing a common fuel supply, the appendix E 
testing must be performed on each individual unit in the group, unless 
some or all of the units in the group belong to an identical group of

[[Page 234]]

units, as defined in paragraph (c)(1)(iv)(B) of this section, in which 
case, representative testing may be conducted on units in the identical 
group of units, as described in paragraph (c)(1)(iv)(B) of this section. 
For the purposes of this section, make the following modifications to 
the appendix E test procedures:
    (1) Do not measure the heat input as required under 2.1.3 of 
appendix E to this part.
    (2) Do not plot the test results as specified under 2.1.6 of 
appendix E to this part.
    (3) Do not correct the NOX concentration to 15% 
O2.
    (4) If the testing is performed on an uncontrolled diffusion flame 
turbine, a correction to the observed average NOX 
concentration from each run of the test must be applied using the 
following Equation LM-1a.
[GRAPHIC] [TIFF OMITTED] TR12JN02.000

Where:

NOXcorr = Corrected NOX concentration (ppm).
NOXobs = Average measured NOX concentration for 
          each run of the test (ppm).
Pr = Average annual atmospheric pressure (or average ozone 
          season atmospheric pressure for a Subpart H unit that reports 
          data only during the ozone season) at the nearest weather 
          station (e.g., a standardized NOAA weather station located at 
          the airport) for the year (or ozone season) prior to the year 
          of the test (mm Hg).
Po = Observed atmospheric pressure during the test run (mm 
          Hg).
Hr = Average annual atmospheric humidity ratio (or average 
          ozone season humidity ratio for a Subpart H unit that reports 
          data only during the ozone season) at the nearest weather 
          station, for the year (or ozone season) prior to the year of 
          the test (g H2O/g air).
Ho = Observed humidity ratio during the test run (g 
          H2O/g air).
Tr = Average annual atmospheric temperature (or average ozone 
          season atmospheric temperature for a Subpart H unit that 
          reports data only during the ozone season) at the nearest 
          weather station, for the year (or ozone season) prior to the 
          year of the test ( K).
Ta = Observed atmospheric temperature during the test run ( 
          K).

    (B) Representative appendix E testing may be done on low mass 
emission units in a group of identical units. All of the units in a 
group of identical units must combust the same fuel type but do not have 
to share a common fuel supply.
    (1) To be considered identical, all low mass emission units must be 
of the same size (based on maximum rated hourly heat input), 
manufacturer and model, and must have the same history of modifications 
(e.g., have the same controls installed, the same types of burners and 
have undergone major overhauls at the same frequency (based on hours of 
operation)). Also, under similar operating conditions, the stack or 
turbine outlet temperature of each unit must be within [50 degrees 
Fahrenheit of the average stack or turbine outlet temperature for all of 
the units.
    (2) If all of the low mass emission units in the group qualify as 
identical, then representative testing of the units in the group may be 
performed according to Table LM-4 of this section.
    (3) [Reserved]
    (4) If the acceptance criteria in paragraph (c)(1)(iv)(B)(1) of this 
section are not met then the group of low mass emission units is not 
considered an identical group of units and individual appendix E testing 
of each unit is required.
    (5) Fuel and unit specific NOX emission rates determined 
according to paragraphs (c)(1)(iv)(F) and (c)(1)(iv)(G) of this section 
may be used in lieu of appendix E testing for one or more low mass 
emission units in a group of identical units.
    (C) Based on the results of the part 75 appendix E testing, 
determine the fuel-and-unit-specific NOX emission rate as 
follows:

[[Page 235]]

    (1) Except for LME units that use selective catalytic reduction 
(SCR) or selective non-catalytic reduction (SNCR) to control 
NOX emissions, the highest three-run average NOX 
emission rate obtained at any load in the appendix E test for a 
particular type of fuel shall be the fuel-and-unit-specific 
NOX emission rate, for that type of fuel.
    (2) [Reserved]
    (3) For a group of identical low mass emissions units (except for 
units that use SCR or SNCR to control NOX emissions), the 
fuel-and-unit-specific NOX emission rate for all units in the 
group, for a particular type of fuel, shall be the highest three-run 
average NOX emission rate obtained at any tested load from 
any unit tested in the group, for that type of fuel.
    (4) Except as provided in paragraphs (c)(1)(iv)(C)(7) and 
(c)(1)(iv)(C)(8) of this section, for an individual low mass emissions 
unit which uses SCR or SNCR to control NOX emissions, the 
fuel-and-unit-specific NOX emission rate for each type of 
fuel combusted in the unit shall be the higher of:
    (i) The highest three-run average emission rate from any load of the 
appendix E test for that type of fuel; or
    (ii) 0.15 lb/mmBtu.
    (5) [Reserved]
    (6) Except as provided in paragraphs (c)(1)(iv)(C)(7) and 
(c)(1)(iv)(C)(8) of this section, for a group of identical low mass 
emissions units that are all equipped with SCR or SNCR to control 
NOX emissions, the fuel-and-unit-specific NOX 
emission rate for each unit in the group of units, for a particular type 
of fuel, shall be the higher of:
    (i) The highest three-run average NOX emission rate at 
any load from all appendix E tests of all tested units in the group, for 
that type of fuel; or
    (ii) 0.15 lb/mmBtu.
    (7) Notwithstanding the requirements of paragraphs (c)(1)(iv)(C)(4) 
and (c)(1)(iv)(C)(6) of this section, for a unit (or group of identical 
units) equipped with SCR (or SNCR) and water (or steam) injection to 
control NOX emissions:
    (i) If the appendix E testing is performed when the water (or steam) 
injection is in use and either upstream of the SCR or SNCR or during a 
time period when the SCR or SNCR is out of service; then
    (ii) The highest three-run average emission rate from the appendix E 
testing may be used as the fuel-and-unit-specific NOX 
emission rate for the unit (or, if applicable, for each unit in the 
group), for each unit operating hour in which the water-to-fuel ratio is 
within the acceptable range established during the appendix E testing.
    (8) Notwithstanding the requirements of paragraphs (c)(1)(iv)(C)(4) 
and (c)(1)(iv)(C)(6) of this section, for a unit (or group of identical 
units) equipped with SCR (or SNCR) and uses dry low-NOX 
technology to control NOX emissions:
    (i) If the appendix E testing is performed during a time period when 
the dry low-NOX controls are in use, but the SCR or SNCR is 
out of service; then
    (ii) The highest three-run average emission rate from the appendix E 
testing may be used as the fuel-and-unit-specific NOX 
emission rate for the unit (or, if applicable, for each unit in the 
group), for each unit operating hour in which the parametric data 
described in paragraph (c)(1)(iv)(H)(2) of this section demonstrate that 
the dry low-NOX controls are operating in the premixed or 
low-NOX mode.
    (9) For an individual combustion turbine (or a group of identical 
turbines) that operate principally at base load (or at a set point 
temperature), but are capable of operating at a higher peak load (or 
higher internal operating temperature), the fuel-and-unit-specific 
NOX emission rate for the unit (or for each unit in the 
group) shall be as follows:
    (i) If the testing is done only at base load, use the three-run 
average NOX emission rate for base load operating hours and 
1.15 times that emission rate for peak load operating hours; or
    (ii) If the testing is done at both base load and peak load, use the 
three-run average NOX emission rate from the base load 
testing for base load operating hours and the three-run average 
NOX emission rate from the peak load testing for peak load 
operating hours.
    (D) For each low mass emissions unit, or group of identical units 
for which the provisions of paragraph

[[Page 236]]

(c)(1)(iv) of this section are used to account for NOX 
emission rate, the owner or operator shall determine a new fuel-and-
unit-specific NOX emission rate every five years (20 calendar 
quarters), unless changes in the fuel supply, physical changes to the 
unit, changes in the manner of unit operation, or changes to the 
emission controls occur which may cause a significant increase in the 
unit's actual NOX emission rate. If such changes occur, the 
fuel-and-unit-specific NOX emission rate(s) shall be re-
determined according to paragraph (c)(1)(iv) of this section. Testing 
shall be done at the number of loads specified in paragraph 
(c)(1)(iv)(A) or (c)(1)(iv)(I) of this section, as applicable. If a low 
mass emissions unit belongs to a group of identical units and it is 
required to retest to determine a new fuel-and-unit-specific 
NOX emission rate because of changes in the fuel supply, 
physical changes to the unit, changes in the manner of unit operation or 
changes to the emission controls occur which may cause a significant 
increase in the unit's actual NOX emission rate, any other 
unit in that group of identical units is not required to re-determine 
the fuel-and-unit-specific NOX emission rate unless such unit 
also undergoes changes in the fuel supply, physical changes to the unit, 
changes in the manner of unit operation or changes to the emission 
controls occur which may cause a significant increase in the unit's 
actual NOX emission rates.
    (E) Each low mass emissions unit or each low mass emissions unit in 
a group of identical units for which a fuel-and-unit-specific 
NOX emission rate(s) are determined shall meet the quality 
assurance and quality control provisions of paragraph (e) of this 
section.
    (F) Low mass emission units may use the results of appendix E 
testing, if such test results are available from a test conducted no 
more than five years prior to the time of initial certification, to 
determine the appropriate fuel-and-unit-specific NOX emission 
rate(s). However, fuel-and-unit-specific NOX emission rates 
from historical testing may not be used longer than five years after the 
appendix E testing was conducted.
    (G) Low mass emissions units for which at least 3 years of quality-
assured NOX emission rate data from a NOX-diluent 
CEMS that meets the quality assurance requirements of either: this part, 
or appendix F to part 60 of this chapter, or a comparable State CEM 
program, and corresponding fuel usage data are available may determine 
fuel-and-unit-specific NOX emission rates from the actual 
data using the following procedure. Separate the actual NOX 
emission rate data into groups, according to the type of fuel combusted. 
Discard data from periods when multiple fuels were combusted. Each fuel-
specific data set must contain at least 168 hours of data and must 
represent all normal operating ranges of the unit when combusting the 
fuel. Sort the data in each fuel-specific data set in ascending order 
according to NOX emission rate. Determine the 95th percentile 
NOX emission rate for each data set as defined in Sec. 72.2 
of this chapter. Use the 95th percentile value for each data set as the 
fuel-and-unit-specific NOX emission rate, except that for a 
unit that uses SCR or SNCR for NOX emission control, if the 
95th percentile value is less than 0.15 lb/mmBtu, a value of 0.15 lb/
mmBtu shall be used as the fuel-and-unit-specific NOX 
emission rate.
    (H) For low mass emission units with add-on NOX emission 
controls, and for units that use dry low-NOX technology, the 
owner or operator shall, during every hour of unit operation during the 
test period, monitor and record parameters, as required under paragraph 
(e)(5) of this section, which indicate that the NOX emission 
controls are operating properly. After the test period, these same 
parameters shall be monitored and recorded and kept for all operating 
hours in order to determine whether the NOX controls are 
operating properly and to allow the determination of the correct 
NOX emission rate as required under paragraph (c)(1)(iv) of 
this section.
    (1) For low mass emission units with steam or water injection, the 
steam-to-fuel or water-to-fuel ratio used during the testing must be 
documented. The water-to-fuel or steam-to-fuel ratio must be maintained 
during unit operations for a unit to use the fuel and

[[Page 237]]

unit specific NOX emission rate determined during the test. 
Owners or operators must include in the monitoring plan the acceptable 
range of the water-to-fuel or steam-to-fuel ratio, which will be used to 
indicate hourly, proper operation of the NOX controls for 
each unit. The water-to-fuel or steam-to-fuel ratio shall be monitored 
and recorded during each hour of unit operation. If the water-to-fuel or 
steam-to-fuel ratio is not within the acceptable range in a given hour 
the fuel and unit specific NOX emission rate may not be used 
for that hour, and the appropriate default NOX emission rate 
from Table LM-2 shall be reported instead.
    (2) For a low mass emissions unit that uses dry low-NOX 
premix technology to control NOX emissions, proper operation 
of the emission controls means that the unit is in the low-
NOX or premixed combustion mode, and fired with natural gas. 
Evidence of operation in the low-NOX or premixed mode shall 
be provided by monitoring the appropriate turbine operating parameters. 
These parameters may include percentage of full load, turbine exhaust 
temperature, combustion reference temperature, compressor discharge 
pressure, fuel and air valve positions, dynamic pressure pulsations, 
internal guide vane (IGV) position, and flame detection or flame scanner 
condition. The acceptable values and ranges for all parameters monitored 
shall be specified in the monitoring plan for the unit, and the 
parameters shall be monitored during each subsequent operating hour. If 
one or more of these parameters is not within the acceptable range or at 
an acceptable value in a given operating hour, the fuel-and-unit-
specific NOX emission rate may not be used for that hour, and 
the appropriate default NOX emission rate from Table LM-2 
shall be reported instead. When the unit is fired with oil the 
appropriate default value from Table LM-2 shall be reported.
    (3) For low mass emission units with other types of add-on 
NOX controls, appropriate parameters and the acceptable range 
of the parameters which indicate hourly proper operation of the 
NOX controls must be specified in the monitoring plan. These 
parameters shall be monitored during each subsequent operating hour. If 
any of these parameters are not within the acceptable range in a given 
operating hour, the fuel and unit specific NOX emission rates 
may not be used in that hour, and the appropriate default NOX 
emission rate from Table LM-2 shall be reported instead.
    (I) Notwithstanding the requirements in paragraph (c)(1)(iv)(A) of 
this section, the appendix E testing to determine (or re-determine) the 
fuel-specific, unit-specific NOX emission rate for a unit (or 
for each unit in a group of identical units) may be performed at fewer 
than four loads, under the following circumstances:
    (1) Testing may be done at one load level if the data analysis 
described in paragraph (c)(1)(iv)(J) of this section is performed and 
the results show that the unit has operated (or all units in the group 
of identical units have operated) at a single load level for at least 
85.0 percent of all operating hours in the previous three years (12 
calendar quarters) prior to the calendar quarter of the appendix E 
testing. For combustion turbines that are operated to produce 
approximately constant output (in MW) but which use internal operating 
and exhaust temperatures and not the actual output in MW to control the 
operation of the turbine, the internal operating temperature set point 
may be used as a surrogate for load in demonstrating that the unit 
qualifies for single-load testing. If the data analysis shows that the 
unit does not qualify for single-load testing, testing may be done at 
two (or three) load levels if the unit has operated (or if all units in 
the group of identical units have operated) cumulatively at two (or 
three) load levels for at least 85.0 percent of all operating hours in 
the previous three years; or
    (2) If a multiple-load appendix E test was initially performed for a 
unit (or group of identical units) to determine the fuel-and-unit 
specific NOX emission rate, then the periodic retests 
required under paragraph (c)(1)(iv)(D) of this section may be single-
load tests, performed at the load level for which the highest average 
NOX emission rate was obtained in the initial test.

[[Page 238]]

    (3) The initial appendix E testing may be performed at a single 
load, between 75 and 100 percent of the maximum sustainable load defined 
in the monitoring plan for the unit, if the average annual capacity 
factor of the LME unit, when calculated according to the definition of 
``capacity factor'' in Sec. 72.2 of this chapter, is 2.5 percent or 
less for the three calendar years immediately preceding the year of the 
testing, and that the annual capacity factor does not exceed 4.0 percent 
in any of those three years. Similarly, for a LME unit that reports 
emissions data on an ozone season-only basis, the initial appendix E 
testing may be performed at a single load between 75 and 100 percent of 
the maximum sustainable load if the 2.5 and 4.0 percent capacity factor 
requirements are met for the three ozone seasons immediately preceding 
the date of the emission testing (see Sec. 75.74(c)(11)). For a group 
of identical LME units, any unit(s) in the group that meet the 2.5 and 
4.0 percent capacity factor requirements may perform the initial 
appendix E testing at a single load between 75 and 100 percent of the 
maximum sustainable load.
    (4) The retest of any LME unit may be performed at a single load 
between 75 and 100 percent of the maximum sustainable load if, for the 
three calendar years immediately preceding the year of the retest (or, 
if applicable, the three ozone seasons immediately preceding the date of 
the retest), the applicable capacity factor requirements described in 
paragraph (c)(1)(iv)(I)(3) of this section are met.
    (5) Alternatively, for combustion turbines, the single-load testing 
described in paragraphs (c)(1)(iv)(I)(3) and (c)(1)(iv)(I)(4) of this 
section may be performed at the highest attainable load level 
corresponding to the season of the year in which the testing is 
conducted.
    (6) In all cases where the alternative single-load testing option 
described in paragraphs (c)(1)(iv)(I)(3) through (c)(1)(iv)(I)(5) of 
this section is used, the owner or operator shall keep records 
documenting that the required capacity factor requirements were met.
    (J) To determine whether a unit qualifies for testing at fewer than 
four loads under paragraph (c)(1)(iv)(I) of this section, follow the 
procedures in paragraph (c)(1)(iv)(J)(1) or (c)(1)(iv)(J)(2) of this 
section, as applicable.
    (1) Determine the range of operation of the unit, according to 
section 6.5.2.1 of appendix A to this part. Divide the range of 
operation into four equal load bands. For example, if the range of 
operation extends from 20 MW to 100 MW, the four equal load bands would 
be: band 1: from 20 MW to 40 MW; band 2: from 41 MW to 
60 MW; band 3: from 61 MW to 80 MW; and band 4: from 
81 to 100 MW. Then, perform a historical load analysis for all unit 
operating hours in the 12 calendar quarters preceding the quarter of the 
test. Alternatively, for sources that report emissions data only during 
the ozone season, the historical load analysis may be based on unit 
operation in the previous three ozone seasons, rather than unit 
operation in the previous 12 calendar quarters. Determine the percentage 
of the data that fall into each load band. For a unit that is not part 
of a group of identical units, if 85.0% or more of the data fall into 
one load band, single-load testing may be performed at any point within 
that load band. For a group of identical units, if each unit in the 
group meets the 85.0% criterion, then representative single-load testing 
within the load band may be performed. If the 85.0% criterion cannot be 
met to qualify for single-load testing but this criterion can be met 
cumulatively for two (or three) load levels, then testing may be 
performed at two (or three) loads instead of four.
    (2) For a combustion turbine that uses exhaust temperature and not 
the actual output in megawatts to control the operation of the turbine 
(or for a group of identical units of this type), the owner or operator 
must document that the unit (or each unit in the group) has operated 
within [10% of the set point temperature for 85.0% of the operating 
hours in the previous 12 calendar quarters to qualify for single-load 
testing. Alternatively, for sources that report emissions data only 
during the ozone season, the historical set point temperature analysis 
may be based on unit operation in the previous three ozone seasons, 
rather than unit

[[Page 239]]

operation in the previous 12 calendar quarters. When the set point 
temperature is used rather than unit load to justify single-load 
testing, the designated representative shall certify in the monitoring 
plan for the unit that this is the normal manner of unit operation and 
shall document the setpoint temperature.
    (2) Records of operating time, fuel usage, unit output and 
NOX emission control operating status. The owner or operator 
shall keep the following records on-site, for three years, in a form 
suitable for inspection, except that for unmanned facilities, the 
records may be kept at a central location, rather than on-site:
    (i) For each low mass emissions unit, the owner or operator shall 
keep hourly records which indicate whether or not the unit operated 
during each clock hour of each calendar year. The owner or operator may 
report partial operating hours or may assume that for each hour the unit 
operated the operating time is a whole hour. Units using partial 
operating hours and the maximum rated hourly heat input to calculate 
heat input for each hour must report partial operating hours.
    (ii) For each low mass emissions unit, the owner or operator shall 
keep hourly records indicating the type(s) of fuel(s) combusted in the 
unit during each hour of unit operation.
    (iii) For each low mass emissions unit using the long term fuel flow 
methodology under paragraph (c)(3)(ii) of this section to determine 
hourly heat input, the owner or operator shall keep hourly records of 
unit load (in megawatts or thousands of pounds of steam per hour), for 
the purpose of apportioning heat input to the individual unit operating 
hours.
    (iv) For each low mass emissions unit with add-on NOX 
emission controls of any kind and each unit that uses dry low-
NOX technology, the owner or operator shall keep hourly 
records of the hourly value of the parameter(s) specified in 
(c)(1)(iv)(H) of this section used to indicate proper operation of the 
unit's NOX controls.
    (3) Heat input. Hourly, quarterly and annual heat input for a low 
mass emissions unit shall be determined using either the maximum rated 
hourly heat input method under paragraph (c)(3)(i) of this section or 
the long term fuel flow method under paragraph (c)(3)(ii) of this 
section.
    (i) Maximum rated hourly heat input method. (A) For the purposes of 
the mass emission calculation methodology of paragraph (c)(3) of this 
section, HIhr, the hourly heat input (mmBtu) to a low mass 
emissions unit shall be deemed to equal the maximum rated hourly heat 
input, as defined in Sec. 72.2 of this chapter, multiplied by the 
operating time of the unit for each hour. The owner or operator may 
choose to record and report partial operating hours or may assume that a 
unit operated for a whole hour for each hour the unit operated. However, 
the owner or operator of a unit may petition the Administrator under 
Sec. 75.66 for a lower value for maximum rated hourly heat input than 
that defined in Sec. 72.2 of this chapter. The Administrator may 
approve such lower value if the owner or operator demonstrates that 
either the maximum hourly heat input specified by the manufacturer or 
the highest observed hourly heat input, or both, are not representative, 
and such a lower value is representative, of the unit's current 
capabilities because modifications have been made to the unit, limiting 
its capacity permanently.
    (B) The quarterly heat input, HIqtr, in mmBtu, shall be 
determined using Equation LM-1:
[GRAPHIC] [TIFF OMITTED] TR12JN02.001

Where:

n = Number of unit operating hours in the quarter.
HIhr = Hourly heat input under paragraph (c)(3)(i)(A) of this section 
          (mmBtu).

    (C) The year-to-date cumulative heat input (mmBtu) shall be the sum 
of the quarterly heat input values for all of the calendar quarters in 
the year to date.
    (D) For a unit subject to the provisions of subpart H of this part, 
which is not required to report emission data on a year-round basis and 
elects to report only during the ozone season, the quarterly heat input 
for the second calendar quarter of the year shall, for

[[Page 240]]

compliance purposes, include only the heat input for the months of May 
and June, and the cumulative ozone season heat input shall be the sum of 
the heat input values for May, June and the third calendar quarter of 
the year.
    (ii) Long term fuel flow heat input method. The owner or operator 
may, for the purpose of demonstrating that a low mass emissions unit or 
group of low mass emission units sharing a common fuel supply meets the 
requirements of this section, use records of long-term fuel flow, to 
calculate hourly heat input to a low mass emissions unit.
    (A) This option may be used for a group of low mass emission units 
only if:
    (1) The low mass emission units combust fuel from a common source of 
supply; and
    (2) Records are kept of the total amount of fuel combusted by the 
group of low mass emission units and the hourly output (in megawatts or 
pounds of steam) from each unit in the group; and
    (3) All of the units in the group are low mass emission units.
    (B) For each fuel used during the quarter, the volume in standard 
cubic feet (for gas) or gallons (for oil) may be determined using any of 
the following methods;
    (1) Fuel billing records (for low mass emission units, or groups of 
low mass emission units, which purchase fuel from non-affiliated 
sources);
    (2) American Petroleum Institute (API) Manual of Petroleum 
Measurement Standards, Chapter 3-Tank Gauging, Section 1A, Standard 
Practice for the Manual Gauging of Petroleum and Petroleum Products, 
Second Edition, August 2005; Section 1B-Standard Practice for Level 
Measurement of Liquid Hydrocarbons in Stationary Tanks by Automatic Tank 
Gauging, Second Edition June 2001; Section 2-Standard Practice for 
Gauging Petroleum and Petroleum Products in Tank Cars, First Edition, 
August 1995 (Reaffirmed March 2006); Section 3-Standard Practice for 
Level Measurement of Liquid Hydrocarbons in Stationary Pressurized 
Storage Tanks by Automatic Tank Gauging, First Edition June 1996 
(Reaffirmed, March 2001); Section 4-Standard Practice for Level 
Measurement of Liquid Hydrocarbons on Marine Vessels by Automatic Tank 
Gauging, First Edition April 1995 (Reaffirmed, September 2000); and 
Section 5-Standard Practice for Level Measurement of Light Hydrocarbon 
Liquids Onboard Marine Vessels by Automatic Tank Gauging, First Edition 
March 1997 (Reaffirmed, March 2003); for Sec. 75.19; Shop Testing of 
Automatic Liquid Level Gages, Bulletin 2509 B, December 1961 (Reaffirmed 
August 1987, October 1992) (all incorporated by reference under Sec. 
75.6 of this part); or
    (3) A fuel flow meter certified and maintained according to appendix 
D to this part.
    (C) Except as provided in paragraph (c)(3)(ii)(C)(3) of this 
section, for each fuel combusted during a quarter, the gross calorific 
value of the fuel shall be determined by either:
    (1) Using the applicable procedures for gas and oil analysis in 
sections 2.2 and 2.3 of appendix D to this part. If this option is 
chosen the highest gross calorific value recorded during the previous 
calendar year shall be used (or, for a new or newly-affected unit, if 
there are no sample results from the previous year, use the highest GCV 
from the samples taken in the current year); or
    (2) Using the appropriate default gross calorific value listed in 
Table LM-5 of this section.
    (3) For gaseous fuels other than pipeline natural gas or natural 
gas, the GCV sampling frequency shall be daily unless the results of a 
demonstration under section 2.3.5 of appendix D to this part show that 
the fuel has a low GCV variability and qualifies for monthly sampling. 
If daily GCV sampling is required, use the highest GCV obtained in the 
calendar quarter as GCVmax in Equation LM-3, of this section.
    (D) If Eq. LM-2 is used for heat input determination, the specific 
gravity of each type of fuel oil combusted during the quarter shall be 
determined either by:
    (1) Using the procedures in section 2.2.6 of appendix D to this 
part. If this option is chosen, use the highest specific gravity value 
recorded during the previous calendar year (or, for a new or

[[Page 241]]

newly-affected unit, if there are no sample results from the previous 
year, use the highest specific gravity from the samples taken in the 
current year); or
    (2) Using the appropriate default specific gravity value in Table 
LM-6 of this section.
    (E) The quarterly heat input from each type of fuel combusted during 
the quarter by a low mass emissions unit or group of low mass emissions 
units sharing a common fuel supply shall be determined using either 
Equation LM-2 or Equation LM-3 for oil (as applicable to the method used 
to quantify oil usage) and Equation LM-3 for gaseous fuels. For a unit 
subject to the provisions of subpart H of this part, which is not 
required to report emission data on a year-round basis and elects to 
report only during the ozone season, the quarterly heat input for the 
second calendar quarter of the year shall include only the heat input 
for the months of May and June.
[GRAPHIC] [TIFF OMITTED] TR12JN02.002

Where:

HIfuel-qtr = Quarterly total heat input from oil (mmBtu).
Mqtr = Mass of oil consumed during the quarter, determined as 
          the product of the volume of oil under paragraph (c)(3)(ii)(B) 
          of this section and the specific gravity under paragraph 
          (c)(3)(ii)(D) of this section (lb).
GCVmax = Gross calorific value of oil, as determined under paragraph 
          (c)(3)(ii)(C) of this section (Btu/lb)
10\6\ = Conversion of Btu to mmBtu.
[GRAPHIC] [TIFF OMITTED] TR12JN02.003

Where:

HIfuel-qtr = Quarterly heat input from gaseous fuel or fuel oil (mmBtu).
Qqtr = Volume of gaseous fuel or fuel oil combusted during 
          the quarter, as determined under paragraph (c)(3)(ii)(B) of 
          this section standard cubic feet (scf) or (gal), as 
          applicable.
GCVmax = Gross calorific value of the gaseous fuel or fuel 
          oil combusted during the quarter, as determined under 
          paragraph (c)(3)(ii)(C) of this section (Btu/scf) or (Btu/
          gal), as applicable.
10\6\ = Conversion of Btu to mmBtu.

    (F) Use Eq. LM-4 to calculate HIqtr-total, the quarterly 
heat input (mmBtu) for all fuels. HIqtr-total shall be the 
sum of the HIfuel-qtr values determined using Equations LM-2 
and LM-3.
[GRAPHIC] [TIFF OMITTED] TR12JN02.004

    (G) The year-to-date cumulative heat input (mmBtu) for all fuels 
shall be the sum of all quarterly total heat input 
(HIqtr-total) values for all calendar quarters in the year to 
date. For a unit subject to the provisions of subpart H of this part, 
which is not required to report emission data on a year-round basis and 
elects to report only during the ozone season, the cumulative ozone 
season heat input shall be the sum of the quarterly heat input values 
for the second and third calendar quarters of the year.
    (H) For each low mass emissions unit or each low mass emissions unit 
in a group of identical units, the owner or operator shall determine the 
cumulative quarterly unit load in megawatt hours or thousands of pounds 
of steam. The quarterly cumulative unit load shall be the sum of the 
hourly unit load values recorded under paragraph (c)(2) of this section 
and shall be determined using Equations LM-5 or LM-6. For a unit subject 
to the provisions of subpart H of this part, which is not required to 
report emission data on a

[[Page 242]]

year-round basis and elects to report only during the ozone season, the 
quarterly cumulative load for the second calendar quarter of the year 
shall include only the unit loads for the months of May and June.
[GRAPHIC] [TIFF OMITTED] TR24JA08.016

[GRAPHIC] [TIFF OMITTED] TR24JA08.017

Where:

MWqtr = Sum of all unit operating loads recorded during the 
          quarter by the unit (MWh).
STfuel-qtr = Sum of all hourly steam loads recorded during 
          the quarter by the unit (klb of steam/hr).
MW = Unit operating load for a particular unit operating hour (MWh).
ST = Unit steam load for a particular unit operating hour (klb of 
          steam).

    (I) For a low mass emissions unit that is not included in a group of 
low mass emission units sharing a common fuel supply, apportion the 
total heat input for the quarter, HIqtr-total to each hour of 
unit operation using either Equation LM-7 or LM-8:
[GRAPHIC] [TIFF OMITTED] TR27OC98.006


(Eq LM-7 for MW output)
[GRAPHIC] [TIFF OMITTED] TR27OC98.007


(Eq LM-8 for steam output)

Where:

HIhr = Hourly heat input to the unit (mmBtu).
MWhr = Hourly operating load for the unit (MW).
SThr = Hourly steam load for the unit (klb of steam/hr).

    (J) For each low mass emissions unit that is included in a group of 
units sharing a common fuel supply, apportion the total heat input for 
the quarter, HIqtr-total to each hour of operation using either Equation 
LM-7a or LM-8a:
[GRAPHIC] [TIFF OMITTED] TR27OC98.008


(Eq LM-7a for MW output)
[GRAPHIC] [TIFF OMITTED] TR27OC98.009


(Eq LM-8a for steam output)

Where:

HIhr = Hourly heat input to the individual unit (mmBtu).
MWhr = Hourly operating load for the individual unit (MW).
SThr = Hourly steam load for the individual unit (klb of 
          steam/hr).
[Sigma]MWqtr = Sum of the quarterly operating
    all-units loads (from Eq. LM-5) for all units in the group (MW).
[Sigma]STqtr = Sum of the quarterly steam
    all-units loads (from Eq. LM-6) for all units in the group (klb of 
steam/hr)

    (4) Calculation of SO2, NOX and CO2 mass emissions. The owner or 
operator shall, for the purpose of demonstrating that a low mass 
emissions unit meets the requirements of this section, calculate 
SO2, NOX and CO2 mass emissions in 
accordance with the following.
    (i) SO2 mass emissions. (A) The hourly SO2 mass emissions 
(lbs) for a low mass emissions unit (Acid Rain Program units, only) 
shall be determined using Equation LM-9 and the appropriate fuel-based 
SO2 emission factor for the fuels combusted in that hour. If 
more than one fuel is combusted in the hour, use the highest emission 
factor for all of the fuels combusted in the hour. If records are 
missing as to which fuel was combusted in the hour, use the highest 
emission factor for all of the

[[Page 243]]

fuels capable of being combusted in the unit.

WSO2 = EFSO2 x HIhr (Eq. LM-9)

Where:

WSO2 = Hourly SO2 mass emissions (lbs.)
EFSO2 = Either the SO2 emission factor from Table 
          LM-1 of this section or the fuel-and-unit-specific 
          SO2 emission rate from paragraph (c)(1)(i) of this 
          section (lb/mmBtu).
HIhr = Either the maximum rated hourly heat input under 
          paragraph (c)(3)(i)(A) of this section or the hourly heat 
          input under paragraph (c)(3)(ii) of this section (mmBtu).

    (B) The quarterly SO2 mass emissions (tons) for the low 
mass emissions unit shall be the sum of all the hourly SO2 
mass emissions in the quarter, as determined under paragraph 
(c)(4)(i)(A) of this section, divided by 2000 lb/ton.
    (C) The year-to-date cumulative SO2 mass emissions (tons) 
for the low mass emissions unit shall be the sum of the quarterly 
SO2 mass emissions, as determined under paragraph 
(c)(4)(i)(B) of this section, for all of the calendar quarters in the 
year to date.
    (ii)(A) The hourly NOX mass emissions for the low mass 
emissions unit (lbs) shall be determined using Equation LM-10. If more 
than one fuel is combusted in the hour, use the highest emission rate 
for all of the fuels combusted in the hour. If records are missing as to 
which fuel was combusted in the hour, use the highest emission factor 
for all of the fuels capable of being combusted in the unit. For low 
mass emission units with NOX emission controls of any kind 
and for which a fuel-and-unit-specific NOX emission rate is 
determined under paragraph (c)(1)(iv) of this section, for any hour in 
which the parameters under paragraph (c)(1)(iv)(A) of this section do 
not show that the NOX emission controls are operating 
properly, use the NOX emission rate from Table LM-2 of this 
section for the fuel combusted during the hour with the highest 
NOX emission rate.

WNOX = EFNOX x  HIhr (Eq. LM-10)

Where:

WNOX = Hourly NOX mass emissions (lbs).
EFNOX = Either the NOX emission factor from Table 
          LM-2 of this section or the fuel- and unit-specific 
          NOX emission rate determined under paragraph 
          (c)(1)(iv) of this section (lb/mmBtu).
HIhr = Either the maximum rated hourly heat input from 
          paragraph (c)(3)(i)(A) of this section or the hourly heat 
          input as determined under paragraph (c)(3)(ii) of this section 
          (mmBtu).

    (B) The quarterly NOX mass emissions (tons) for the low 
mass emissions unit shall be the sum of all of the hourly NOX 
mass emissions in the quarter, as determined under paragraph 
(c)(4)(ii)(A) of this section, divided by 2000 lb/ton.
    (C) The year-to-date cumulative NOX mass emissions (tons) 
for the low mass emissions unit shall be the sum of the quarterly 
NOX mass emissions, as determined under paragraph 
(c)(4)(ii)(B) of this section, for all of the calendar quarters in the 
year to date. For a unit subject to the provisions of subpart H of this 
part, which is not required to report emission data on a year-round 
basis and elects to report only during the ozone season, the ozone 
season NOX mass emissions for the unit shall be the sum of 
the quarterly NOX mass emissions, as determined under 
paragraph (c)(4)(ii)(B) of this section, for the second and third 
calendar quarters of the year, and the second quarter report shall 
include emissions data only for May and June.
    (D) The quarterly and cumulative NOX emission rate in lb/
mmBtu (if required by the applicable program(s)) shall be determined as 
follows. Calculate the quarterly NOX emission rate by taking 
the arithmetic average of all of the hourly EFNOX values. 
Calculate the cumulative (year-to-date) NOX emission rate by 
taking the arithmetic average of the quarterly NOX emission 
rates.
    (iii) CO2 Mass Emissions. (A) The hourly CO2 mass 
emissions (tons) for the affected low mass emissions unit (Acid Rain 
Program units, only) shall be determined using Equation LM-11 and the 
appropriate fuel-based CO2 emission factor from Table LM-3 of 
this section for the fuel being combusted in that hour. If more than one 
fuel is combusted in the hour, use the highest emission factor for all 
of the fuels combusted in the hour. If records are missing as to which 
fuel was combusted in the hour, use the highest emission factor for all 
of the fuels capable of being combusted in the unit.


[[Page 244]]


WCO2 = EFCO2 x HIhr (Eq. LM-11)

Where:

WCO2 = Hourly CO2 mass emissions (tons).
EFCO2 = Either the fuel-based CO2 emission factor from Table 
          LM-3 of this section or the fuel-and-unit-specific 
          CO2 emission rate from paragraph (c)(1)(iii) of 
          this section (tons/mmBtu).
HIhr = Either the maximum rated hourly heat input from 
          paragraph (c)(3)(i)(A) of this section or the hourly heat 
          input as determined under paragraph (c)(3)(ii) of this section 
          (mmBtu).

    (B) The quarterly CO2 mass emissions (tons) for the low 
mass emissions unit shall be the sum of all of the hourly CO2 
mass emissions in the quarter, as determined under paragraph 
(c)(4)(iii)(A)of this section.
    (C) The year-to-date cumulative CO2 mass emissions (tons) 
for the low mass emissions unit shall be the sum of all of the quarterly 
CO2 mass emissions, as determined under paragraph 
(c)(4)(iii)(B) of this section, for all of the calendar quarters in the 
year to date.
    (d) Each unit that qualifies under this section to use the low mass 
emissions methodology must follow the recordkeeping and reporting 
requirements pertaining to low mass emissions units in subparts F and G 
of this part.
    (e) The quality control and quality assurance requirements in Sec. 
75.21 are not applicable to a low mass emissions unit for which the low 
mass emissions excepted methodology under paragraph (c) of this section 
is being used in lieu of a continuous emission monitoring system or an 
excepted monitoring system under appendix D or E to this part, except 
for fuel flowmeters used to meet the provisions in paragraph (c)(3)(ii) 
of this section. However, the owner or operator of a low mass emissions 
unit shall implement the following quality assurance and quality control 
provisions:
    (1) For low mass emission units or groups of units which use the 
long term fuel flow methodology under paragraph (c)(3)(ii) of this 
section and which use fuel billing records to determine fuel usage, the 
owner or operator shall keep, at the facility, for three years, the 
records of the fuel billing statements used for long term fuel flow 
determinations.
    (2) For low mass emissions units or groups of units which use the 
long term fuel flow methodology under paragraph (c)(3)(ii) of this 
section and which use one of the methods specified in paragraph 
(c)(3)(ii)(B)(2) of this section to determine fuel usage, the owner or 
operator shall keep, at the facility, a copy of the standard used and 
shall keep records, for three years, of all measurements obtained for 
each quarter using the methodology.
    (3) For low mass emission units or groups of units which use the 
long term fuel flow methodology under paragraph (c)(3)(ii) of this 
section and which use a certified fuel flow meter to determine fuel 
usage, the owner or operator shall comply with the quality control 
quality assurance requirements for a fuel flow meter under section 2.1.6 
of appendix D of this part.
    (4) For each low mass emissions unit for which fuel-and-unit-
specific NOX emission rates are determined in accordance with 
paragraph (c)(1)(iv) of this section, the owner or operator shall keep, 
at the facility, records which document the results of all 
NOX emission rate tests conducted according to appendix E to 
this part. If CEMS data are used to determine the fuel-and-unit-specific 
NOX emission rates under paragraph (c)(1)(iv)(G) of this 
section, the owner or operator shall keep, at the facility, records of 
the CEMS data and the data analysis performed to determine a fuel-and-
unit-specific NOX emission rate. The appendix E test records 
and historical CEMS data records shall be kept until the fuel and unit 
specific NOX emission rates are re-determined.
    (5) For each low mass emissions unit for which fuel-and-unit-
specific NOX emission rates are determined in accordance with 
paragraph (c)(1)(iv) of this section and which has add-on NOX 
emission controls of any kind or uses dry low-NOX technology, 
the owner or operator shall develop and keep on-site a quality assurance 
plan which explains the procedures used to document proper operation of 
the NOX emission controls. The plan shall include the 
parameters monitored (e.g., water-to-fuel ratio) and the acceptable 
ranges for each parameter used to determine

[[Page 245]]

proper operation of the unit's NOX controls.
    (6) For unmanned facilities, the records required by paragraphs 
(e)(1), (e)(2) and (e)(4) of this section may be kept at a central 
location, rather than at the facility.

   Table LM-1--SO2 Emission Factors (lb/mmBtu) for Various Fuel Types
------------------------------------------------------------------------
                 Fuel type                      SO2 emission factors
------------------------------------------------------------------------
Pipeline Natural Gas......................  0.0006 lb/mmBtu.
Other Natural Gas.........................  0.06 lb/mmBtu.
Residual Oil..............................  2.1 lb/mmBtu.
Diesel Fuel...............................  0.5 lb/mmBtu.
------------------------------------------------------------------------


 Table LM-2--NOX Emission Rates (lb/mmBtu) for Various Boiler/Fuel Types
------------------------------------------------------------------------
                                                                  NOX
               Unit type                       Fuel type        emission
                                                                  rate
------------------------------------------------------------------------
Turbine................................  Gas.................        0.7
Turbine................................  Oil.................        1.2
Boiler.................................  Gas.................        1.5
Boiler.................................  Oil.................        2
------------------------------------------------------------------------


      Table LM-3--CO2 Emission Factors (ton/mmBtu) for Gas and Oil
------------------------------------------------------------------------
                 Fuel type                      CO2 emission factors
------------------------------------------------------------------------
Pipeline (or other) Natural Gas...........  0.059 ton/mmBtu.
Oil.......................................  0.081 ton/mmBtu.
------------------------------------------------------------------------


             Table LM-4--Identical Unit Testing Requirements
------------------------------------------------------------------------
                                             Number of appendix E tests
  Number of identical units in the group              required
------------------------------------------------------------------------
2.........................................  1
3 to 6....................................  2
7.........................................  3
7..............................  n tests; where n = number of
                                             units divided by 3 and
                                             rounded to nearest integer.
------------------------------------------------------------------------


   Table LM-5--Default Gross Calorific Values (GCVs) for Various Fuels
------------------------------------------------------------------------
                                            GCV for use in equation LM-2
                   Fuel                                or LM-3
------------------------------------------------------------------------
Pipeline Natural Gas......................  1050 Btu/scf.
Other Natural Gas.........................  1100 Btu/scf.
Residual Oil..............................  19,700 Btu/lb or 167,500 Btu/
                                             gallon.
Diesel Fuel...............................  20,500 Btu/lb or 151,700 Btu/
                                             gallon.
------------------------------------------------------------------------


        Table LM-6--Default Specific Gravity Values for Fuel Oil
------------------------------------------------------------------------
                                                               Specific
                            Fuel                                gravity
                                                               (lb/gal)
------------------------------------------------------------------------
Residual Oil................................................         8.5
Diesel Fuel.................................................         7.4
------------------------------------------------------------------------


[63 FR 57500, Oct. 27, 1998, as amended at 64 FR 28592, May 26, 1999; 64 
FR 37582, July 12, 1999; 67 FR 40424, 40425, June 12, 2002; 67 FR 53504, 
Aug. 16, 2002; 73 FR 4344, Jan. 24, 2008]



            Subpart C_Operation and Maintenance Requirements



Sec. 75.20  Initial certification and recertification procedures.

    (a) Initial certification approval process. The owner or operator 
shall ensure that each continuous emission or opacity monitoring system 
required by this part meets the initial certification requirements of 
this section and shall ensure that all applicable initial certification 
tests under paragraph (c) of this section are completed by the deadlines 
specified in Sec. 75.4 and prior to use in the Acid Rain Program. In 
addition, whenever the owner or operator installs a continuous emission 
or opacity monitoring system in order to meet the requirements of 
Sec. Sec. 75.11 through 75.18, where no continuous emission or opacity 
monitoring system was previously installed, initial certification is 
required.
    (1) Notification of initial certification test dates. The owner or 
operator or designated representative shall submit a written notice of 
the dates of initial certification testing at the unit as specified in 
Sec. 75.61(a)(1).
    (2) Certification application. The owner or operator shall apply for 
certification of each continuous emission or opacity monitoring system 
used under the Acid Rain Program. The owner or operator shall submit the 
certification application in accordance with Sec. 75.60 and each 
complete certification application shall include the information 
specified in Sec. 75.63.
    (3) Provisional approval of certification (or recertification) 
applications. Upon the successful completion of the required 
certification (or recertification) procedures of this section, each 
continuous emission or opacity monitoring system

[[Page 246]]

shall be deemed provisionally certified (or recertified) for use under 
the Acid Rain Program for a period not to exceed 120 days following 
receipt by the Administrator of the complete certification (or 
recertification) application under paragraph (a)(4) of this section. 
Notwithstanding this paragraph, no continuous emission or opacity 
monitor systems for a combustion source seeking to enter the Opt-in 
Program in accordance with part 74 of this chapter shall be deemed 
provisionally certified (or recertified) for use under the Acid Rain 
Program. Data measured and recorded by a provisionally certified (or 
recertified) continuous emission or opacity monitoring system , operated 
in accordance with the requirements of appendix B to this part, will be 
considered valid quality-assured data (retroactive to the date and time 
of provisional certification or recertification), provided that the 
Administrator does not invalidate the provisional certification (or 
recertification) by issuing a notice of disapproval within 120 days of 
receipt by the Administrator of the complete certification (or 
recertification) application. Note that when the conditional data 
validation procedures of paragraph (b)(3) of this section are used for 
the initial certification (or recertification) of a continuous emissions 
monitoring system, the date and time of provisional certification (or 
recertification) of the CEMS may be earlier than the date and time of 
completion of the required certification (or recertification) tests.
    (4) Certification (or recertification) application formal approval 
process. The Administrator will issue a notice of approval or 
disapproval of the certification (or recertification) application to the 
owner or operator within 120 days of receipt of the complete 
certification (or recertification) application. In the event the 
Administrator does not issue such a notice within 120 days of receipt, 
each continuous emission or opacity monitoring system which meets the 
performance requirements of this part and is included in the 
certification (or recertification) application will be deemed certified 
(or recertified) for use under the Acid Rain Program.
    (i) Approval notice. If the certification (or recertification) 
application is complete and shows that each continuous emission or 
opacity monitoring system meets the performance requirements of this 
part, then the Administrator will issue a notice of approval of the 
certification (or recertification) application within 120 days of 
receipt.
    (ii) Incomplete application notice. A certification (or 
recertification) application will be considered complete when all of the 
applicable information required to be submitted in Sec. 75.63 has been 
received by the Administrator, the EPA Regional Office, and the 
appropriate State and/or local air pollution control agency. If the 
certification (or recertification) application is not complete, then the 
Administrator will issue a notice of incompleteness that provides a 
reasonable timeframe for the designated representative to submit the 
additional information required to complete the certification (or 
recertification) application. If the designated representative has not 
complied with the notice of incompleteness by a specified due date, then 
the Administrator may issue a notice of disapproval specified under 
paragraph (a)(4)(iii) of this section. The 120-day review period shall 
not begin prior to receipt of a complete application.
    (iii) Disapproval notice. If the certification (or recertification) 
application shows that any continuous emission or opacity monitoring 
system does not meet the performance requirements of this part, or if 
the certification (or recertification) application is incomplete and the 
requirement for disapproval under paragraph (a)(4)(ii) of this section 
has been met, the Administrator shall issue a written notice of 
disapproval of the certification (or recertification) application within 
120 days of receipt. By issuing the notice of disapproval, the 
provisional certification (or recertification) is invalidated by the 
Administrator, and the data measured and recorded by each uncertified 
continuous emission or opacity monitoring system shall not be considered 
valid quality-assured data as follows: from the hour of the probationary 
calibration error test that began the initial certification (or 
recertification) test period (if the conditional data validation 
procedures of paragraph (b)(3)

[[Page 247]]

of this section were used to retrospectively validate data); or from the 
date and time of completion of the invalid certification or 
recertification tests (if the conditional data validation procedures of 
paragraph (b)(3) of this section were not used). The owner or operator 
shall follow the procedures for loss of initial certification in 
paragraph (a)(5) of this section for each continuous emission or opacity 
monitoring system which is disapproved for initial certification. For 
each disapproved recertification, the owner or operator shall follow the 
procedures of paragraph (b)(5) of this section.
    (iv) Audit decertification. The Administrator may issue a notice of 
disapproval of the certification status of a continuous emission or 
opacity monitoring system, in accordance with Sec. 75.21.
    (5) Procedures for loss of certification. When the Administrator 
issues a notice of disapproval of a certification application or a 
notice of disapproval of certification status (as specified in paragraph 
(a)(4) of this section), then:
    (i) Until such time, date, and hour as the continuous emission 
monitoring system can be adjusted, repaired, or replaced and 
certification tests successfully completed (or, if the conditional data 
validation procedures in paragraphs (b)(3)(ii) through (b)(3)(ix) of 
this section are used, until a probationary calibration error test is 
passed following corrective actions in accordance with paragraph 
(b)(3)(ii) of this section), the owner or operator shall substitute the 
following values, as applicable, for each hour of unit operation during 
the period of invalid data specified in paragraph (a)(4)(iii) of this 
section or in Sec. 75.21: the maximum potential concentration of 
SO2, as defined in section 2.1.1.1 of appendix A to this 
part, to report SO2 concentration; the maximum potential 
NOX emission rate, as defined in Sec. 72.2 of this chapter, 
to report NOX emissions in lb/mmBtu; the maximum potential 
concentration of NOX, as defined in section 2.1.2.1 of 
appendix A to this part, to report NOX emissions in ppm (when 
a NOX concentration monitoring system is used to determine 
NOX mass emissions, as defined under Sec. 75.71(a)(2)); the 
maximum potential flow rate, as defined in section 2.1.4.1 of appendix A 
to this part, to report volumetric flow; the maximum potential 
concentration of CO2, as defined in section 2.1.3.1 of 
appendix A to this part, to report CO2 concentration data; 
and either the minimum potential moisture percentage, as defined in 
section 2.1.5 of appendix A to this part or, if Equation 19-3, 19-4 or 
19-8 in Method 19 in appendix A to part 60 of this chapter is used to 
determine NOX emission rate, the maximum potential moisture 
percentage, as defined in section 2.1.6 of appendix A to this part; and
    (ii) The designated representative shall submit a notification of 
certification retest dates as specified in Sec. 75.61(a)(1)(ii) and a 
new certification application according to the procedures in paragraph 
(a)(2) of this section; and
    (iii) The owner or operator shall repeat all certification tests or 
other requirements that were failed by the continuous emission or 
opacity 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.
    (b) Recertification approval process. Whenever the owner or operator 
makes a replacement, modification, or change in a certified continuous 
emission monitoring system or continuous opacity monitoring system that 
may significantly affect the ability of the system to accurately measure 
or record the SO2 or CO2 concentration, stack gas 
volumetric flow rate, NOX emission rate, NOX 
concentration, percent moisture, or opacity, or to meet the requirements 
of Sec. 75.21 or appendix B to this part, the owner or operator shall 
recertify the continuous emission monitoring system or continuous 
opacity monitoring system, according to the procedures in this 
paragraph. Furthermore, whenever the owner or operator makes a 
replacement, modification, or change to the flue gas handling system or 
the unit operation that may significantly change the flow or 
concentration profile, the owner or operator shall recertify the 
monitoring system according to the procedures in this paragraph. 
Examples of changes which

[[Page 248]]

require recertification include: replacement of the analyzer; change in 
location or orientation of the sampling probe or site; and complete 
replacement of an existing continuous emission monitoring system or 
continuous opacity monitoring system. The owner or operator shall also 
recertify the continuous emission monitoring systems for a unit that has 
recommenced commercial operation following a period of long-term cold 
storage as defined in Sec. 72.2 of this chapter. The owner or operator 
shall recertify a continuous opacity monitoring system whenever the 
monitor path length changes or as required by an applicable State or 
local regulation or permit. Any change to a flow monitor or gas 
monitoring system for which a RATA is not necessary shall not be 
considered a recertification event. In addition, changing the polynomial 
coefficients or K factor(s) of a flow monitor shall require a 3-load 
RATA, but is not considered to be a recertification event; however, 
records of the polynomial coefficients or K factor (s) currently in use 
shall be maintained on-site in a format suitable for inspection. 
Changing the coefficient or K factor(s) of a moisture monitoring system 
shall require a RATA, but is not considered to be a recertification 
event; however, records of the coefficient or K factor (s) currently in 
use by the moisture monitoring system shall be maintained on-site in a 
format suitable for inspection. In such cases, any other tests that are 
necessary to ensure continued proper operation of the monitoring system 
(e.g., 3-load flow RATAs following changes to flow monitor polynomial 
coefficients, linearity checks, calibration error tests, DAHS 
verifications, etc.) shall be performed as diagnostic tests, rather than 
as recertification tests. The data validation procedures in paragraph 
(b)(3) of this section shall be applied to RATAs associated with changes 
to flow or moisture monitor coefficients, and to linearity checks, 7-day 
calibration error tests, and cycle time tests, when these are required 
as diagnostic tests. When the data validation procedures of paragraph 
(b)(3) of this section are applied in this manner, replace the word 
``recertification'' with the word ``diagnostic.''
    (1) Tests required. For all recertification testing, the owner or 
operator shall complete all initial certification tests in paragraph (c) 
of this section that are applicable to the monitoring system, except as 
otherwise approved by the Administrator. For diagnostic testing after 
changing the flow rate monitor polynomial coefficients, the owner or 
operator shall complete a 3-level RATA. For diagnostic testing after 
changing the K factor or mathematical algorithm of a moisture monitoring 
system, the owner or operator shall complete a RATA.
    (2) Notification of recertification test dates. The owner, operator, 
or designated representative shall submit notice of testing dates for 
recertification under this paragraph as specified in Sec. 
75.61(a)(1)(ii), unless all of the tests in paragraph (c) of this 
section are required for recertification, in which case the owner or 
operator shall provide notice in accordance with the notice provisions 
for initial certification testing in Sec. 75.61(a)(1)(i).
    (3) Recertification test period requirements and data validation. 
The data validation provisions in paragraphs (b)(3)(i) through 
(b)(3)(ix) of this section shall apply to all CEMS recertifications and 
diagnostic testing. The provisions in paragraphs (b)(3)(ii) through 
(b)(3)(ix) of this section may also be applied to initial certifications 
(see sections 6.2(a), 6.3.1(a), 6.3.2(a), 6.4(a) and 6.5(f) of appendix 
A to this part) and may be used to supplement the linearity check and 
RATA data validation procedures in sections 2.2.3(b) and 2.3.2(b) of 
appendix B to this part.
    (i) The owner or operator shall use substitute data, according to 
the standard missing data procedures in Sec. Sec. 75.33 through 75.37 
(or shall report emission data using a reference method or another 
monitoring system that has been certified or approved for use under this 
part), in the period extending from the hour of the replacement, 
modification or change made to a monitoring system that triggers the 
need to perform recertification testing, until either: the hour of 
successful completion of all of the required recertification

[[Page 249]]

tests; or the hour in which a probationary calibration error test 
(according to paragraph (b)(3)(ii) of this section) is performed and 
passed, following all necessary repairs, adjustments or reprogramming of 
the monitoring system. The first hour of quality-assured data for the 
recertified monitoring system shall either be the hour after all 
recertification tests have been completed or, if conditional data 
validation is used, the first quality-assured hour shall be determined 
in accordance with paragraphs (b)(3)(ii) through (b)(3)(ix) of this 
section. Notwithstanding these requirements, if the replacement, 
modification, or change requiring recertification of the CEMS is such 
that the historical data stream is no longer representative (e.g., where 
the SO2 concentration and stack flow rate change 
significantly after installation of a wet scrubber), the owner or 
operator shall substitute for missing data as follows, in lieu of using 
the standard missing data procedures in Sec. Sec. 75.33 through 75.37: 
for a change that results in a significantly higher concentration or 
flow rate, substitute maximum potential values according to the 
procedures in paragraph (a)(5) of this section; or for a change that 
results in a significantly lower concentration or flow rate, substitute 
data using the standard missing data procedures. The owner or operator 
shall then use the initial missing data procedures in Sec. 75.31, 
beginning with the first hour of quality-assured data obtained with the 
recertified monitoring system, unless otherwise provided by Sec. 75.34 
for units with add-on emission controls.
    (ii) Once the modification or change to the CEMS has been completed 
and all of the associated repairs, component replacements, adjustments, 
linearization, and reprogramming of the CEMS have been completed, a 
probationary calibration error test is required to establish the 
beginning point of the recertification test period. In this instance, 
the first successful calibration error test of the monitoring system 
following completion of all necessary repairs, component replacements, 
adjustments, linearization and reprogramming shall be the probationary 
calibration error test. The probationary calibration error test must be 
passed before any of the required recertification tests are commenced.
    (iii) Beginning with the hour of commencement of a recertification 
test period, emission data recorded by the CEMS are considered to be 
conditionally valid, contingent upon the results of the subsequent 
recertification tests.
    (iv) Each required recertification test shall be completed no later 
than the following number of unit operating hours (or unit operating 
days) after the probationary calibration error test that initiates the 
test period:
    (A) For a linearity check and/or cycle time test, 168 consecutive 
unit operating hours, as defined in Sec. 72.2 of this chapter or, for 
CEMS installed on common stacks or bypass stacks, 168 consecutive stack 
operating hours, as defined in Sec. 72.2 of this chapter;
    (B) For a RATA (whether normal-load or multiple-load), 720 
consecutive unit operating hours, as defined in Sec. 72.2 of this 
chapter or, for CEMS installed on common stacks or bypass stacks, 720 
consecutive stack operating hours, as defined in Sec. 72.2 of this 
chapter; and
    (C) For a 7-day calibration error test, 21 consecutive unit 
operating days, as defined in Sec. 72.2 of this chapter.
    (v) All recertification tests shall be performed hands-off. No 
adjustments to the calibration of the CEMS, other than the routine 
calibration adjustments following daily calibration error tests as 
described in section 2.1.3 of appendix B to this part, are permitted 
during the recertification test period. Routine daily calibration error 
tests shall be performed throughout the recertification test period, in 
accordance with section 2.1.1 of appendix B to this part. The additional 
calibration error test requirements in section 2.1.3 of appendix B to 
this part shall also apply during the recertification test period.
    (vi) If all of the required recertification tests and required daily 
calibration error tests are successfully completed in succession with no 
failures, and if each recertification test is completed within the time 
period specified in paragraph (b)(3)(iv)(A), (B), or (C) of this 
section, then all of the conditionally valid emission data recorded

[[Page 250]]

by the CEMS shall be considered quality-assured, from the hour of 
commencement of the recertification test period until the hour of 
completion of the required test(s).
    (vii) If a required recertification test is failed or aborted due to 
a problem with the CEMS, or if a daily calibration error test is failed 
during a recertification test period, data validation shall be done as 
follows:
    (A) If any required recertification test is failed, it shall be 
repeated. If any recertification test other than a 7-day calibration 
error test is failed or aborted due to a problem with the CEMS, the 
original recertification test period is ended, and a new recertification 
test period must be commenced with a probationary calibration error 
test. The tests that are required in the new recertification test period 
will include any tests that were required for the initial 
recertification event which were not successfully completed and any 
recertification or diagnostic tests that are required as a result of 
changes made to the monitoring system to correct the problems that 
caused the failure of the recertification test. For a 2- or 3-load flow 
RATA, if the relative accuracy test is passed at one or more load 
levels, but is failed at a subsequent load level, provided that the 
problem that caused the RATA failure is corrected without re-linearizing 
the instrument, the length of the new recertification test period shall 
be equal to the number of unit operating hours remaining in the original 
recertification test period, as of the hour of failure of the RATA. 
However, if re-linearization of the flow monitor is required after a 
flow RATA is failed at a particular load level, then a subsequent 3-load 
RATA is required, and the new recertification test period shall be 720 
consecutive unit (or stack) operating hours. The new recertification 
test sequence shall not be commenced until all necessary maintenance 
activities, adjustments, linearizations, and reprogramming of the CEMS 
have been completed;
    (B) If a linearity check, RATA, or cycle time test is failed or 
aborted due to a problem with the CEMS, all conditionally valid emission 
data recorded by the CEMS are invalidated, from the hour of commencement 
of the recertification test period to the hour in which the test is 
failed or aborted, except for the case in which a multiple-load flow 
RATA is passed at one or more load levels, failed at a subsequent load 
level, and the problem that caused the RATA failure is corrected without 
re-linearizing the instrument. In that case, data invalidation shall be 
prospective, from the hour of failure of the RATA until the commencement 
of the new recertification test period. Data from the CEMS remain 
invalid until the hour in which a new recertification test period is 
commenced, following corrective action, and a probationary calibration 
error test is passed, at which time the conditionally valid status of 
emission data from the CEMS begins again;
    (C) If a 7-day calibration error test is failed within the 
recertification test period, previously-recorded conditionally valid 
emission data from the CEMS are not invalidated. The conditionally valid 
data status is unaffected, unless the calibration error on the day of 
the failed 7-day calibration error test exceeds twice the performance 
specification in section 3 of appendix A to this part, as described in 
paragraph (b)(3)(vii)(D) of this section; and
    (D) If a daily calibration error test is failed during a 
recertification test period (i.e., the results of the test exceed twice 
the performance specification in section 3 of appendix A to this part), 
the CEMS is out-of-control as of the hour in which the calibration error 
test is failed. Emission data from the CEMS shall be invalidated 
prospectively from the hour of the failed calibration error test until 
the hour of completion of a subsequent successful calibration error test 
following corrective action, at which time the conditionally valid 
status of data from the monitoring system resumes. Failure to perform a 
required daily calibration error test during a recertification test 
period shall also cause data from the CEMS to be invalidated 
prospectively, from the hour in which the calibration error test was due 
until the hour of completion of a subsequent successful calibration 
error test. Whenever a calibration error test

[[Page 251]]

is failed or missed during a recertification test period, no further 
recertification tests shall be performed until the required subsequent 
calibration error test has been passed, re-establishing the 
conditionally valid status of data from the monitoring system. If a 
calibration error test failure occurs while a linearity check or RATA is 
still in progress, the linearity check or RATA must be re-started.
    (E) Trial gas injections and trial RATA runs are permissible during 
the recertification test period, prior to commencing a linearity check 
or RATA, for the purpose of optimizing the performance of the CEMS. The 
results of such gas injections and trial runs shall not affect the 
status of previously-recorded conditionally valid data or result in 
termination of the recertification test period, provided that the 
following specifications and conditions are met:
    (1) For gas injections, the stable, ending monitor response is 
within [5 percent or within 5 ppm of the tag value of the reference gas;
    (2) For RATA trial runs, the average reference method reading and 
the average CEMS reading for the run differ by no more than [10% of the 
average reference method value or [15 ppm, or [1.5% H2O, or 
[0.02 lb/mmBtu from the average reference method value, as applicable;
    (3) No adjustments to the calibration of the CEMS are made following 
the trial injection(s) or run(s), other than the adjustments permitted 
under section 2.1.3 of appendix B to this part; and
    (4) The CEMS is not repaired, re-linearized or reprogrammed (e.g., 
changing flow monitor polynomial coefficients, linearity constants, or 
K-factors) after the trial injection(s) or run(s).
    (F) If the results of any trial gas injection(s) or RATA run(s) are 
outside the limits in paragraphs (b)(3)(vii)(E)(1) or (2) of this 
section or if the CEMS is repaired, re-linearized or reprogrammed after 
the trial injection(s) or run(s), the trial injection(s) or run(s) shall 
be counted as a failed linearity check or RATA attempt. If this occurs, 
follow the procedures pertaining to failed and aborted recertification 
tests in paragraphs (b)(3)(vii)(A) and (b)(3)(vii)(B) of this section.
    (viii) If any required recertification test is not completed within 
its allotted time period, data validation shall be done as follows. For 
a late linearity test, RATA, or cycle time test that is passed on the 
first attempt, data from the monitoring system shall be invalidated from 
the hour of expiration of the recertification test period until the hour 
of completion of the late test. For a late 7-day calibration error test, 
whether or not it is passed on the first attempt, data from the 
monitoring system shall also be invalidated from the hour of expiration 
of the recertification test period until the hour of completion of the 
late test. For a late linearity test, RATA, or cycle time test that is 
failed on the first attempt or aborted on the first attempt due to a 
problem with the monitor, all conditionally valid data from the 
monitoring system shall be considered invalid back to the hour of the 
first probationary calibration error test which initiated the 
recertification test period. Data from the monitoring system shall 
remain invalid until the hour of successful completion of the late 
recertification test and any additional recertification or diagnostic 
tests that are required as a result of changes made to the monitoring 
system to correct problems that caused failure of the late 
recertification test.
    (ix) If any required recertification test of a monitoring system has 
not been completed by the end of a calendar quarter and if data 
contained in the quarterly report are conditionally valid pending the 
results of test(s) to be completed in a subsequent quarter, the owner or 
operator shall indicate this by means of a suitable conditionally valid 
data flag in the electronic quarterly report for that quarter. The owner 
or operator shall resubmit the report for that quarter if the required 
recertification test is subsequently failed. In the resubmitted report, 
the owner or operator shall use the appropriate missing data routine in 
Sec. 75.31 or Sec. 75.33 to replace with substitute data each hour of 
conditionally valid data that was invalidated by the failed 
recertification test. Alternatively, if any required recertification

[[Page 252]]

test is not completed by the end of a particular calendar quarter but is 
completed no later than 30 days after the end of that quarter (i.e., 
prior to the deadline for submitting the quarterly report under Sec. 
75.64), the test data and results may be submitted with the earlier 
quarterly report even though the test date(s) are from the next calendar 
quarter. In such instances, if the recertification test(s) are passed in 
accordance with the provisions of paragraph (b)(3) of this section, 
conditionally valid data may be reported as quality-assured, in lieu of 
reporting a conditional data flag. If the recertification test(s) is 
failed and if conditionally valid data are replaced, as appropriate, 
with substitute data, then neither the reporting of a conditional data 
flag nor resubmission is required. In addition, if the owner or operator 
uses a conditionally valid data flag in any of the four quarterly 
reports for a given year, the owner or operator shall indicate the final 
status of the conditionally valid data (i.e., resolved or unresolved) in 
the annual compliance certification report required under Sec. 72.90 of 
this chapter for that year. The Administrator may invalidate any 
conditionally valid data that remains unresolved at the end of a 
particular calendar year and may require the owner or operator to 
resubmit one or more of the quarterly reports for that calendar year, 
replacing the unresolved conditionally valid data with substitute data 
values determined in accordance with Sec. 75.31 or Sec. 75.33, as 
appropriate.
    (4) Recertification application. The designated representative shall 
apply for recertification of each continuous emission or opacity 
monitoring system used under the Acid Rain Program. The owner or 
operator shall submit the recertification application in accordance with 
Sec. 75.60, and each complete recertification application shall include 
the information specified in Sec. 75.63.
    (5) Approval or disapproval of request for recertification. The 
procedures for provisional certification in paragraph (a)(3) of this 
section shall apply to recertification applications. The Administrator 
will issue a notice of approval, disapproval, or incompleteness 
according to the procedures in paragraph (a)(4) of this section. In the 
event that a recertification application is disapproved, data from the 
monitoring system are invalidated and the applicable missing data 
procedures in Sec. Sec. 75.31 or 75.33 shall be used from the date and 
hour of receipt of the disapproval notice back to the hour of the 
adjustment or change to the CEMS that triggered the need for 
recertification testing or, if the conditional data validation 
procedures in paragraphs (b)(3)(ii) through (b)(3)(ix) of this section 
were used, back to the hour of the probationary calibration error test 
that began the recertification test period. Data from the monitoring 
system remain invalid until all required recertification tests have been 
passed or until a subsequent probationary calibration error test is 
passed, beginning a new recertification test period. The owner or 
operator shall repeat all recertification tests or other requirements, 
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. The designated representative shall submit a notification 
of the recertification retest dates, as specified in Sec. 
75.61(a)(1)(ii), and shall submit a new recertification application 
according to the procedures in paragraph (b)(4) of this section.
    (c) Initial certification and recertification procedures. Prior to 
the deadline in Sec. 75.4, the owner or operator shall conduct initial 
certification tests and in accordance with Sec. 75.63, the designated 
representative shall submit an application to demonstrate that the 
continuous emission or opacity monitoring system and components thereof 
meet the specifications in appendix A to this part. The owner or 
operator shall compare reference method values with output from the 
automated data acquisition and handling system that is part of the 
continuous emission monitoring system being tested. Except as otherwise 
specified in paragraphs (b)(1), (d), and (e) of this section, and in 
sections 6.3.1 and 6.3.2 of appendix A to this part, the owner or 
operator shall perform the following tests for initial certification or 
recertification of continuous emission or opacity monitoring systems or 
components according to the requirements of appendix A to this part:

[[Page 253]]

    (1) For each SO2 pollutant concentration monitor, each 
NOX concentration monitoring system used to determine 
NOX mass emissions, as defined under Sec. 75.71(a)(2), and 
each NOX-diluent continuous emission monitoring system:
    (i) A 7-day calibration error test, where, for the NOX -
diluent continuous emission monitoring system, the test is performed 
separately on the NOX pollutant concentration monitor and the 
diluent gas monitor;
    (ii) A linearity check, where, for the NOX-diluent 
continuous emission monitoring system, the test is performed separately 
on the NOX pollutant concentration monitor and the diluent 
gas monitor;
    (iii) A relative accuracy test audit. For the NOX-diluent 
continuous emission monitoring system, the RATA shall be done on a 
system basis, in units of lb/mmBtu. For the NOX concentration 
monitoring system, the RATA shall be done on a ppm basis;
    (iv) A bias test;
    (v) A cycle time test, (where, for the NOX-diluent 
continuous emission monitoring system, the test is performed separately 
on the NOX pollutant concentration monitor and the diluent 
gas monitor); and
    (2) For each flow monitor:
    (i) A 7-day calibration error test;
    (ii) Relative accuracy test audits, as follows:
    (A) A single-load (or single-level) RATA at the normal load (or 
level), as defined in section 6.5.2.1(d) of appendix A to this part, for 
a flow monitor installed on a peaking unit or bypass stack, or for a 
flow monitor exempted from multiple-level RATA testing under section 
6.5.2(e) of appendix A to this part;
    (B) For all other flow monitors, a RATA at each of the three load 
levels (or operating levels) corresponding to the three flue gas 
velocities described in section 6.5.2(a) of appendix A to this part;
    (iii) A bias test for the single-load (or single-level) flow RATA 
described in paragraph (c)(2)(ii)(A) of this section; and
    (iv) A bias test (or bias tests) for the 3-level flow RATA described 
in paragraph (c)(2)(ii)(B) of this section, at the following load or 
operational level(s):
    (A) At each load level designated as normal under section 6.5.2.1(d) 
of appendix A to this part, for units that produce electrical or thermal 
output, or
    (B) At the operational level identified as normal in section 
6.5.2.1(d) of appendix A to this part, for units that do not produce 
electrical or thermal output.
    (3) The initial certification test data from an O2 or a 
CO2 diluent gas monitor certified for use in a NOX 
continuous emission monitoring system may be submitted to meet the 
requirements of paragraph (c)(4) of this section. Also, for a diluent 
monitor that is used both as a CO2 monitoring system and to 
determine heat input, only one set of diluent monitor certification data 
need be submitted (under the component and system identification numbers 
of the CO2 monitoring system).
    (4) For each CO2 pollutant concentration monitor, each 
CO2 monitoring system that uses an O2 monitor to 
determine CO2 concentration, and each diluent gas monitor 
used only to monitor heat input rate:
    (i) A 7-day calibration error test;
    (ii) A linearity check;
    (iii) A relative accuracy test audit, where, for an O2 
monitor used to determine CO2 concentration, the 
CO2 reference method shall be used for the RATA; and
    (iv) A cycle-time test.
    (5) For each continuous moisture monitoring system consisting of 
wet- and dry-basis O2 analyzers:
    (i) A 7-day calibration error test of each O2 analyzer;
    (ii) A cycle time test of each O2 analyzer;
    (iii) A linearity test of each O2 analyzer; and
    (iv) A RATA, directly comparing the percent moisture measured by the 
monitoring system to a reference method.
    (6) For each continuous moisture sensor: A RATA, directly comparing 
the percent moisture measured by the monitor sensor to a reference 
method.
    (7) For a continuous moisture monitoring system consisting of a 
temperature sensor and a data acquisition and

[[Page 254]]

handling system (DAHS) software component programmed with a moisture 
lookup table:
    (i) A demonstration that the correct moisture value for each hour is 
being taken from the moisture lookup tables and applied to the emission 
calculations. At a minimum, the demonstration shall be made at three 
different temperatures covering the normal range of stack temperatures 
from low to high.
    (ii) [Reserved]
    (8) The owner or operator shall ensure that initial certification or 
recertification of a continuous opacity monitor for use under the Acid 
Rain Program is conducted according to one of the following procedures:
    (i) Performance of the tests for initial certification or 
recertification, according to the requirements of Performance 
Specification 1 in appendix B to part 60 of this chapter; or
    (ii) A continuous opacity monitoring system tested and certified 
previously under State or other Federal requirements to meet the 
requirements of Performance Specification 1 shall be deemed certified 
for the purposes of this part.
    (9) [Reserved]
    (10) For the automated data acquisition and handling system, tests 
designed to verify:
    (i) Proper computation of hourly averages for pollutant 
concentrations, flow rate, pollutant emission rates, and pollutant mass 
emissions; and
    (ii) Proper computation and application of the missing data 
substitution procedures in subpart D of this part and the bias 
adjustment factors in section 7 of appendix A to this part.
    (11) The owner or operator shall provide adequate facilities for 
initial certification or recertification testing that include:
    (i) Sampling ports adequate for test methods applicable to such 
facility, such that:
    (A) Volumetric flow rate, pollutant concentration, and pollutant 
emission rates can be accurately determined by applicable test methods 
and procedures; and
    (B) A stack or duct free of cyclonic flow during performance tests 
is available, as demonstrated by applicable test methods and procedures.
    (ii) Basic facilities (e.g., electricity) for sampling and testing 
equipment.
    (d) Initial certification and recertification and quality assurance 
procedures for optional backup continuous emission monitoring systems--
(1) Redundant backups. The owner or operator of an optional redundant 
backup CEMS shall comply with all the requirements for initial 
certification and recertification according to the procedures specified 
in paragraphs (a), (b), and (c) of this section. The owner or operator 
shall operate the redundant backup CEMS during all periods of unit 
operation, except for periods of calibration, quality assurance, 
maintenance, or repair. The owner or operator shall perform upon the 
redundant backup CEMS all quality assurance and quality control 
procedures specified in appendix B to this part, except that the daily 
assessments in section 2.1 of appendix B to this part are optional for 
days on which the redundant backup CEMS is not used to report emission 
data under this part. For any day on which a redundant backup CEMS is 
used to report emission data, the system must meet all of the applicable 
daily assessment criteria in appendix B to this part.
    (2) Non-redundant backups. The owner or operator of an optional non-
redundant backup CEMS or like-kind replacement analyzer shall comply 
with all of the following requirements for initial certification, 
quality assurance, recertification, and data reporting:
    (i) Except as provided in paragraph (d)(2)(v) of this section, for a 
regular non-redundant backup CEMS (i.e., a non-redundant backup CEMS 
that has its own separate probe, sample interface, and analyzer), or a 
non-redundant backup flow monitor, all of the tests in paragraph (c) of 
this section are required for initial certification of the system, 
except for the 7-day calibration error test.
    (ii) For a like-kind replacement non-redundant backup analyzer 
(i.e., a non-redundant backup analyzer that uses the same probe and 
sample interface as a primary monitoring system), no initial 
certification of the analyzer is required. A non-redundant backup 
analyzer, connected to the same probe and

[[Page 255]]

interface as a primary CEMS in order to satisfy the dual span 
requirements of section 2.1.1.4 or 2.1.2.4 of appendix A to this part, 
shall be treated in the same manner as a like-kind replacement analyzer.
    (iii) Each non-redundant backup CEMS or like-kind replacement 
analyzer shall comply with the daily and quarterly quality assurance and 
quality control requirements in appendix B to this part for each day and 
quarter that the non-redundant backup CEMS or like-kind replacement 
analyzer is used to report data, and shall meet the additional linearity 
and calibration error test requirements specified in this paragraph. The 
owner or operator shall ensure that each non-redundant backup CEMS or 
like-kind replacement analyzer passes a linearity check (for pollutant 
concentration and diluent gas monitors) or a calibration error test (for 
flow monitors) prior to each use for recording and reporting emissions. 
For a primary NOX-diluent CEMS consisting of the primary 
pollutant analyzer and a like-kind replacement diluent analyzer (or 
vice-versa), provided that the primary pollutant or diluent analyzer (as 
applicable) is operating and is not out-of-control with respect to any 
of its quality assurance requirements, only the like-kind replacement 
analyzer must pass a linearity check before the system is used for data 
reporting. When a non-redundant backup CEMS or like-kind replacement 
analyzer is brought into service, prior to conducting the linearity 
test, a probationary calibration error test (as described in paragraph 
(b)(3)(ii) of this section), which will begin a period of conditionally 
valid data, may be performed in order to allow the validation of data 
retrospectively, as follows. Conditionally valid data from the CEMS or 
like-kind replacement analyzer are validated back to the hour of 
completion of the probationary calibration error test if the following 
conditions are met: if no adjustments are made to the CEMS or like-kind 
replacement analyzer other than the allowable calibration adjustments 
specified in section 2.1.3 of appendix B to this part between the 
probationary calibration error test and the successful completion of the 
linearity test; and if the linearity test is passed within 168 unit (or 
stack) operating hours of the probationary calibration error test. 
However, if the linearity test is performed within 168 unit or stack 
operating hours but is either failed or aborted due to a problem with 
the CEMS or like-kind replacement analyzer, then all of the 
conditionally valid data are invalidated back to the hour of the 
probationary calibration error test, and data from the non-redundant 
backup CEMS or from the primary monitoring system of which the like-kind 
replacement analyzer is a part remain invalid until the hour of 
completion of a successful linearity test. Notwithstanding this 
requirement, the conditionally valid data status may be re-established 
after a failed or aborted linearity check, if corrective action is taken 
and a calibration error test is subsequently passed. However, in no case 
shall the use of conditional data validation extend for more than 168 
unit or stack operating hours beyond the date and time of the original 
probationary calibration error test when the analyzer was brought into 
service.
    (iv) When data are reported from a non-redundant backup CEMS or 
like-kind replacement analyzer, the appropriate bias adjustment factor 
shall be determined as follows:
    (A) For a regular non-redundant backup CEMS, as described in 
paragraph (d)(2)(i) of this section, apply the bias adjustment factor 
from the most recent RATA of the non-redundant backup system (even if 
that RATA was done more than 12 months previously); or
    (B) When a like-kind replacement non-redundant backup analyzer is 
used as a component of a primary CEMS (as described in paragraph 
(d)(2)(ii) of this section), apply the primary monitoring system bias 
adjustment factor.
    (v) For each parameter monitored (i.e., SO2, 
CO2, O2, NOX, Hg or flow rate) at each 
unit or stack, a regular non-redundant backup CEMS may not be used to 
report data at that affected unit or common stack for more than 720 
hours in any one calendar year (or 720 hours in any ozone season, for 
sources that report emission data only during the ozone season, in 
accordance with

[[Page 256]]

Sec. 75.74(c)), unless the CEMS passes a RATA at that unit or stack. 
For each parameter monitored at each unit or stack, the use of a like-
kind replacement non-redundant backup analyzer (or analyzers) is 
restricted to 720 cumulative hours per calendar year (or ozone season, 
as applicable), unless the owner or operator redesignates the like-kind 
replacement analyzer(s) as component(s) of regular non-redundant backup 
CEMS and each redesignated CEMS passes a RATA at that unit or stack.
    (vi) For each regular non-redundant backup CEMS, no more than eight 
successive calendar quarters shall elapse following the quarter in which 
the last RATA of the CEMS was done at a particular unit or stack, 
without performing a subsequent RATA. Otherwise, the CEMS may not be 
used to report data from that unit or stack until the hour of completion 
of a passing RATA at that location.
    (vii) Each regular non-redundant backup CEMS shall be represented in 
the monitoring plan required under Sec. 75.53 as a separate monitoring 
system, with unique system and component identification numbers. When 
like-kind replacement non-redundant backup analyzers are used, the owner 
or operator shall represent each like-kind replacement analyzer used 
during a particular calendar quarter in the monitoring plan required 
under Sec. 75.53 as a component of a primary monitoring system. The 
owner or operator shall also assign a unique component identification 
number to each like-kind replacement analyzer, beginning with the 
letters ``LK'' (e.g., ``LK1,'' ``LK2,'' etc.) and shall specify the 
manufacturer, model and serial number of the like-kind replacement 
analyzer. This information may be added, deleted or updated as 
necessary, from quarter to quarter. The owner or operator shall also 
report data from the like-kind replacement analyzer using the system 
identification number of the primary monitoring system and the assigned 
component identification number of the like-kind replacement analyzer. 
For the purposes of the electronic quarterly report required under Sec. 
75.64, the owner or operator may manually enter the appropriate 
component identification number(s) of any like-kind replacement 
analyzer(s) used for data reporting during the quarter.
    (viii) When reporting data from a certified regular non-redundant 
backup CEMS, use a method of determination (MODC) code of ``02.'' When 
reporting data from a like-kind replacement non-redundant backup 
analyzer, use a MODC of ``17'' (see Table 4a under Sec. 75.57). For the 
purposes of the electronic quarterly report required under Sec. 75.64, 
the owner or operator may manually enter the required MODC of ``17'' for 
a like-kind replacement analyzer.
    (3) Reference method backups. A monitoring system that is operated 
as a reference method backup system pursuant to the reference method 
requirements of methods 2, 6C, 7E, or 3A in appendix A of part 60 of 
this chapter need not perform and pass the certification tests required 
by paragraph (c) of this section prior to its use pursuant to this 
paragraph.
    (e) Certification/recertification procedures for either peaking unit 
or by-pass stack/duct continuous emission monitoring systems. The owner 
or operator of either a peaking unit or by-pass stack/duct continuous 
emission monitoring system shall comply with all the requirements for 
certification or recertification according to the procedures specified 
in paragraphs (a), (b), and (c) of this section, except as follows: the 
owner or operator need only perform one nine-run relative accuracy test 
audit for certification or recertification of a flow monitor installed 
on the by-pass stack/duct or on the stack/duct used only by affected 
peaking unit(s). The relative accuracy test audit shall be performed 
during normal operation of the peaking unit(s) or the by-pass stack/
duct.
    (f) Certification/recertification procedures for alternative 
monitoring systems. The designated representative representing the owner 
or operator of each alternative monitoring system approved by the 
Administrator as equivalent to or better than a continuous emission 
monitoring system according to the criteria in subpart E of this part 
shall apply for certification to the Administrator prior to use of the 
system under the Acid Rain Program, and

[[Page 257]]

shall apply for recertification to the Administrator following a 
replacement, modification, or change according to the procedures in 
paragraph (c) of this section. The owner or operator of an alternative 
monitoring system shall comply with the notification and application 
requirements for certification or recertification according to the 
procedures specified in paragraphs (a) and (b) of this section.
    (g) Initial certification and recertification procedures for 
excepted monitoring systems under appendices D and E. The owner or 
operator of a gas-fired unit, oil-fired unit, or diesel-fired unit using 
the optional protocol under appendix D or E to this part shall ensure 
that an excepted monitoring system under appendix D or E to this part 
meets the applicable general operating requirements of Sec. 75.10, the 
applicable requirements of appendices D and E to this part, and the 
initial certification or recertification requirements of this paragraph.
    (1) Initial certification and recertification testing. The owner or 
operator shall use the following procedures for initial certification 
and recertification of an excepted monitoring system under appendix D or 
E to this part.
    (i) When the optional SO2 mass emissions estimation 
procedure in appendix D to this part or the optional NOX 
emissions estimation protocol in appendix E to this part is used, the 
owner or operator shall provide data from a flowmeter accuracy test (or 
shall provide a statement of calibration if the flowmeter meets the 
accuracy standard by design) for each fuel flowmeter, according to 
section 2.1.5.1 of appendix D to this part. For orifice, nozzle, and 
venturi-type flowmeters, the results of primary element visual 
inspections and/or calibrations of the transmitters or transducers shall 
also be provided.
    (ii) For the automated data acquisition and handling system used 
under either the optional SO2 mass emissions estimation 
procedure in appendix D of this part or the optional NOX 
emissions estimation protocol in appendix E of this part, the owner or 
operator shall perform tests designed to verify:
    (A) The proper computation of hourly averages for pollutant 
concentrations, fuel flow rates, emission rates, heat input, and 
pollutant mass emissions; and
    (B) Proper computation and application of the missing data 
substitution procedures in appendix D or E of this part.
    (iii) When the optional NOX emissions protocol in 
appendix E is used, the owner or operator shall complete all initial 
performance testing under section 2.1 of appendix E.
    (2) Initial certification, recertification, and QA testing 
notification. The designated representative shall provide initial 
certification testing notification, recertification testing 
notification, and routine periodic quality-assurance testing, as 
specified in Sec. 75.61. Initial certification testing notification, 
recertification testing notification, or periodic quality assurance 
testing notification is not required for an excepted monitoring system 
under appendix D to this part.
    (3) Monitoring plan. The designated representative shall submit an 
initial monitoring plan in accordance with Sec. 75.62(a).
    (4) Initial certification or recertification application. The 
designated representative shall submit an initial certification or 
recertification application in accordance with Sec. Sec. 75.60 and 
75.63.
    (5) Provisional approval of initial certification and 
recertification applications. Upon the successful completion of the 
required initial certification or recertification procedures for each 
excepted monitoring system under appendix D or E to this part, each 
excepted monitoring system under appendix D or E to this part shall be 
deemed provisionally certified (or recertified) for use under the Acid 
Rain Program during the period for the Administrator's review. The 
provisions for the initial certification or recertification application 
formal approval process in paragraph (a)(4) of this section shall apply, 
except that the term ``excepted monitoring system'' shall apply rather 
than ``continuous emission or opacity monitoring system'' and except 
that the procedures for loss of certification or for disapproval of a 
recertification request in paragraph (g)(7) of this section shall apply 
rather than the procedures for loss of certification or denial of a 
recertification request in paragraph

[[Page 258]]

(a)(5) or (b)(5) of this section. Data measured and recorded by a 
provisionally certified (or recertified) excepted monitoring system 
under appendix D or E to this part will be considered quality-assured 
data from the date and time of completion of the last initial 
certification or recertification test, provided that the Administrator 
does not revoke the provisional certification or recertification by 
issuing a notice of disapproval in accordance with the provisions in 
paragraph (a)(4) or (b)(5) of this section.
    (6) Recertification requirements. Recertification of an excepted 
monitoring system under appendix D or E to this part is required for any 
modification to the system or change in operation that could 
significantly affect the ability of the system to accurately account for 
emissions and for which the Administrator determines that an accuracy 
test of the fuel flowmeter or a retest under appendix E to this part to 
re-establish the NOX correlation curve is required. Examples 
of such changes or modifications include fuel flowmeter replacement, 
changes in unit configuration, or exceedance of operating parameters.
    (7) Procedures for loss of certification or recertification for 
excepted monitoring systems under appendices D and E to this part. In 
the event that a certification or recertification application is 
disapproved for an excepted monitoring system, data from the monitoring 
system are invalidated, and the applicable missing data procedures in 
section 2.4 of appendix D or section 2.5 of appendix E to this part 
shall be used from the date and hour of receipt of such notice back to 
the hour of the provisional certification. Data from the excepted 
monitoring system remain invalid until all required tests are repeated 
and the excepted monitoring system is again provisionally certified. The 
owner or operator shall repeat all certification or recertification 
tests or other requirements, 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. The designated representative 
shall submit a notification of the certification or recertification 
retest dates if required under paragraph (g)(2) of this section and 
shall submit a new certification or recertification application 
according to the procedures in paragraph (g)(4) of this section.
    (h) Initial certification and recertification procedures for low 
mass emission units using the excepted methodologies under Sec. 75.19. 
The owner or operator of a gas-fired or oil-fired unit using the low 
mass emissions excepted methodology under Sec. 75.19 shall meet the 
applicable general operating requirements of Sec. 75.10, the applicable 
requirements of Sec. 75.19, and the applicable certification 
requirements of this paragraph.
    (1) Monitoring plan. The designated representative shall submit a 
monitoring plan in accordance with Sec. Sec. 75.53 and 75.62.
    (2) Certification application. The designated representative shall 
submit a certification application in accordance with Sec. 
75.63(a)(1)(ii).
    (3) Approval of certification applications. The provisions for the 
certification application formal approval process in the introductory 
text of paragraph (a)(4) and in paragraphs (a)(4)(i), (ii), and (iv) of 
this section shall apply, except that ``continuous emission or opacity 
monitoring system'' shall be replaced with ``low mass emissions excepted 
methodology.'' Provisional certification status for the low mass 
emissions methodology begins on the date of submittal (consistent with 
the definition of ``submit'' in Sec. 72.2 of this chapter) of a 
complete certification application, and the methodology is considered to 
be certified either upon receipt of a written approval notice from the 
Administrator or, if such notice is not provided, at the end of the 
Administrator's 120-day review period. However, in contrast to CEM 
systems or appendix D and E monitoring systems, a provisionally 
certified or certified low mass emissions excepted methodology may not 
be used to report data under the Acid Rain Program or in a 
NOX mass emissions reduction program under subpart H of this 
part prior to the applicable commencement date specified in Sec. 
75.19(a)(2)(i).

[[Page 259]]

    (4) Disapproval of low mass emissions unit certification 
applications. If the Administrator determines that the certification 
application for a low mass emissions unit does not demonstrate that the 
unit meets the requirements of Sec. Sec. 75.19(a) and (b), the 
Administrator shall issue a written notice of disapproval of the 
certification application within 120 days of receipt. By issuing the 
notice of disapproval, the provisional certification is invalidated by 
the Administrator, and any emission data reported using the excepted 
methodology during the Administrator's 120-day review period shall be 
considered invalid. The owner or operator shall use the following 
procedures when a certification application is disapproved:
    (i) The owner or operator shall substitute the following values, as 
applicable, for each hour of unit operation in which data were reported 
using the low mass emissions methodology until such time, date, and hour 
as continuous emission monitoring systems or excepted monitoring 
systems, where applicable, are installed and provisionally certified: 
the maximum potential concentration of SO2, as defined in 
section 2.1.1.1 of appendix A to this part; the maximum potential fuel 
flowrate, as defined in section 2.4.2 of appendix D to this part; the 
maximum potential values of fuel sulfur content, GCV, and density (if 
applicable) in Table D-6 of appendix D to this part; the maximum 
potential NOX emission rate, as defined in Sec. 72.2 of this 
chapter; the maximum potential flow rate, as defined in section 2.1.4.1 
of appendix A to this part; or the maximum potential CO2 
concentration as defined in section 2.1.3.1 of appendix A to this part. 
For a unit subject to a State or federal NOX mass reduction 
program where the owner or operator intends to monitor NOX 
mass emissions with a NOX pollutant concentration monitor and 
a flow monitoring system, substitute for NOX concentration 
using the maximum potential concentration of NOX, as defined 
in section 2.1.2.1 of appendix A to this part, and substitute for 
volumetric flow using the maximum potential flow rate, as defined in 
section 2.1.4.1 of appendix A to this part; and
    (ii) The designated representative shall submit a notification of 
certification test dates for the required monitoring systems, as 
specified in Sec. 75.61(a)(1)(i), and shall submit a certification 
application according to the procedures in paragraph (a)(2) of this 
section.
    (5) Recertification. Recertification of an approved low mass 
emissions excepted methodology is not required. Once the Administrator 
has approved the methodology for use, the owner or operator is subject 
to the on-going qualification and disqualification procedures in Sec. 
75.19(b), on an annual or ozone season basis, as applicable.

[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26524, May 17, 1995; 60 
FR 40296, Aug. 8, 1995; 61 FR 59158, Nov. 20, 1996; 63 FR 57506, Oct. 
27, 1998; 64 FR 28592, May 26, 1999; 67 FR 40431, June 12, 2002; 70 FR 
28678, May 18, 2005; 72 FR 51527, Sept. 7, 2007; 73 FR 4345, Jan. 24, 
2008; 76 FR 17308, Mar. 28, 2011]



Sec. 75.21  Quality assurance and quality control requirements.

    (a) Continuous emission monitoring systems. The owner or operator of 
an affected unit shall operate, calibrate and maintain each continuous 
emission monitoring system used to report emission data under the Acid 
Rain Program as follows:
    (1) The owner or operator shall operate, calibrate and maintain each 
primary and redundant backup continuous emission monitoring system 
according to the quality assurance and quality control procedures in 
appendix B of this part.
    (2) The owner or operator shall ensure that each non-redundant 
backup CEMS meets the quality assurance requirements of Sec. 75.20(d) 
for each day and quarter that the system is used to report data.
    (3) The owner or operator shall perform quality assurance upon a 
reference method backup monitoring system according to the requirements 
of Method 2, 6C, 7E, or 3A in Appendices A-1, A-2 and A-4 to part 60 of 
this chapter (supplemented, as necessary, by guidance from the 
Administrator), instead of the procedures specified in appendix B to 
this part.

[[Page 260]]

    (4) The owner or operator of a unit with an SO2 
continuous emission monitoring system is not required to perform the 
daily or quarterly assessments of the SO2 monitoring system 
under appendix B to this part on any day or in any calendar quarter in 
which only gaseous fuel is combusted in the unit if, during those days 
and calendar quarters, SO2 emissions are determined in 
accordance with Sec. 75.11(e)(1). However, such assessments are 
permissible, and if any daily calibration error test or linearity test 
of the SO2 monitoring system is failed while the unit is 
combusting only gaseous fuel, the SO2 monitoring system shall 
be considered out-of-control. The length of the out-of-control period 
shall be determined in accordance with the applicable procedures in 
section 2.1.4 or 2.2.3 of appendix B to this part.
    (5) For a unit with an SO2 continuous monitoring system, 
in which gaseous fuel that is very low sulfur fuel (as defined in Sec. 
72.2 of this chapter) is sometimes burned as a primary or backup fuel 
and in which higher-sulfur fuel(s) such as oil or coal are, at other 
times, burned as primary or backup fuel(s), the owner shall perform the 
relative accuracy test audits of the SO2 monitoring system 
(as required by section 6.5 of appendix A to this part and section 2.3.1 
of appendix B to this part) only when the higher-sulfur fuel is 
combusted in the unit and shall not perform SO2 relative 
accuracy test audits when the very low sulfur gaseous fuel is the only 
fuel being combusted.
    (6) If the designated representative certifies that a unit with an 
SO2 monitoring system burns only very low sulfur fuel (as 
defined in Sec. 72.2 of this chapter), the SO2 monitoring 
system is exempted from the relative accuracy test audit requirements in 
appendices A and B to this part.
    (7) If the designated representative certifies that a particular 
unit with an SO2 monitoring system combusts primarily fuel(s) 
that are very low sulfur fuel(s) (as defined in Sec. 72.2 of this 
chapter) and combusts higher sulfur fuel(s) only for infrequent, non-
routine operations (e.g., only as emergency backup fuel(s) or for short-
term testing), the SO2 monitoring system shall be exempted 
from the RATA requirements of appendices A and B to this part in any 
calendar year that the unit combusts the higher sulfur fuel(s) for no 
more than 480 hours. If, in a particular calendar year, the higher-
sulfur fuel usage exceeds 480 hours, the owner or operator shall perform 
a RATA of the SO2 monitor (while combusting the higher-sulfur 
fuel) either by the end of the calendar quarter in which the exceedance 
occurs or by the end of a 720 unit (or stack) operating hour grace 
period (under section 2.3.3 of appendix B to this part) following the 
quarter in which the exceedance occurs.
    (8) The quality assurance provisions of Sec. Sec. 75.11(e)(3)(i) 
through 75.11(e)(3)(iv) shall apply to all units with SO2 
monitoring systems during hours in which only very low sulfur fuel (as 
defined in Sec. 72.2 of this chapter) is combusted in the unit.
    (9) Provided that a unit with an SO2 monitoring system is 
not exempted from the SO2 RATA requirements of this part 
under paragraphs (a)(6) or (a)(7) of this section, any calendar quarter 
during which a unit combusts only very low sulfur fuel (as defined in 
Sec. 72.2 of this chapter) shall be excluded in determining the quarter 
in which the next relative accuracy test audit must be performed for the 
SO2 monitoring system. However, no more than eight successive 
calendar quarters shall elapse after a relative accuracy test audit of 
an SO2 monitoring system, without a subsequent relative 
accuracy test audit having been performed. The owner or operator shall 
ensure that a relative accuracy test audit is performed, in accordance 
with paragraph (a)(5) of this section, either by the end of the eighth 
successive elapsed calendar quarter since the last RATA or by the end of 
a 720 unit (or stack) operating hour grace period, as provided in 
section 2.3.3 of appendix B to this part.
    (10) The owner or operator who, in accordance with Sec. 
75.11(e)(1), uses a certified flow monitor and a certified diluent 
monitor and Equation F-23 in appendix F to this part to calculate 
SO2 emissions during hours in which a unit combusts only 
natural gas or pipeline natural gas (as defined in Sec. 72.2 of this 
chapter) shall meet all quality control and quality assurance 
requirements in

[[Page 261]]

appendix B to this part for the flow monitor and the diluent monitor.
    (b) Continuous opacity monitoring systems. The owner or operator of 
an affected unit shall operate, calibrate, and maintain each continuous 
opacity monitoring system used under the Acid Rain Program according to 
the procedures specified for State Implementation Plans, pursuant to 
part 51, appendix M of this chapter.
    (c) Calibration gases. The owner or operator shall ensure that all 
calibration gases used to quality assure the operation of the 
instrumentation required by this part shall meet the definition in Sec. 
72.2 of this chapter.
    (d) Notification for periodic relative accuracy test audits. The 
owner or operator or the designated representative shall submit a 
written notice of the dates of relative accuracy testing as specified in 
Sec. 75.61.
    (e) Consequences of audits. The owner or operator shall invalidate 
data from a continuous emission monitoring system or continuous opacity 
monitoring system upon failure of an audit under appendix B to this part 
or any other audit, beginning with the unit operating hour of completion 
of a failed audit as determined by the Administrator. The owner or 
operator shall not use invalidated data for reporting either emissions 
or heat input, nor for calculating monitor data availability.
    (1) Audit decertification. Whenever both an audit of a continuous 
emission or opacity monitoring system (or component thereof, including 
the data acquisition and handling system), of any excepted monitoring 
system under appendix D or E to this part, or of any alternative 
monitoring system under subpart E of this part, and a review of the 
initial certification application or of a 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 of this part, 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 or component. For 
the purposes of this paragraph, an audit shall be either a field audit 
of the facility or an audit of any information submitted to EPA or the 
State agency regarding the facility. By issuing the notice of 
disapproval, the certification status is revoked prospectively by the 
Administrator. The data measured and recorded by each 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. The owner or operator shall 
follow the procedures in Sec. 75.20(a)(5) for initial certification or 
Sec. 75.20(b)(5) for recertification to replace, prospectively, all of 
the invalid, non-quality-assured data for each disapproved system.
    (2) Out-of-control period. Whenever a continuous emission monitoring 
system or continuous opacity monitoring system fails a quality assurance 
audit or any other audit, the system is out-of-control. The owner or 
operator shall follow the procedures for out-of-control periods in Sec. 
75.24.
    (f) Requirements for Air Emission Testing. On and after March 27, 
2012, relative accuracy testing under Sec. 75.74(c)(2)(ii), section 6.5 
of appendix A to this part, and section 2.3.1 of appendix B to this 
part, and stack testing under Sec. 75.19 and section 2.1 of appendix E 
to this part shall be performed by an ``Air Emission Testing Body'', as 
defined in Sec. 72.2 of this chapter. Conformance to the requirements 
of ASTM D7036-04 (incorporated by reference, see Sec. 75.6), referred 
to in section 6.1.2 of appendix A to this part, shall apply only to 
these tests. Section 1.1.4 of appendix B to this part, and section 2.1 
of appendix E to this part require compliance with section 6.1.2 of 
appendix A to this part. Tests and activities under this part not 
required to be performed by an AETB as defined in Sec. 72.2 of this 
chapter include daily CEMS operation, daily calibration error checks, 
daily flow interference checks, quarterly linearity checks, routine 
maintenance of CEMS, voluntary emissions testing, or emissions testing 
required under other regulations.
    (g) Requirements for EPA Protocol Gas Verification Program. Any EPA 
Protocol

[[Page 262]]

gas production site that chooses to participate in the EPA Protocol Gas 
Verification Program (PGVP) must notify the Administrator of its intent 
to participate. An EPA Protocol gas production site's participation 
shall commence immediately upon notification to EPA and shall extend 
through the end of the calendar year in which notification is provided. 
EPA will issue a vendor ID to each participating EPA Protocol gas 
production site. In each year of the PGVP, EPA may audit up to four EPA 
Protocol gas cylinders from each participating EPA Protocol gas 
production site.
    (1) A production site participating in the PGVP shall provide the 
following information in its initial and ongoing notifications to EPA in 
an electronic format prescribed by the Administrator (see the CAMD Web 
site http://www.epa.gov/airmarkets/emissions/pgvp.html):
    (i) The specialty gas company name which owns or operates the 
participating production site;
    (ii) The name, e-mail address, and telephone number of a contact 
person for that specialty gas company;
    (iii) The name and address of that participating EPA Protocol gas 
production site, owned or operated by the specialty gas company; and
    (iv) The name, e-mail address, and telephone number of a contact 
person for that participating EPA Protocol gas production site.
    (2) An EPA Protocol gas production site that elects to continue 
participating in the PGVP in the next calendar year must notify the 
Administrator of its intent to continue in the program by December 31 of 
the current year by submitting to EPA the information described in 
paragraph (g)(1) of this section.
    (3) A list of the names, contact information, and vendor IDs of EPA 
Protocol gas production sites participating in the PGVP will be made 
publicly available by posting on EPA Web sites (see the CAMD Web site 
http://www.epa.gov/airmarkets/emissions/pgvp.html).
    (4) EPA may remove an EPA Protocol gas production site from the list 
of PGVP participants and give notice to the production site for any of 
the following reasons:
    (i) If the EPA Protocol gas production site fails to provide all of 
the information required by paragraph (g)(1) of this section in 
accordance with paragraph (g)(2) of this section;
    (ii) If, after being notified that its EPA Protocol gas cylinders 
are being audited by EPA, the EPA Protocol gas production site fails to 
cancel its invoice or to credit the purchaser's account for the 
cylinders within 45 calendar days of such notification; or
    (iii) If, after being notified that its EPA Protocol gas cylinders 
are being audited by EPA, the EPA Protocol gas production site cannot 
provide to EPA upon demand proof of payment to the National Institute of 
Standards and Technology (NIST) and a valid contract with NIST;
    (5) EPA may relist an EPA Protocol gas production site as follows:
    (i) An EPA Protocol gas production site may be relisted immediately 
after its failure is remedied if the only reason for removal from the 
list of PGVP participants is failure to provide all of the information 
required by paragraph (g)(1) of this section;
    (ii) If EPA does not receive hardcopy or electronic proof of a 
credit receipt or of cancellation of the invoice for the cylinders from 
the EPA Protocol gas production site within 45 calendar days of 
notifying the EPA Protocol gas production site that its cylinders are 
being audited by EPA, the cylinders shall be returned to the EPA 
Protocol gas production site free of any demurrage, and that EPA 
Protocol gas production site shall not be eligible for relisting for 180 
calendar days from the date of notice that it was removed from the list 
and until it submits to EPA the information required by paragraph (g)(1) 
of this section;
    (iii) For any EPA Protocol gas production site which is notified by 
EPA that its cylinders are being audited and cannot provide to EPA upon 
demand proof of payment to NIST and a valid contract with NIST, the 
cylinders may either be kept by NIST or returned to the EPA Protocol gas 
production site free of any demurrage and at no cost to

[[Page 263]]

NIST, and that EPA Protocol gas production site shall not be eligible 
for relisting for 180 calendar days from the date of notice that it was 
removed from the list and until it submits to EPA the information 
required by paragraph (g)(1) of this section.
    (6) On and after May 27, 2011 for each unit subject to this part 
that uses EPA Protocol gases, the owner or operator must obtain such 
gases from either an EPA Protocol gas production site that is on the EPA 
list of sites participating in the PGVP on the date the owner or 
operator procures such gases or from a reseller that sells to the owner 
or operator unaltered EPA Protocol gases produced by an EPA Protocol gas 
production site that was on the EPA list of participating sites on the 
date the reseller procured such gases.
    (7) An EPA Protocol gas cylinder certified by or ordered from any 
non-participating EPA Protocol gas production site no later than May 27, 
2011 may be used for the purposes of this part until the earlier of the 
cylinder's expiration date or the date on which the cylinder gas 
pressure reaches 150 psig. In the event that an EPA Protocol gas 
production site is removed from the list of PGVP participants on the 
same date as or after the date on which a particular cylinder has been 
certified or ordered, that gas cylinder may continue to be used for the 
purposes of this part until the earlier of the cylinder's expiration 
date or the date on which the cylinder gas pressure reaches 150 psig. 
However, in no case shall a cylinder described in this paragraph (g)(7) 
be recertified by a non-participating EPA Protocol gas production site 
to extend its useful life and be used by a source subject to this part.
    (8) If EPA notifies a participating EPA Protocol gas production site 
that its EPA Protocol gas cylinders are being audited and identifies the 
purchaser as an EPA representative or contractor participating in the 
audit process, the production site shall:
    (i) Either cancel that purchaser's invoice or credit that 
purchaser's account for the purchase of those EPA Protocol gas 
cylinders;
    (ii) Not charge for demurrage for those EPA Protocol gas cylinders;
    (iii) Arrange for and pay for the return shipment of its cylinders 
from NIST; and
    (iv) Provide sufficient funding to NIST for:
    (A) The analysis of those EPA Protocol gas cylinders by NIST;
    (B) The production site's pro rata share of draft and final NIST 
electronic audit reports as specified in paragraphs (g)(9)(ii) through 
(g)(9)(v) of this section on all cylinders in the current audit; and
    (C) The full cost of a draft redacted electronic audit report 
containing just that production site's results and the information as 
specified in paragraphs (g)(9)(ii) through (g)(9)(v) of this section;
    (9) If EPA notifies a participating EPA Protocol gas production site 
that its EPA Protocol gas cylinders are being audited then:
    (i) Each participating EPA Protocol gas production site must have 
NIST analyze its EPA Protocol gas cylinders provided for audit as soon 
after NIST receives the batch containing those cylinders as possible, 
preferably within two weeks of NIST's receipt, using analytical 
procedures consistent with metrology institute practices and at least as 
rigorous as the ``EPA Traceability Protocol for Assay and Certification 
of Gaseous Calibration Standards'' (Traceability Protocol), September 
1997, as amended August 25, 1999, EPA-600/R-97/121, (incorporated by 
reference, see Sec. 75.6) or equivalent written cylinder analysis 
protocol that has been approved by EPA.
    (ii) Each cylinder's concentration must be determined by NIST and 
the results compared to each cylinder's certification documentation and 
tag value to establish conformance with section 5.1 of appendix A to 
this part. After NIST analysis, each cylinder must be provided with a 
NIST analyzed concentration with an expanded uncertainty, as defined in 
Sec. 72.2, (coverage factor, as defined in Sec. 72.2, k = 2) of plus 
or minus 1.0 percent (calculated combined standard uncertainty of plus 
or minus 0.5%), inclusive, or better, unless otherwise approved by EPA.
    (iii) The certification documentation accompanying each cylinder 
must be verified in the audit report as meeting

[[Page 264]]

the requirements of ``EPA Traceability Protocol for Assay and 
Certification of Gaseous Calibration Standards,'' September 1997, as 
amended August 25, 1999, EPA-600/R-97/121 (incorporated by reference, 
see Sec. 75.6) or a revised procedure approved by the Administrator.
    (iv) Each participating EPA Protocol gas production site shall have 
NIST provide all of the information required by paragraphs (g)(9)(ii) 
through (g)(9)(v) of this section in draft and final electronic audit 
reports on all cylinders in the current audit, and in a draft redacted 
electronic audit report containing just that production site's 
information. The draft audit report on all cylinders in the current 
audit and each draft redacted version of the audit report shall be 
submitted electronically by NIST to [email protected], unless otherwise 
provided by the Administrator, within four weeks of completion of all 
cylinder analyses or as soon as possible thereafter. The draft and final 
audit report on all cylinders in the current audit shall only be sent to 
EPA. EPA will send the applicable draft redacted audit report to each 
participating production site for comment. To be considered in the final 
posted audit report, EPA must receive comments, and any cylinder re-
analyses from participating EPA Protocol gas production sites within 60 
days of the participating EPA Protocol gas production site's receipt of 
the draft redacted audit report. All comments from production sites, 
including any cylinder re-analyses, on the draft redacted versions of 
the audit report shall be submitted electronically to [email protected], 
unless otherwise provided by the Administrator. The final audit report 
on all cylinders in the current audit shall be submitted electronically 
by NIST to [email protected], unless otherwise provided by the Administrator, 
within 90 days of the participating EPA Protocol gas production site's 
receipt of the draft redacted audit report sent by EPA or as soon as 
possible thereafter. EPA will post the final results of the NIST 
analyses on EPA Web sites (see the CAMD Web site http://www.epa.gov/
airmarkets/emissions/pgvp.html). Each audit report shall include:
    (A) A table with the information and in the format specified by 
Figure 3 (or the Note below Figure 3, as applicable) of appendix B to 
this part or such revised format as approved by the Administrator; and
    (B) Complete documentation of the NIST procedures used to analyze 
the cylinders, including the analytical reference standards, analytical 
method, analytical method uncertainty, analytical instrumentation, and 
instrument calibration procedures.
    (v) For EPA Protocol gas production sites that produce EPA Protocol 
gas cylinders claiming NIST traceability for both NO and NOX 
concentrations in the same cylinder, if analyzed by NIST for the PGVP, 
such cylinders must be analyzed by NIST for both the NO and 
NOX components (where total NOX is determined by 
NO plus NO2) and the results of the analyses shall be 
included in the audit report.
    (10) An EPA Protocol gas production site shall continue to be on the 
EPA list of sites participating in the PGVP and may continue to sell EPA 
Protocol gases to sources subject to part 75 if it is not notified by 
EPA that its cylinders are being audited under the PGVP if it provides 
the information described in paragraph (g)(1) of this section in 
accordance with paragraph (g)(2) of this section.
    (11) The data validation procedures under Sec. Sec. 2.1.4, 2.2.3, 
and 2.3.2 of appendix B to this part apply.

[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26527, 26566, May 17, 
1995; 61 FR 25582, May 22, 1996; 61 FR 59159, Nov. 20, 1996; 64 FR 
28599, May 26, 1999; 67 FR 40433, June 12, 2002; 67 FR 53505, Aug. 16, 
2002; 70 FR 28679, May 18, 2005; 73 FR 4345, Jan. 24, 2008; 76 FR 17308, 
Mar. 28, 2011]



Sec. 75.22  Reference test methods.

    (a) The owner or operator shall use the following methods, which are 
found in appendices A-1 through A-4 to part 60 of this chapter, to 
conduct the following tests: Monitoring system tests for certification 
or recertification of continuous emission monitoring Systems; 
NOX emission tests of low mass emission units under Sec. 
75.19(c)(1)(iv); NOX emission tests of excepted monitoring 
systems under appendix E to

[[Page 265]]

this part; and required quality assurance and quality control tests:
    (1) Methods 1 or 1A are the reference methods for selection of 
sampling site and sample traverses.
    (2) Method 2 or its allowable alternatives, as provided in appendix 
A to part 60 of this chapter, except for Methods 2B and 2E, are the 
reference methods for determination of volumetric flow.
    (3) Methods 3, 3A, or 3B are the reference methods for the 
determination of the dry molecular weight O2 and 
CO2 concentrations in the emissions.
    (4) Method 4 (either the standard procedure described in section 8.1 
of the method or the moisture approximation procedure described in 
section 8.2 of the method) shall be used to correct pollutant 
concentrations from a dry basis to a wet basis (or from a wet basis to a 
dry basis) and shall be used when relative accuracy test audits of 
continuous moisture monitoring systems are conducted. For the purpose of 
determining the stack gas molecular weight, however, the alternative wet 
bulb-dry bulb technique for approximating the stack gas moisture content 
described in section 2.2 of Method 4 may be used in lieu of the 
procedures in sections 8.1 and 8.2 of the method.
    (5) Methods 6, 6A, 6B or 6C, and 7, 7A, 7C, 7D or 7E in appendix A-4 
to part 60 of this chapter, as applicable, are the reference methods for 
determining SO2 and NOX pollutant concentrations. 
(Methods 6A and 6B in appendix A-4 to part 60 of this chapter may also 
be used to determine SO2 emission rate in lb/mmBtu.) Methods 
7, 7A, 7C, 7D, or 7E in appendix A-4 to part 60 of this chapter must be 
used to measure total NOX emissions, both NO and 
NO2, for purposes of this part. The owner or operator shall 
not use the following sections, exceptions, and options of method 7E in 
appendix A-4 to part 60 of this chapter:
    (i) Section 7.1 of the method allowing for use of prepared 
calibration gas mixtures that are produced in accordance with method 205 
in Appendix M of 40 CFR Part 51;
    (ii) The sampling point selection procedures in section 8.1 of the 
method, for the emission testing of boilers and combustion turbines 
under appendix E to this part. The number and location of the sampling 
points for those applications shall be as specified in sections 2.1.2.1 
and 2.1.2.2 of appendix E to this part;
    (iii) Paragraph (3) in section 8.4 of the method allowing for the 
use of a multi-hole probe to satisfy the multipoint traverse requirement 
of the method;
    (iv) Section 8.6 of the method allowing for the use of ``Dynamic 
Spiking'' as an alternative to the interference and system bias checks 
of the method. Dynamic spiking may be conducted (optionally) as an 
additional quality assurance check; and
    (v) That portion of Section 8.5 of the method allowing multiple 
sampling runs to be conducted before performing the post-run system bias 
check or system calibration error check.
    (6) Method 3A in appendix A-2 and method 7E in appendix A-4 to part 
60 of this chapter are the reference methods for determining 
NOX and diluent emissions from stationary gas turbines for 
testing under appendix E to this part.
    (b) The owner or operator may use any of the following methods, 
which are found in appendices A-1 through A-4 to part 60 of this 
chapter, as a reference method backup monitoring system to provide 
quality-assured monitor data:
    (1) Method 3A for determining O2 or CO2 
concentration;
    (2) Method 6C for determining SO2 concentration;
    (3) Method 7E for determining total NOX concentration 
(both NO and NO2);
    (4) Method 2, or its allowable alternatives, as provided in appendix 
A to part 60 of this chapter, except for Methods 2B and 2E, for 
determining volumetric flow. The sample point(s) for reference methods 
shall be located according to the provisions of section 6.5.5 of 
appendix A to this part.
    (c)(1) Instrumental EPA Reference Methods 3A, 6C, and 7E in 
appendices A-2 and A-4 of part 60 of this chapter shall be conducted 
using calibration gases as defined in section 5 of appendix A to this 
part. Otherwise, performance tests shall be conducted and data reduced 
in accordance with the test methods and procedures of this part unless 
the Administrator:

[[Page 266]]

    (i) Specifies or approves, in specific cases, the use of a reference 
method with minor changes in methodology;
    (ii) Approves the use of an equivalent method; or
    (iii) Approves shorter sampling times and smaller sample volumes 
when necessitated by process variables or other factors.
    (2) Nothing in this paragraph shall be construed to abrogate the 
Administrator's authority to require testing under Section 114 of the 
Act.

[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26528, May 17, 1995; 64 
FR 28600, May 26, 1999; 67 FR 40433, June 12, 2002; 67 FR 53505, Aug. 
16, 2002; 70 FR 28679, May 18, 2005; 73 FR 4345, Jan. 24, 2008; 76 FR 
17310, Mar. 28, 2011]



Sec. 75.23  Alternatives to standards incorporated by reference.

    (a) The designated representative of a unit may petition the 
Administrator for an alternative to any standard incorporated by 
reference and prescribed in this part in accordance with Sec. 75.66(c).
    (b) [Reserved]

[60 FR 26528, May 17, 1995]



Sec. 75.24  Out-of-control periods and adjustment for system bias.

    (a) If an out-of-control period occurs to a monitor or continuous 
emission monitoring system, the owner or operator shall take corrective 
action and repeat the tests applicable to the ``out-of-control 
parameter'' as described in appendix B of this part.
    (1) For daily calibration error tests, an out-of-control period 
occurs when the calibration error of a pollutant concentration monitor 
exceeds the applicable specification in section 2.1.4 of appendix B to 
this part.
    (2) For quarterly linearity checks, an out-of-control period occurs 
when the error in linearity at any of three gas concentrations (low, 
mid-range, and high) exceeds the applicable specification in appendix A 
to this part.
    (3) For relative accuracy test audits, an out-of-control period 
occurs when the relative accuracy exceeds the applicable specification 
in appendix A to this part.
    (b) When a monitor or continuous emission monitoring system is out-
of-control, any data recorded by the monitor or monitoring system are 
not quality-assured and shall not be used in calculating monitor data 
availabilities pursuant to Sec. 75.32 of this part.
    (c) When a monitor or continuous emission monitoring system is out-
of-control, the owner or operator shall take one of the following 
actions until the monitor or monitoring system has successfully met the 
relevant criteria in appendices A and B of this part as demonstrated by 
subsequent tests:
    (1) Apply the procedures for missing data substitution to emissions 
from affected unit(s); or
    (2) Use a certified backup monitoring system or a reference method 
for measuring and recording emissions from the affected unit(s); or
    (3) Adjust the gas discharge paths from the affected unit(s) with 
emissions normally observed by the out-of-control monitor or monitoring 
system so that all exhaust gases are monitored by a certified monitor or 
monitoring system meeting the requirements of appendices A and B of this 
part.
    (d) When the bias test indicates that an SO2 monitor, a 
flow monitor, a NOX-diluent continuous emission monitoring 
system, or a NOX concentration monitoring system used to 
determine NOX mass emissions, as defined in Sec. 
75.71(a)(2), is biased low (i.e., the arithmetic mean of the differences 
between the reference method value and the monitor or monitoring system 
measurements in a relative accuracy test audit exceed the bias statistic 
in section 7 of appendix A to this part), the owner or operator shall 
adjust the monitor or continuous emission monitoring system to eliminate 
the cause of bias such that it passes the bias test or calculate and use 
the bias adjustment factor as specified in section 2.3.4 of appendix B 
to this part.
    (e) The owner or operator shall determine if a continuous opacity 
monitoring system is out-of-control and shall take appropriate 
corrective actions according to the procedures specified for State 
Implementation Plans, pursuant to appendix M of part 51 of this chapter. 
The owner or operator shall comply with the monitor data availability 
requirements of the State. If the State has no monitor data availability 
requirements for continuous

[[Page 267]]

opacity monitoring systems, then the owner or operator shall comply with 
the monitor data availability requirements as stated in the data capture 
provisions of appendix M, part 51 of this chapter.

[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26528, May 17, 1995; 64 
FR 28600, May 26, 1999; 67 FR 40433, June 12, 2002; 70 FR 28680, May 18, 
2005; 76 FR 17311, Mar. 28, 2011]



             Subpart D_Missing Data Substitution Procedures



Sec. 75.30  General provisions.

    (a) Except as provided in Sec. 75.34, the owner or operator shall 
provide substitute data for each affected unit using a continuous 
emission monitoring system according to the missing data procedures in 
this subpart whenever the unit combusts any fuel and:
    (1) A valid, quality-assured hour of SO2 concentration 
data (in ppm) has not been measured and recorded for an affected unit by 
a certified SO2 pollutant concentration monitor, or by an 
approved alternative monitoring method under subpart E of this part, 
except as provided in paragraph (d) of this section; or
    (2) A valid, quality-assured hour of flow data (in scfh) has not 
been measured and recorded for an affected unit from a certified flow 
monitor, or by an approved alternative monitoring system under subpart E 
of this part; or
    (3) A valid, quality-assured hour of NOX emission rate 
data (in lb/mmBtu) has not been measured or recorded for an affected 
unit, either by a certified NOX-diluent continuous emission 
monitoring system or by an approved alternative monitoring system under 
subpart E of this part; or
    (4) A valid, quality-assured hour of CO2 concentration 
data (in percent CO2, or percent O2 converted to 
percent CO2 using the procedures in appendix F to this part) 
has not been measured and recorded for an affected unit, either by a 
certified CO2 continuous emission monitoring system or by an 
approved alternative monitoring method under subpart E of this part; or
    (5) A valid, quality-assured hour of NOX concentration 
data (in ppm) has not been measured or recorded for an affected unit, 
either by a certified NOX concentration monitoring system 
used to determine NOX mass emissions, as defined in Sec. 
75.71(a)(2), or by an approved alternative monitoring system under 
subpart E of this part; or
    (6) A valid, quality-assured hour of CO2 or O2 
concentration data (in percent CO2, or percent O2) 
used for the determination of heat input has not been measured and 
recorded for an affected unit, either by a certified CO2 or 
O2 diluent monitor, or by an approved alternative monitoring 
method under subpart E of this part; or
    (7) A valid, quality-assured hour of moisture data (in percent 
H2O) has not been measured or recorded for an affected unit, 
either by a certified moisture monitoring system or an approved 
alternative monitoring method under subpart E of this part. This 
requirement does not apply when a default percent moisture value, as 
provided in Sec. Sec. 75.11(b) or 75.12(b), is used to account for the 
hourly moisture content of the stack gas; or
    (8) A valid, quality-assured hour of heat input rate data (in mmBtu/
hr) has not been measured and recorded for a unit from a certified flow 
monitor and a certified diluent (CO2 or O2) 
monitor or by an approved alternative monitoring system under subpart E 
of this part.
    (b) However, the owner or operator shall have no need to provide 
substitute data according to the missing data procedures in this subpart 
if the owner or operator uses SO2, CO2, 
NOX, or O2 concentration, flow rate, percent 
moisture, or NOX emission rate data recorded from either a 
certified redundant or regular non-redundant backup CEMS, a like-kind 
replacement non-redundant backup analyzer, or a backup reference method 
monitoring system when the certified primary monitor is not operating or 
is out-of-control. A redundant or non-redundant backup continuous 
emission monitoring system must have been certified according to the 
procedures in Sec. 75.20 prior to the missing data period. Non-
redundant backup continuous emission monitoring system must pass a 
linearity check (for pollutant concentration monitors) or a calibration 
error test (for flow monitors) prior to each period of use of the 
certified backup monitor

[[Page 268]]

for recording and reporting emissions. Use of a certified backup 
monitoring system or backup reference method monitoring system is 
optional and at the discretion of the owner or operator.
    (c) When the certified primary monitor is not operating or out-of-
control, then data recorded for an affected unit from a certified backup 
continuous emission monitor or backup reference method monitoring system 
are used, as if such data were from the certified primary monitor, to 
calculate monitor data availability in Sec. 75.32, and to provide the 
quality-assured data used in the missing data procedures in Sec. Sec. 
75.31 and 75.33, such as the ``hour after'' value.
    (d) The owner or operator shall comply with the applicable 
provisions of this paragraph during hours in which a unit with an 
SO2 continuous emission monitoring system combusts only 
gaseous fuel.
    (1) Whenever a unit with an SO2 CEMS combusts only 
natural gas or pipeline natural gas (as defined in Sec. 72.2 of this 
chapter) and the owner or operator is using the procedures in section 7 
of appendix F to this part to determine SO2 mass emissions 
pursuant to Sec. 75.11(e)(1), the owner or operator shall, for purposes 
of reporting heat input data under Sec. 75.57(b)(5), and for the 
calculation of SO2 mass emissions using Equation F-23 in 
section 7 of appendix F to this part, substitute for missing data from a 
flow monitoring system, CO2 diluent monitor or O2 
diluent monitor using the missing data substitution procedures in Sec. 
75.36.
    (2) Whenever a unit with an SO2 CEMS combusts gaseous 
fuel and the owner or operator uses the gas sampling and analysis and 
fuel flow procedures in appendix D to this part to determine 
SO2 mass emissions pursuant to Sec. 75.11(e)(2), the owner 
or operator shall substitute for missing total sulfur content, gross 
calorific value, and fuel flowmeter data using the missing data 
procedures in appendix D to this part and shall also, for purposes of 
reporting heat input data under Sec. 75.54(b)(5) or Sec. 75.57(b)(5), 
as applicable, substitute for missing data from a flow monitoring 
system, CO2 diluent monitor, or O2 diluent monitor 
using the missing data substitution procedures in Sec. 75.36.
    (3) The owner or operator of a unit with an SO2 
monitoring system shall not include hours when the unit combusts only 
gaseous fuel in the SO2 data availability calculations in 
Sec. 75.32 or in the calculations of substitute SO2 data 
using the procedures of either Sec. 75.31 or Sec. 75.33, for hours 
when SO2 emissions are determined in accordance with Sec. 
75.11(e)(1) or (e)(2). For the purpose of the missing data and 
availability procedures for SO2 pollutant concentration 
monitors in Sec. Sec. 75.31 and 75.33 only, all hours during which the 
unit combusts only gaseous fuel shall be excluded from the definition of 
``monitor operating hour,'' ``quality-assured monitor operating hour,'' 
``unit operating hour,'' and ``unit operating day,'' when SO2 
emissions are determined in accordance with Sec. 75.11(e)(1) or (e)(2).
    (4) During all hours in which a unit with an SO2 
continuous emission monitoring system combusts only gaseous fuel and the 
owner or operator uses the SO2 monitoring system to determine 
SO2 mass emissions pursuant to Sec. 75.11(e)(3), the owner 
or operator shall determine the percent monitor data availability for 
SO2 in accordance with Sec. 75.32 and shall use the standard 
SO2 missing data procedures of Sec. 75.33.

[60 FR 26528, 26566, May 17, 1995, as amended at 61 FR 59160, Nov. 20, 
1996; 64 FR 28600, May 26, 1999; 67 FR 40433, June 12, 2002]



Sec. 75.31  Initial missing data procedures.

    (a) During the first 720 quality-assured monitor operating hours 
following initial certification of the required SO2, 
CO2, O2, or moisture monitoring system(s) at a 
particular unit or stack location (i.e., the date and time at which 
quality assured data begins to be recorded by CEMS(s) installed at that 
location), and during the first 2,160 quality assured monitor operating 
hours following initial certification of the required NOX-
diluent, NOX concentration, or flow monitoring system(s) at 
the unit or stack location, the owner or operator shall provide 
substitute data required under this subpart according to the procedures 
in paragraphs (b) and (c) of this section. The owner or operator of a 
unit shall use these procedures for no longer than three years (26,280 
clock hours) following initial certification.

[[Page 269]]

    (b) SO2, CO2, or O2 concentration 
data, and moisture data. For each hour of missing SO2 or 
CO2 emissions concentration data (including CO2 
data converted from O2 data using the procedures in appendix 
F of this part), or missing O2 or CO2 diluent 
concentration data used to calculate heat input, or missing moisture 
data, the owner or operator shall calculate the substitute data as 
follows:
    (1) Whenever prior quality-assured data exist, the owner or operator 
shall substitute, by means of the data acquisition and handling system, 
for each hour of missing data, the average of the hourly SO2, 
CO2, or O2 concentrations or moisture percentages 
recorded by a certified monitor for the unit operating hour immediately 
before and the unit operating hour immediately after the missing data 
period.
    (2) Whenever no prior quality assured SO2, 
CO2, or O2 concentration data or moisture data 
exist, the owner or operator shall substitute, as applicable, for each 
hour of missing data, the maximum potential SO2 concentration 
or the maximum potential CO2 concentration or the minimum 
potential O2 concentration or (unless Equation 19-3, 19-4 or 
19-8 in Method 19 in appendix A-7 to part 60 of this chapter is used to 
determine NOX emission rate) the minimum potential moisture 
percentage, as specified, respectively, in sections 2.1.1.1, 2.1.3.1, 
2.1.3.2 and 2.1.5 of appendix A to this part. If Equation 19-3, 19-4 or 
19-8 in Method 19 in appendix A-7 to part 60 of this chapter is used to 
determine NOX emission rate, substitute the maximum potential 
moisture percentage, as specified in section 2.1.6 of appendix A to this 
part.
    (c) Volumetric flow and NOX emission rate or NOX concentration data 
(load ranges or operational bins used). The procedures in this paragraph 
apply to affected units for which load-based ranges or non-load-based 
operational bins, as defined, respectively, in sections 2 and 3 of 
appendix C to this part are used to provide substitute NOX 
and flow rate data. For each hour of missing volumetric flow rate data, 
NOX emission rate data, or NOX concentration data 
used to determine NOX mass emissions:
    (1) Whenever prior quality-assured data exist in the load range (or 
operational bin) corresponding to the operating load (or operating 
conditions) at the time of the missing data period, the owner or 
operator shall substitute, by means of the automated data acquisition 
and handling system, for each hour of missing data, the arithmetic 
average of all of the prior quality-assured hourly flow rates, 
NOX emission rates, or NOX concentrations in the 
corresponding load range (or operational bin) as determined using the 
procedure in appendix C to this part. When non-load-based operational 
bins are used, if essential operating or parametric data are unavailable 
for any hour in the missing data period, such that the operational bin 
cannot be determined, the owner or operator shall, for that hour, 
substitute (as applicable) the maximum potential flow rate as specified 
in section 2.1.4.1 of appendix A to this part or the maximum potential 
NOX emission rate or the maximum potential NOX 
concentration as specified in section 2.1.2.1 of appendix A to this 
part.
    (2) This paragraph (c)(2) does not apply to non-load-based units 
using operational bins. Whenever no prior quality-assured flow or 
NOX emission rate or NOX concentration data exist 
for the corresponding load range, the owner or operator shall 
substitute, for each hour of missing data, the average hourly flow rate 
or the average hourly NOX emission rate or NOX 
concentration at the next higher level load range for which quality-
assured data are available.
    (3) Whenever no prior quality-assured flow rate or NOX 
emission rate or NOX concentration data exist for the 
corresponding load range, or any higher load range (or for non-load-
based units using operational bins, when no prior quality-assured data 
exist in the corresponding operational bin), the owner or operator 
shall, as applicable, substitute, for each hour of missing data, the 
maximum potential flow rate as specified in section 2.1.4.1 of appendix 
A to this part or shall substitute the maximum potential NOX 
emission rate or the maximum potential NOX concentration, as 
specified in section

[[Page 270]]

2.1.2.1 of appendix A to this part. Alternatively, where a unit with 
add-on NOX emission controls can demonstrate that the 
controls are operating properly during the hour, as provided in Sec. 
75.34(d), the owner or operator may substitute, as applicable, the 
maximum controlled NOX emission rate (MCR) or the maximum 
expected NOX concentration (MEC).
    (d) Non-load-based volumetric flow and NOX emission rate or NOX 
concentration data (operational bins not used). The procedures in this 
paragraph, (d), apply only to affected units that do not produce 
electrical output (in megawatts) or thermal output (in klb/hr of steam) 
and for which operational bins are not used. For each hour of missing 
volumetric flow rate data, NOX emission rate data, or 
NOX concentration data used to determine NOX mass 
emissions:
    (1) Whenever prior quality-assured data exist at the time of the 
missing data period, the owner or operator shall substitute, by means of 
the automated data acquisition and handling system, for each hour of 
missing data, the arithmetic average of all of the prior quality-assured 
hourly average flow rates or NOX emission rates or 
NOX concentrations.
    (2) Whenever no prior quality-assured flow rate, NOX 
emission rate, or NOX concentration data exist, the owner or 
operator shall, as applicable, substitute for each hour of missing data, 
the maximum potential flow rate as specified in section 2.1.4.1 of 
appendix A to this part or the maximum potential NOX emission 
rate or the maximum potential NOX concentration as specified 
in section 2.1.2.1 of appendix A to this part.

[64 FR 28601, May 26, 1999, as amended at 67 FR 40433, June 12, 2002; 70 
FR 28680, May 18, 2005; 73 FR 4346, Jan. 24, 2008; 76 FR 17311, Mar. 28, 
2011]



Sec. 75.32  Determination of monitor data availability for standard
missing data procedures.

    (a) Following initial certification of the required SO2, 
CO2, O2, or moisture monitoring system(s) at a 
particular unit or stack location (i.e., the date and time at which 
quality assured data begins to be recorded by CEMS(s) at that location), 
the owner or operator shall begin calculating the percent monitor data 
availability as described in paragraph (a)(1) of this section, and 
shall, upon completion of the first 720 quality-assured monitor 
operating hours, record, by means of the automated data acquisition and 
handling system, the percent monitor data availability for each 
monitored parameter. Similarly, following initial certification of the 
required NOX-diluent, NOX concentration, or flow 
monitoring system(s) at a unit or stack location, the owner or operator 
shall begin calculating the percent monitor data availability as 
described in paragraph (a)(1) of this section, and shall, upon 
completion of the first 2,160 quality-assured monitor operating hours, 
record, by means of the automated data acquisition and handling system, 
the percent monitor data availability for each monitored parameter. 
Notwithstanding these requirements, if three years (26,280 clock hours) 
have elapsed since the date and hour of initial certification and fewer 
than 720 (or 2,160, as applicable) quality-assured monitor operating 
hours have been recorded, the owner or operator shall begin recording 
the percent monitor data availability. The percent monitor data 
availability shall be calculated for each monitored parameter at each 
unit or stack location, as follows:
    (1) Prior to completion of 8,760 unit or stack operating hours 
following initial certification, the owner or operator shall, for the 
purpose of applying the standard missing data procedures of Sec. 75.33, 
use Equation 8 to calculate, hourly, percent monitor data availability.

[[Page 271]]

[GRAPHIC] [TIFF OMITTED] TC13NO91.041

    (2) Upon completion of 8,760 unit (or stack) operating hours 
following initial certification and thereafter, the owner or operator 
shall, for the purpose of applying the standard missing data procedures 
of Sec. 75.33, use Equation 9 to calculate hourly, percent monitor data 
availability. Notwithstanding this requirement, if three years (26,280 
clock hours) have elapsed since initial certification and fewer than 
8,760 unit or stack operating hours have been accumulated, the owner or 
operator shall begin using a modified version of Equation 9, as 
described in paragraph (a)(3) of this section.
[GRAPHIC] [TIFF OMITTED] TC13NO91.042

    (3) When calculating percent monitor data availability using 
Equation 8 or 9, the owner or operator shall include all unit operating 
hours, and all monitor operating hours for which quality-assured data 
were recorded by a certified primary monitor; a certified redundant or 
non-redundant backup monitor or a reference method for that unit; or by 
an approved alternative monitoring system under subpart E of this part. 
No hours from more than three years (26,280 clock hours) earlier shall 
be used in Equation 9. For a unit that has accumulated fewer than 8,760 
unit operating hours in the previous three years (26,280 clock hours), 
replace the words ``during previous 8,760 unit operating hours'' in the 
numerator of Equation 9 with ``in the previous three years'' and replace 
``8,760'' in the denominator of Equation 9 with ``total unit operating 
hours in the previous three years.'' The owner or operator of a unit 
with an SO2 monitoring system shall, when SO2 
emissions are determined in accordance with Sec. 75.11(e)(1) or (e)(2), 
exclude hours in which a unit combusts only gaseous fuel from 
calculations of percent monitor data availability for SO2 
pollutant concentration monitors, as provided in Sec. 75.30(d).
    (b) The monitor data availability shall be calculated for each hour 
during each missing data period. The owner or operator shall record the 
percent monitor data availability for each hour of each missing data 
period to implement the missing data substitution procedures.

[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26529, 26567, May 17, 
1995; 61 FR 59160, Nov. 20, 1996; 64 FR 28602, May 26, 1999; 67 FR 
40434, June 12, 2002; 70 FR 28680, May 18, 2005; 73 FR 4346, Jan. 24, 
2008; 76 FR 17311, Mar. 28, 2011]



Sec. 75.33  Standard missing data procedures for SO[bdi2], NOX,
and flow rate.

    (a) Following initial certification of the required SO2, 
NOX, and flow rate monitoring system(s) at a particular unit 
or stack location (i.e., the date and time at which quality-assured data 
begins to be recorded by CEMS(s) at that location) and upon completion 
of the first 720 quality-assured monitor operating hours (for 
SO2) or the first 2,160 quality-assured monitor operating 
hours (for flow, NOX emission rate, or

[[Page 272]]

NOX concentration), the owner or operator shall provide 
substitute data required under this subpart according to the procedures 
in paragraphs (b) and (c) of this section and depicted in Table 1 
(SO2) and Table 2 of this section (NOX, flow). The 
owner or operator may either implement the provisions of paragraphs (b) 
and (c) of this section on a non-fuel-specific basis, or may, as 
described in paragraphs (b)(5), (b)(6), (c)(7) and (c)(8) of this 
section, provide fuel-specific substitute data values. Notwithstanding 
these requirements, if three years (26,280 clock hours) have elapsed 
since the date and hour of initial certification, and fewer than 720 (or 
2,160, as applicable) quality-assured monitor operating hours have been 
recorded, the owner or operator shall begin using the missing data 
procedures of this section. The owner or operator of a unit shall 
substitute for missing data using quality-assured monitor operating 
hours of data from no earlier than three years (26,280 clock hours) 
prior to the date and time of the missing data period.
    (b) SO2 concentration data. For each hour of missing SO2 
concentration data,
    (1) If the monitor data availability is equal to or greater than 
95.0 percent, the owner or operator shall calculate substitute data by 
means of the automated data acquisition and handling system for that 
hour of the missing data period according to the following procedures:
    (i) For a missing data period less than or equal to 24 hours, 
substitute the average of the hourly SO2 concentrations 
recorded by an SO2 pollutant concentration monitor for the 
hour before and the hour after the missing data period.
    (ii) For a missing data period greater than 24 hours, substitute the 
greater of:
    (A) The 90th percentile hourly SO2 concentration recorded 
by an SO2 pollutant concentration monitor during the previous 
720 quality-assured monitor operating hours; or
    (B) The average of the hourly SO2 concentrations recorded 
by an SO2 pollutant concentration monitor for the hour before 
and the hour after the missing data period.
    (2) If the monitor data availability is at least 90.0 percent but 
less than 95.0 percent, the owner or operator shall calculate substitute 
data by means of the automated data acquisition and handling system for 
that hour of the missing data period according to the following 
procedures:
    (i) For a missing data period of less than or equal to 8 hours, 
substitute the average of the hourly SO2 concentrations 
recorded by an SO2 pollutant concentration monitor for the 
hour before and the hour after the missing data period.
    (ii) For a missing data period of more than 8 hours, substitute the 
greater of:
    (A) the 95th percentile hourly SO2 concentration recorded 
by an SO2 pollutant concentration monitor during the previous 
720 quality-assured monitor operating hours; or
    (B) The average of the hourly SO2 concentrations recorded 
by an SO2 pollutant concentration monitor for the hour before 
and the hour after the missing data period.
    (3) If the monitor data availability is at least 80.0 percent but 
less than 90.0 percent, the owner or operator shall substitute for that 
hour of the missing data period the maximum hourly SO2 
concentration recorded by an SO2 pollutant concentration 
monitor during the previous 720 quality-assured monitor operating hours.
    (4) If the monitor data availability is less than 80.0 percent, the 
owner or operator shall substitute for that hour of the missing data 
period the maximum potential SO2 concentration, as defined in 
section 2.1.1.1 of appendix A to this part.
    (5) For units that combust more than one type of fuel, the owner or 
operator may opt to implement the missing data routines in paragraphs 
(b)(1) through (b)(4) of this section on a fuel-specific basis. If this 
option is selected, the owner or operator shall document this in the 
monitoring plan required under Sec. 75.53.
    (6) Use the following guidelines to implement paragraphs (b)(1) 
through (b)(4) of this section on a fuel-specific basis:
    (i) Separate the historical, quality-assured SO2 
concentration data according to the type of fuel combusted;

[[Page 273]]

    (ii) For units that co-fire different types of fuel, either group 
the co-fired hours with the historical data for the fuel with the 
highest SO2 emission rate (e.g., if diesel oil and pipeline 
natural gas are co-fired, count co-fired hours as oil-burning hours), or 
separate the co-fired hours from the single-fuel hours;
    (iii) For the purposes of providing substitute data under paragraph 
(b)(4) of this section, determine a separate, fuel-specific maximum 
potential SO2 concentration (MPC) value for each type of fuel 
combusted in the unit, in a manner consistent with section 2.1.1.1 of 
appendix A to this part. For fuel that qualifies as pipeline natural gas 
or natural gas (as defined in Sec. 72.2 of this chapter), the owner or 
operator shall, for the purposes of determining the MPC, either 
determine the maximum total sulfur content and minimum gross calorific 
value (GCV) of the gas by fuel sampling and analysis or shall use a 
default total sulfur content of 0.05 percent by weight (dry basis) and a 
default GCV value of 950 Btu/scf. For co-firing, the MPC value shall be 
based on the fuel with the highest SO2 emission rate. The 
exact methodology used to determine each fuel-specific MPC value shall 
be documented in the monitoring plan for the unit or stack; and
    (iv) For missing data periods that require 720-hour (or, if 
applicable, 3-year) lookbacks, use historical data for the type of fuel 
combusted during each hour of the missing data period to determine the 
appropriate substitute data value for that hour. For co-fired missing 
data hours, if the historical data are separated into single-fuel and 
co-fired hours, use co-fired data to provide the substitute data values. 
Otherwise, use data for the fuel with the highest SO2 
emission rate to provide substitute data values for co-fired missing 
data hours.
    (7) Table 1 summarizes the provisions of paragraphs (b)(1) through 
(b)(6) of this section.
    (c) Volumetric flow rate, NOX emission rate and NOX concentration 
data. Use the procedures in this paragraph to provide substitute 
NOX and flow rate data for all affected units for which load-
based ranges have been defined in accordance with section 2 of appendix 
C to this part. For units that do not produce electrical or thermal 
output (i.e., non-load-based units), use the procedures in this 
paragraph only to provide substitute data for volumetric flow rate, and 
only if operational bins have been defined for the unit, as described in 
section 3 of appendix C to this part. Otherwise, use the applicable 
missing data procedures in paragraph (d) or (e) of this section for non-
load-based units. For each hour of missing volumetric flow rate data, 
NOX emission rate data, or NOX concentration data 
used to determine NOX mass emissions:
    (1) If the monitor data availability is equal to or greater than 
95.0 percent, the owner or operator shall calculate substitute data by 
means of the automated data acquisition and handling system for that 
hour of the missing data period according to the following procedures:
    (i) For a missing data period less than or equal to 24 hours, 
substitute, as applicable, for each missing hour, the arithmetic average 
of the flow rates or NOX emission rates or NOX 
concentrations recorded by a monitoring system during the previous 2,160 
quality-assured monitor operating hours at the corresponding unit load 
range or operational bin, as determined using the procedure in appendix 
C to this part.
    (ii) For a missing data period greater than 24 hours, substitute, as 
applicable, for each missing hour, the greater of:
    (A) The 90th percentile hourly flow rate or the 90th percentile 
NOX emission rate or the 90th percentile NOX 
concentration recorded by a monitoring system during the previous 2,160 
quality-assured monitor operating hours at the corresponding unit load 
range or operational bin, as determined using the procedure in appendix 
C to this part; or
    (B) The average of the recorded hourly flow rates, NOX 
emission rates or NOX concentrations recorded by a monitoring 
system for the hour before and the hour after the missing data period.
    (2) If the monitor data availability is at least 90.0 percent but 
less than 95.0 percent, the owner or operator shall calculate substitute 
data by means of the automated data acquisition and handling system for 
that hour of the missing data period according to the following 
procedures:

[[Page 274]]

    (i) For a missing data period of less than or equal to 8 hours, 
substitute, as applicable, the arithmetic average hourly flow rate or 
NOX emission rate or NOX concentration recorded by 
a monitoring system during the previous 2,160 quality-assured monitor 
operating hours at the corresponding unit load range or operational bin, 
as determined using the procedure in appendix C to this part.
    (ii) For a missing data period greater than 8 hours, substitute, as 
applicable, for each missing hour, the greater of:
    (A) The 95th percentile hourly flow rate or the 95th percentile 
NOX emission rate or the 95th percentile NOX 
concentration recorded by a monitoring system during the previous 2,160 
quality-assured monitor operating hours at the corresponding unit load 
range or operational bin, as determined using the procedure in appendix 
C to this part; or
    (B) The average of the hourly flow rates, NOX emission 
rates or NOX concentrations recorded by a monitoring system 
for the hour before and the hour after the missing data period.
    (3) If the monitor data availability is at least 80.0 percent but 
less than 90.0 percent, the owner or operator shall, by means of the 
automated data acquisition and handling system, substitute, as 
applicable, for that hour of the missing data period, the maximum hourly 
flow rate or the maximum hourly NOX emission rate or the 
maximum hourly NOX concentration recorded during the previous 
2,160 quality-assured monitor operating hours at the corresponding unit 
load range or operational bin, as determined using the procedure in 
appendix C to this part.
    (4) If the monitor data availability is less than 80.0 percent, the 
owner or operator shall substitute, as applicable, for that hour of the 
missing data period, the maximum potential flow rate, as defined in 
section 2.1.4.1 of appendix A to this part, or the maximum 
NOX emission rate, as defined in section 2.1.2.1 of appendix 
A to this part, or the maximum potential NOX concentration, 
as defined in section 2.1.2.1 of appendix A to this part. In addition, 
when non-load-based operational bins are used, the owner or operator 
shall substitute the maximum potential flow rate for any hour in the 
missing data period in which essential operating or parametric data are 
unavailable and the operational bin cannot be determined.
    (5) This paragraph, (c)(5), does not apply to non-load-based, 
affected units using operational bins. Whenever no prior quality-assured 
flow rate data, NOX concentration data or NOX 
emission rate data exist for the corresponding load range, the owner or 
operator shall substitute, as applicable, for each hour of missing data, 
the maximum hourly flow rate or the maximum hourly NOX 
concentration or maximum hourly NOX emission rate at the next 
higher level load range for which quality-assured data are available.
    (6) Whenever no prior quality-assured flow rate data, NOX 
concentration data or NOX emission rate data exist at either 
the corresponding load range (or a higher load range) or at the 
corresponding operational bin, the owner or operator shall substitute, 
as applicable, either the maximum potential NOX emission rate 
or the maximum potential NOX concentration, as defined in 
section 2.1.2.1 of appendix A to this part or the maximum potential flow 
rate, as defined in section 2.1.4.1 of appendix A to this part.
    (7) This paragraph (c)(7) does not apply to affected units using 
non-load-based operational bins. For units that combust more than one 
type of fuel, the owner or operator may opt to implement the missing 
data routines in paragraphs (c)(1) through (c)(6) of this section on a 
fuel-specific basis. If this option is selected, the owner or operator 
shall document this in the monitoring plan required under Sec. 75.53.
    (8) This paragraph, (c)(8), does not apply to affected units using 
non-load-based operational bins. Use the following guidelines to 
implement paragraphs (c)(1) through (c)(6) of this section on a fuel-
specific basis:
    (i) Separate the historical, quality-assured NOX emission 
rate, NOX concentration, or flow rate data according to the 
type of fuel combusted;
    (ii) For units that co-fire different types of fuel, either group 
the co-fired hours with the historical data for the fuel with the 
highest NOX emission

[[Page 275]]

rate, NOX concentration or flow rate, or separate the co-
fired hours from the single-fuel hours;
    (iii) For the purposes of providing substitute data under paragraph 
(c)(4) of this section, a separate, fuel-specific maximum potential 
concentration (MPC), maximum potential NOX emission rate 
(MER), or maximum potential flow rate (MPF) value (as applicable) shall 
be determined for each type of fuel combusted in the unit, in a manner 
consistent with Sec. 72.2 of this chapter and with section 2.1.2.1 or 
2.1.4.1 of appendix A to this part. For co-firing, the MPC, MER or MPF 
value shall be based on the fuel with the highest emission rate or flow 
rate (as applicable). Furthermore, for a unit with add-on NOX 
emission controls, a separate fuel-specific maximum controlled 
NOX emission rate (MCR) or maximum expected NOX 
concentration (MEC) value (as applicable) shall be determined for each 
type of fuel combusted in the unit. The exact methodology used to 
determine each fuel-specific MPC, MER, MEC, MCR or MPF value shall be 
documented in the monitoring plan for the unit or stack.
    (iv) For missing data periods that require 2,160-hour (or, if 
applicable, 3-year) lookbacks, use historical data for the type of fuel 
combusted during each hour of the missing data period to determine the 
appropriate substitute data value for that hour. For co-fired missing 
data hours, if the historical data are separated into single-fuel and 
co-fired hours, use co-fired data to provide the substitute data values. 
Otherwise, use data for the fuel with the highest NOX 
emission rate, NOX concentration or flow rate (as applicable) 
to provide substitute data values for co-fired missing data hours. 
Tables 1 and 2 follow.

Table 1--Missing Data Procedure for SO2 CEMS, CO2 CEMS, Moisture CEMS, and Diluent (CO2 or O2) Monitors for Heat
                                               Input Determination
----------------------------------------------------------------------------------------------------------------
                      Trigger conditions                                      Calculation routines
----------------------------------------------------------------------------------------------------------------
                                         Duration (N) of CEMS
 Monitor data availability (percent)      outage (hours) \2\             Method              Lookback period
----------------------------------------------------------------------------------------------------------------
95 or more...........................  N <=24.................  Average................  HB/HA.
                                       N 24........  For SO2, CO2, and H2O
                                                                 **, the greater of:
                                                                Average................  HB/HA.
                                                                90th percentile........  720 hours. *
                                                                For O2 and H2O\X\, the   HB/HA.
                                                                 lesser of:
                                                                10th percentile........  720 hours. *
90 or more, but below 95.............  N <=8..................  Average................  HB/HA.
                                       N 8.........  For SO2, CO2, and H2O
                                                                 **, the greater of:
                                                                Average................  HB/HA.
                                                                95th percentile........  720 hours. *
                                                                For O2 and H2O\X\, the
                                                                 lesser of:
                                                                Average................  HB/HA.
                                                                5th Percentile.........  720 hours. *
80 or more, but below 90.............  N 0.........  For SO2, CO2, and H2O
                                                                 **,
                                                                Maximum value\1\.......  720 hours. *
                                                                For O2 and H2O\X\:
                                                                Minimum value\1\.......  720 hours. *
Below 80.............................  N 0.........  Maximum potential
                                                                 concentration\3\ or %
                                                                 (for SO2, CO2, and
                                                                 H2O**) or
                                                                Minimum potential        None.
                                                                 concentration or %
                                                                 (for O2 and H2O\X\).
----------------------------------------------------------------------------------------------------------------
HB/HA = hour before and hour after the CEMS outage.
* Quality-assured, monitor operating hours, during unit operation. May be either fuel-specific or non-fuel-
  specific. For units that report data only for the ozone season, include only quality assured monitor operating
  hours within the ozone season in the lookback period. Use data from no earlier than 3 years prior to the
  missing data period.
\1\ Where a unit with add-on SO2 emission controls can demonstrate that the controls are operating properly
  during the missing data period, as provided in Sec. 75.34, the unit may use the maximum controlled
  concentration from the previous 720 quality-assured monitor operating hours.
\2\ During unit operating hours.
\3\ Where a unit with add-on SO2 emission controls can demonstrate that the controls are operating properly
  during the missing data period, the unit may report the greater of: (a) the maximum expected SO2 concentration
  or (b) 1.25 times the maximum controlled value from the previous 720 quality-assured monitor operating hours
  (see Sec. 75.34).
\X\ Use this algorithm for moisture except when Equation 19-3, 19-4 or 19-8 in Method 19 in appendix A-7 to part
  60 of this chapter is used for NOX emission rate.
** Use this algorithm for moisture only when Equation 19-3, 19-4 or 19-8 in Method 19 in appendix A-7 to part 60
  of this chapter is used for NOX emission rate.


[[Page 276]]


   Table 2--Load-Based Missing Data Procedure for NOX-Diluent CEMS, NOX Concentration CEMS and Flow Rate CEMS
----------------------------------------------------------------------------------------------------------------
                 Trigger conditions                                      Calculation routines
----------------------------------------------------------------------------------------------------------------
                                   Duration (N) of
   Monitor data availability     CEMS outage (hours)        Method          Lookback period       Load ranges
           (percent)                     \2\
----------------------------------------------------------------------------------------------------------------
95 or more.....................  N <=24               Average...........  2,160 hours *.....  Yes.
                                 N 24      The greater of:
                                                         Average........  HB/HA.............  No.
                                                         90th percentile  2,160 hours *.....  Yes.
90 or more, but below 95.......  N <=8                Average...........  2,160 hours *.....  Yes.
                                 N 8       The greater of:
                                                         Average........  HB/HA.............  No.
                                                         95th percentile  2,160 hours *.....  Yes.
80 or more, but below 90.......  N 0       Maximum value \1\.  2,160 hours *.....  Yes.
Below 80.......................  N 0       Maximum potential   None..............  No.
                                                       NOX emission rate
                                                       \3\; or maximum
                                                       potential NOX
                                                       concentration
                                                       \3\; or maximum
                                                       potential flow
                                                       rate.
----------------------------------------------------------------------------------------------------------------
HB/HA = hour before and hour after the CEMS outage.
* Quality-assured, monitor operating hours, using data at the corresponding load range (``load bin'') for each
  hour of the missing data period. May be either fuel-specific or non-fuel-specific. For units that report data
  only for the ozone season, include only quality assured monitor operating hours within the ozone season in the
  lookback period. Use data from no earlier than three years prior to the missing data period.
\1\ Where a unit with add-on NOX emission controls can demonstrate that the controls are operating properly
  during the missing data period, as provided in Sec. 75.34, the unit may use the maximum controlled NOX
  concentration or emission rate from the previous 2,160 quality-assured monitor operating hours. Units with add-
  on controls that report NOX mass emissions on a year-round basis under subpart H of this part may use separate
  ozone season and non-ozone season data pools to provide substitute data values, as described in Sec.
  75.34(a)(2).
\2\ During unit operating hours.
\3\ Alternatively, where a unit with add-on NOX emission controls can demonstrate that the controls are
  operating properly during the missing data period, as provided in Sec. 75.34, the unit may report the
  greater of: (a) the maximum expected NOX concentration (or maximum controlled NOX emission rate, as
  applicable); or (b) 1.25 times the maximum controlled value at the corresponding load bin, from the previous
  2,160 quality-assured monitor operating hours.

    (9) The load-based provisions of paragraphs (c)(1) through (c)(8) of 
this section are summarized in Table 2 of this section. The non-load-
based provisions for volumetric flow rate, found in paragraphs (c)(1) 
through (c)(4), and (c)(6) of this section, are presented in Table 4 of 
this section.
    (d) Non-load-based NO X emission rate and NOX 
concentration data. Use the procedures in this paragraph to provide 
substitute NOX data for affected units that do not produce 
electrical output (in megawatts) or thermal output (in klb/hr of steam). 
For each hour of missing NOX emission rate data, or 
NOX concentration data used to determine NOX mass 
emissions:
    (1) If the monitor data availability is equal to or greater than 
95.0 percent, the owner or operator shall calculate substitute data by 
means of the automated data acquisition and handling system for that 
hour of the missing data period according to the following procedures:
    (i) For a missing data period less than or equal to 24 hours, 
substitute, as applicable, for each missing hour, the arithmetic average 
of the NOX emission rates or NOX concentrations 
recorded by a monitoring system in a 2,160 hour lookback period. The 
lookback period may be comprised of either:
    (A) The previous 2,160 quality-assured monitor operating hours, or
    (B) The previous 2,160 quality-assured monitor operating hours at 
the corresponding operational bin, if operational bins, as defined in 
section 3 of appendix C to this part, are used.
    (ii) For a missing data period greater than 24 hours, substitute, 
for each missing hour, the 90th percentile NOX emission rate 
or the 90th percentile NOX concentration recorded by a 
monitoring system during the previous 2,160 quality-assured monitor 
operating hours (or during the previous 2,160 quality-assured monitor 
operating hours at the corresponding operational bin, if operational 
bins are used).
    (2) If the monitor data availability is at least 90.0 percent but 
less than 95.0 percent, the owner or operator shall calculate substitute 
data by means of the automated data acquisition and

[[Page 277]]

handling system for that hour of the missing data period according to 
the following procedures:
    (i) For a missing data period of less than or equal to eight hours, 
substitute, as applicable, the arithmetic average of the hourly 
NOX emission rates or NOX concentrations recorded 
by a monitoring system during the previous 2,160 quality-assured monitor 
operating hours (or during the previous 2,160 quality-assured monitor 
operating hours at the corresponding operational bin, if operational 
bins are used).
    (ii) For a missing data period greater than eight hours, substitute, 
for each missing hour, the 95th percentile hourly flow rate or the 95th 
percentile NOX emission rate or the 95th percentile 
NOX concentration recorded by a monitoring system during the 
previous 2,160 quality-assured monitor operating hours (or during the 
previous 2,160 quality-assured monitor operating hours at the 
corresponding operational bin, if operational bins are used).
    (3) If the monitor data availability is at least 80.0 percent but 
less than 90.0 percent, the owner or operator shall, by means of the 
automated data acquisition and handling system, substitute, as 
applicable, for that hour of the missing data period, the maximum hourly 
NOX emission rate or the maximum hourly NOX 
concentration recorded during the previous 2,160 quality-assured monitor 
operating hours (or during the previous 2,160 quality-assured monitor 
operating hours at the corresponding operational bin, if operational 
bins are used).
    (4) If the monitor data availability is less than 80.0 percent, the 
owner or operator shall substitute, as applicable, for that hour of the 
missing data period, the maximum NOX emission rate, as 
defined in Sec. 72.2 of this chapter, or the maximum potential 
NOX concentration, as defined in section 2.1.2.1 of appendix 
A to this part. In addition, when operational bins are used, the owner 
or operator shall substitute (as applicable) the maximum potential 
NOX emission rate or the maximum potential NOX 
concentration for any hour in the missing data period in which essential 
operating or parametric data are unavailable and the operational bin 
cannot be determined.
    (5) If operational bins are used and no prior quality-assured 
NOX concentration data or NOX emission rate data 
exist for the corresponding operational bin, the owner or operator shall 
substitute, as applicable, either the maximum potential NOX 
emission rate, as defined in Sec. 72.2 of this chapter, or the maximum 
potential NOX concentration, as defined in section 2.1.2.1 of 
appendix A to this part.
    (6) Table 3 of this section summarizes the provisions of paragraphs 
(d)(1) through (d)(5) of this section.
    (e) Non-load-based volumetric flow rate data. (1) If operational 
bins, as defined in section 3 of appendix C to this part, are used for a 
unit that does not produce electrical or thermal output, use the missing 
data procedures in paragraph (c) of this section to provide substitute 
volumetric flow rate data for the unit.
    (2) If operational bins are not used, modify the procedures in 
paragraph (c) of this section as follows:
    (i) In paragraphs (c)(1) through (c)(3), the words ``previous 2,160 
quality-assured monitor operating hours'' shall apply rather than 
``previous 2,160 quality-assured monitor operating hours at the 
corresponding unit load range or operational bin, as determined using 
the procedure in appendix C to this part;''
    (ii) The last sentence in paragraph (c)(4) does not apply;
    (iii) Paragraphs (c)(5), (c)(7), and (c)(8) are not applicable; and
    (iv) In paragraph (c)(6), the words, ``for either the corresponding 
load range (or a higher load range) or at the corresponding operational 
bin'' do not apply.
    (3) Table 4 of this section summarizes the provisions of paragraphs 
(e)(1) and (e)(2) of this section. Tables 3 and 4 follow:

[[Page 278]]



         Table 3--Non-load-based Missing Data Procedure for NOX-Diluent CEMS and NOX Concentration CEMS
----------------------------------------------------------------------------------------------------------------
                     Trigger conditions                                      Calculation routines
----------------------------------------------------------------------------------------------------------------
                                        Duration (N) of CEMS
 Monitor data availability (percent)     outage (hours) \1\            Method                Lookback period
----------------------------------------------------------------------------------------------------------------
95 or more...........................  N <=24                 Average.................  2,160 hours. *
                                       N 24        90th percentile.........  2,160 hours. *
90 or more, but below 95.............  N <=8                  Average.................  2,160 hours. *
                                       N 8         95th percentile.........  2,160 hours. *
80 or more, but below 90.............  N 0         Maximum value \3\.......  2,160 hours. *
Below 80, or operational bin           N 0         Maximum potential NOX     None.
 indeterminable.                                               emission rate \2\ or
                                                               maximum potential NOX
                                                               concentration \2\.
----------------------------------------------------------------------------------------------------------------
* If operational bins are used, the lookback period is 2,160 quality-assured, monitor operating hours, and data
  at the corresponding operational bin are used to provide substitute data values. If operational bins are not
  used, the lookback period is the previous 2,160 quality-assured monitor operating hours. For units that report
  data only for the ozone season, include only quality-assured monitor operating hours within the ozone season
  in the lookback period. Use data from no earlier than three years prior to the missing data period.
\1\ During unit operation.
\2\ Alternatively, where a unit with add-on NOX emission controls can demonstrate that the controls are
  operating properly, as provided in Sec. 75.34, the unit may report the greater of: (a) the maximum expected
  NOX concentration, (or maximum controlled NOX emission rate, as applicable); or (b) 1.25 times the maximum
  controlled value at the corresponding operational bin (if applicable), from the previous 2,160 quality-assured
  monitor operating hours.
\3\ Where a unit with add-on NOX emission controls can demonstrate that the controls are operating properly
  during the missing data period, as provided in Sec. 75.34, the unit may use the maximum controlled NOX
  concentration or emission rate from the previous 2,160 quality-assured monitor operating hours. Units with add-
  on controls that report NOX mass emissions on a year-round basis under subpart H of this part may use separate
  ozone season and non-ozone season data pools to provide substitute data values, as described in Sec.
  75.34(a)(2).


                        Table 4--Non-load-based Missing Data Procedure for Flow Rate CEMS
----------------------------------------------------------------------------------------------------------------
                     Trigger conditions                                      Calculation routines
----------------------------------------------------------------------------------------------------------------
                                        Duration (N) of CEMS
 Monitor data availability (percent)     outage (hours) \1\            Method                Lookback period
----------------------------------------------------------------------------------------------------------------
95 or more...........................  N <=24                 Average.................  2160 hours*
                                       N 24        The greater of:.........  ........................
                                                              Average.................  HB/HA
                                                              90th percentile.........  2160 hours*
90 or more, but below 95.............  N <=8                  Average.................  2160 hours*
                                       N 8         The greater of:.........
                                                              Average.................
                                                              95th percentile.........
                                                              HB/HA...................
                                                              2160 hours*.............
80 or more, but below 90.............  N 0         Maximum value...........  2160 hours*
Below 80, or operational bin           N 0         Maximum potential flow    None
 indeterminable.                                               rate.
----------------------------------------------------------------------------------------------------------------
* If operational bins are used, the lookback period is the previous 2,160 quality-assured, monitor operating
  hours and data at the corresponding operational bin are used to provide substitute data values. If operational
  bins are not used, the lookback period is the previous 2,160 quality-assured, monitor operating hours. For
  units that report data only for the ozone season, include only quality-assured monitor operating hours within
  the ozone season in the lookback period. Use data from no earlier than three years prior to the missing data
  period.
\1\ During unit operation.


[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26529, May 17, 1995; 61 
FR 25582, May 22, 1996; 64 FR 28602, May 26, 1999; 67 FR 40434, June 12, 
2002; 67 FR 53505, Aug. 16, 2002; 67 FR 57274, Sept. 9, 2002; 70 FR 
28680, May 18, 2005; 73 FR 4346, Jan. 24, 2008; 76 FR 17311, Mar. 28, 
2011]



Sec. 75.34  Units with add-on emission controls.

    (a) The owner or operator of an affected unit equipped with add-on 
SO2 and/or NOX emission controls shall provide 
substitute data in accordance with paragraphs (a)(1), through (a)(5) of 
this section for each hour in which quality-assured data from the outlet 
SO2 and/or NOX monitoring system(s) are not 
obtained.
    (1) The owner or operator may use the missing data substitution 
procedures specified in Sec. Sec. 75.31 through 75.33

[[Page 279]]

to provide substitute data for any missing data hour(s) in which the 
add-on emission controls are documented to be operating properly, as 
described in the quality assurance/quality control program for the unit, 
required by section 1 in appendix B of this part. To provide the 
necessary documentation, the owner or operator shall, for each missing 
data period, record parametric data to verify the proper operation of 
the SO2 or NOX add-on emission controls during 
each hour, as described in paragraph (d) of this section. For any 
missing data hour(s) in which such parametric data are either not 
provided or, if provided, do not demonstrate that proper operation of 
the SO2 or NOX add-on emission controls has been 
maintained, the owner or operator shall substitute (as applicable) the 
maximum potential NOX concentration (MPC) as defined in 
section 2.1.2.1 of appendix A to this part, the maximum potential 
NOX emission rate, as defined in Sec. 72.2 of this chapter, 
or the maximum potential concentration for SO2, as defined by 
section 2.1.1.1. Alternatively, for SO2 or NOX, 
the owner or operator may substitute, if available, the hourly 
SO2 or NOX concentration recorded by a certified 
inlet monitor, in lieu of the MPC. For each hour in which data from an 
inlet monitor are reported, the owner or operator shall use a method of 
determination code (MODC) of ``22'' (see Table 4a in Sec. 75.57). In 
addition, under Sec. 75.64(c), the designated representative shall 
submit as part of each electronic quarterly report, a certification 
statement, verifying the proper operation of the SO2 or 
NOX add-on emission control for each missing data period in 
which the missing data procedures of Sec. Sec. 75.31 through 75.33 were 
applied; or
    (2) This paragraph, (a)(2), applies only to a unit which, as 
provided in Sec. 75.74(a) or Sec. 75.74(b)(1), reports NOX 
mass emissions on a year-round basis under a state or Federal 
NOX mass emissions reduction program that adopts the 
emissions monitoring provisions of this part. If the add-on 
NOX emission controls installed on such a unit are operated 
only during the ozone season or are operated in a more efficient manner 
during the ozone season than outside the ozone season, the owner or 
operator may implement the missing data provisions of paragraph (a)(1) 
of this section in the following alternative manner:
    (i) The historical, quality-assured NOX emission rate or 
NOX concentration data may be separated into two categories, 
i.e., data recorded inside the ozone season and data recorded outside 
the ozone season;
    (ii) For the purposes of the missing data lookback periods described 
under Sec. Sec. 75.33 (c)(1), (c)(2), (c)(3) and (c)(5) of this 
section, the substitute data values shall be taken from the appropriate 
database, depending on the date(s) and hour(s) of the missing data 
period. That is, if the missing data period occurs inside the ozone 
season, the ozone season data shall be used to provide substitute data. 
If the missing data period occurs outside the ozone season, data from 
outside the ozone season shall be used to provide substitute data.
    (iii) A missing data period that begins outside the ozone season and 
continues into the ozone season shall be considered to be two separate 
missing data periods, one ending on April 30, hour 23, and the other 
beginning on May 1, hour 00;
    (iv) For missing data hours outside the ozone season, the procedures 
of Sec. 75.33 may be applied unconditionally, i.e., documentation of 
the operational status of the emission controls is not required in order 
to apply the standard missing data routines.
    (3) For each missing data hour in which the percent monitor data 
availability for SO2 or NOX, calculated in 
accordance with Sec. 75.32, is less than 90.0 percent and is greater 
than or equal to 80.0 percent; and parametric data establishes that the 
add-on emission controls were operating properly (i.e. within the range 
of operating parameters provided in the quality assurance/quality 
control program) during the hour, the owner or operator may:
    (i) Replace the maximum SO2 concentration recorded in the 
720 quality-assured monitor operating hours immediately preceding the 
missing data period, with the maximum controlled SO2 concentration 
recorded in the previous 720 quality-assured monitor operating hours; or

[[Page 280]]

    (ii) Replace the maximum NOX concentration(s) or 
NOX emission rate(s) from the appropriate load bin(s) (based 
on a lookback through the 2,160 quality-assured monitor operating hours 
immediately preceding the missing data period), with the maximum 
controlled NOX concentration(s) or emission rate(s) from the 
appropriate load bin(s) in the same 2,160 quality-assured monitor 
operating hour lookback period.
    (4) The designated representative may petition the Administrator 
under Sec. 75.66 for approval of site-specific parametric monitoring 
procedure(s) for calculating substitute data for missing SO2 
pollutant concentration, NOX pollutant concentration, and 
NOX emission rate data in accordance with the requirements of 
paragraphs (b) and (c) of this section and appendix C to this part. The 
owner or operator shall record the data required in appendix C to this 
part, pursuant to Sec. 75.58(b).
    (5) For each missing data hour in which the percent monitor data 
availability for SO2 or NOX, calculated in 
accordance with Sec. 75.32, is below 80.0 percent and parametric data 
establish that the add-on emission controls were operating properly 
(i.e. within the range of operating parameters provided in the quality 
assurance/quality control program),in lieu of reporting the maximum 
potential value, the owner or operator may substitute, as applicable, 
the greater of:
    (i) The maximum expected SO2 concentration or 1.25 times 
the maximum hourly controlled SO2 concentration recorded in 
the previous 720 quality-assured monitor operating hours;
    (ii) The maximum expected NOX concentration or 1.25 times 
the maximum hourly controlled NOX concentration recorded in 
the previous 2,160 quality-assured monitor operating hours at the 
corresponding unit load range or operational bin;
    (iii) The maximum controlled hourly NOX emission rate 
(MCR) or 1.25 times the maximum hourly controlled NOX 
emission rate recorded in the previous 2,160 quality-assured monitor 
operating hours at the corresponding unit load range or operational bin;
    (iv) For the purposes of implementing the missing data options in 
paragraphs (a)(5)(i) through (a)(5)(iii) of this section, the maximum 
expected SO2 and NOX concentrations shall be 
determined, respectively, according to sections 2.1.1.2 and 2.1.2.2 of 
appendix A to this part. The MCR shall be calculated according to the 
basic procedure described in section 2.1.2.1(b) of appendix A to this 
part, except that the words ``maximum potential NOX emission 
rate (MER)'' shall be replaced with the words ``maximum controlled 
NOX emission rate (MCR)'' and the NOX MEC shall be 
used instead of the NOX MPC.
    (b) For an affected unit equipped with add-on SO2 
emission controls, the designated representative may petition the 
Administrator to approve a parametric monitoring procedure, as described 
in appendix C of this part, for calculating substitute SO2 
concentration data for missing data periods. The owner or operator shall 
use the procedures in Sec. Sec. 75.31, 75.33, or 75.34(a) for providing 
substitute data for missing SO2 concentration data unless a 
parametric monitoring procedure has been approved by the Administrator.
    (1) Where the monitor data availability is 90.0 percent or more for 
an outlet SO2 pollutant concentration monitor, the owner or 
operator may calculate substitute data using an approved parametric 
monitoring procedure.
    (2) Where the monitor data availability for an outlet SO2 
pollutant concentration monitor is less than 90.0 percent, the owner or 
operator shall calculate substitute data using the procedures in Sec. 
75.34(a) (1) or (2), even if the Administrator has approved a parametric 
monitoring procedure.
    (c) For an affected unit with NOX add-on emission 
controls, the designated representative may petition the Administrator 
to approve a parametric monitoring procedure, as described in appendix C 
of this part, in order to calculate substitute NOX emission 
rate data for missing data periods. The owner or operator shall use the 
procedures in Sec. 75.31 or 75.33 for providing substitute data for 
missing NOX emission rate data prior to receiving the 
Administrator's approval for a parametric monitoring procedure.

[[Page 281]]

    (1) Where monitor data availability for a NOX continuous 
emission monitoring system is 90.0 percent or more, the owner or 
operator may calculate substitute data using an approved parametric 
monitoring procedure.
    (2) Where monitor data availability for a NOX continuous 
emission monitoring system is less than 90.0 percent, the owner or 
operator shall calculate substitute data using the procedure in Sec. 
75.34(a) (1) or (2), even if the Administrator has approved a parametric 
monitoring procedure.
    (d) In order to implement the options in paragraphs (a)(1), (a)(3) 
and (a)(5) of this section; and Sec. Sec. 75.31(c)(3) and 75.72(c)(3), 
the owner or operator shall keep records of information as described in 
Sec. 75.58(b)(3) to verify the proper operation of all add-on 
SO2 or NOX emission controls, during all periods 
of SO2 or NOX emission missing data. If the owner 
or operator elects to implement the missing data option in paragraph 
(a)(2) of this section, the records in Sec. 75.58(b)(3) are required to 
be kept only for the ozone season. The owner or operator shall document 
in the quality assurance/quality control (QA/QC) program required by 
section 1 of appendix B to this part, the parameters monitored and (as 
applicable) the ranges and combinations of parameters that indicate 
proper operation of the controls. The owner or operator shall provide 
the information recorded under Sec. 75.58(b)(3) and the related QA/QC 
program information to the Administrator, to the EPA Regional Office, or 
to the appropriate State or local agency, upon request.

[60 FR 26567, May 17, 1995, as amended at 61 FR 59160, Nov. 20, 1996; 64 
FR 28604, May 26, 1999; 67 FR 40438, June 12, 2002; 73 FR 4348, Jan. 24, 
2008; 76 FR 17312, Mar. 28, 2011]



Sec. 75.35  Missing data procedures for CO [bdi2].

    (a) The owner or operator of a unit with a CO2 continuous 
emission monitoring system for determining CO2 mass emissions 
in accordance with Sec. 75.10 (or an O2 monitor that is used 
to determine CO2 concentration in accordance with appendix F 
to this part) shall substitute for missing CO2 pollutant 
concentration data using the procedures of paragraphs (b) and (d) of 
this section.
    (b) During the first 720 quality-assured monitor operating hours 
following initial certification at a particular unit or stack location 
(i.e., the date and time at which quality-assured data begins to be 
recorded by a CEMS at that location), or (when implementing these 
procedures for a previously certified CO2 monitoring system) 
during the 720 quality-assured monitor operating hours preceding 
implementation of the standard missing data procedures in paragraph (d) 
of this section, the owner or operator shall provide substitute 
CO2 pollutant concentration data or substitute CO2 
data for heat input determination, as applicable, according to the 
procedures in Sec. 75.31(b).
    (c) [Reserved]
    (d) Upon completion of 720 quality-assured monitor operating hours 
using the initial missing data procedures of Sec. 75.31(b), the owner 
or operator shall provide substitute data for CO2 
concentration or substitute CO2 data for heat input 
determination, as applicable, in accordance with the procedures in Sec. 
75.33(b) except that the term ``CO2 concentration'' shall 
apply rather than ``SO2 concentration,'' the term 
``CO2 pollutant concentration monitor'' or ``CO2 
diluent monitor'' shall apply rather than ``SO2 pollutant 
concentration monitor,'' and the term ``maximum potential CO2 
concentration, as defined in section 2.1.3.1 of appendix A to this 
part'' shall apply, rather than ``maximum potential SO2 
concentration.''

[67 FR 40439, June 12, 2002]



Sec. 75.36  Missing data procedures for heat input rate 
determinations.

    (a) When hourly heat input rate is determined using a flow 
monitoring system and a diluent gas (O2 or CO2) 
monitor, substitute data must be provided to calculate the heat input 
whenever quality-assured data are unavailable from the flow monitor, the 
diluent gas monitor, or both. When flow rate data are unavailable, 
substitute flow rate data for the heat input rate calculation shall be 
provided according to Sec. 75.31 or Sec. 75.33, as applicable. When 
diluent gas

[[Page 282]]

data are unavailable, the owner or operator shall provide substitute 
O2 or CO2 data for the heat input rate 
calculations in accordance with paragraphs (b) and (d) of this section.
    (b) During the first 720 quality-assured monitor operating hours 
following initial certification at a particular unit or stack location 
(i.e., the date and time at which quality-assured data begins to be 
recorded by a CEMS at that location), or (when implementing these 
procedures for a previously certified CO2 or O2 
monitor) during the 720 quality-assured monitor operating hours 
preceding implementation of the standard missing data procedures in 
paragraph (d) of this section, the owner or operator shall provide 
substitute CO2 or O2 data, as applicable, for the 
calculation of heat input (under section 5.2 of appendix F to this part) 
according to Sec. 75.31(b).
    (c) [Reserved]
    (d) Upon completion of 720 quality-assured monitor operating hours 
using the initial missing data procedures of Sec. 75.31(b), the owner 
or operator shall provide substitute data for CO2 or 
O2 concentration to calculate heat input rate, as follows. 
Substitute CO2 data for heat input rate determinations shall 
be provided according to Sec. 75.35(d). Substitute O2 data 
for the heat input rate determinations shall be provided in accordance 
with the procedures in Sec. 75.33(b), except that the term 
``O2 concentration'' shall apply rather than the term 
``SO2 concentration'' and the term ``O2 diluent 
monitor'' shall apply rather than the term ``SO2 pollutant 
concentration monitor.'' In addition, the term ``substitute the lesser 
of'' shall apply rather than ``substitute the greater of;'' the terms 
``minimum hourly O2 concentration'' and ``minimum potential 
O2 concentration, as determined under section 2.1.3.2 of 
appendix A to this part'' shall apply rather than, respectively, the 
terms ``maximum hourly SO2 concentration'' and ``maximum 
potential SO2 concentration, as determined under section 
2.1.1.1 of appendix A to this part;'' and the terms ``10th percentile'' 
and ``5th percentile'' shall apply rather than, respectively, the terms 
``90th percentile'' and ``95th percentile'' (see Table 1 of Sec. 
75.33).

[60 FR 26530, May 17, 1995, as amended at 64 FR 28604, May 26, 1999; 67 
FR 40439, June 12, 2002]



Sec. 75.37  Missing data procedures for moisture.

    (a) The owner or operator of a unit with a continuous moisture 
monitoring system shall substitute for missing moisture data using the 
procedures of this section.
    (b) Where no prior quality-assured moisture data exist, substitute 
the minimum potential moisture percentage, from section 2.1.5 of 
appendix A to this part, except when Equation 19-3, 19-4 or 19-8 in 
Method 19 in appendix A to part 60 of this chapter is used to determine 
NOX emission rate. If Equation 19-3, 19-4 or 19-8 in Method 
19 in appendix A to part 60 of this chapter is used to determine 
NOX emission rate, substitute the maximum potential moisture 
percentage, as specified in section 2.1.6 of appendix A to this part.
    (c) During the first 720 quality-assured monitor operating hours 
following initial certification at a particular unit or stack location 
(i.e., the date and time at which quality-assured data begins to be 
recorded by a moisture monitoring system at that location), the owner or 
operator shall provide substitute data for moisture according to Sec. 
75.31(b).
    (d) Upon completion of the first 720 quality-assured monitor 
operating hours following initial certification, the owner or operator 
shall provide substitute data for moisture as follows:
    (1) Unless Equation 19-3, 19-4 or 19-8 in Method 19 in appendix A to 
part 60 of this chapter is used to determine NOX emission 
rate, follow the missing data procedures in Sec. 75.33(b), except that 
the term ``moisture percentage'' shall apply rather than 
``SO2 concentration;'' the term ``moisture monitoring 
system'' shall apply rather than the term ``SO2 pollutant 
concentration monitor;'' the term ``substitute the lesser of'' shall 
apply rather than ``substitute the greater of;'' the terms ``minimum 
hourly moisture percentage'' and ``minimum potential moisture 
percentage, as determined under section 2.1.5 of appendix A to this 
part''

[[Page 283]]

shall apply rather than, respectively, the terms ``maximum hourly 
SO2 concentration'' and ``maximum potential SO2 
concentration, as determined under section 2.1.1.1 of appendix A to this 
part;'' and the terms ``10th percentile'' and ``5th percentile'' shall 
apply rather than, respectively, the terms ``90th percentile'' and 
``95th percentile'' (see Table 1 of Sec. 75.33).
    (2) When Equation 19-3, 19-4 or 19-8 in Method 19 in appendix A to 
part 60 of this chapter is used to determine NOX emission 
rate:
    (i) Provided that none of the following equations is used to 
determine SO2 emissions, CO2 emissions or heat 
input: Equation F-2, F-14b, F-16, F-17, or F-18 in appendix F to this 
part, or Equation 19-5 or 19-9 in Method 19 in appendix A to part 60 of 
this chapter, use the missing data procedures in Sec. 75.33(b), except 
that the term ``moisture percentage'' shall apply rather than 
``SO2 concentration,'' the term ``moisture monitoring 
system'' shall apply rather than ``SO2 pollutant 
concentration monitor,'' and the term ``maximum potential moisture 
percentage, as defined in section 2.1.6 of appendix A to this part'' 
shall apply, rather than ``maximum potential SO2 
concentration;'' or
    (ii) If any of the following equations is used to determine 
SO2 emissions, CO2 emissions or heat input: 
Equation F-2, F-14b, F-16, F-17, or F-18 in appendix F to this part, or 
Equation 19-5 or 19-9 in Method 19 in appendix A to part 60 of this 
chapter, the owner or operator shall petition the Administrator under 
Sec. 75.66(l) for permission to use an alternative moisture missing 
data procedure.

[64 FR 28604, May 26, 1999, as amended at 67 FR 40439, June 12, 2002]



Sec. Sec. 75.38-75.39  [Reserved]



                Subpart E_Alternative Monitoring Systems



Sec. 75.40  General demonstration requirements.

    (a) The owner or operator of an affected unit, or the owner or 
operator of an affected unit and representing a class of affected units 
which meet the criteria specified in Sec. 75.47, required to install a 
continuous emission monitoring system may apply to the Administrator for 
approval of an alternative monitoring system (or system component) to 
determine average hourly emission data for SO2, 
NOX, and/or volumetric flow by demonstrating that the 
alternative monitoring system has the same or better precision, 
reliability, accessibility, and timeliness as that provided by the 
continuous emission monitoring system.
    (b) The requirements of this subpart shall be met by the alternative 
monitoring system when compared to a contemporaneously operating, fully 
certified continuous emission monitoring system or a contemporaneously 
operating reference method, where the appropriate reference methods are 
listed in Sec. 75.22.



Sec. 75.41  Precision criteria.

    (a) Data collection and analysis. To demonstrate precision equal to 
or better than the continuous emission monitoring system, the owner or 
operator shall conduct an F-test, a correlation analysis, and a t-test 
for bias as described in this section. The t-test shall be performed 
only on sample data at the normal operating level and primary fuel 
supply, whereas the F-test and the correlation analysis must be 
performed on each of the data sets required under paragraphs (a)(4) and 
(a)(5) of this section. The owner or operator shall collect and analyze 
data according to the following requirements:
    (1) Data from the alternative monitoring system and the continuous 
emission monitoring system shall be collected and paired in a manner 
that ensures each pair of values applies to hourly average emissions 
during the same hour.
    (2) An alternative monitoring system that directly measures 
emissions shall have probes or other measuring devices in locations that 
are in proximity to the continuous emission monitoring system and shall 
provide data on the same parameters as those measured by the continuous 
emission monitoring system. Data from the alternative monitoring system 
shall meet the statistical tests for precision in paragraph (c) of this 
section and the t-test for bias in appendix A of this part.

[[Page 284]]

    (3) An alternative monitoring system that indirectly quantifies 
emission values by measuring inputs, operating characteristics, or 
outputs and then applying a regression or another quantitative technique 
to estimate emissions, shall meet the statistical tests for precision in 
paragraph (c) of this section and the t-test for bias in appendix A of 
this part.
    (4) For flow monitor alternatives, the alternative monitoring system 
must provide sample data for each of three different exhaust gas 
velocities while the unit or units, if more than one unit exhausts into 
the stack or duct, is burning its primary fuel at:
    (i) A frequently used low operating level, selected within the range 
between the minimum safe and stable operating level and 50 percent of 
the maximum operating level,
    (ii) A frequently used high operating level, selected within the 
range between 80 percent of the maximum operating level and the maximum 
operating level, and
    (iii) The normal operating level, or an evenly spaced intermediary 
level between low and high levels used if the normal operating level is 
within a specified range (10.0 percent of the maximum operating level), 
of either paragraphs (a)(4) (i) or (ii) of this section.
    (5) For pollutant concentration monitor alternatives, the 
alternative monitoring system shall provide sample data for the primary 
fuel supply and for all alternative fuel supplies that have 
significantly different sulfur content.
    (6) For the normal unit operating level and primary fuel supply, 
paired hourly sample data shall be provided for at least 90.0 percent of 
the hours during 720 unit operating hours. For each of the remaining two 
operating levels for flow monitor alternatives, and for each alternative 
fuel supply for pollutant concentration monitor alternatives, paired 
hourly sample data shall be provided for at least 24 successive unit 
operating hours.
    (7) The owner or operator shall not use missing data substitution 
procedures to provide sample data.
    (8) If the collected data meet the requirements of the F-test, the 
correlation test, and the t-test at one or more, but not all, of the 
operating levels or fuel supplies, the owner or operator may elect to 
continue collecting the paired data for up to 1,440 additional operating 
hours and repeat the statistical tests using the data for the entire 30- 
to 90-day period.
    (9) The owner or operator shall provide two separate time series 
data plots for the data at each operating level or fuel supply described 
in paragraphs (a)(4) and (a)(5) of this section. Each data plot shall 
have a horizontal axis that represents the clock hour and calendar date 
of the readings and shall contain a separate data point for every hour 
for the duration of the performance evaluation. The data plots shall 
show the following:
    (i) Percentage difference versus time where the vertical axis 
represents the percentage difference between each paired hourly reading 
generated by the continuous emission monitoring system (or reference 
method) and the alternative emission monitoring system as calculated 
using the following equation:
[GRAPHIC] [TIFF OMITTED] TC01SE92.156


(Eq. 10)

where,

[Delta] e = Percentage difference between the readings generated by the 
          alternative monitoring system and the continuous emission 
          monitoring system.
ep = Measured value from the alternative monitoring system.
ev = Measured value from the continuous emission monitoring 
          system.

    (ii) Alternative monitoring system readings and continuous emission 
monitoring system (or reference method) readings versus time where the 
vertical axis represents hourly pollutant concentrations or volumetric 
flow, as appropriate, and two different symbols are used to represent 
the readings from the alternative monitoring system and the continuous 
emission monitoring system (or reference method), respectively.
    (b) Data screening and calculation adjustments. In preparation for 
conducting the statistical tests described in paragraph (c) of this 
section, the

[[Page 285]]

owner or operator may screen the data for lognormality and time 
dependency autocorrelation. If either is detected, the owner or operator 
shall make the following calculation adjustments:
    (1) Lognormality. The owner or operator shall conduct any screening 
and adjustment for lognormality according to the following procedures.
    (i) Apply the log transformation to each measured value of either 
the certified continuous emissions monitoring system or certified flow 
monitor, using the following equation:

lv = ln ev


(Eq. 11)

where,

ev = Hourly value generated by the certified continuous 
          emissions monitoring system or certified flow monitoring 
          system
lv = Hourly lognormalized data values for the certified 
          monitoring system


and to each measured value, ep, of the proposed alternative 
monitoring system, using the following equation to obtain the 
lognormalized data values, lp:

lp = ln ep


(Eq. 12)

where,

ep = Hourly value generated by the proposed alternative 
          monitoring system.
lp = Hourly lognormalized data values for the proposed 
          alternative monitoring system.

    (ii) Separately test each set of transformed data, lv and 
lp, for normality, using the following:
    (A) Shapiro-Wilk test;
    (B) Histogram of the transformed data; and
    (C) Quantile-Quantile plot of the transformed data.
    (iii) The transformed data in a data set will be considered normally 
distributed if all of the following conditions are satisfied:
    (A) The Shapiro-Wilk test statistic, W, is greater than or equal to 
0.75 or is not statistically significant at [alpha] = 0.05.
    (B) The histogram of the data is unimodal and symmetric.
    (C) The Quantile-Quantile plot is a diagonal straight line.
    (iv) If both of the transformed data sets, lv and 
lp, meet the conditions for normality, specified in 
paragraphs (b)(1)(iii) (A) through (C) of this section, the owner or 
operator may use the transformed data, lv and lp, 
in place of the original measured data values in the statistical tests 
for alternative monitoring systems as described in paragraph (c) of this 
section and in appendix A of this part.
    (v) If the transformed data are used in the statistical tests in 
paragraph (c) of this section and in appendix A of this part, the owner 
or operator shall provide the following:
    (A) Copy of the original measured values and the corresponding 
transformed data in printed and electronic format.
    (B) Printed copy of the test results and plots described in 
paragraphs (b)(1) (i) through (iii) of this section.
    (2) Time dependency (autocorrelation). The screening and adjustment 
for time dependency are conducted according to the following procedures:
    (i) Calculate the degree of autocorrelation of the data on their 
LAG1 values, where the degree of autocorrelation is represented by the 
Pearson autocorrelation coefficient, [rho], computed from an AR(1) 
autoregression model, such that:
[GRAPHIC] [TIFF OMITTED] TC01SE92.101


(Eq. 13)

where,

x'i = The original data value at hour i.
x''i = The LAG1 data value at hour i.
COV(x'i, x''i) = The autocovariance of x'i and defined by,
[GRAPHIC] [TIFF OMITTED] TC01SE92.102


(Eq. 14)

where,

n = The total number of observations in which both the original value, 
          x'i, and the lagged value, x''i, are available in the data 
          set.
s'x i = The standard deviation of the original data values, 
          x'i defined by,

[[Page 286]]

[GRAPHIC] [TIFF OMITTED] TC01SE92.103


(Eq. 15)

where,

s''x i = The standard deviation of the LAG1 data values, x''i, defined 
          by
          [GRAPHIC] [TIFF OMITTED] TC01SE92.104
          

(Eq. 16)

where,

x' = The mean of the original data values, x'i defined by
[GRAPHIC] [TIFF OMITTED] TC01SE92.105


(Eq. 17)

where,

x'' = The mean of the LAG1 data values, x''i, defined by
[GRAPHIC] [TIFF OMITTED] TC01SE92.106


(Eq. 18)


where,

    (ii) The data in a data set will be considered autocorrelated if the 
autocorrelation coefficient, [rho], is significant at the 5 percent 
significance level. To determine if this condition is satisfied, 
calculate Z using the following equation:
[GRAPHIC] [TIFF OMITTED] TC01SE92.107


(Eq. 19)

If Z 1.96, then the autocorrelation coefficient, [rho], is 
significant at the 5 percent significance level (a = 0.05).

    (iii) If the data in a data set satisfy the conditions for 
autocorrelation, specified in paragraph (b)(2)(ii) of this section, the 
variance of the data, S\2\, may be adjusted using the following 
equation:

S\2\adj = VIF x S\2\

(Eq. 20)

where,

S\2\ = The original, unadjusted variance of the data set.
VIF = The variance inflation factor, defined by
[GRAPHIC] [TIFF OMITTED] TC01SE92.108


(Eq. 21)

S\2\adj = The autocorrelation-adjusted variance for the data set.

    (iv) The procedures described in paragraphs (b)(2)(i)-(iii) of this 
section may be separately applied to the following data sets in order to 
derive distinct autocorrelation coefficients and variance inflation 
factors for each data set:
    (A) The set of measured hourly values, ev, generated by 
the certified continuous emissions monitoring system or certified flow 
monitoring system.
    (B) The set of hourly values, ep, generated by the 
proposed alternative monitoring system,
    (C) The set of hourly differences, ev-ep, 
between the hourly values, ev, generated by the certified 
continuous emissions monitoring system or certified flow monitoring 
system and the hourly values, ep, generated by the proposed 
alternative monitoring system.
    (v) For any data set, listed in paragraph (b)(2)(iv) of this 
section, that satisfies the conditions for autocorrelation specified in 
paragraph (b)(2)(ii) of this section, the owner or operator may adjust 
the variance of that data set, using equation 20 of this section.
    (A) The adjusted variance may be used in place of the corresponding 
original variance, as calculated using equation 23 of this section, in 
the F-test (Equation 24) of this section.
    (B) In place of the standard error of the mean,

[[Page 287]]

[GRAPHIC] [TIFF OMITTED] TC01SE92.111


in the bias test Equation A-9 of appendix A of this part the following 
adjusted standard error of the mean may be used:
[GRAPHIC] [TIFF OMITTED] TC01SE92.109


(Eq. 22)where
[GRAPHIC] [TIFF OMITTED] TC01SE92.110

    (vi) For each data set in which a variance adjustment is used, the 
owner or operator shall provide the following:
    (A) All values in the data set in printed and electronic format.
    (B) Values of the autocorrelation coefficient, its level of 
significance, the variance inflation factor, and the unadjusted original 
and adjusted values found in equations 20 and 22 of this section.
    (C) Equation and related statistics of the AR(1) autoregression 
model of the data set.
    (D) Printed documentation of the intermediate calculations used to 
derive the autocorrelation coefficient and the Variance Inflation 
Factor.
    (c) Statistical Tests. The owner or operator shall perform the F-
test and correlation analysis as described in this paragraph and the t-
test for bias described in appendix A of this part to demonstrate the 
precision of the alternative monitoring system.
    (1) F-test. The owner or operator shall conduct the F-test according 
to the following procedures.
    (i) Calculate the variance of the certified continuous emission 
monitoring system or certified flow monitor as applicable, 
Sv2, and the proposed method, Sp2, using the 
following equation.
[GRAPHIC] [TIFF OMITTED] TR08AU95.064


(Eq. 23)

where,

ei = Measured values of either the certified continuous 
          emission monitoring system or certified flow monitor, as 
          applicable, or proposed method.
em = Mean of either the certified continuous emission 
          monitoring system or certified flow monitor, as applicable, or 
          proposed method values.
n = Total number of paired samples.

    (ii) Determine if the variance of the proposed method is 
significantly different from that of the certified continuous emission 
monitoring system or certified flow monitor, as applicable, by 
calculating the F-value using the following equation.
[GRAPHIC] [TIFF OMITTED] TR08AU95.065


(Eq. 24)


Compare the experimental F-value with the critical value of F at the 95-
percent confidence level with n-1 degrees of freedom. The critical value 
is

[[Page 288]]

obtained from a table for F-distribution. If the calculated F-value is 
greater than the critical value, the proposed method is unacceptable.
    (2) Correlation analysis. The owner or operator shall conduct the 
correlation analysis according to the following procedures.
    (i) Plot each of the paired emissions readings as a separate point 
on a graph where the vertical axis represents the value (pollutant 
concentration or volumetric flow, as appropriate) generated by the 
alternative monitoring system and the horizontal axis represents the 
value (pollutant concentration or volumetric flow, as appropriate) 
generated by the continuous emission monitoring system (or reference 
method). On the graph, draw a horizontal line representing the mean 
value, ep, for the alternative monitoring system and a 
vertical line representing the mean value, ev, for the 
continuous emission monitoring system where,
[GRAPHIC] [TIFF OMITTED] TC01SE92.112


(Eq. 25)
[GRAPHIC] [TIFF OMITTED] TC01SE92.113


(Eq. 26)

where,

ep = Hourly value generated by the alternative monitoring 
          system.
ev = Hourly value generated by the continuous emission 
          monitoring system.
n = Total number of hours for which data were generated for the tests.


A separate graph shall be produced for the data generated at each of the 
operating levels or fuel supplies described in paragraphs (a)(4) and 
(a)(5) of this section.
    (ii) Use the following equation to calculate the coefficient of 
correlation, r, between the emissions data from the alternative 
monitoring system and the continuous emission monitoring system using 
all hourly data for which paired values were available from both 
monitoring systems.
[GRAPHIC] [TIFF OMITTED] TR12JN02.007


(Eq. 27)

    (iii) If the calculated r-value is less than 0.8, the proposed 
method is unacceptable.

[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26530, May 17, 1995; 60 
FR 40296, Aug. 8, 1995; 67 FR 40440, June 12, 2002]



Sec. 75.42  Reliability criteria.

    To demonstrate reliability equal to or better than the continuous 
emission monitoring system, the owner or operator shall demonstrate that 
the alternative monitoring system is capable of providing valid 1-hr 
averages for 95.0 percent or more of unit operating hours over a 1-yr 
period and that the system meets the applicable requirements of appendix 
B of this part.



Sec. 75.43  Accessibility criteria.

    To demonstrate accessibility equal to or better than the continuous 
emission monitoring system, the owner or operator shall provide reports 
and onsite records of emission data to demonstrate that the alternative 
monitoring system provides data meeting the requirements of subparts F 
and G of this part.



Sec. 75.44  Timeliness criteria.

    To demonstrate timeliness equal to or better than the continuous 
emission monitoring system, the owner or operator shall demonstrate that 
the alternative monitoring system can meet the requirements of subparts 
F and G of this part; can provide a continuous,

[[Page 289]]

quality-assured, permanent record of certified emissions data on an 
hourly basis; and can issue a record of data for the previous day within 
24 hours.



Sec. 75.45  Daily quality assurance criteria.

    The owner or operator shall either demonstrate that daily tests 
equivalent to those specified in appendix B of this part can be 
performed on the alternative monitoring system or demonstrate and 
document that such tests are unnecessary for providing quality-assured 
data.



Sec. 75.46  Missing data substitution criteria.

    The owner or operator shall demonstrate that all missing data can be 
accounted for in a manner consistent with the applicable missing data 
procedures in subpart D of this part.



Sec. 75.47  Criteria for a class of affected units.

    (a) The owner or operator of an affected unit may represent a class 
of affected units for the purpose of applying to the Administrator for a 
class-approved alternative monitoring system.
    (b) The owner or operator of an affected unit representing a class 
of affected units shall provide the following information:
    (1) A description of the affected unit and how it appropriately 
represents the class of affected units;
    (2) A description of the class of affected units, including data 
describing all of the affected units that will comprise the class.

[60 FR 40297, Aug. 8, 1995, as amended at 76 FR 17312, Mar. 28, 2011]



Sec. 75.48  Petition for an alternative monitoring system.

    (a) The designated representative shall submit the following 
information in the application for certification or recertification of 
an alternative monitoring system.
    (1) Source identification information.
    (2) A description of the alternative monitoring system.
    (3) Data, calculations, and results of the statistical tests, 
specified in Sec. 75.41(c) of this part, including:
    (i) Date and hour.
    (ii) Hourly test data for the alternative monitoring system at each 
required operating level and fuel type. The fuel type, operating level 
and gross unit load shall be recorded.
    (iii) Hourly test data for the continuous emissions monitoring 
system at each required operating level and fuel type. The fuel type, 
operating level and gross unit load shall be recorded.
    (iv) Arithmetic mean of the alternative monitoring system 
measurement values, as specified in Equation 25 in Sec. 75.41(c) of 
this part, of the continuous emission monitoring system values, as 
specified in Equation 26 in Sec. 75.41(c) of this part, and of their 
differences.
    (v) Standard deviation of the difference, as specified in equation 
A-8 in appendix A of this part.
    (vi) Confidence coefficient, as specified in equation A-9 in 
appendix A of this part.
    (vii) The bias test results as specified in Sec. 7.6.4 in appendix 
A of this part.
    (viii) Variance of the measured values for the alternative 
monitoring system and of the measured values for the continuous emission 
monitoring system, as specified in Equation 23 in Sec. 75.41(c) of this 
part.
    (ix) F-statistic, as specified in Equation 24 in Sec. 75.41(c) of 
this part.
    (x) Critical value of F at the 95-percent confidence level with n-1 
degrees of freedom.
    (xi) Coefficient of correlation, r, as specified in Equation 27 in 
Sec. 75.41(c) of this part.
    (4) Data plots, specified in Sec. Sec. 75.41(a)(9) and 
75.41(c)(2)(i) of this part.
    (5) Results of monitor reliability analysis.
    (6) Results of monitor accessibility analysis.
    (7) Results of monitor timeliness analysis.
    (8) A detailed description of the process used to collect data, 
including location and method of ensuring an accurate assessment of 
operating hourly conditions on a real-time basis.
    (9) A detailed description of the operation, maintenance, and 
quality assurance procedures for the alternative monitoring system as 
required in appendix B of this part.

[[Page 290]]

    (10) A description of methods used to calculate heat input or 
diluent gas concentration, if applicable.
    (11) Results of tests and measurements (including the results of all 
reference method field test sheets, charts, laboratory analyses, example 
calculations, or other data as appropriate) necessary to substantiate 
that the alternative monitoring system is equivalent in performance to 
an appropriate, certified operating continuous emission monitoring 
system.
    (b) [Reserved]

[60 FR 40297, Aug. 8, 1995, as amended at 64 FR 28605, May 26, 1999]



                  Subpart F_Recordkeeping Requirements



Sec. Sec. 75.50-75.52  [Reserved]



Sec. 75.53  Monitoring plan.

    (a) General provisions. (1) The provisions of paragraphs (e) and (f) 
of this section shall be met through December 31, 2008. The owner or 
operator shall meet the requirements of paragraphs (a), (b), (e), and 
(f) of this section through December 31, 2008, except as otherwise 
provided in paragraph (g) of this section. On and after January 1, 2009, 
the owner or operator shall meet the requirements of paragraphs (a), 
(b), (g), and (h) of this section only. In addition, the provisions in 
paragraphs (g) and (h) of this section that support a regulatory option 
provided in another section of this part must be followed if the 
regulatory option is used prior to January 1, 2009.
    (2) The owner or operator of an affected unit shall prepare and 
maintain a monitoring plan. Except as provided in paragraphs (f) or (h) 
of this section (as applicable), a monitoring plan shall contain 
sufficient information on the continuous emission or opacity monitoring 
systems, excepted methodology under Sec. 75.19, or excepted monitoring 
systems under appendix D or E to this part and the use of data derived 
from these systems to demonstrate that all unit SO2 
emissions, NOX emissions, CO2 emissions, and 
opacity are monitored and reported.
    (b) Whenever the owner or operator makes a replacement, 
modification, or change in the certified CEMS, continuous opacity 
monitoring system, excepted methodology under Sec. 75.19, excepted 
monitoring system under appendix D or E to this part, or alternative 
monitoring system under subpart E of this part, including a change in 
the automated data acquisition and handling system or in the flue gas 
handling system, that affects information reported in the monitoring 
plan (e.g., a change to a serial number for a component of a monitoring 
system), then the owner or operator shall update the monitoring plan, by 
the applicable deadline specified in Sec. 75.62 or elsewhere in this 
part.
    (c)-(d) [Reserved]
    (e) Contents of the monitoring plan. Each monitoring plan shall 
contain the information in paragraph (e)(1) of this section in 
electronic format and the information in paragraph (e)(2) of this 
section in hardcopy format. Electronic storage of all monitoring plan 
information, including the hardcopy portions, is permissible provided 
that a paper copy of the information can be furnished upon request for 
audit purposes.
    (1) Electronic. (i) ORISPL numbers developed by the Department of 
Energy and used in the National Allowance Data Base (or equivalent 
facility ID number assigned by EPA, if the facility does not have an 
ORSPL number), for all affected units involved in the monitoring plan, 
with the following information for each unit:
    (A) Short name;
    (B) Classification of the unit as one of the following: Phase I 
(including substitution or compensating units), Phase II, new, or 
nonaffected;
    (C) Type of boiler (or boilers for a group of units using a common 
stack);
    (D) Type of fuel(s) fired by boiler, fuel type start and end dates, 
primary/secondary/emergency/startup fuel indicator, and, if more than 
one fuel, the fuel classification of the boiler;
    (E) Type(s) of emission controls for SO2, NOX, 
and particulates installed or to be installed, including specifications 
of whether such controls are pre-combustion, post-combustion, or 
integral to the combustion process; control equipment code, installation 
date, and optimization date; control equipment retirement date (if 
applicable); primary/secondary controls indicator; and

[[Page 291]]

an indicator for whether the controls are an original installation;
    (F) Maximum hourly heat input capacity;
    (G) Date of first commercial operation;
    (H) Unit retirement date (if applicable);
    (I) Maximum hourly gross load (in MW, rounded to the nearest MW, or 
steam load in 1000 lb/hr, rounded to the nearest 100 lb/hr);
    (J) Identification of all units using a common stack;
    (K) Activation date for the stack/pipe;
    (L) Retirement date of the stack/pipe (if applicable); and
    (M) Indicator of whether the stack is a bypass stack.
    (ii) For each unit and parameter required to be monitored, 
identification of monitoring methodology information, consisting of 
monitoring methodology, type of fuel associated with the methodology, 
primary/secondary methodology indicator, missing data approach for the 
methodology, methodology start date, and methodology end date (if 
applicable).
    (iii) The following information:
    (A) Program(s) for which the EDR is submitted;
    (B) Unit classification;
    (C) Reporting frequency;
    (D) Program participation date;
    (E) State regulation code (if applicable); and
    (F) State or local regulatory agency code.
    (iv) Identification and description of each monitoring system 
component (including each monitor and its identifiable components, such 
as analyzer and/or probe) in the CEMS (e.g., SO2 pollutant 
concentration monitor, flow monitor, moisture monitor; NOX 
pollutant concentration monitor, and diluent gas monitor), the 
continuous opacity monitoring system, or the excepted monitoring system 
(e.g., fuel flowmeter, data acquisition and handling system), including:
    (A) Manufacturer, model number and serial number;
    (B) Component/system identification code assigned by the utility to 
each identifiable monitoring component (such as the analyzer and/or 
probe). Each code shall use a three-digit format, unique to each 
monitoring component and unique to each monitoring system;
    (C) Designation of the component type and method of sample 
acquisition or operation, (e.g., in situ pollutant concentration monitor 
or thermal flow monitor);
    (D) Designation of the system as a primary, redundant backup, non-
redundant backup, data backup, or reference method backup system, as 
provided in Sec. 75.10(e);
    (E) First and last dates the system reported data;
    (F) Status of the monitoring component; and
    (G) Parameter monitored.
    (v) Identification and description of all major hardware and 
software components of the automated data acquisition and handling 
system, including:
    (A) Hardware components that perform emission calculations or store 
data for quarterly reporting purposes (provide the manufacturer and 
model number); and
    (B) Software components (provide the identification of the provider 
and model/version number).
    (vi) Explicit formulas for each measured emission parameter, using 
component/system identification codes for the primary system used to 
measure the parameter that links CEMS or excepted monitoring system 
observations with reported concentrations, mass emissions, or emission 
rates, according to the conversions listed in appendix D or E to this 
part. Formulas for backup monitoring systems are required only if 
different formulas for the same parameter are used for the primary and 
backup monitoring systems (e.g., if the primary system measures 
pollutant concentration on a different moisture basis from the backup 
system). The formulas must contain all constants and factors required to 
derive mass emissions or emission rates from component/system code 
observations and an indication of whether the formula is being added, 
corrected, deleted, or is unchanged. Each emissions formula is 
identified with a unique three digit code. The owner or operator of a 
low mass emissions unit for which the owner or operator is using the 
optional

[[Page 292]]

low mass emissions excepted methodology in Sec. 75.19(c) is not 
required to report such formulas.
    (vii) Inside cross-sectional area (ft\2\) at flue exit (for all 
units) and at flow monitoring location (for units with flow monitors, 
only).
    (viii) Stack exit height (ft) above ground level and ground level 
elevation above sea level.
    (ix) Monitoring location identification, facility identification 
code as assigned by the Administrator for use under the Acid Rain 
Program or this part, and the following information, as reported to the 
Energy Information Administration (EIA): facility identification number, 
flue identification number, boiler identification number, ARP/Subpart H 
facility ID number or ORISPL number (as applicable), reporting year, and 
767 reporting indicator (or equivalent).
    (x) For each parameter monitored: Scale, maximum potential 
concentration (and method of calculation), maximum expected 
concentration (if applicable) (and method of calculation), maximum 
potential flow rate (and method of calculation), maximum potential 
NOX emission rate, span value, full-scale range, daily 
calibration units of measure, span effective date/hour, span 
inactivation date/hour, indication of whether dual spans are required, 
default high range value, flow rate span, and flow rate span value and 
full scale value (in scfh) for each unit or stack using SO2, 
NOX, CO2, O2, or flow component 
monitors.
    (xi) If the monitoring system or excepted methodology provides for 
the use of a constant, assumed, or default value for a parameter under 
specific circumstances, then include the following information for each 
such value for each parameter:
    (A) Identification of the parameter;
    (B) Default, maximum, minimum, or constant value, and units of 
measure for the value;
    (C) Purpose of the value;
    (D) Indicator of use during controlled/uncontrolled hours;
    (E) Type of fuel;
    (F) Source of the value;
    (G) Value effective date and hour;
    (H) Date and hour value is no longer effective (if applicable); and
    (I) For units using the excepted methodology under Sec. 75.19, the 
applicable SO2 emission factor.
    (xii) Uless otherwise specified in section 6.5.2.1 of appendix A to 
this part, for each unit of common stack on which hardware CEMS are 
installed:
    (A) The upper and lower boundaries of the range of operation (as 
defined in section 6.5.2.1 of appendix A to this part), expressed in 
megawatts, or thousands of lb/hr of steam, or ft/sec (as applicable);
    (B) The load or operating level(s) designated as normal in section 
6.5.2.1 of appendix A to this part, expressed in megawatts, or thousands 
of lb/hr of steam, or ft/sec (as applicable);
    (C) The two load or operating levels (i.e., low, mid, or high) 
identified in section 6.5.2.1 of appendix A to this part as the most 
frequently used;
    (D) The date of the data analysis used to determine the normal load 
(or operating) level(s) and the two most frequently-used load (or 
operating) levels; and
    (E) Activation and deactivation dates, when the normal load or 
operating level(s) or two most frequently-used load or operating levels 
change and are updated.
    (xiii) For each unit for which the optional fuel flow-to-load test 
in section 2.1.7 of appendix D to this part is used:
    (A) The upper and lower boundaries of the range of operation (as 
defined in section 6.5.2.1 of appendix A to this part), expressed in 
megawatts or thousands of lb/hr of steam;
    (B) The load level designated as normal, pursuant to section 6.5.2.1 
of appendix A to this part, expressed in megawatts or thousands of lb/hr 
of steam; and
    (C) The date of the load analysis used to determine the normal load 
level.
    (xiv) For each unit with a flow monitor installed on a rectangular 
stack or duct, if a wall effects adjustment factor (WAF) is determined 
and applied to the hourly flow rate data:
    (A) Stack or duct width at the test location, ft;
    (B) Stack or duct depth at the test location, ft;
    (C) Wall effects adjustment factor (WAF), to the nearest 0.0001;
    (D) Method of determining the WAF;

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    (E) WAF Effective date and hour;
    (F) WAF no longer effective date and hour (if applicable);
    (G) WAF determination date;
    (H) Number of WAF test runs;
    (I) Number of Method 1 traverse points in the WAF test;
    (J) Number of test ports in the WAF test; and
    (K) Number of Method 1 traverse points in the reference flow RATA.
    (2) Hardcopy. (i) Information, including (as applicable): 
identification of the test strategy; protocol for the relative accuracy 
test audit; other relevant test information; calibration gas levels 
(percent of span) for the calibration error test and linearity check; 
calculations for determining maximum potential concentration, maximum 
expected concentration (if applicable), maximum potential flow rate, 
maximum potential NOX emission rate, and span; and 
apportionment strategies under Sec. Sec. 75.10 through 75.18.
    (ii) Description of site locations for each monitoring component in 
the continuous emission or opacity monitoring systems, including 
schematic diagrams and engineering drawings specified in paragraphs 
(e)(2)(iv) and (e)(2)(v) of this section and any other documentation 
that demonstrates each monitor location meets the appropriate siting 
criteria.
    (iii) A data flow diagram denoting the complete information handling 
path from output signals of CEMS components to final reports.
    (iv) For units monitored by a continuous emission or opacity 
monitoring system, a schematic diagram identifying entire gas handling 
system from boiler to stack for all affected units, using identification 
numbers for units, monitor components, and stacks corresponding to the 
identification numbers provided in paragraphs (e)(1)(i), (e)(1)(iv), 
(e)(1)(vi), and (e)(1)(ix) of this section. The schematic diagram must 
depict stack height and the height of any monitor locations. 
Comprehensive and/or separate schematic diagrams shall be used to 
describe groups of units using a common stack.
    (v) For units monitored by a continuous emission or opacity 
monitoring system, stack and duct engineering diagrams showing the 
dimensions and location of fans, turning vanes, air preheaters, monitor 
components, probes, reference method sampling ports, and other equipment 
that affects the monitoring system location, performance, or quality 
control checks.
    (f) Contents of monitoring plan for specific situations. The 
following additional information shall be included in the monitoring 
plan for the specific situations described:
    (1) For each gas-fired unit or oil-fired unit for which the owner or 
operator uses the optional protocol in appendix D to this part for 
estimating heat input and/or SO2 mass emissions, or for each 
gas-fired or oil-fired peaking unit for which the owner/operator uses 
the optional protocol in appendix E to this part for estimating 
NOX emission rate (using a fuel flowmeter), the designated 
representative shall include the following additional information in the 
monitoring plan:
    (i) Electronic. (A) Parameter monitored;
    (B) Type of fuel measured, maximum fuel flow rate, units of measure, 
and basis of maximum fuel flow rate (i.e., upper range value or unit 
maximum) for each fuel flowmeter;
    (C) Test method used to check the accuracy of each fuel flowmeter;
    (D) Submission status of the data;
    (E) Monitoring system identification code; and
    (F) The method used to demonstrate that the unit qualifies for 
monthly GCV sampling or for daily or annual fuel sampling for sulfur 
content, as applicable.
    (ii) Hardcopy. (A) A schematic diagram identifying the relationship 
between the unit, all fuel supply lines, the fuel flowmeter(s), and the 
stack(s). The schematic diagram must depict the installation location of 
each fuel flowmeter and the fuel sampling location(s). Comprehensive 
and/or separate schematic diagrams shall be used to describe groups of 
units using a common pipe;
    (B) For units using the optional default SO2 emission 
rate for ``pipeline natural gas'' or ``natural gas'' in appendix D to 
this part, the information on the sulfur content of the gaseous fuel 
used to demonstrate compliance

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with either section 2.3.1.4 or 2.3.2.4 of appendix D to this part;
    (C) For units using the 720 hour test under 2.3.6 of Appendix D of 
this part to determine the required sulfur sampling requirements, report 
the procedures and results of the test; and
    (D) For units using the 720 hour test under 2.3.5 of Appendix D of 
this part to determine the appropriate fuel GCV sampling frequency, 
report the procedures used and the results of the test;
    (2) For each gas-fired peaking unit and oil-fired peaking unit for 
which the owner or operator uses the optional procedures in appendix E 
to this part for estimating NOX emission rate, the designated 
representative shall include in the monitoring plan:
    (i) Electronic. Unit operating and capacity factor information 
demonstrating that the unit qualifies as a peaking unit or gas-fired 
unit, as defined in Sec. 72.2 of this chapter, and NOX 
correlation test information, including:
    (A) Test date;
    (B) Test number;
    (C) Operating level;
    (D) Segment ID of the NOX correlation curve;
    (E) NOX monitoring system identification;
    (F) Low and high heat input rate values and corresponding 
NOX emission rates;
    (G) Type of fuel; and
    (H) To document the unit qualifies as a peaking unit, current 
calendar year or ozone season, capacity factor data as specified in the 
definition of peaking unit in Sec. 72.2 of this chapter, and an 
indication of whether the data are actual or projected data.
    (ii) Hardcopy. (A) A protocol containing methods used to perform the 
baseline or periodic NOX emission test; and
    (B) Unit operating parameters related to NOX formation by 
the unit.
    (3) For each gas-fired unit and diesel-fired unit or unit with a wet 
flue gas pollution control system for which the designated 
representative claims an opacity monitoring exemption under Sec. 75.14, 
the designated representative shall include in the hardcopy monitoring 
plan the information specified under Sec. 75.14(b), (c), or (d), 
demonstrating that the unit qualifies for the exemption.
    (4) For each monitoring system recertification, maintenance, or 
other event, the designated representative shall include the following 
additional information in electronic format in the monitoring plan:
    (i) Component/system identification code;
    (ii) Event code or code for required test;
    (iii) Event begin date and hour;
    (iv) Conditionally valid data period begin date and hour (if 
applicable);
    (v) Date and hour that last test is successfully completed; and
    (vi) Indicator of whether conditionally valid data were reported at 
the end of the quarter.
    (5) For each unit using the low mass emission excepted methodology 
under Sec. 75.19 the designated representative shall include the 
following additional information in the monitoring plan that accompanies 
the initial certification application:
    (i) Electronic. For each low mass emissions unit, report the results 
of the analysis performed to qualify as a low mass emissions unit under 
Sec. 75.19(c). This report will include either the previous three years 
actual or projected emissions. The following items should be included:
    (A) Current calendar year of application;
    (B) Type of qualification;
    (C) Years one, two, and three;
    (D) Annual or ozone season measured, estimated or projected 
NOX mass emissions for years one, two, and three;
    (E) Annual measured, estimated or projected SO2 mass 
emissions for years one, two, and three; and
    (F) Annual or ozone season operating hours for years one, two, and 
three.
    (ii) Hardcopy. (A) A schematic diagram identifying the relationship 
between the unit, all fuel supply lines and tanks, any fuel 
flowmeter(s), and the stack(s). Comprehensive and/or separate schematic 
diagrams shall be used to describe groups of units using a common pipe;
    (B) For units which use the long term fuel flow methodology under 
Sec. 75.19(c)(3), the designated representative must provide a diagram 
of the fuel

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flow to each affected unit or group of units and describe in detail the 
procedures used to determine the long term fuel flow for a unit or group 
of units for each fuel combusted by the unit or group of units;
    (C) A statement that the unit burns only gaseous fuel(s) and/or fuel 
oil and a list of the fuels that are burned or a statement that the unit 
is projected to burn only gaseous fuel(s) and/or fuel oil and a list of 
the fuels that are projected to be burned;
    (D) A statement that the unit meets the applicability requirements 
in Sec. Sec. 75.19(a) and (b); and
    (E) Any unit historical actual, estimated and projected emissions 
data and calculated emissions data demonstrating that the affected unit 
qualifies as a low mass emissions unit under Sec. Sec. 75.19(a) and 
75.19(b).
    (6) For each gas-fired unit the designated representative shall 
include in the monitoring plan, in electronic format, the following: 
current calendar year, fuel usage data as specified in the definition of 
gas-fired in Sec. 72.2 of this part, and an indication of whether the 
data are actual or projected data.
    (g) Contents of the monitoring plan. The requirements of paragraphs 
(g) and (h) of this section shall be met on and after January 1, 2009. 
Notwithstanding this requirement, the provisions of paragraphs (g) and 
(h) of this section may be implemented prior to January 1, 2009, as 
follows. In 2008, the owner or operator may opt to record and report the 
monitoring plan information in paragraphs (g) and (h) of this section, 
in lieu of recording and reporting the information in paragraphs (e) and 
(f) of this section. Each monitoring plan shall contain the information 
in paragraph (g)(1) of this section in electronic format and the 
information in paragraph (g)(2) of this section in hardcopy format. 
Electronic storage of all monitoring plan information, including the 
hardcopy portions, is permissible provided that a paper copy of the 
information can be furnished upon request for audit purposes.
    (1) Electronic. (i) The facility ORISPL number developed by the 
Department of Energy and used in the National Allowance Data Base (or 
equivalent facility ID number assigned by EPA, if the facility does not 
have an ORISPL number). Also provide the following information for each 
unit and (as applicable) for each common stack and/or pipe, and each 
multiple stack and/or pipe involved in the monitoring plan:
    (A) A representation of the exhaust configuration for the units in 
the monitoring plan. On and after April 27, 2011, provide the activation 
date and deactivation date (if applicable) of the configuration. Provide 
the ID number of each unit and assign a unique ID number to each common 
stack, common pipe multiple stack and/or multiple pipe associated with 
the unit(s) represented in the monitoring plan. For common and multiple 
stacks and/or pipes, provide the activation date and deactivation date 
(if applicable) of each stack and/or pipe;
    (B) Identification of the monitoring system location(s) (e.g., at 
the unit-level, on the common stack, at each multiple stack, etc.). 
Provide an indicator (``flag'') if the monitoring location is at a 
bypass stack or in the ductwork (breeching);
    (C) The stack exit height (ft) above ground level and ground level 
elevation above sea level, and the inside cross-sectional area (ft\2\) 
at the flue exit and at the flow monitoring location (for units with 
flow monitors, only). Also use appropriate codes to indicate the 
material(s) of construction and the shape(s) of the stack or duct cross-
section(s) at the flue exit and (if applicable) at the flow monitor 
location. On and after April 27, 2011, provide the activation date and 
deactivation date (if applicable) for the information in this paragraph 
(g)(1)(i)(C);
    (D) The type(s) of fuel(s) fired by each unit. Indicate the start 
and (if applicable) end date of combustion for each type of fuel, and 
whether the fuel is the primary, secondary, emergency, or startup fuel;
    (E) The type(s) of emission controls that are used to reduce 
SO2, NOX, and particulate emissions from each 
unit. Also provide the installation date, optimization date, and 
retirement date (if applicable) of the emission controls, and indicate 
whether the controls are an original installation;
    (F) Maximum hourly heat input capacity of each unit. On and after 
April

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27, 2011, provide the activation date and deactivation date (if 
applicable) for this parameter; and
    (G) A non-load based unit indicator (if applicable) for units that 
do not produce electrical or thermal output.
    (ii) For each monitored parameter (e.g., SO2, 
NOX, flow, etc.) at each monitoring location, specify the 
monitoring methodology and the missing data approach for the parameter. 
If the unmonitored bypass stack approach is used for a particular 
parameter, indicate this by means of an appropriate code. Provide the 
activation date/hour, and deactivation date/hour (if applicable) for 
each monitoring methodology and each missing data approach.
    (iii) For each required continuous emission monitoring system, each 
fuel flowmeter system, and each continuous opacity monitoring system, 
identify and describe the major monitoring components in the monitoring 
system (e.g., gas analyzer, flow monitor, opacity monitor, moisture 
sensor, fuel flowmeter, DAHS software, etc.). Other important components 
in the system (e.g., sample probe, PLC, data logger, etc.) may also be 
represented in the monitoring plan, if necessary. Provide the following 
specific information about each component and monitoring system:
    (A) For each required monitoring system:
    (1) Assign a unique, 3-character alphanumeric identification code to 
the system;
    (2) Indicate the parameter monitored by the system;
    (3) Designate the system as a primary, redundant backup, non-
redundant backup, data backup, or reference method backup system, as 
provided in Sec. 75.10(e); and
    (4) Indicate the system activation date/hour and deactivation date/
hour (as applicable).
    (B) For each component of each monitoring system represented in the 
monitoring plan:
    (1) Assign a unique, 3-character alphanumeric identification code to 
the component;
    (2) Indicate the manufacturer, model and serial number;
    (3) Designate the component type;
    (4) For dual-span applications, indicate whether the analyzer 
component ID represents a high measurement scale, a low scale, or a dual 
range;
    (5) For gas analyzers, indicate the moisture basis of measurement;
    (6) Indicate the method of sample acquisition or operation, (e.g., 
extractive pollutant concentration monitor or thermal flow monitor); and
    (7) Indicate the component activation date/hour and deactivation 
date/hour (as applicable).
    (iv) Explicit formulas, using the component and system 
identification codes for the primary monitoring system, and containing 
all constants and factors required to derive the required mass 
emissions, emission rates, heat input rates, etc. from the hourly data 
recorded by the monitoring systems. Formulas using the system and 
component ID codes for backup monitoring systems are required only if 
different formulas for the same parameter are used for the primary and 
backup monitoring systems (e.g., if the primary system measures 
pollutant concentration on a different moisture basis from the backup 
system). Provide the equation number or other appropriate code for each 
emissions formula (e.g., use code F-1 if Equation F-1 in appendix F to 
this part is used to calculate SO2 mass emissions). Also 
identify each emissions formula with a unique three character 
alphanumeric code. The formula effective start date/hour and 
inactivation date/hour (as applicable) shall be included for each 
formula. The owner or operator of a unit for which the optional low mass 
emissions excepted methodology in Sec. 75.19 is being used is not 
required to report such formulas.
    (v) For each parameter monitored with CEMS, provide the following 
information:
    (A) Measurement scale (high or low);
    (B) Maximum potential value (and method of calculation). If 
NOX emission rate in lb/mmBtu is monitored, calculate and 
provide the maximum potential NOX emission rate in addition 
to the maximum potential NOX concentration;
    (C) Maximum expected value (if applicable) and method of 
calculation;
    (D) Span value(s) and full-scale measurement range(s);

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    (E) Daily calibration units of measure;
    (F) Effective date/hour, and (if applicable) inactivation date/hour 
of each span value. On and after April 27, 2011, provide the activation 
date and deactivation date (if applicable) for the measurement scale and 
dual span information in paragraphs (g)(1)(v)(A), (g)(1)(v)(G), and 
(g)(1)(v)(H) of this section;
    (G) An indication of whether dual spans are required. If two span 
values are required, then, on and after April 27, 2011, indicate whether 
an autoranging analyzer is used to represent the two measurement scales; 
and
    (H) The default high range value (if applicable) and the maximum 
allowable low-range value for this option.
    (vi) If the monitoring system or excepted methodology provides for 
the use of a constant, assumed, or default value for a parameter under 
specific circumstances, then include the following information for each 
such value for each parameter:
    (A) Identification of the parameter;
    (B) Default, maximum, minimum, or constant value, and units of 
measure for the value;
    (C) Purpose of the value;
    (D) Indicator of use, i.e., during controlled hours, uncontrolled 
hours, or all operating hours;
    (E) Type of fuel;
    (F) Source of the value;
    (G) Value effective date and hour;
    (H) Date and hour that the value is no longer effective (if 
applicable);
    (I) For units using the excepted methodology under Sec. 75.19, the 
applicable SO2 emission factor; and
    (J) On and after April 27, 2011, group identification code.
    (vii) Unless otherwise specified in section 6.5.2.1 of appendix A to 
this part, for each unit or common stack on which hardware CEMS are 
installed:
    (A) Maximum hourly gross load (in MW, rounded to the nearest MW, or 
steam load in 1000 lb/hr (i.e., klb/hr), rounded to the nearest klb/hr, 
or thermal output in mmBtu/hr, rounded to the nearest mmBtu/hr), for 
units that produce electrical or thermal output;
    (B) The upper and lower boundaries of the range of operation (as 
defined in section 6.5.2.1 of appendix A to this part), expressed in 
megawatts, thousands of lb/hr of steam, mmBtu/hr of thermal output, or 
ft/sec (as applicable);
    (C) Except for peaking units, identify the most frequently and 
second most frequently used load (or operating) levels (i.e., low, mid, 
or high) in accordance with section 6.5.2.1 of appendix A to this part, 
expressed in megawatts, thousands of lb/hr of steam, mmBtu/hr of thermal 
output, or ft/sec (as applicable);
    (D) Except for peaking units, an indicator of whether the second 
most frequently used load (or operating) level is designated as normal 
in section 6.5.2.1 of appendix A to this part;
    (E) The date of the data analysis used to determine the normal load 
(or operating) level(s) and the two most frequently-used load (or 
operating) levels (as applicable); and
    (F) Activation and deactivation dates and hours, when the maximum 
hourly gross load, boundaries of the range of operation, normal load (or 
operating) level(s) or two most frequently-used load (or operating) 
levels change and are updated.
    (viii) For each unit for which CEMS are not installed:
    (A) Maximum hourly gross load (in MW, rounded to the nearest MW, or 
steam load in klb/hr, rounded to the nearest klb/hr, or steam load in 
mmBtu/hr, rounded to the nearest mmBtu/hr);
    (B) The upper and lower boundaries of the range of operation (as 
defined in section 6.5.2.1 of appendix A to this part), expressed in 
megawatts, mmBtu/hr of thermal output, or thousands of lb/hr of steam;
    (C) Except for peaking units and units using the low mass emissions 
excepted methodology under Sec. 75.19, identify the load level 
designated as normal, pursuant to section 6.5.2.1 of appendix A to this 
part, expressed in megawatts, mmBtu/hr of thermal output, or thousands 
of lb/hr of steam;
    (D) The date of the load analysis used to determine the normal load 
level (as applicable); and
    (E) Activation and deactivation dates and hours, when the maximum 
hourly gross load, boundaries of the range of

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operation, or normal load level change and are updated.
    (ix) For each unit with a flow monitor installed on a rectangular 
stack or duct, if a wall effects adjustment factor (WAF) is determined 
and applied to the hourly flow rate data:
    (A) Stack or duct width at the test location, ft;
    (B) Stack or duct depth at the test location, ft;
    (C) Wall effects adjustment factor (WAF), to the nearest 0.0001;
    (D) Method of determining the WAF;
    (E) WAF Effective date and hour;
    (F) WAF no longer effective date and hour (if applicable);
    (G) WAF determination date;
    (H) Number of WAF test runs;
    (I) Number of Method 1 traverse points in the WAF test;
    (J) Number of test ports in the WAF test; and
    (K) Number of Method 1 traverse points in the reference flow RATA.
    (2) Hardcopy. (i) Information, including (as applicable): 
Identification of the test strategy; protocol for the relative accuracy 
test audit; other relevant test information; calibration gas levels 
(percent of span) for the calibration error test and linearity check; 
calculations for determining maximum potential concentration, maximum 
expected concentration (if applicable), maximum potential flow rate, 
maximum potential NOX emission rate, and span; and 
apportionment strategies under Sec. Sec. 75.10 through 75.18.
    (ii) Description of site locations for each monitoring component in 
the continuous emission or opacity monitoring systems, including 
schematic diagrams and engineering drawings specified in paragraphs 
(e)(2)(iv) and (e)(2)(v) of this section and any other documentation 
that demonstrates each monitor location meets the appropriate siting 
criteria.
    (iii) A data flow diagram denoting the complete information handling 
path from output signals of CEMS components to final reports.
    (iv) For units monitored by a continuous emission or opacity 
monitoring system, a schematic diagram identifying entire gas handling 
system from boiler to stack for all affected units, using identification 
numbers for units, monitoring systems and components, and stacks 
corresponding to the identification numbers provided in paragraphs 
(g)(1)(i) and (g)(1)(iii) of this section. The schematic diagram must 
depict stack height and the height of any monitor locations. 
Comprehensive and/or separate schematic diagrams shall be used to 
describe groups of units using a common stack.
    (v) For units monitored by a continuous emission or opacity 
monitoring system, stack and duct engineering diagrams showing the 
dimensions and location of fans, turning vanes, air preheaters, monitor 
components, probes, reference method sampling ports, and other equipment 
that affects the monitoring system location, performance, or quality 
control checks.
    (h) Contents of monitoring plan for specific situations. The 
following additional information shall be included in the monitoring 
plan for the specific situations described:
    (1) For each gas-fired unit or oil-fired unit for which the owner or 
operator uses the optional protocol in appendix D to this part for 
estimating heat input and/or SO2 mass emissions, or for each 
gas-fired or oil-fired peaking unit for which the owner/operator uses 
the optional protocol in appendix E to this part for estimating 
NOX emission rate (using a fuel flowmeter), the designated 
representative shall include the following additional information for 
each fuel flowmeter system in the monitoring plan:
    (i) Electronic. (A) Parameter monitored;
    (B) Type of fuel measured, maximum fuel flow rate, units of measure, 
and basis of maximum fuel flow rate (i.e., upper range value or unit 
maximum) for each fuel flowmeter;
    (C) Test method used to check the accuracy of each fuel flowmeter;
    (D) Monitoring system identification code;
    (E) The method used to demonstrate that the unit qualifies for 
monthly GCV sampling or for daily or annual fuel sampling for sulfur 
content, as applicable; and
    (F) Activation date/hour and (if applicable) inactivation date/hour 
for the fuel flowmeter system;

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    (ii) Hardcopy. (A) A schematic diagram identifying the relationship 
between the unit, all fuel supply lines, the fuel flowmeter(s), and the 
stack(s). The schematic diagram must depict the installation location of 
each fuel flowmeter and the fuel sampling location(s). Comprehensive 
and/or separate schematic diagrams shall be used to describe groups of 
units using a common pipe;
    (B) For units using the optional default SO2 emission 
rate for ``pipeline natural gas'' or ``natural gas'' in appendix D to 
this part, the information on the sulfur content of the gaseous fuel 
used to demonstrate compliance with either section 2.3.1.4 or 2.3.2.4 of 
appendix D to this part;
    (C) For units using the 720 hour test under 2.3.6 of Appendix D of 
this part to determine the required sulfur sampling requirements, report 
the procedures and results of the test; and
    (D) For units using the 720 hour test under 2.3.5 of Appendix D of 
this part to determine the appropriate fuel GCV sampling frequency, 
report the procedures used and the results of the test.
    (2) For each gas-fired peaking unit and oil-fired peaking unit for 
which the owner or operator uses the optional procedures in appendix E 
to this part for estimating NOX emission rate, the designated 
representative shall include in the monitoring plan:
    (i) Electronic. Unit operating and capacity factor information 
demonstrating that the unit qualifies as a peaking unit, as defined in 
Sec. 72.2 of this chapter for the current calendar year or ozone 
season, including: capacity factor data for three calendar years (or 
ozone seasons) as specified in the definition of peaking unit in Sec. 
72.2 of this chapter; the method of qualification used; and an 
indication of whether the data are actual or projected data. On and 
after April 27, 2011, provide the activation date and deactivation date 
(if applicable) for the peaking unit qualification information in this 
paragraph (h)(2)(i).
    (ii) Hardcopy. (A) A protocol containing methods used to perform the 
baseline or periodic NOX emission test; and
    (B) Unit operating parameters related to NOX formation by 
the unit.
    (3) For each gas-fired unit and diesel-fired unit or unit with a wet 
flue gas pollution control system for which the designated 
representative claims an opacity monitoring exemption under Sec. 75.14, 
the designated representative shall include in the hardcopy monitoring 
plan the information specified under Sec. 75.14(b), (c), or (d), 
demonstrating that the unit qualifies for the exemption.
    (4) For each unit using the low mass emissions excepted methodology 
under Sec. 75.19 the designated representative shall include the 
following additional information in the monitoring plan that accompanies 
the initial certification application:
    (i) Electronic. For each low mass emissions unit, report the results 
of the analysis performed to qualify as a low mass emissions unit under 
Sec. 75.19(c). This report will include either the previous three years 
actual or projected emissions. The following items should be included:
    (A) Current calendar year of application;
    (B) Type of qualification;
    (C) Years one, two, and three;
    (D) Annual and/or ozone season measured, estimated or projected 
NOX mass emissions for years one, two, and three;
    (E) Annual measured, estimated or projected SO2 mass 
emissions (if applicable) for years one, two, and three; and
    (F) Annual or ozone season operating hours for years one, two, and 
three.
    (ii) Hardcopy. (A) A schematic diagram identifying the relationship 
between the unit, all fuel supply lines and tanks, any fuel 
flowmeter(s), and the stack(s). Comprehensive and/or separate schematic 
diagrams shall be used to describe groups of units using a common pipe;
    (B) For units which use the long term fuel flow methodology under 
Sec. 75.19(c)(3), the designated representative must provide a diagram 
of the fuel flow to each affected unit or group of units and describe in 
detail the procedures used to determine the long term fuel flow for a 
unit or group of units for each fuel combusted by the unit or group of 
units;
    (C) A statement that the unit burns only gaseous fuel(s) and/or fuel 
oil and

[[Page 300]]

a list of the fuels that are burned or a statement that the unit is 
projected to burn only gaseous fuel(s) and/or fuel oil and a list of the 
fuels that are projected to be burned;
    (D) A statement that the unit meets the applicability requirements 
in Sec. 75.19(a) and (b); and
    (E) Any unit historical actual, estimated and projected emissions 
data and calculated emissions data demonstrating that the affected unit 
qualifies as a low mass emissions unit under Sec. 75.19(a) and 
75.19(b).
    (5) For qualification as a gas-fired unit, as defined in Sec. 72.2 
of this part, the designated representative shall include in the 
monitoring plan, in electronic format, the following: current calendar 
year, fuel usage data for three calendar years (or ozone seasons) as 
specified in the definition of gas-fired in Sec. 72.2 of this chapter, 
the method of qualification used, and an indication of whether the data 
are actual or projected data. On and after April 27, 2011, provide the 
activation date and deactivation date (if applicable) for the gas-fired 
unit qualification information in this paragraph (h)(5).
    (6) For each monitoring location with a stack flow monitor that is 
exempt from performing 3-load flow RATAs (peaking units, bypass stacks, 
or by petition) the designated representative shall include in the 
monitoring plan an indicator of exemption from 3-load flow RATA using 
the appropriate exemption code.

[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26532, 26568, May 17, 
1995; 61 FR 59161, Nov. 20, 1996; 64 FR 28605, May 26, 1999; 67 FR 
40440, June 12, 2002; 70 FR 28682, May 18, 2005; 73 FR 4350, Jan. 24, 
2008; 76 FR 17312, Mar. 28, 2011]



Sec. Sec. 75.54-75.56  [Reserved]



Sec. 75.57  General recordkeeping provisions.

    The owner or operator shall meet all of the applicable recordkeeping 
requirements of this section.
    (a) Recordkeeping requirements for affected sources. The owner or 
operator of any affected source subject to the requirements of this part 
shall maintain for each affected unit a file of all measurements, data, 
reports, and other information required by this part at the source in a 
form suitable for inspection for at least three (3) years from the date 
of each record. Unless otherwise provided, throughout this subpart the 
phrase ``for each affected unit'' also applies to each group of affected 
or nonaffected units utilizing a common stack and common monitoring 
systems, pursuant to Sec. Sec. 75.16 through 75.18, or utilizing a 
common pipe header and common fuel flowmeter, pursuant to section 2.1.2 
of appendix D to this part. The file shall contain the following 
information:
    (1) The data and information required in paragraphs (b) through (h) 
of this section, beginning with the earlier of the date of provisional 
certification or the deadline in Sec. 75.4(a), (b), or (c);
    (2) The supporting data and information used to calculate values 
required in paragraphs (b) through (g) of this section, excluding the 
subhourly data points used to compute hourly averages under Sec. 
75.10(d), beginning with the earlier of the date of provisional 
certification or the deadline in Sec. 75.4(a), (b), or (c);
    (3) The data and information required in Sec. 75.58 for specific 
situations, beginning with the earlier of the date of provisional 
certification or the deadline in Sec. 75.4(a), (b), or (c);
    (4) The certification test data and information required in Sec. 
75.59 for tests required under Sec. 75.20, beginning with the date of 
the first certification test performed, the quality assurance and 
quality control data and information required in Sec. 75.59 for tests, 
and the quality assurance/quality control plan required under Sec. 
75.21 and appendix B to this part, beginning with the date of 
provisional certification;
    (5) The current monitoring plan as specified in Sec. 75.53, 
beginning with the initial submission required by Sec. 75.62;
    (6) The quality control plan as described in section 1 of appendix B 
to this part, beginning with the date of provisional certification; and
    (7) The information required by sections 6.1.2(b) and (c) of 
appendix A to this part.
    (b) Operating parameter record provisions. The owner or operator 
shall record for each hour the following information on unit operating 
time, heat input rate, and load, separately for

[[Page 301]]

each affected unit and also for each group of units utilizing a common 
stack and a common monitoring system or utilizing a common pipe header 
and common fuel flowmeter:
    (1) Date and hour;
    (2) Unit operating time (rounded up to the nearest fraction of an 
hour (in equal increments that can range from one hundredth to one 
quarter of an hour, at the option of the owner or operator));
    (3) Hourly gross unit load (rounded to nearest MWge) (or steam load 
in 1000 lb/hr at stated temperature and pressure, rounded to the nearest 
1000 lb/hr, or mmBtu/hr of thermal output, rounded to the nearest mmBtu/
hr, if elected in the monitoring plan);
    (4) Operating load range corresponding to hourly gross load of 1 to 
10, except for units using a common stack or common pipe header, which 
may use up to 20 load ranges for stack or fuel flow, as specified in the 
monitoring plan;
    (5) Hourly heat input rate (mmBtu/hr, rounded to the nearest tenth);
    (6) Identification code for formula used for heat input, as provided 
in Sec. 75.53; and
    (7) For CEMS units only, F-factor for heat input calculation and 
indication of whether the diluent cap was used for heat input 
calculations for the hour.
    (c) SO2 emission record provisions. The owner or operator shall 
record for each hour the information required by this paragraph for each 
affected unit or group of units using a common stack and common 
monitoring systems, except as provided under Sec. 75.11(e) or for a 
gas-fired or oil-fired unit for which the owner or operator is using the 
optional protocol in appendix D to this part or for a low mass emissions 
unit for which the owner or operator is using the optional low mass 
emissions methodology in Sec. 75.19(c) for estimating SO2 
mass emissions:
    (1) For SO2 concentration during unit operation, as 
measured and reported from each certified primary monitor, certified 
back-up monitor, or other approved method of emissions determination:
    (i) Component-system identification code, as provided in Sec. 
75.53;
    (ii) Date and hour;
    (iii) Hourly average SO2 concentration (ppm, rounded to 
the nearest tenth);
    (iv) Hourly average SO2 concentration (ppm, rounded to 
the nearest tenth), adjusted for bias if bias adjustment factor is 
required, as provided in Sec. 75.24(d);
    (v) Percent monitor data availability (recorded to the nearest tenth 
of a percent), calculated pursuant to Sec. 75.32; and
    (vi) Method of determination for hourly average SO2 
concentration using Codes 1-55 in Table 4a of this section.
    (2) For flow rate during unit operation, as measured and reported 
from each certified primary monitor, certified back-up monitor, or other 
approved method of emissions determination:
    (i) Component-system identification code, as provided in Sec. 
75.53;
    (ii) Date and hour;
    (iii) Hourly average volumetric flow rate (in scfh, rounded to the 
nearest thousand);
    (iv) Hourly average volumetric flow rate (in scfh, rounded to the 
nearest thousand), adjusted for bias if bias adjustment factor required, 
as provided in Sec. 75.24(d);
    (v) Percent monitor data availability (recorded to the nearest tenth 
of a percent) for the flow monitor, calculated pursuant to Sec. 75.32; 
and
    (vi) Method of determination for hourly average flow rate using 
Codes 1-55 in Table 4a of this section.
    (3) For flue gas moisture content during unit operation (where 
SO2 concentration is measured on a dry basis), as measured 
and reported from each certified primary monitor, certified back-up 
monitor, or other approved method of emissions determination:
    (i) Component-system identification code, as provided in Sec. 
75.53;
    (ii) Date and hour;
    (iii) Hourly average moisture content of flue gas (percent, rounded 
to the nearest tenth). If the continuous moisture monitoring system 
consists of wet- and dry-basis oxygen analyzers, also record both the 
wet- and dry-basis oxygen hourly averages (in percent O2, 
rounded to the nearest tenth);

[[Page 302]]

    (iv) Percent monitor data availability (recorded to the nearest 
tenth of a percent) for the moisture monitoring system, calculated 
pursuant to Sec. 75.32; and
    (v) Method of determination for hourly average moisture percentage, 
using Codes 1-55 in Table 4a of this section.
    (4) For SO2 mass emission rate during unit operation, as 
measured and reported from the certified primary monitoring system(s), 
certified redundant or non-redundant back-up monitoring system(s), or 
other approved method(s) of emissions determination:
    (i) Date and hour;
    (ii) Hourly SO2 mass emission rate (lb/hr, rounded to the 
nearest tenth);
    (iii) Hourly SO2 mass emission rate (lb/hr, rounded to 
the nearest tenth), adjusted for bias if bias adjustment factor 
required, as provided in Sec. 75.24(d); and
    (iv) Identification code for emissions formula used to derive hourly 
SO2 mass emission rate from SO2 concentration and 
flow and (if applicable) moisture data in paragraphs (c)(1), (c)(2), and 
(c)(3) of this section, as provided in Sec. 75.53.

     Table 4a--Codes for Method of Emissions and Flow Determination
------------------------------------------------------------------------
                                  Hourly emissions/flow measurement or
             Code                          estimation method
------------------------------------------------------------------------
1............................  Certified primary emission/flow
                                monitoring system.
2............................  Certified backup emission/flow monitoring
                                system.
3............................  Approved alternative monitoring system.
4............................  Reference method:
                               SO2: Method 6C.
                               Flow: Method 2 or its allowable
                                alternatives under appendix A to part 60
                                of this chapter.
                               NOX: Method 7E.
                               CO2 or O2: Method 3A.
5............................  For units with add-on SO2 and/or NOX
                                emission controls: SO2 concentration or
                                NOX emission rate estimate from Agency
                                preapproved parametric monitoring
                                method.
6............................  Average of the hourly SO2 concentrations,
                                CO2 concentrations, O2 concentrations,
                                NOX concentrations, flow rates, moisture
                                percentages or NOX emission rates for
                                the hour before and the hour following a
                                missing data period.
7............................  Initial missing data procedures used.
                                Either: (a) the average of the hourly
                                SO2 concentration, CO2 concentration, O2
                                concentration, or moisture percentage
                                for the hour before and the hour
                                following a missing data period; or (b)
                                the arithmetic average of all NOX
                                concentration, NOX emission rate, or
                                flow rate values at the corresponding
                                load range (or a higher load range), or
                                at the corresponding operational bin
                                (non-load-based units, only); or (c) the
                                arithmetic average of all previous NOX
                                concentration, NOX emission rate, or
                                flow rate values (non-load-based units,
                                only).
8............................  90th percentile hourly SO2 concentration,
                                CO2 concentration, NOX concentration,
                                flow rate, moisture percentage, or NOX
                                emission rate or 10th percentile hourly
                                O2 concentration or moisture percentage
                                in the applicable lookback period
                                (moisture missing data algorithm depends
                                on which equations are used for
                                emissions and heat input).
9............................  95th percentile hourly SO2 concentration,
                                CO2 concentration, NOX concentration,
                                flow rate, moisture percentage, or NOX
                                emission rate or 5th percentile hourly
                                O2 concentration or moisture percentage
                                in the applicable lookback period
                                (moisture missing data algorithm depends
                                on which equations are used for
                                emissions and heat input).
10...........................  Maximum hourly SO2 concentration, CO2
                                concentration, NOX concentration, flow
                                rate, moisture percentage, or NOX
                                emission rate or minimum hourly O2
                                concentration or moisture percentage in
                                the applicable lookback period (moisture
                                missing data algorithm depends on which
                                equations are used for emissions and
                                heat input).
11...........................  Average of hourly flow rates, NOX
                                concentrations or NOX emission rates in
                                corresponding load range, for the
                                applicable lookback period. For non-load-
                                based units, report either the average
                                flow rate, NOX concentration or NOX
                                emission rate in the applicable lookback
                                period, or the average flow rate or NOX
                                value at the corresponding operational
                                bin (if operational bins are used).
12...........................  Maximum potential concentration of SO2,
                                maximum potential concentration of CO2,
                                maximum potential concentration of NOX
                                maximum potential flow rate, maximum
                                potential NOX emission rate, maximum
                                potential moisture percentage, minimum
                                potential O2 concentration or minimum
                                potential moisture percentage, as
                                determined using Sec. 72.2 of this
                                chapter and section 2.1 of appendix A to
                                this part (moisture missing data
                                algorithm depends on which equations are
                                used for emissions and heat input).
13...........................  Maximum expected concentration of SO2,
                                maximum expected concentration of NOX,,
                                or maximum controlled NOX emission rate.
                                (See Sec. 75.34(a)(5)).
14...........................  Diluent cap value (if the cap is
                                replacing a CO2 measurement, use 5.0
                                percent for boilers and 1.0 percent for
                                turbines; if it is replacing an O2
                                measurement, use 14.0 percent for
                                boilers and 19.0 percent for turbines).
15...........................  1.25 times the maximum hourly controlled
                                SO2 concentration, NOX concentration at
                                the corresponding load or operational
                                bin, or NOX emission rate at the
                                corresponding load or operational bin,
                                in the applicable lookback period (See
                                Sec. 75.34(a)(5)).
16...........................  SO2 concentration value of 2.0 ppm during
                                hours when only ``very low sulfur
                                fuel``, as defined in Sec. 72.2 of
                                this chapter, is combusted.
17...........................  Like-kind replacement non-redundant
                                backup analyzer.
19...........................  200 percent of the MPC; default high
                                range value.
20...........................  200 percent of the full-scale range
                                setting (full-scale exceedance of high
                                range).

[[Page 303]]

 
21...........................  Negative hourly CO2 concentration, SO2
                                concentration, NOX concentration,
                                percent moisture, or NOX emission rate
                                replaced with zero.
22...........................  Hourly average SO2 or NOX concentration,
                                measured by a certified monitor at the
                                control device inlet (units with add-on
                                emission controls only).
23...........................  Maximum potential SO2 concentration, NOX
                                concentration, CO2 concentration, or NOX
                                emission rate, or minimum potential O2
                                concentration or moisture percentage,
                                for an hour in which flue gases are
                                discharged through an unmonitored bypass
                                stack.
24...........................  Maximum expected NOX concentration, or
                                maximum controlled NOX emission rate for
                                an hour in which flue gases are
                                discharged downstream of the NOX
                                emission controls through an unmonitored
                                bypass stack, and the add-on NOX
                                emission controls are confirmed to be
                                operating properly.
25...........................  Maximum potential NOX emission rate
                                (MER). (Use only when a NOX
                                concentration full-scale exceedance
                                occurs and the diluent monitor is
                                unavailable.)
26...........................  1.0 mmBtu/hr substituted for Heat Input
                                Rate for an operating hour in which the
                                calculated Heat Input Rate is zero or
                                negative.
40...........................  Fuel specific default value (or prorated
                                default value) used for the hour.
53...........................  Other quality-assured data approved
                                through petition. These are treated as
                                available hours for percent monitor
                                availability calculations and are
                                included in missing data lookback.
54...........................  Other quality assured methodologies
                                approved through petition. These hours
                                are included in missing data lookback
                                and are treated as unavailable hours for
                                percent monitor availability
                                calculations.
55...........................  Other substitute data approved through
                                petition. These hours are not included
                                in missing data lookback and are treated
                                as unavailable hours for percent monitor
                                availability calculations.
------------------------------------------------------------------------

    (d) NOX emission record provisions. The owner or operator shall 
record the applicable information required by this paragraph for each 
affected unit for each hour or partial hour during which the unit 
operates, except for a gas-fired peaking unit or oil-fired peaking unit 
for which the owner or operator is using the optional protocol in 
appendix E to this part or a low mass emissions unit for which the owner 
or operator is using the optional low mass emissions excepted 
methodology in Sec. 75.19(c) for estimating NOX emission 
rate. For each NOX emission rate (in lb/mmBtu) measured by a 
NOX-diluent monitoring system, or, if applicable, for each 
NOX concentration (in ppm) measured by a NOX 
concentration monitoring system used to calculate NOX mass 
emissions under Sec. 75.71(a)(2), record the following data as measured 
and reported from the certified primary monitor, certified back-up 
monitor, or other approved method of emissions determination:
    (1) Component-system identification code, as provided in Sec. 75.53 
(including identification code for the moisture monitoring system, if 
applicable);
    (2) Date and hour;
    (3) Hourly average NOX concentration (ppm, rounded to the 
nearest tenth) and hourly average NOX concentration (ppm, 
rounded to the nearest tenth) adjusted for bias if bias adjustment 
factor required, as provided in Sec. 75.24(d);
    (4) Hourly average diluent gas concentration (for NOX-
diluent monitoring systems, only, in units of percent O2 or 
percent CO2, rounded to the nearest tenth);
    (5) If applicable, the hourly average moisture content of the stack 
gas (percent H2O, rounded to the nearest tenth). If the 
continuous moisture monitoring system consists of wet- and dry-basis 
oxygen analyzers, also record both the hourly wet- and dry-basis oxygen 
readings (in percent O2, rounded to the nearest tenth);
    (6) Hourly average NOX emission rate (for NOX-
diluent monitoring systems only, in units of lb/mmBtu, rounded to the 
nearest thousandth);
    (7) Hourly average NOX emission rate (for NOX-
diluent monitoring systems only, in units of lb/mmBtu, rounded to the 
nearest thousandth), adjusted for bias if bias adjustment factor is 
required, as provided in Sec. 75.24(d). The requirement to report 
hourly NOX emission rates to the nearest thousandth shall not 
affect NOX compliance determinations under part 76 of this 
chapter; compliance with each applicable emission limit under part 76 
shall be determined to the nearest hundredth pound per million Btu;
    (8) Percent monitoring system data availability (recorded to the 
nearest tenth of a percent), for the NOX-diluent

[[Page 304]]

or NOX concentration monitoring system, and, if applicable, 
for the moisture monitoring system, calculated pursuant to Sec. 75.32;
    (9) Method of determination for hourly average NOX 
emission rate or NOX concentration and (if applicable) for 
the hourly average moisture percentage, using Codes 1-55 in Table 4a of 
this section; and
    (10) Identification codes for emissions formulas used to derive 
hourly average NOX emission rate and total NOX 
mass emissions, as provided in Sec. 75.53, and (if applicable) the F-
factor used to convert NOX concentrations into emission 
rates.
    (e) CO2 emission record provisions. Except for a low mass emissions 
unit for which the owner or operator is using the optional low mass 
emissions excepted methodology in Sec. 75.19(c) for estimating 
CO2 mass emissions, the owner or operator shall record or 
calculate CO2 emissions for each affected unit using one of 
the following methods specified in this section:
    (1) If the owner or operator chooses to use a CO2 CEMS 
(including an O2 monitor and flow monitor, as specified in 
appendix F to this part), then the owner or operator shall record for 
each hour or partial hour during which the unit operates the following 
information for CO2 mass emissions, as measured and reported 
from the certified primary monitor, certified back-up monitor, or other 
approved method of emissions determination:
    (i) Component-system identification code, as provided in Sec. 75.53 
(including identification code for the moisture monitoring system, if 
applicable);
    (ii) Date and hour;
    (iii) Hourly average CO2 concentration (in percent, 
rounded to the nearest tenth);
    (iv) Hourly average volumetric flow rate (scfh, rounded to the 
nearest thousand scfh);
    (v) Hourly average moisture content of flue gas (percent, rounded to 
the nearest tenth), where CO2 concentration is measured on a 
dry basis. If the continuous moisture monitoring system consists of wet- 
and dry-basis oxygen analyzers, also record both the hourly wet- and 
dry-basis oxygen readings (in percent O2, rounded to the 
nearest tenth);
    (vi) Hourly average CO2 mass emission rate (tons/hr, 
rounded to the nearest tenth);
    (vii) Percent monitor data availability for both the CO2 
monitoring system and, if applicable, the moisture monitoring system 
(recorded to the nearest tenth of a percent), calculated pursuant to 
Sec. 75.32;
    (viii) Method of determination for hourly average CO2 
mass emission rate and hourly average CO2 concentration, and, 
if applicable, for the hourly average moisture percentage, using Codes 
1-55 in Table 4a of this section;
    (ix) Identification code for emissions formula used to derive hourly 
average CO2 mass emission rate, as provided in Sec. 75.53; 
and
    (x) Indication of whether the diluent cap was used for 
CO2 calculation for the hour.
    (2) As an alternative to paragraph (e)(1) of this section, the owner 
or operator may use the procedures in Sec. 75.13 and in appendix G to 
this part, and shall record daily the following information for 
CO2 mass emissions:
    (i) Date;
    (ii) Daily combustion-formed CO2 mass emissions (tons/
day, rounded to the nearest tenth);
    (iii) For coal-fired units, flag indicating whether optional 
procedure to adjust combustion-formed CO2 mass emissions for 
carbon retained in flyash has been used and, if so, the adjustment;
    (iv) For a unit with a wet flue gas desulfurization system or other 
controls generating CO2, daily sorbent-related CO2 
mass emissions (tons/day, rounded to the nearest tenth); and
    (v) For a unit with a wet flue gas desulfurization system or other 
controls generating CO2, total daily CO2 mass 
emissions (tons/day, rounded to the nearest tenth) as the sum of 
combustion-formed emissions and sorbent-related emissions.
    (f) Opacity records. The owner or operator shall record opacity data 
as specified by the State or local air pollution control agency. If the 
State or local air pollution control agency does not specify 
recordkeeping requirements for opacity, then record the information

[[Page 305]]

required by paragraphs (f) (1) through (5) of this section for each 
affected unit, except as provided in Sec. Sec. 75.14(b), (c), and (d). 
The owner or operator shall also keep records of all incidents of 
opacity monitor downtime during unit operation, including reason(s) for 
the monitor outage(s) and any corrective action(s) taken for opacity, as 
measured and reported by the continuous opacity monitoring system:
    (1) Component/system identification code;
    (2) Date, hour, and minute;
    (3) Average opacity of emissions for each six minute averaging 
period (in percent opacity);
    (4) If the average opacity of emissions exceeds the applicable 
standard, then a code indicating such an exceedance has occurred; and
    (5) Percent monitor data availability (recorded to the nearest tenth 
of a percent), calculated according to the requirements of the procedure 
recommended for State Implementation Plans in appendix M to part 51 of 
this chapter.
    (g) Diluent record provisions. The owner or operator of a unit using 
a flow monitor and an O2 diluent monitor to determine heat 
input, in accordance with Equation F-17 or F-18 of appendix F to this 
part, or a unit that accounts for heat input using a flow monitor and a 
CO2 diluent monitor (which is used only for heat input 
determination and is not used as a CO2 pollutant 
concentration monitor) shall keep the following records for the 
O2 or CO2 diluent monitor:
    (1) Component-system identification code, as provided in Sec. 
75.53;
    (2) Date and hour;
    (3) Hourly average diluent gas (O2 or CO2) 
concentration (in percent, rounded to the nearest tenth);
    (4) Percent monitor data availability for the diluent monitor 
(recorded to the nearest tenth of a percent), calculated pursuant to 
Sec. 75.32; and
    (5) Method of determination code for diluent gas (O2 or 
CO2) concentration data using Codes 1-55, in Table 4a of this 
section.
    (h) Missing data records. The owner or operator shall record the 
causes of any missing data periods and the actions taken by the owner or 
operator to correct such causes.

[64 FR 28609, May 26, 1999; 64 FR 37582, July 12, 1999; 67 FR 40440, 
June 12, 2002; 70 FR 28682, May 18, 2005; 72 FR 51528, Sept. 7, 2007; 73 
FR 4353, Jan. 24, 2008; 76 FR 17313, Mar. 28, 2011]



Sec. 75.58  General recordkeeping provisions for specific situations.

    The owner or operator shall meet all of the applicable recordkeeping 
requirements of this section.
    (a) [Reserved]
    (b) Specific parametric data record provisions for calculating 
substitute emissions data for units with add-on emission controls. In 
accordance with Sec. 75.34, the owner or operator of an affected unit 
with add-on emission controls shall either record the applicable 
information in paragraph (b)(3) of this section for each hour of missing 
SO2 concentration data or NOX emission rate (in 
addition to other information), or shall record the information in 
paragraph (b)(1) of this section for SO2 or paragraph (b)(2) 
of this section for NOX through an automated data acquisition 
and handling system, as appropriate to the type of add-on emission 
controls:
    (1) For units with add-on SO2 emission controls using the 
optional parametric monitoring procedures in appendix C to this part, 
for each hour of missing SO2 concentration or volumetric flow 
data:
    (i) The information required in Sec. 75.57(c) for SO2 
concentration and volumetric flow, if either one of these monitors is 
still operating;
    (ii) Date and hour;
    (iii) Number of operating scrubber modules;
    (iv) Total feedrate of slurry to each operating scrubber module 
(gal/min);
    (v) Pressure differential across each operating scrubber module 
(inches of water column);
    (vi) For a unit with a wet flue gas desulfurization system, an in-
line measure of absorber pH for each operating scrubber module;
    (vii) For a unit with a dry flue gas desulfurization system, the 
inlet and outlet temperatures across each operating scrubber module;

[[Page 306]]

    (viii) For a unit with a wet flue gas desulfurization system, the 
percent solids in slurry for each scrubber module;
    (ix) For a unit with a dry flue gas desulfurization system, the 
slurry feed rate (gal/min) to the atomizer nozzle;
    (x) For a unit with SO2 add-on emission controls other 
than wet or dry limestone, corresponding parameters approved by the 
Administrator;
    (xi) Method of determination of SO2 concentration and 
volumetric flow using Codes 1-55 in Table 4a of Sec. 75.57; and
    (xii) Inlet and outlet SO2 concentration values, recorded 
by an SO2 continuous emission monitoring system, and the 
removal efficiency of the add-on emission controls.
    (2) For units with add-on NOX emission controls using the 
optional parametric monitoring procedures in appendix C to this part, 
for each hour of missing NOX emission rate data:
    (i) Date and hour;
    (ii) Inlet air flow rate (scfh, rounded to the nearest thousand);
    (iii) Excess O2 concentration of flue gas at stack outlet 
(percent, rounded to the nearest tenth of a percent);
    (iv) Carbon monoxide concentration of flue gas at stack outlet (ppm, 
rounded to the nearest tenth);
    (v) Temperature of flue gas at furnace exit or economizer outlet 
duct (F);
    (vi) Other parameters specific to NOX emission controls 
(e.g., average hourly reagent feedrate);
    (vii) Method of determination of NOX emission rate using 
Codes 1-55 in Table 4a of Sec. 75.57; and
    (viii) Inlet and outlet NOX emission rate values recorded 
by a NOX continuous emission monitoring system and the 
removal efficiency of the add-on emission controls.
    (3) Except as otherwise provided in Sec. 75.34(d), for units with 
add-on SO2 or NOX emission controls following the 
provisions of Sec. Sec. 75.34(a)(1), (a)(2), (a)(3) or (a)(5), the 
owner or operator shall record:
    (i) Parametric data which demonstrate, for each hour of missing 
SO2 or NOX emission data, the proper operation of 
the add-on emission controls, as described in the quality assurance/
quality control program for the unit. The parametric data shall be 
maintained on site and shall be submitted, upon request, to the 
Administrator, EPA Regional office, State, or local agency;
    (ii) A flag indicating, for each hour of missing SO2 or 
NOX emission data, either that the add-on emission controls 
are operating properly, as evidenced by all parameters being within the 
ranges specified in the quality assurance/quality control program, or 
that the add-on emission controls are not operating properly.
    (c) Specific SO2 emission record provisions for gas-fired or oil-
fired units using optional protocol in appendix D to this part. In lieu 
of recording the information in Sec. 75.57(c), the owner or operator 
shall record the applicable information in this paragraph for each 
affected gas-fired or oil-fired unit for which the owner or operator is 
using the optional protocol in appendix D to this part for estimating 
SO2 mass emissions:
    (1) For each hour when the unit is combusting oil:
    (i) Date and hour;
    (ii) Hourly average volumetric flow rate of oil, while the unit 
combusts oil, with the units in which oil flow is recorded (gal/hr, scf/
hr, m\3\/hr, or bbl/hr, rounded to the nearest tenth) (flag value if 
derived from missing data procedures);
    (iii) Sulfur content of oil sample used to determine SO2 
mass emission rate (rounded to nearest hundredth for diesel fuel or to 
the nearest tenth of a percent for other fuel oil) (flag value if 
derived from missing data procedures);
    (iv) [Reserved];
    (v) Mass flow rate of oil combusted each hour and method of 
determination (lb/hr, rounded to the nearest tenth) (flag value if 
derived from missing data procedures);
    (vi) SO2 mass emission rate from oil (lb/hr, rounded to 
the nearest tenth);
    (vii) For units using volumetric oil flowmeters, density of oil with 
the units in which oil density is recorded and method of determination 
(flag value if derived from missing data procedures);
    (viii) Gross calorific value of oil used to determine heat input and 
method of determination (Btu/lb) (flag value if derived from missing 
data procedures);

[[Page 307]]

    (ix) Hourly heat input rate from oil, according to procedures in 
appendix D to this part (mmBtu/hr, to the nearest tenth);
    (x) Fuel usage time for combustion of oil during the hour (rounded 
up to the nearest fraction of an hour (in equal increments that can 
range from one hundredth to one quarter of an hour, at the option of the 
owner or operator)) (flag to indicate multiple/single fuel types 
combusted);
    (xi) Monitoring system identification code;
    (xii) Operating load range corresponding to gross unit load (01-20);
    (xiii) Type of oil combusted; and
    (xiv) Heat input formula ID and SO2 Formula ID (required 
beginning January 1, 2009).
    (2) For gas-fired units or oil-fired units using the optional 
protocol in appendix D to this part for daily manual oil sampling, when 
the unit is combusting oil, the highest sulfur content recorded from the 
most recent 30 daily oil samples (rounded to the nearest tenth of a 
percent).
    (3) For gas-fired units or oil-fired units using the optional 
protocol in appendix D to this part, when either an assumed oil sulfur 
content or density value is used, or when as-delivered oil sampling is 
performed:
    (i) Record the measured sulfur content, gross calorific value, and, 
if applicable, density from each fuel sample; and
    (ii) Record and report the assumed sulfur content, gross calorific 
value, and, if applicable, density used to calculate SO2 mass 
emission rate or heat input rate.
    (4) For each hour when the unit is combusting gaseous fuel:
    (i) Date and hour.
    (ii) Hourly heat input rate from gaseous fuel, according to 
procedures in appendix F to this part (mmBtu/hr, rounded to the nearest 
tenth).
    (iii) Sulfur content or SO2 emission rate, in one of the 
following formats, in accordance with the appropriate procedure from 
appendix D to this part:
    (A) Sulfur content of gas sample and method of determination 
(rounded to the nearest 0.1 grains/100 scf) (flag value if derived from 
missing data procedures); or
    (B) Default SO2 emission rate of 0.0006 lb/mmBtu for 
pipeline natural gas, or calculated SO2 emission rate for 
natural gas from section 2.3.2.1.1 of appendix D to this part.
    (iv) Hourly flow rate of gaseous fuel, while the unit combusts gas 
(100 scfh) and source of data code for gas flow rate.
    (v) Gross calorific value of gaseous fuel used to determine heat 
input rate (Btu/100 scf) (flag value if derived from missing data 
procedures).
    (vi) SO2 mass emission rate due to the combustion of 
gaseous fuels (lb/hr).
    (vii) Fuel usage time for combustion of gaseous fuel during the hour 
(rounded up to the nearest fraction of an hour (in equal increments that 
can range from one hundredth to one quarter of an hour, at the option of 
the owner or operator)) (flag to indicate multiple/single fuel types 
combusted).
    (viii) Monitoring system identification code.
    (ix) Operating load range corresponding to gross unit load (01-20).
    (x) Type of gas combusted; and
    (xi) Heat input formula ID and SO2 Formula ID (required 
beginning January 1, 2009).
    (5) For each oil sample or sample of diesel fuel:
    (i) Date of sampling;
    (ii) Sulfur content (percent, rounded to either the nearest 
hundredth, or nearest ten-thousandth for diesel fuels and to the nearest 
tenth for other fuel oil);
    (iii) Gross calorific value (Btu/lb); and
    (iv) Density or specific gravity, if required to convert volume to 
mass.
    (6) For each sample of gaseous fuel for sulfur content:
    (i) Date of sampling; and
    (ii) Sulfur content (grains/100 scf, rounded to the nearest tenth).
    (7) For each sample of gaseous fuel for gross calorific value:
    (i) Date of sampling; and
    (ii) Gross calorific value (Btu/100 scf).
    (8) For each oil sample or sample of gaseous fuel:
    (i) Type of oil or gas; and
    (ii) Type of sulfur sampling (using codes in tables D-4 and D-5 of 
appendix D to this part) and value used in calculations, and type of GCV 
or density

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sampling (using codes in tables D-4 and D-5 of appendix D to this part).
    (d) Specific NOX emission record provisions for gas-fired 
peaking units or oil-fired peaking units using optional protocol in 
appendix E to this part. In lieu of recording the information in Sec. 
75.57(d), the owner or operator shall record the applicable information 
in this paragraph for each affected gas-fired peaking unit or oil-fired 
peaking unit for which the owner or operator is using the optional 
protocol in appendix E to this part for estimating NOX 
emission rate. The owner or operator shall meet the requirements of this 
section, except that the requirements under paragraphs (d)(1)(vii) and 
(d)(2)(vii) of this section shall become applicable on the date on which 
the owner or operator is required to monitor, record, and report 
NOX mass emissions under an applicable State or federal 
NOX mass emission reduction program, if the provisions of 
subpart H of this part are adopted as requirements under such a program.
    (1) For each hour when the unit is combusting oil:
    (i) Date and hour;
    (ii) Hourly average mass flow rate of oil while the unit combusts 
oil with the units in which oil flow is recorded (lb/hr);
    (iii) Gross calorific value of oil used to determine heat input 
(Btu/lb);
    (iv) Hourly average NOX emission rate from combustion of 
oil (lb/mmBtu, rounded to the nearest hundredth);
    (v) Heat input rate of oil (mmBtu/hr, rounded to the nearest tenth);
    (vi) Fuel usage time for combustion of oil during the hour (rounded 
up to the nearest fraction of an hour, in equal increments that can 
range from one hundredth to one quarter of an hour, at the option of the 
owner or operator);
    (vii) NOX mass emissions, calculated in accordance with 
section 8.1 of appendix F to this part;
    (viii) NOX monitoring system identification code;
    (ix) Fuel flow monitoring system identification code;
    (x) Segment identification of the correlation curve; and
    (xi) Heat input rate formula ID (required beginning January 1, 
2009).
    (2) For each hour when the unit is combusting gaseous fuel:
    (i) Date and hour;
    (ii) Hourly average fuel flow rate of gaseous fuel, while the unit 
combusts gas (100 scfh);
    (iii) Gross calorific value of gaseous fuel used to determine heat 
input (Btu/100 scf) (flag value if derived from missing data 
procedures);
    (iv) Hourly average NOX emission rate from combustion of 
gaseous fuel (lb/mmBtu, rounded to nearest hundredth);
    (v) Heat input rate from gaseous fuel, while the unit combusts gas 
(mmBtu/hr, rounded to the nearest tenth);
    (vi) Fuel usage time for combustion of gaseous fuel during the hour 
(rounded up to the nearest fraction of an hour, in equal increments that 
can range from one hundredth to one quarter of an hour, at the option of 
the owner or operator);
    (vii) NOX mass emissions, calculated in accordance with 
section 8.1 of appendix F to this part;
    (viii) NOX monitoring system identification code;
    (ix) Fuel flow monitoring system identification code;
    (x) Segment identification of the correlation curve; and
    (xi) Heat input rate formula ID (required beginning January 1, 
2009).
    (3) For each hour when the unit combusts multiple fuels:
    (i) Date and hour;
    (ii) Hourly average heat input rate from all fuels (mmBtu/hr, 
rounded to the nearest tenth); and
    (iii) Hourly average NOX emission rate for the unit for 
all fuels (lb/mmBtu, rounded to the nearest hundredth).
    (4) For each hour when the unit combusts any fuel(s):
    (i) For stationary gas turbines and diesel or dual-fuel 
reciprocating engines, hourly averages of operating parameters under 
section 2.3 of appendix E to this part (flag if value is outside of 
manufacturer's recommended range); and
    (ii) For boilers, hourly average boiler O2 reading 
(percent, rounded to the nearest tenth) (flag if value exceeds by more 
than 2 percentage points the O2 level recorded at the same 
heat input

[[Page 309]]

during the previous NOX emission rate test); and
    (iii) On and after April 27, 2011, operating condition codes for the 
following:
    (A) Unit operated on emergency fuel;
    (B) Correlation curve for the fuel mixture has expired;
    (C) Operating parameter is outside of normal limits;
    (D) Uncontrolled hour;
    (E) Operation above highest tested heat input rate point on the 
curve;
    (F) Operating parameter data missing or invalid;
    (G) Designated operational and control equipment parameters within 
normal limits; and
    (H) Operation below lowest tested heat input rate point on the 
curve.
    (5) For each fuel sample:
    (i) Date of sampling;
    (ii) Gross calorific value (Btu/lb for oil, Btu/100 scf for gaseous 
fuel); and
    (iii) Density or specific gravity, if required to convert volume to 
mass.
    (6) Flag to indicate multiple or single fuels combusted.
    (e) Specific SO2 emission record provisions during the 
combustion of gaseous fuel. (1) If SO2 emissions are 
determined in accordance with the provisions in Sec. 75.11(e)(2) during 
hours in which only gaseous fuel is combusted in a unit with an 
SO2 CEMS, the owner or operator shall record the information 
in paragraph (c)(3) of this section in lieu of the information in 
Sec. Sec. 75.57(c)(1), (c)(3), and (c)(4), for those hours.
    (2) The provisions of this paragraph apply to a unit which, in 
accordance with the provisions of Sec. 75.11(e)(3), uses an 
SO2 CEMS to determine SO2 emissions during hours 
in which only gaseous fuel is combusted in the unit. If the unit 
sometimes burns only gaseous fuel that is very low sulfur fuel (as 
defined in Sec. 72.2 of this chapter) as a primary and/or backup fuel 
and at other times combusts higher sulfur fuels, such as coal or oil, as 
primary and/or backup fuel(s), then the owner or operator shall keep 
records on-site, in a form suitable for inspection, of the type(s) of 
fuel(s) burned during each period of missing SO2 data and the 
number of hours that each type of fuel was combusted in the unit during 
each missing data period. This recordkeeping requirement does not apply 
to an affected unit that burns very low sulfur fuel exclusively, nor 
does it apply to a unit that burns such gaseous fuel(s) only during unit 
startup.
    (f) Specific SO2, NOX, and CO2 record provisions for gas-fired or 
oil-fired units using the optional low mass emissions excepted 
methodology in Sec. 75.19. In lieu of recording the information in 
Sec. Sec. 75.57(b) through (e), the owner or operator shall record the 
following information for each affected low mass emissions unit for 
which the owner or operator is using the optional low mass emissions 
excepted methodology in Sec. 75.19(c):
    (1) All low mass emission units shall report for each hour:
    (i) Date and hour;
    (ii) Unit operating time (units using the long term fuel flow 
methodology report operating time to be 1);
    (iii) Fuel type (pipeline natural gas, natural gas, other gaseous 
fuel, residual oil, or diesel fuel). If more than one type of fuel is 
combusted in the hour, either:
    (A) Indicate the fuel type which results in the highest emission 
factors for NOX (this option is in effect through December 
31, 2008); or
    (B) Indicate the fuel type resulting in the highest emission factor 
for each parameter (SO2, NOX emission rate, and 
CO2) separately (this option is required on and after January 
1, 2009);
    (iv) Average hourly NOX emission rate (lb/mmBtu, rounded 
to the nearest thousandth);
    (v) Hourly NOX mass emissions (lbs, rounded to the 
nearest tenth);
    (vi) Hourly SO2 mass emissions (lbs, rounded to the 
nearest tenth);
    (vii) Hourly CO2 mass emissions (tons, rounded to the 
nearest tenth);
    (viii) Hourly calculated unit heat input in mmBtu;
    (ix) Hourly unit output in gross load or steam load;
    (x) The method of determining hourly heat input: unit maximum rated 
heat input, unit long term fuel flow or group long term fuel flow;
    (xi) The method of determining NOX emission rate used for 
the hour: default based on fuel combusted, unit specific default based 
on testing or historical data, group default based on representative 
testing of identical units, unit

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specific based on testing of a unit with NOX controls 
operating, or missing data value;
    (xii) Control status of the unit; and
    (xiii) Base or peak load indicator (as applicable); and
    (xiv) Multiple fuel flag.
    (2) Low mass emission units using the optional long term fuel flow 
methodology to determine unit heat input shall report for each quarter:
    (i) Type of fuel;
    (ii) Beginning date and hour of long term fuel flow measurement 
period;
    (iii) End date and hour of long term fuel flow period;
    (iv) Quantity of fuel measured;
    (v) Units of measure;
    (vi) Fuel GCV value used to calculate heat input;
    (vii) Units of GCV;
    (viii) Method of determining fuel GCV used;
    (ix) Method of determining fuel flow over period;
    (x) Monitoring-system identification code;
    (xi) Quarter and year;
    (xii) Total heat input (mmBtu); and
    (xiii) Operating hours in period.

[64 FR 28612, May 26, 1999, as amended at 67 FR 40441, 40442, June 12, 
2002; 70 FR 28683, May 18, 2005; 73 FR 4354, Jan. 24, 2008; 76 FR 17314, 
Mar. 28, 2011]



Sec. 75.59  Certification, quality assurance, and quality control 
record provisions.

    The owner or operator shall meet all of the applicable recordkeeping 
requirements of this section.
    (a) Continuous emission or opacity monitoring systems. The owner or 
operator shall record the applicable information in this section for 
each certified monitor or certified monitoring system (including 
certified backup monitors) measuring and recording emissions or flow 
from an affected unit.
    (1) For each SO2 or NOX pollutant 
concentration monitor, flow monitor, CO2 emissions 
concentration monitor (including O2 monitors used to 
determine CO2 emissions), or diluent gas monitor (including 
wet- and dry-basis O2 monitors used to determine percent 
moisture), the owner or operator shall record the following for all 
daily and 7-day calibration error tests, and all off-line calibration 
demonstrations, including any follow-up tests after corrective action:
    (i) Component-system identification code (on and after January 1, 
2009, only the component identification code is required);
    (ii) Instrument span and span scale;
    (iii) On and after April 27, 2011, date, hour, and minute;
    (iv) Reference value (i.e., calibration gas concentration or 
reference signal value, in ppm or other appropriate units);
    (v) Observed value (monitor response during calibration, in ppm or 
other appropriate units);
    (vi) Percent calibration error (rounded to the nearest tenth of a 
percent) (flag if using alternative performance specification for low 
emitters or differential pressure flow monitors);
    (vii) Reference signal or calibration gas level;
    (viii) For 7-day calibration error tests, a test number and reason 
for test;
    (ix) For 7-day calibration tests for certification or 
recertification, a certification from the cylinder gas vendor or CEMS 
vendor that calibration gas, as defined in Sec. 72.2 of this chapter 
and appendix A to this part, was used to conduct calibration error 
testing;
    (x) Description of any adjustments, corrective actions, or 
maintenance prior to a passed test or following a failed test; and
    (xi) Indication of whether the unit is off-line or on-line.
    (2) For each flow monitor, the owner or operator shall record the 
following for all daily interference checks, including any follow-up 
tests after corrective action.
    (i) Component-system identification code (after January 1, 2009, 
only the component identification code is required);
    (ii) Date and hour;
    (iii) Code indicating whether monitor passes or fails the 
interference check; and
    (iv) Description of any adjustments, corrective actions, or 
maintenance prior to a passed test or following a failed test.
    (3) For each SO2 or NOX pollutant 
concentration monitor, CO2 emissions

[[Page 311]]

concentration monitor (including O2 monitors used to 
determine CO2 emissions), or diluent gas monitor (including 
wet- and dry-basis O2 monitors used to determine percent 
moisture), the owner or operator shall record the following for the 
initial and all subsequent linearity check(s), including any follow-up 
tests after corrective action.
    (i) Component-system identification code (on and after January 1, 
2009, only the component identification code is required);
    (ii) Instrument span and span scale (only span scale is required on 
and after January 1, 2009);
    (iii) Calibration gas level;
    (iv) Date and time (hour and minute) of each gas injection at each 
calibration gas level;
    (v) Reference value (i.e., reference gas concentration for each gas 
injection at each calibration gas level, in ppm or other appropriate 
units);
    (vi) Observed value (monitor response to each reference gas 
injection at each calibration gas level, in ppm or other appropriate 
units);
    (vii) Mean of reference values and mean of measured values at each 
calibration gas level;
    (viii) Linearity error at each of the reference gas concentrations 
(rounded to nearest tenth of a percent) (flag if using alternative 
performance specification);
    (ix) Test number and reason for test (flag if aborted test); and
    (x) Description of any adjustments, corrective action, or 
maintenance prior to a passed test or following a failed test.
    (4) For each differential pressure type flow monitor, the owner or 
operator shall record items in paragraphs (a)(4) (i) through (v) of this 
section, for all quarterly leak checks, including any follow-up tests 
after corrective action. For each flow monitor, the owner or operator 
shall record items in paragraphs (a)(4) (vi) and (vii) for all flow-to-
load ratio and gross heat rate tests:
    (i) Component-system identification code (on and after January 1, 
2009, only the system identification code is required).
    (ii) Date and hour.
    (iii) Reason for test.
    (iv) Code indicating whether monitor passes or fails the quarterly 
leak check.
    (v) Description of any adjustments, corrective actions, or 
maintenance prior to a passed test or following a failed test.
    (vi) Test data from the flow-to-load ratio or gross heat rate (GHR) 
evaluation, including:
    (A) Monitoring system identification code;
    (B) Calendar year and quarter;
    (C) Indication of whether the test is a flow-to-load ratio or gross 
heat rate evaluation;
    (D) Indication of whether bias adjusted flow rates were used;
    (E) Average absolute percent difference between reference ratio (or 
GHR) and hourly ratios (or GHR values);
    (F) Test result;
    (G) Number of hours used in final quarterly average;
    (H) Number of hours exempted for use of a different fuel type;
    (I) Number of hours exempted for load ramping up or down;
    (J) Number of hours exempted for scrubber bypass;
    (K) Number of hours exempted for hours preceding a normal-load flow 
RATA;
    (L) Number of hours exempted for hours preceding a successful 
diagnostic test, following a documented monitor repair or major 
component replacement;
    (M) Number of hours excluded for flue gases discharging 
simultaneously thorough a main stack and a bypass stack; and
    (N) Test number.
    (vii) Reference data for the flow-to-load ratio or gross heat rate 
evaluation, including (as applicable):
    (A) Reference flow RATA end date and time;
    (B) Test number of the reference RATA;
    (C) Reference RATA load and load level;
    (D) Average reference method flow rate during reference flow RATA;
    (E) Reference flow/load ratio;
    (F) Average reference method diluent gas concentration during flow 
RATA and diluent gas units of measure;

[[Page 312]]

    (G) Fuel specific Fd -or Fc-factor during flow 
RATA and F-factor units of measure;
    (H) Reference gross heat rate value;
    (I) Monitoring system identification code;
    (J) Average hourly heat input rate during RATA;
    (K) Average gross unit load;
    (L) Operating load level; and
    (M) An indicator (``flag'') if separate reference ratios are 
calculated for each multiple stack.
    (5) For each SO2 pollutant concentration monitor, flow 
monitor, each CO2 emissions concentration monitor (including 
any O2 concentration monitor used to determine CO2 
mass emissions or heat input), each NOX-diluent continuous 
emission monitoring system, each NOX concentration monitoring 
system, each diluent gas (O2 or CO2) monitor used 
to determine heat input, each moisture monitoring system, and each 
approved alternative monitoring system, the owner or operator shall 
record the following information for the initial and all subsequent 
relative accuracy test audits:
    (i) Reference method(s) used.
    (ii) Individual test run data from the relative accuracy test audit 
for the SO2 concentration monitor, flow monitor, 
CO2 emissions concentration monitor, NOX-diluent 
continuous emission monitoring system, diluent gas (O2 or 
CO2) monitor used to determine heat input, NOX 
concentration monitoring system, moisture monitoring system, or approved 
alternative monitoring system, including:
    (A) Date, hour, and minute of beginning of test run;
    (B) Date, hour, and minute of end of test run;
    (C) Monitoring system identification code;
    (D) Test number and reason for test;
    (E) Operating level (low, mid, high, or normal, as appropriate) and 
number of operating levels comprising test;
    (F) Normal load (or operating level) indicator for flow RATAs 
(except for peaking units);
    (G) Units of measure;
    (H) Run number;
    (I) Run value from CEMS being tested, in the appropriate units of 
measure;
    (J) Run value from reference method, in the appropriate units of 
measure;
    (K) Flag value (0, 1, or 9, as appropriate) indicating whether run 
has been used in calculating relative accuracy and bias values or 
whether the test was aborted prior to completion;
    (L) Average gross unit load, expressed as a total gross unit load, 
rounded to the nearest MWe, or as steam load, rounded to the nearest 
thousand lb/hr; on and after April 27, 2011, for units that do not 
produce electrical or thermal output, record, instead, the average stack 
gas velocity at the operating level being tested; and
    (M) Flag to indicate whether an alternative performance 
specification has been used.
    (iii) Calculations and tabulated results, as follows:
    (A) Arithmetic mean of the monitoring system measurement values, of 
the reference method values, and of their differences, as specified in 
Equation A-7 in appendix A to this part;
    (B) Standard deviation, as specified in Equation A-8 in appendix A 
to this part;
    (C) Confidence coefficient, as specified in Equation A-9 in appendix 
A to this part;
    (D) Statistical ``t'' value used in calculations;
    (E) Relative accuracy test results, as specified in Equation A-10 in 
appendix A to this part. For multi-level flow monitor tests the relative 
accuracy test results shall be recorded at each load (or operating) 
level tested. Each load (or operating) level shall be expressed as a 
total gross unit load, rounded to the nearest MWe, or as steam load, 
rounded to the nearest thousand lb/hr, or as otherwise specified by the 
Administrator, for units that do not produce electrical or thermal 
output;
    (F) Bias test results as specified in section 7.6.4 of appendix A to 
this part;
    (G) Bias adjustment factor from Equation A-12 in appendix A to this 
part for any monitoring system that failed the bias test (except as 
otherwise provided in section 7.6.5 of appendix A to this part) and 
1.000 for any monitoring system that passed the bias test; and

[[Page 313]]

    (H) On and after April 27, 2011, RATA frequency code.
    (iv) Description of any adjustment, corrective action, or 
maintenance prior to a passed test or following a failed or aborted 
test.
    (v) F-factor value(s) used to convert NOX pollutant 
concentration and diluent gas (O2 or CO2) 
concentration measurements into NOX emission rates (in lb/
mmBtu), heat input or CO2 emissions.
    (vi) For flow monitors, the equation used to linearize the flow 
monitor and the numerical values of the polynomial coefficients or K 
factor(s) of that equation.
    (vii) For moisture monitoring systems, the coefficient or ``K'' 
factor or other mathematical algorithm used to adjust the monitoring 
system with respect to the reference method.
    (6) For each SO2, NOX, or CO2 
pollutant concentration monitor, each component of a NOX-
diluent continuous emission monitoring system, and each CO2 
or O2 monitor used to determine heat input, the owner or 
operator shall record the following information for the cycle time test:
    (i) Component-system identification code (on and after January 1, 
2009, only the component identification code is required);
    (ii) Date;
    (iii) Start and end times;
    (iv) Upscale and downscale cycle times for each component;
    (v) Stable start monitor value;
    (vi) Stable end monitor value;
    (vii) Reference value of calibration gas(es);
    (viii) Calibration gas level;
    (ix) Total cycle time;
    (x) Reason for test; and
    (xi) Test number.
    (7) In addition to the information in paragraph (a)(5) of this 
section, the owner or operator shall record, for each relative accuracy 
test audit, supporting information sufficient to substantiate compliance 
with all applicable sections and appendices in this part. Unless 
otherwise specified in this part or in an applicable test method, the 
information in paragraphs (a)(7)(i) through (a)(7)(vi) of this section 
may be recorded either in hard copy format, electronic format or a 
combination of the two, and the owner or operator shall maintain this 
information in a format suitable for inspection and audit purposes. This 
RATA supporting information shall include, but shall not be limited to, 
the following data elements:
    (i) For each RATA using Reference Method 2 (or its allowable 
alternatives) in appendix A to part 60 of this chapter to determine 
volumetric flow rate:
    (A) Information indicating whether or not the location meets 
requirements of Method 1 in appendix A to part 60 of this chapter; and
    (B) Information indicating whether or not the equipment passed the 
required leak checks.
    (ii) For each run of each RATA using Reference Method 2 (or its 
allowable alternatives in appendix A to part 60 of this chapter) to 
determine volumetric flow rate, record the following data elements (as 
applicable to the measurement method used):
    (A) Operating level (low, mid, high, or normal, as appropriate);
    (B) Number of reference method traverse points;
    (C) Average stack gas temperature (F);
    (D) Barometric pressure at test port (inches of mercury);
    (E) Stack static pressure (inches of H2O);
    (F) Absolute stack gas pressure (inches of mercury);
    (G) Percent CO2 and O2 in the stack gas, dry 
basis;
    (H) CO2 and O2 reference method used;
    (I) Moisture content of stack gas (percent H2O);
    (J) Molecular weight of stack gas, dry basis (lb/lb-mole);
    (K) Molecular weight of stack gas, wet basis (lb/lb-mole);
    (L) Stack diameter (or equivalent diameter) at the test port (ft);
    (M) Average square root of velocity head of stack gas (inches of 
H2O) for the run;
    (N) Stack or duct cross-sectional area at test port (ft\2\);
    (O) Average velocity (ft/sec);
    (P) Average stack flow rate, adjusted, if applicable, for wall 
effects (scfh, wet basis);
    (Q) Flow rate reference method used;

[[Page 314]]

    (R) Average velocity, adjusted for wall effects;
    (S) Calculated (site-specific) wall effects adjustment factor 
determined during the run, and, if different, the wall effects 
adjustment factor used in the calculations; and
    (T) Default wall effects adjustment factor used.
    (iii) For each traverse point of each run of each RATA using 
Reference Method 2 (or its allowable alternatives in appendix A to part 
60 of this chapter) to determine volumetric flow rate, record the 
following data elements (as applicable to the measurement method used):
    (A) Reference method probe type;
    (B) Pressure measurement device type;
    (C) Traverse point ID;
    (D) Probe or pitot tube calibration coefficient;
    (E) Date of latest probe or pitot tube calibration;
    (F) Average velocity differential pressure at traverse point (inches 
of H2O) or the average of the square roots of the velocity 
differential pressures at the traverse point ((inches of 
H2O)\1/2\);
    (G) TS, stack temperature at the traverse point (F);
    (H) Composite (wall effects) traverse point identifier;
    (I) Number of points included in composite traverse point;
    (J) Yaw angle of flow at traverse point (degrees);
    (K) Pitch angle of flow at traverse point (degrees);
    (L) Calculated velocity at traverse point both accounting and not 
accounting for wall effects (ft/sec); and
    (M) Probe identification number.
    (iv) For each RATA using Method 6C, 7E, or 3A in appendix A to part 
60 of this chapter to determine SO2, NOX, 
CO2, or O2 concentration:
    (A) Pollutant or diluent gas being measured;
    (B) Span of reference method analyzer;
    (C) Type of reference method system (e.g., extractive or dilution 
type);
    (D) Reference method dilution factor (dilution type systems, only);
    (E) Reference gas concentrations (zero, mid, and high gas levels) 
used for the 3-point pre-test analyzer calibration error test (or, for 
dilution type reference method systems, for the 3-point pre-test system 
calibration error test) and for any subsequent recalibrations;
    (F) Analyzer responses to the zero-, mid-, and high-level 
calibration gases during the 3-point pre-test analyzer (or system) 
calibration error test and during any subsequent recalibration(s);
    (G) Analyzer calibration error at each gas level (zero, mid, and 
high) for the 3-point pre-test analyzer (or system) calibration error 
test and for any subsequent recalibration(s) (percent of span value);
    (H) Upscale gas concentration (mid or high gas level) used for each 
pre-run or post-run system bias check or (for dilution type reference 
method systems) for each pre-run or post-run system calibration error 
check;
    (I) Analyzer response to the calibration gas for each pre-run or 
post-run system bias (or system calibration error) check;
    (J) The arithmetic average of the analyzer responses to the zero-
level gas, for each pair of pre- and post-run system bias (or system 
calibration error) checks;
    (K) The arithmetic average of the analyzer responses to the upscale 
calibration gas, for each pair of pre- and post-run system bias (or 
system calibration error) checks;
    (L) The results of each pre-run and each post-run system bias (or 
system calibration error) check using the zero-level gas (percentage of 
span value);
    (M) The results of each pre-run and each post-run system bias (or 
system calibration error) check using the upscale calibration gas 
(percentage of span value);
    (N) Calibration drift and zero drift of analyzer during each RATA 
run (percentage of span value);
    (O) Moisture basis of the reference method analysis;
    (P) Moisture content of stack gas, in percent, during each test run 
(if needed to convert to moisture basis of CEMS being tested);
    (Q) Unadjusted (raw) average pollutant or diluent gas concentration 
for each run;
    (R) Average pollutant or diluent gas concentration for each run, 
corrected

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for calibration bias (or calibration error) and, if applicable, 
corrected for moisture;
    (S) The F-factor used to convert reference method data to units of 
lb/mmBtu (if applicable);
    (T) Date(s) of the latest analyzer interference test(s);
    (U) Results of the latest analyzer interference test(s);
    (V) Date of the latest NO2 to NO conversion test (Method 
7E only);
    (W) Results of the latest NO2 to NO conversion test 
(Method 7E only); and
    (X) For each calibration gas cylinder used during each RATA, record 
the cylinder gas vendor, cylinder number, expiration date, pollutant(s) 
in the cylinder, and certified gas concentration(s).
    (v) For each test run of each moisture determination using Method 4 
in appendix A to part 60 of this chapter (or its allowable 
alternatives), whether the determination is made to support a gas RATA, 
to support a flow RATA, or to quality assure the data from a continuous 
moisture monitoring system, record the following data elements (as 
applicable to the moisture measurement method used):
    (A) Test number;
    (B) Run number;
    (C) The beginning date, hour, and minute of the run;
    (D) The ending date, hour, and minute of the run;
    (E) Unit operating level (low, mid, high, or normal, as 
appropriate);
    (F) Moisture measurement method;
    (G) Volume of H2O collected in the impingers (ml);
    (H) Mass of H2O collected in the silica gel (g);
    (I) Dry gas meter calibration factor;
    (J) Average dry gas meter temperature (F);
    (K) Barometric pressure (inches of mercury);
    (L) Differential pressure across the orifice meter (inches of 
H2O);
    (M) Initial and final dry gas meter readings (ft\3\);
    (N) Total sample gas volume, corrected to standard conditions 
(dscf); and
    (O) Percentage of moisture in the stack gas (percent 
H2O).
    (vi) The raw data and calculated results for any stratification 
tests performed in accordance with sections 6.5.6.1 through 6.5.6.3 of 
appendix A to this part.
    (vii) [Reserved]
    (viii) [Reserved]
    (ix) For a unit with a flow monitor installed on a rectangular stack 
or duct, if a site-specific default or measured wall effects adjustment 
factor (WAF) is used to correct the stack gas volumetric flow rate data 
to account for velocity decay near the stack or duct wall, the owner or 
operator shall keep records of the following for each flow RATA 
performed with EPA Method 2 in appendices A-1 and A-2 to part 60 of this 
chapter, subsequent to the WAF determination:
    (A) Monitoring system ID;
    (B) Test number;
    (C) Operating level;
    (D) RATA end date and time;
    (E) Number of Method 1 traverse points; and
    (F) Wall effects adjustment factor (WAF), to the nearest 0.0001.
    (8) For each certified continuous emission monitoring system, 
continuous opacity monitoring system, excepted monitoring system, or 
alternative monitoring system, the date and description of each event 
which requires certification, recertification, or certain diagnostic 
testing of the system and the date and type of each test performed. If 
the conditional data validation procedures of Sec. 75.20(b)(3) are to 
be used to validate and report data prior to the completion of the 
required certification, recertification, or diagnostic testing, the date 
and hour of the probationary calibration error test shall be reported to 
mark the beginning of conditional data validation.
    (9) When hardcopy relative accuracy test reports, certification 
reports, recertification reports, or semiannual or annual reports for 
gas or flow rate CEMS are required or requested under Sec. 75.60(b)(6) 
or Sec. 75.63, the reports shall include, at a minimum, the following 
elements (as applicable to the type(s) of test(s) performed):
    (i) Summarized test results.
    (ii) DAHS printouts of the CEMS data generated during the 
calibration

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error, linearity, cycle time, and relative accuracy tests.
    (iii) For pollutant concentration monitor or diluent monitor 
relative accuracy tests at normal operating load:
    (A) The raw reference method data from each run, i.e., the data 
under paragraph (a)(7)(iv)(Q) of this section (usually in the form of a 
computerized printout, showing a series of one-minute readings and the 
run average);
    (B) The raw data and results for all required pre-test, post-test, 
pre-run and post-run quality assurance checks (i.e., calibration gas 
injections) of the reference method analyzers, i.e., the data under 
paragraphs (a)(7)(iv)(E) through (a)(7)(iv)(N) of this section;
    (C) The raw data and results for any moisture measurements made 
during the relative accuracy testing, i.e., the data under paragraphs 
(a)(7)(v)(A) through (a)(7)(v)(O) of this section; and
    (D) Tabulated, final, corrected reference method run data (i.e., the 
actual values used in the relative accuracy calculations), along with 
the equations used to convert the raw data to the final values and 
example calculations to demonstrate how the test data were reduced.
    (iv) For relative accuracy tests for flow monitors:
    (A) The raw flow rate reference method data, from Reference Method 2 
(or its allowable alternatives) under appendix A to part 60 of this 
chapter, including auxiliary moisture data (often in the form of 
handwritten data sheets), i.e., the data under paragraphs (a)(7)(ii)(A) 
through (a)(7)(ii)(T), paragraphs (a)(7)(iii)(A) through (a)(7)(iii)(M), 
and, if applicable, paragraphs (a)(7)(v)(A) through (a)(7)(v)(O) of this 
section; and
    (B) The tabulated, final volumetric flow rate values used in the 
relative accuracy calculations (determined from the flow rate reference 
method data and other necessary measurements, such as moisture, stack 
temperature and pressure), along with the equations used to convert the 
raw data to the final values and example calculations to demonstrate how 
the test data were reduced.
    (v) Calibration gas certificates for the gases used in the 
linearity, calibration error, and cycle time tests and for the 
calibration gases used to quality assure the gas monitor reference 
method data during the relative accuracy test audit.
    (vi) Laboratory calibrations of the source sampling equipment.
    (vii) A copy of the test protocol used for the CEMS certifications 
or recertifications, including narrative that explains any testing 
abnormalities, problematic sampling, and analytical conditions that 
required a change to the test protocol, and/or solutions to technical 
problems encountered during the testing program.
    (viii) Diagrams illustrating test locations and sample point 
locations (to verify that locations are consistent with information in 
the monitoring plan). Include a discussion of any special traversing or 
measurement scheme. The discussion shall also confirm that sample points 
satisfy applicable acceptance criteria.
    (ix) Names of key personnel involved in the test program, including 
test team members, plant contacts, agency representatives and test 
observers on site.
    (x) For testing involving use of EPA Protocol gases, the owner or 
operator shall record in electronic and hardcopy format the following 
information, as applicable:
    (A) On and after September 26, 2011, for each gas monitor, for both 
low and high measurement ranges, record the following information for 
the mid-level or high-level EPA Protocol gas (as applicable) that is 
used for daily calibration error tests, and the low-, mid-, and high-
level gases used for quarterly linearity checks. For O2, if 
purified air is used as the high-level gas for daily calibrations or 
linearity checks, record the following information for the low- and mid-
level EPA Protocol gas used for linearity checks, instead:
    (1) Gas level code;
    (2) A code for the type of EPA Protocol gas used;
    (3) The PGVP vendor ID issued by EPA for the EPA Protocol gas 
production site that supplied the EPA Protocol gas cylinder;
    (4) The expiration date for the EPA Protocol gas cylinder; and
    (5) The cylinder number.

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    (B) On and after September 26, 2011, for each usage of Reference 
Method 3A in appendix A-2 to part 60 of this chapter, or Method 6C or 7E 
in appendix A-4 to part 60 of this chapter performed using EPA Protocol 
gas for the certification, recertification, routine quality assurance or 
diagnostic testing (reportable diagnostics, only) of a Part 75 
monitoring system, record the information required by paragraphs 
(a)(9)(x)(A)(1) through (5) of this section.
    (xi) On and after March 27, 2012, for all RATAs performed pursuant 
to Sec. 75.74(c)(2)(ii), section 6.5 of appendix A to this part and 
section 2.3.1 of appendix B to this part, and for all NOX 
emission testing performed pursuant to section 2.1 of appendix E to this 
part, or Sec. 75.19(c)(1)(iv), the owner or operator shall record the 
following information as provided by the AETB:
    (A) The name, telephone number and e-mail address of the Air 
Emission Testing Body;
    (B) The name of each on-site Qualified Individual, as defined in 
Sec. 72.2 of this chapter;
    (C) For the reference method(s) that were performed, the date(s) 
that each on-site Qualified Individual took and passed the relevant 
qualification exam(s) required by ASTM D7036-04 (incorporated by 
reference, see Sec. 75.6); and
    (D) The name and e-mail address of each qualification exam provider.
    (10) Whenever reference methods are used as backup monitoring 
systems pursuant to Sec. 75.20(d)(3), the owner or operator shall 
record the following information:
    (i) For each test run using Reference Method 2 (or its allowable 
alternatives in appendix A to part 60 of this chapter) to determine 
volumetric flow rate, record the following data elements (as applicable 
to the measurement method used):
    (A) Unit or stack identification number;
    (B) Reference method system and component identification numbers;
    (C) Run date and hour;
    (D) The data in paragraph (a)(7)(ii) of this section, except for 
paragraphs (a)(7)(ii)(A), (F), (H), (L) and (Q) through (T); and
    (E) The data in paragraph (a)(7)(iii), except on a run basis.
    (ii) For each reference method test run using Method 6C, 7E, or 3A 
in appendix A to part 60 of this chapter to determine SO2, 
NOX, CO2, or O2 concentration:
    (A) Unit or stack identification number;
    (B) The reference method system and component identification 
numbers;
    (C) Run number;
    (D) Run start date and hour;
    (E) Run end date and hour;
    (F) The data in paragraphs (a)(7)(iv)(B) through (I) and (L) through 
(O); and (G) Stack gas density adjustment factor (if applicable).
    (iii) For each hour of each reference method test run using Method 
6C, 7E, or 3A in appendix A to part 60 of this chapter to determine 
SO2, NOX, CO2, or O2 
concentration:
    (A) Unit or stack identification number;
    (B) The reference method system and component identification 
numbers;
    (C) Run number;
    (D) Run date and hour;
    (E) Pollutant or diluent gas being measured;
    (F) Unadjusted (raw) average pollutant or diluent gas concentration 
for the hour; and
    (G) Average pollutant or diluent gas concentration for the hour, 
adjusted as appropriate for moisture, calibration bias (or calibration 
error) and stack gas density.
    (11) For each other quality-assurance test or other quality 
assurance activity, the owner or operator shall record the following (as 
applicable):
    (i) Component/system identification code;
    (ii) Parameter;
    (iii) Test or activity completion date and hour;
    (iv) Test or activity description;
    (v) Test result;
    (vi) Reason for test; and
    (vii) Test code.
    (12) For each request for a quality assurance test extension or 
exemption, for any loss of exempt status, and for each single-load flow 
RATA claim pursuant to section 2.3.1.3(c)(3) of appendix B to this part, 
the owner or operator

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shall record the following (as applicable):
    (i) For a RATA deadline extension or exemption request:
    (A) Monitoring system identification code;
    (B) Date of last RATA;
    (C) RATA expiration date without extension;
    (D) RATA expiration date with extension;
    (E) Type of RATA extension of exemption claimed or lost;
    (F) Year to date hours of usage of fuel other than very low sulfur 
fuel;
    (G) Year to date hours of non-redundant back-up CEMS usage at the 
unit/stack; and
    (H) Quarter and year.
    (ii) For a linearity test or flow-to-load ratio test quarterly 
exemption:
    (A) Component-system identification code;
    (B) Type of test;
    (C) Basis for exemption;
    (D) Quarter and year; and
    (E) Span scale.
    (iii) [Reserved]
    (iv) For a fuel flowmeter accuracy test extension:
    (A) Component-system identification code;
    (B) Date of last accuracy test;
    (C) Accuracy test expiration date without extension;
    (D) Accuracy test expiration date with extension;
    (E) Type of extension;
    (F) Quarter and year; and
    (G) On and after April 27, 2011, fuel code for Ozone Season Only 
reporters under Sec. 75.74(c).
    (v) For a single-load (or single-level) flow RATA claim:
    (A) Monitoring system identification code;
    (B) Ending date of last annual flow RATA;
    (C) The relative frequency (percentage) of unit or stack operation 
at each load (or operating) level (low, mid, and high) since the 
previous annual flow RATA, to the nearest 0.1 percent;
    (D) End date of the historical load (or operating level) data 
collection period; and
    (E) Indication of the load (or operating) level (low, mid or high) 
claimed for the single-load flow RATA.
    (13) An indication that data have been excluded from a periodic span 
and range evaluation of an SO2 or NOX monitor 
under section 2.1.1.5 or 2.1.2.5 of appendix A to this part and the 
reason(s) for excluding the data. For purposes of reporting under Sec. 
75.64(a), this information shall be reported with the quarterly report 
as descriptive text consistent with Sec. 75.64(g).
    (14) [Reserved]
    (15) On and after March 27, 2012, for all RATAs performed pursuant 
to Sec. 75.74(c)(2)(ii), section 6.5 of appendix A to this part or 
section 2.3.1 of appendix B to this part, the owner or operator shall 
record in electronic format the following information as provided by the 
AETB:
    (i) The name, telephone number and e-mail address of the Air 
Emission Testing Body;
    (ii) The name of each on-site Qualified Individual, as defined in 
Sec. 72.2 of this chapter;
    (iii) For the reference method(s) that were performed, the date(s) 
that each on-site Qualified Individual took and passed the relevant 
qualification exam(s) required by ASTM D7036-04 (incorporated by 
reference, see Sec. 75.6); and
    (iv) The name and e-mail address of each qualification exam 
provider.
    (b) Excepted monitoring systems for gas-fired and oil-fired units. 
The owner or operator shall record the applicable information in this 
section for each excepted monitoring system following the requirements 
of appendix D to this part or appendix E to this part for determining 
and recording emissions from an affected unit.
    (1) For certification and quality assurance testing of fuel 
flowmeters tested against a reference fuel flow rate (i.e., flow rate 
from another fuel flowmeter under section 2.1.5.2 of appendix D to this 
part or flow rate from a procedure according to a standard incorporated 
by reference under section 2.1.5.1 of appendix D to this part):
    (i) Unit or common pipe header identification code;
    (ii) Component and system identification codes of the fuel flowmeter 
being tested (on and after January 1, 2009, only the component 
identification code is required);

[[Page 319]]

    (iii) Date and hour of test completion, for a test performed in-line 
at the unit;
    (iv) Date and hour of flowmeter reinstallation, for laboratory 
tests;
    (v) Test number;
    (vi) Upper range value of the fuel flowmeter;
    (vii) Flowmeter measurements during accuracy test (and mean of 
values), including units of measure;
    (viii) Reference flow rates during accuracy test (and mean of 
values), including units of measure;
    (ix) Level of fuel flowrate test during runs (low, mid or high);
    (x) Average flowmeter accuracy for low and high fuel flowrates and 
highest flowmeter accuracy of any level designated as mid, expressed as 
a percent of upper range value;
    (xi) Indicator of whether test method was a lab comparison to 
reference meter or an in-line comparison against a master meter;
    (xii) Test result (aborted, pass, or fail); and
    (xiii) Description of fuel flowmeter calibration specification or 
procedure (in the certification application, or periodically if a 
different method is used for annual quality assurance testing).
    (2) For each transmitter or transducer accuracy test for an orifice-
, nozzle-, or venturi-type flowmeter used under section 2.1.6 of 
appendix D to this part:
    (i) Component and system identification codes of the fuel flowmeter 
being tested (on and after January 1, 2009, only the component 
identification code is required);
    (ii) Completion date and hour of test;
    (iii) For each transmitter or transducer: transmitter or transducer 
type (differential pressure, static pressure, or temperature); the full-
scale value of the transmitter or transducer, transmitter input (pre-
calibration) prior to accuracy test, including units of measure; and 
expected transmitter output during accuracy test (reference value from 
NIST-traceable equipment), including units of measure;
    (iv) For each transmitter or transducer tested: output during 
accuracy test, including units of measure; transmitter or transducer 
accuracy as a percent of the full-scale value; and transmitter output 
level as a percent of the full-scale value;
    (v) Average flowmeter accuracy at low and high level fuel flowrates 
and highest flowmeter accuracy of any level designated as mid fuel 
flowrate, expressed as a percent of upper range value;
    (vi) Test result (pass, fail, or aborted);
    (vii) Test number; and
    (viii) Accuracy determination methodology.
    (3) For each visual inspection of the primary element or transmitter 
or transducer accuracy test for an

orifice-, nozzle-, or venturi-type flowmeter under sections 2.1.6.1 
through 2.1.6.4 of appendix D to this part:
    (i) Date of inspection/test;
    (ii) Hour of completion of inspection/test;
    (iii) Component and system identification codes of the fuel 
flowmeter being inspected/tested; and
    (iv) Results of inspection/test (pass or fail).
    (4) For fuel flowmeters that are tested using the optional fuel 
flow-to-load ratio procedures of section 2.1.7 of appendix D to this 
part:
    (i) Test data for the fuel flowmeter flow-to-load ratio or gross 
heat rate check, including:
    (A) Component/system identification code (on and after January 1, 
2009, only the monitoring system identification code is required);
    (B) Calendar year and quarter;
    (C) Indication of whether the test is for fuel flow-to-load ratio or 
gross heat rate;
    (D) Quarterly average absolute percent difference between baseline 
for fuel flow-to-load ratio (or baseline gross heat rate and hourly 
quarterly fuel flow-to-load ratios (or gross heat rate value);
    (E) Test result;
    (F) Number of hours used in the analysis;
    (G) Number of hours excluded due to co-firing;
    (H) Number of hours excluded due to ramping;
    (I) Number of hours excluded in lower 25.0 percent range of 
operation; and
    (J) Test number.

[[Page 320]]

    (ii) Reference data for the fuel flowmeter flow-to-load ratio or 
gross heat rate evaluation, including:
    (A) Completion date and hour of most recent primary element 
inspection or test number of the most recent primary element inspection 
(as applicable); (on and after January 1, 2009, the test number of the 
most recent primary element inspection is required in lieu of the 
completion date and hour for the most recent primary element 
inspection);
    (B) Completion date and hour of most recent flow meter of 
transmitter accuracy test or test number of the most recent flowmeter or 
transmitter accuracy test (as applicable); (on and after January 1, 
2009, the test number of the most recent flowmeter or transmitter 
accuracy test is required in lieu of the completion date and hour for 
the most recent flowmeter or transmitter accuracy test);
    (C) Beginning date and hour of baseline period;
    (D) Completion date and hour of baseline period;
    (E) Average fuel flow rate, in 100 scfh for gas and lb/hr for oil;
    (F) Average load, in megawatts, 1000 lb/hr of steam, or mmBtu/hr 
thermal output;
    (G) Baseline fuel flow-to-load ratio, in the appropriate units of 
measure (if using fuel flow-to-load ratio);
    (H) Baseline gross heat rate if using gross heat rate, in the 
appropriate units of measure (if using gross heat rate check);
    (I) Number of hours excluded from baseline data due to ramping;
    (J) Number of hours excluded from baseline data in lower 25.0 
percent of range of operation;
    (K) Average hourly heat input rate;
    (L) Flag indicating baseline data collection is in progress and that 
fewer than four calendar quarters have elapsed since the quarter of the 
last flowmeter QA test;
    (M) Number of hours excluded due to co-firing; and
    (N) Monitoring system identification code.
    (5) For gas-fired peaking units or oil-fired peaking units using the 
optional procedures of appendix E to this part, for each initial 
performance, periodic, or quality assurance/quality control-related 
test:
    (i) For each run of emission data, record the following data:
    (A) Unit or common pipe identification code;
    (B) Monitoring system identification code for appendix E system (on 
and after January 1, 2009, component identification codes shall be 
reported in addition to the monitoring system identification code);
    (C) Run start date and time;
    (D) Run end date and time;
    (E) Total heat input during the run (mmBtu);
    (F) NOX emission rate (lb/mmBtu) from reference method;
    (G) Response time of the O2 and NOX reference 
method analyzers;
    (H) Type of fuel(s) combusted during the run. This requirement 
remains in effect through December 31, 2008;
    (I) Heat input rate (mmBtu/hr) during the run;
    (J) Test number;
    (K) Run number;
    (L) Operating level during the run;
    (M) NOX concentration recorded by the reference method 
during the run;
    (N) Diluent concentration recorded by the reference method during 
the run; and
    (O) Moisture measurement for the run (if applicable).
    (ii) For each run during which oil or mixed fuels are combusted 
record the following data:
    (A) Unit or common pipe identification code;
    (B) Monitoring system identification code for oil monitoring system 
(on and after January 1, 2009, component identification codes shall be 
reported in addition to the monitoring system identification code);
    (C) Run start date and time;
    (D) Run end date and time;
    (E) Mass flow or volumetric flow of oil, in the units of measure for 
the type of fuel flowmeter;
    (F) Gross calorific value of oil in the appropriate units of 
measure;
    (G) Density of fuel oil in the appropriate units of measure (if 
density is used to convert oil volume to mass);
    (H) Hourly heat input (mmBtu) during run from oil;
    (I) Test number;

[[Page 321]]

    (J) Run number; and
    (K) Operating level during the run.
    (iii) For each run during which gas or mixed fuels are combusted 
record the following data:
    (A) Unit or common pipe identification code;
    (B) Monitoring system identification code for gas monitoring system 
(on and after January 1, 2009, component identification codes shall be 
reported in addition to the monitoring system identification code);
    (C) Run start date and time;
    (D) Run end date and time;
    (E) Volumetric flow of gas (100 scf);
    (F) Gross calorific value of gas (Btu/100 scf);
    (G) Hourly heat input (mmBtu) during run from gas;
    (H) Test number;
    (I) Run number; and
    (J) Operating level during the run.
    (iv) For each operating level at which runs were performed:
    (A) Completion date and time of last run for operating level (as 
applicable). This requirement remains in effect through December 31, 
2008;
    (B) Type of fuel(s) combusted during test;
    (C) Average heat input rate at that operating level (mmBtu/hr);
    (D) Arithmetic mean of NOX emission rates from reference 
method run at this level;
    (E) F-factor used in calculations of NOX emission rate at 
that operating level;
    (F) Unit operating parametric data related to NOX 
formation for that unit type (e.g., excess O2 level, water/
fuel ratio);
    (G) Test number;
    (H) Operating level for runs; and
    (I) Component identification code (required on and after January 1, 
2009).
    (6) On and after March 27, 2012, for all stack testing performed 
pursuant to section 2.1 of appendix E to this part, the owner or 
operator shall record in electronic format the following information as 
provided by the AETB:
    (i) The name, telephone number and e-mail address of the Air 
Emission Testing Body;
    (ii) The name of each on-site Qualified Individual, as defined in 
Sec. 72.2 of this chapter;
    (iii) For the reference method(s) that were performed, the date(s) 
that each on-site Qualified Individual took and passed the relevant 
qualification exam(s) required by ASTM D7036-04 (incorporated by 
reference, see Sec. 75.6); and
    (iv) The name and e-mail address of each qualification exam 
provider.
    (c) Except as otherwise provided in Sec. 75.58(b)(3)(i), for units 
with add-on SO2 or NOX emission controls following 
the provisions of Sec. 75.34(a)(1) or (a)(2), the owner or operator 
shall keep the following records on-site in the quality assurance/
quality control plan required by section 1 of appendix B to this part:
    (1) A list of operating parameters for the add-on emission controls, 
including parameters in Sec. 75.58(b), appropriate to the particular 
installation of add-on emission controls; and
    (2) The range of each operating parameter in the list that indicates 
the add-on emission controls are properly operating.
    (d) Excepted monitoring for low mass emissions units under Sec. 
75.19(c)(1)(iv). For oil-and gas-fired units using the optional 
SO2, NOX and CO2 emissions calculations 
for low mass emission units under Sec. 75.19, the owner or operator 
shall record the following information for tests performed to determine 
a fuel and unit-specific default as provided in Sec. 75.19(c)(1)(iv):
    (1) For each run of each test performed using the procedures of 
section 2.1 of appendix E to this part, record the following data:
    (i) Unit or common pipe identification code;
    (ii) Run start date and time;
    (iii) Run end date and time;
    (iv) NOX emission rate (lb/mmBtu) from reference method;
    (v) Response time of the O2 and NOX reference 
method analyzers;
    (vi) Type of fuel(s) combusted during the run;
    (vii) Test number;
    (viii) Run number;
    (ix) Operating level during the run;
    (x) NOX concentration recorded by the reference method 
during the run;
    (xi) Diluent concentration recorded by the reference method during 
the run;
    (xii) Moisture measurement for the run (if applicable); and

[[Page 322]]

    (xiii) An indicator (``flag'') if the run is used to calculate the 
highest 3-run average NOX emission rate at any load level.
    (2) For each single-load or multiple-load appendix E test, record 
the following:
    (i) The three-run average NOX emission rate for each load 
level;
    (ii) An indicator that the average NOX emission rate is 
the highest NOX average emission rate recorded at any load 
level of the test (if appropriate);
    (iii) The default NOX emission rate (highest three-run 
average NOX emission rate at any load level);
    (iv) An indicator that the add-on NOX emission controls 
were operating or not operating during each run of the test;
    (v) Parameter data indicating the use and efficacy of control 
equipment during the test; and
    (vi) Indicator of whether the testing was done at base load, peak 
load or both (if appropriate); and
    (vii) The default NOX emission rate for peak load hours 
(if applicable).
    (3) For each unit in a group of identical units qualifying for 
reduced testing under Sec. 75.19(c)(1)(iv)(B), record the following 
data:
    (i) The unique group identification code assigned to the group. This 
code must include the ORIS code of one of the units in the group;
    (ii) The ORIS code or facility identification code for the unit;
    (iii) The plant name of the facility at which the unit is located, 
consistent with the facility's monitoring plan;
    (iv) The identification code for the unit, consistent with the 
facility's monitoring plan;
    (v) A record of whether or not the unit underwent fuel and unit-
specific testing for purposes of establishing a fuel and unit-specific 
NOX emission rate for purposes of Sec. 75.19;
    (vi) The completion date of the fuel and unit-specific test 
performed for purposes of establishing a fuel and unit-specific 
NOX emission rate for purposes of Sec. 75.19;
    (vii) The fuel and unit-specific NOX default rate 
established for the group of identical units under Sec. 75.19;
    (viii) The type of fuel combusted for the units during testing and 
represented by the resulting default NOX emission rate;
    (ix) The control status for the units during testing and represented 
by the resulting default NOX emission rate;
    (x) Documentation supporting the qualification of all units in the 
group for reduced testing, in accordance with the criteria established 
in Sec. 75.19(c)(1)(iv)(B)(1);
    (xi) Purpose of group tests;
    (xii) On and after April 27, 2011, the number of tests for group; 
and
    (xiii) On and after April 27, 2011, the number of units in group.
    (4) On and after March 27, 2012, for all NOX emission 
testing performed pursuant to Sec. 75.19(c)(1)(iv), the owner or 
operator shall record in electronic format the following information as 
provided by the AETB:
    (i) The name, telephone number and e-mail address of the Air 
Emission Testing Body;
    (ii) The name of each on-site Qualified Individual, as defined in 
Sec. 72.2 of this chapter;
    (iii) For the reference method(s) that were performed, the date(s) 
that each on-site Qualified Individual took and passed the relevant 
qualification exam(s) required by ASTM D7036-04 (incorporated by 
reference, see Sec. 75.6); and
    (iv) The name and e-mail address of each qualification exam 
provider.
    (e) DAHS Verification. For each DAHS (missing data and formula) 
verification that is required for initial certification, 
recertification, or for certain diagnostic testing of a monitoring 
system, record the date and hour that the DAHS verification is 
successfully completed. (This requirement only applies to units that 
report monitoring plan data in accordance with Sec. 75.53(g) and (h).)

[64 FR 28614, May 26, 1999, as amended at 67 FR 40442, June 12, 2002; 70 
FR 28683, May 18, 2005; 63 FR 4354, Jan. 24, 2008; 76 FR 17315, Mar. 28, 
2011]



                    Subpart G_Reporting Requirements



Sec. 75.60  General provisions.

    (a) The designated representative for any affected unit subject to 
the requirements of this part shall comply with all reporting 
requirements in this

[[Page 323]]

section and with the signatory requirements of Sec. 72.21 of this 
chapter for all submissions.
    (b) Submissions. The designated representative shall submit all 
reports and petitions (except as provided in Sec. 75.61) as follows:
    (1) Initial certifications. The designated representative shall 
submit initial certification applications according to Sec. 75.63.
    (2) Recertifications. The designated representative shall submit 
recertification applications according to Sec. 75.63.
    (3) Monitoring plans. The designated representative shall submit 
monitoring plans according to Sec. 75.62.
    (4) Electronic quarterly reports. The designated representative 
shall submit electronic quarterly reports according to Sec. 75.64.
    (5) Other petitions and communications. The designated 
representative shall submit petitions, correspondence, application 
forms, designated representative signature, and petition-related test 
results in hardcopy to the Administrator. Additional petition 
requirements are specified in Sec. Sec. 75.66 and 75.67.
    (6) Semiannual or annual RATA reports. If requested in writing (or 
by electronic mail) by the applicable EPA Regional Office, appropriate 
State, and/or appropriate local air pollution control agency, the 
designated representative shall submit a hardcopy RATA report within 45 
days after completing a required semiannual or annual RATA according to 
section 2.3.1 of appendix B to this part, or within 15 days of receiving 
the request, whichever is later. The designated representative shall 
report the hardcopy information required by Sec. 75.59(a)(9) to the 
applicable EPA Regional Office, appropriate State, and/or appropriate 
local air pollution control agency that requested the RATA report.
    (7) Routine appendix E retest reports. If requested in writing (or 
by electronic mail) by the applicable EPA Regional Office, appropriate 
State, and/or appropriate local air pollution control agency, the 
designated representative shall submit a hardcopy report within 45 days 
after completing a required periodic retest according to section 2.2 of 
appendix E to this part, or within 15 days of receiving the request, 
whichever is later. The designated representative shall report the 
hardcopy information required by Sec. 75.59(b)(5) to the applicable EPA 
Regional Office, appropriate State, and/or appropriate local air 
pollution control agency that requested the hardcopy report.
    (c) Confidentiality of data. The following provisions shall govern 
the confidentiality of information submitted under this part.
    (1) All emission data reported in quarterly reports under Sec. 
75.64 shall remain public information.
    (2) For information submitted under this part other than emission 
data submitted in quarterly reports, the designated representative must 
assert a claim of confidentiality at the time of submission for any 
information he or she wishes to have treated as confidential business 
information (CBI) under subpart B of part 2 of this chapter. Failure to 
assert a claim of confidentiality at the time of submission may result 
in disclosure of the information by EPA without further notice to the 
designated representative.
    (3) Any claim of confidentiality for information submitted in 
quarterly reports under Sec. 75.64 must include substantiation of the 
claim. Failure to provide substantiation may result in disclosure of the 
information by EPA without further notice.
    (4) As provided under subpart B of part 2 of this chapter, EPA may 
review information submitted to determine whether it is entitled to 
confidential treatment even when confidentiality claims are initially 
received. The EPA will contact the designated representative as part of 
such a review process.

[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26538, May 17, 1995; 64 
FR 28620, May 26, 1999; 67 FR 40442, June 12, 2002; 73 FR 4356, Jan. 24, 
2008; 76 FR 17316, Mar. 28, 2011]



Sec. 75.61  Notifications.

    (a) Submission. The designated representative for an affected unit 
(or owner or operator, as specified) shall submit notice to the 
Administrator, to the appropriate EPA Regional Office, and to the 
applicable State and local air pollution control agencies for the 
following purposes, as required by this part.

[[Page 324]]

    (1) Initial certification and recertification test notifications. 
The owner or operator or designated representative for an affected unit 
shall submit written notification of initial certification tests and 
revised test dates as specified in Sec. 75.20 for continuous emission 
monitoring systems, for alternative monitoring systems under subpart E 
of this part, or for excepted monitoring systems under appendix E to 
this part, except as provided in paragraphs (a)(1)(iii), (a)(1)(iv) and 
(a)(4) of this section. The owner or operator shall also provide written 
notification of testing performed under Sec. 75.19(c)(1)(iv)(A) to 
establish fuel-and-unit-specific NOX emission rates for low 
mass emissions units. Such notifications are not required, however, for 
initial certifications and recertifications of excepted monitoring 
systems under appendix D to this part.
    (i) Notification of initial certification testing and full 
recertification. Initial certification test notifications and 
notifications of full recertification testing under Sec. 75.20(b)(2) 
shall be submitted not later than 21 days prior to the first scheduled 
day of certification or recertification testing. In emergency situations 
when full recertification testing is required following an 
uncontrollable failure of equipment that results in lost data, notice 
shall be sufficient if provided within 2 business days following the 
date when testing is scheduled. Testing may be performed on a date other 
than that already provided in a notice under this subparagraph as long 
as notice of the new date is provided either in writing or by telephone 
or other means at least 7 days prior to the original scheduled test date 
or the revised test date, whichever is earlier.
    (ii) Notification of certification retesting, and partial 
recertification testing. For retesting required following a loss of 
certification under Sec. 75.20(a)(5) or for partial recertification 
testing required under Sec. 75.20(b)(2), notice of the date of any 
required RATA testing or any requred retesting under section 2.3 in 
appendix E to this part shall be submitted either in writing or by 
telephone at least 7 days prior to the first scheduled day of testing; 
except that in emergency situations when testing is required following 
an uncontrollable failure of equipment that results in lost data, notice 
shall be sufficient if provided within 2 business days following the 
date when testing is scheduled. Testing may be performed on a date other 
than that already provided in a notice under this subparagraph as long 
as notice of the new date is provided by telephone or other means at 
least 2 business days prior to the original scheduled test date or the 
revised test date, whichever is earlier.
    (iii) Repeat of testing without notice. Notwithstanding the above 
notice requirements, the owner or operator may elect to repeat a 
certification or recertification test immediately, without advance 
notification, whenever the owner or operator has determined during the 
certification or recertification testing that a test was failed or must 
be aborted, or that a second test is necessary in order to attain a 
reduced relative accuracy test frequency.
    (iv) Waiver from notification requirements. The Administrator, the 
appropriate EPA Regional Office, or the applicable State or local air 
pollution control agency may issue a waiver from the notification 
requirement of paragraph (a)(1)(ii) of this section, for a unit or a 
group of units, for one or more recertification tests or other retests. 
The Administrator, the appropriate EPA Regional Office, or the 
applicable State or local air pollution control agency may also 
discontinue the waiver and reinstate the notification requirement of 
paragraph (a)(1)(ii) of this section for future recertification tests 
(or other retests) of a unit or a group of units.
    (2) New unit, newly affected unit, new stack, or new flue gas 
desulfurization system operation notification. The designated 
representative for an affected unit shall submit written notification: 
For a new unit or a newly affected unit, of the planned date when a new 
unit or newly affected unit will commence commercial operation, or 
becomes affected, or, for new stack or flue gas desulfurization system, 
of the planned date when a new stack or flue gas desulfurization system 
will be completed and emissions will first exit to the atmosphere.

[[Page 325]]

    (i) Notification of the planned date shall be submitted not later 
than 45 days prior to the date the unit commences commercial operation 
or becomes affected, or not later than 45 days prior to the date when a 
new stack or flue gas desulfurization system exhausts emissions to the 
atmosphere.
    (ii) If the date when the unit commences commercial operation or 
becomes affected, or the date when the new stack or flue gas 
desulfurization system exhausts emissions to the atmosphere, whichever 
is applicable, changes from the planned date, a notification of the 
actual date shall be submitted not later than 7 days following: The date 
the unit commences commercial operation or becomes affected, or the date 
when a new stack or flue gas desulfurization system exhausts emissions 
to the atmosphere.
    (3) Unit shutdown and recommencement of commercial operation. For an 
affected unit that will be shut down on the relevant compliance date 
specified in Sec. 75.4 or in a State or Federal pollutant mass 
emissions reduction program that adopts the monitoring and reporting 
requirements of this part, if the owner or operator is relying on the 
provisions in Sec. 75.4(d) to postpone certification testing, the 
designated representative for the unit shall submit notification of unit 
shutdown and recommencement of commercial operation as follows:
    (i) For planned unit shutdowns (e.g., extended maintenance outages), 
written notification of the planned shutdown date shall be provided at 
least 21 days prior to the applicable compliance date, and written 
notification of the planned date of recommencement of commercial 
operation shall be provided at least 21 days in advance of unit restart. 
If the actual shutdown date or the actual date of recommencement of 
commercial operation differs from the planned date, written notice of 
the actual date shall be submitted no later than 7 days following the 
actual date of shutdown or of recommencement of commercial operation, as 
applicable;
    (ii) For unplanned unit shutdowns (e.g., forced outages), written 
notification of the actual shutdown date shall be provided no more than 
7 days after the shutdown, and written notification of the planned date 
of recommencement of commercial operation shall be provided at least 21 
days in advance of unit restart. If the actual date of recommencement of 
commercial operation differs from the expected date, written notice of 
the actual date shall be submitted no later than 7 days following the 
actual date of recommencement of commercial operation.
    (4) Use of backup fuels for appendix E procedures. The designated 
representative for an affected oil-fired or gas-fired peaking unit that 
is using an excepted monitoring system under appendix E of this part and 
that is relying on the provisions in Sec. 75.4(f) to postpone testing 
of a fuel shall submit written notification of that fact no later than 
45 days prior to the deadline in Sec. 75.4. The designated 
representative shall also submit a notification that such a fuel has 
been combusted no later than 7 days after the first date of combustion 
of any fuel for which testing has not been performed under appendix E 
after the deadline in Sec. 75.4. Such notice shall also include notice 
that testing under appendix E either was performed during the initial 
combustion or notice of the date that testing will be performed.
    (5) Periodic relative accuracy test audits, appendix E retests, and 
low mass emissions unit retests. The owner or operator or designated 
representative of an affected unit shall submit written notice of the 
date of periodic relative accuracy testing performed under section 2.3.1 
of appendix B to this part, of periodic retesting performed under 
section 2.2 of appendix E to this part, and of periodic retesting of low 
mass emissions units performed under Sec. 75.19(c)(1)(iv)(D), no later 
than 21 days prior to the first scheduled day of testing. Testing may be 
performed on a date other than that already provided in a notice under 
this subparagraph as long as notice of the new date is provided either 
in writing or by telephone or other means acceptable to the respective 
State agency or office of EPA, and the notice is provided as soon as 
practicable after the new testing date is known, but no later than 
twenty-four (24) hours in advance of the new date of testing.

[[Page 326]]

    (i) Written notification under paragraph (a) (5) of this section may 
be provided either by mail or by facsimile. In addition, written 
notification may be provided by electronic mail, provided that the 
respective State agency or office of EPA agrees that this is an 
acceptable form of notification.
    (ii) Notwithstanding the notice requirements under paragraph (a)(5) 
of this section, the owner or operator may elect to repeat a periodic 
relative accuracy test, appendix E restest, or low mass emissions unit 
retest immediately, without additional notification whenever the owner 
or operator has determined that a test was failed, or that a second test 
is necessary in order to attain a reduced relative accuracy test 
frequency.
    (iii) Waiver from notification requirements. The Administrator, the 
appropriate EPA Regional Office, or the applicable State air pollution 
control agency may issue a waiver from the requirement of paragraph 
(a)(5) of this section to provide notice to the respective State agency 
or office of EPA for a unit or a group of units for one or more tests. 
The Administrator, the appropriate EPA Regional Office, or the 
applicable State air pollution control agency may also discontinue the 
waiver and reinstate the requirement of paragraph (a)(5) of this section 
to provide notice to the respective State agency or office of EPA for 
future tests for a unit or a group of units. In addition, if an observer 
from a State agency or EPA is present when a test is rescheduled, the 
observer may waive all notification requirements under paragraph (a)(5) 
of this section for the rescheduled test.
    (6) Notice of combustion of emergency fuel under appendix D or E. 
The designated representative of an oil-fired unit or gas-fired unit 
using appendix D or E of this part shall, for each calendar quarter in 
which emergency fuel is combusted, provide notice of the combustion of 
the emergency fuel in the cover letter (or electronic equivalent) which 
transmits the next quarterly report submitted under Sec. 75.64. The 
notice shall specify the exact dates and hours during which the 
emergency fuel was combusted.
    (7) Long-term cold storage and recommencement of commercial 
operation. The designated representative for an affected unit that is 
placed into long-term cold storage that is relying on the provisions in 
Sec. 75.4(d) or Sec. 75.64(a), either to postpone certification 
testing or to discontinue the submittal of quarterly reports during the 
period of long-term cold storage, shall provide written notification of 
long-term cold storage status and recommencement of commercial operation 
as follows:
    (i) Whenever an affected unit has been placed into long-term cold 
storage, written notification of the date and hour that the unit was 
shutdown and a statement from the designated representative stating that 
the shutdown is expected to last for at least two years from that date, 
in accordance with the definition for long-term cold storage of a unit 
as provided in Sec. 72.2 of this chapter.
    (ii) Whenever an affected unit that has been placed into long-term 
cold storage is expected to resume operation, written notification shall 
be submitted 45 calendar days prior to the planned date of 
recommencement of commercial operation. If the actual date of 
recommencement of commercial operation differs from the expected date, 
written notice of the actual date shall be submitted no later than 7 
days following the actual date of recommencement of commercial 
operation.
    (8) Certification deadline date for new or newly affected units. The 
designated representative of a new or newly affected unit shall provide 
notification of the date on which the relevant deadline for initial 
certification is reached, either as provided in Sec. 75.4(b) or Sec. 
75.4(c), or as specified in a State or Federal SO2 or 
NOX mass emission reduction program that incorporates by 
reference, or otherwise adopts, the monitoring, recordkeeping, and 
reporting requirements of subpart F, G, or H of this part. The 
notification shall be submitted no later than 7 calendar days after the 
applicable certification deadline is reached.

[[Page 327]]

    (b) The owner or operator or designated representative shall submit 
notification of certification tests and recertification tests for 
continuous opacity monitoring systems as specified in Sec. 75.20(c)(8) 
to the State or local air pollution control agency.
    (c) If the Administrator determines that notification substantially 
similar to that required in this section is required by any other State 
or local agency, the owner or operator or designated representative may 
send the Administrator a copy of that notification to satisfy the 
requirements of this section, provided the ORISPL unit identification 
number(s) is denoted.

[60 FR 26538, May 17, 1995, as amended at 61 FR 25582, May 22, 1996; 61 
FR 59162, Nov. 22, 1996; 64 FR 28620, May 26, 1999; 67 FR 40442, 40443, 
June 12, 2002; 73 FR 4356, Jan. 24, 2008; 76 FR 17316, Mar. 28, 2011]



Sec. 75.62  Monitoring plan submittals.

    (a) Submission--(1) Electronic. Using the format specified in 
paragraph (c) of this section, the designated representative for an 
affected unit shall submit a complete, electronic, up-to-date monitoring 
plan file (except for hardcopy portions identified in paragraph (a)(2) 
of this section) to the Administrator as follows: no later than 21 days 
prior to the initial certification tests; at the time of each 
certification or recertification application submission; and (prior to 
or concurrent with) the submittal of the electronic quarterly report for 
a reporting quarter where an update of the electronic monitoring plan 
information is required, either under Sec. 75.53(b) or elsewhere in 
this part.
    (2) Hardcopy. The designated representative shall submit all of the 
hardcopy information required under Sec. 75.53 to the appropriate EPA 
Regional Office and the appropriate State and/or local air pollution 
control agency prior to initial certification. Thereafter, the 
designated representative shall submit hardcopy information only if that 
portion of the monitoring plan is revised. The designated representative 
shall submit the required hardcopy information as follows: no later than 
21 days prior to the initial certification test; with any certification 
or recertification application, if a hardcopy monitoring plan change is 
associated with the certification or recertification event; and within 
30 days of any other event with which a hardcopy monitoring plan change 
is associated, pursuant to Sec. 75.53(b). Electronic submittal of all 
monitoring plan information, including hardcopy portions, is permissible 
provided that a paper copy of the hardcopy portions can be furnished 
upon request.
    (b) Contents. Monitoring plans shall contain the information 
specified in Sec. 75.53 of this part.
    (c) Format. The designated representative shall submit each 
monitoring plan in a format specified by the Administrator.
    (d) On and after April 27, 2011, consistent with Sec. 72.21 of this 
chapter, a hardcopy cover letter signed by the Designated Representative 
(DR) shall accompany each hardcopy monitoring plan submittal. The cover 
letter shall include the certification statement described in Sec. 
72.21(b) of this chapter, and shall be submitted to the applicable EPA 
Regional Office and to the appropriate State or local air pollution 
control agency. For electronic monitoring plan submittals to the 
Administrator, a cover letter is not required. However, at his or her 
discretion, the DR may include important explanatory text or comments 
with an electronic monitoring plan submittal, so long as the information 
is provided in an electronic format that is compatible with the other 
data required to be reported under this section.

[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26539, May 17, 1995; 64 
FR 28621, May 26, 1999; 67 FR 40443, June 12, 2002; 73 FR 4356, Jan. 24, 
2008; 76 FR 17316, Mar. 28, 2011]



Sec. 75.63  Initial certification or recertification application.

    (a) Submission. The designated representative for an affected unit 
or a combustion source shall submit applications and reports as follows:
    (1) Initial certifications. (i) For CEM systems or excepted 
monitoring systems under appendix D or E to this part, within 45 days 
after completing all initial certification tests, submit:
    (A) To the Administrator, the electronic information required by 
paragraph (b)(1) of this section. Except for

[[Page 328]]

subpart E applications for alternative monitoring systems or unless 
specifically requested by the Administrator, do not submit a hardcopy of 
the test data and results to the Administrator.
    (B) To the applicable EPA Regional Office and the appropriate State 
and/or local air pollution control agency, the hardcopy information 
required by paragraph (b)(2) of this section.
    (ii) For units for which the owner or operator is applying for 
certification approval of the optional excepted methodology under Sec. 
75.19 for low mass emissions units, submit, no later than 45 days prior 
to commencing use of the methodology:
    (A) To the Administrator, the electronic low mass emission 
qualification information required by Sec. 75.53(f)(5)(i) or Sec. 
75.53(h)(4)(i) (as applicable) and paragraph (b)(1)(i) of this section; 
and
    (B) To the applicable EPA Regional Office and appropriate State and/
or local air pollution control agency, the hardcopy information required 
by Sec. 75.19(a)(2) and Sec. 75.53(f)(5)(ii) or Sec. 75.53(h)(4)(ii) 
(as applicable), the hardcopy results of any appendix E (of this part) 
tests or any CEMS data analysis used to derive a fuel-and-unit-specific 
default NOX emission rate.
    (2) Recertifications and diagnostic testing. (i) Within 45 days 
after completing all recertification tests under Sec. 75.20(b), submit 
to the Administrator the electronic information required by paragraph 
(b)(1) of this section. Except for subpart E applications for 
alternative monitoring systems or unless specifically requested by the 
Administrator, do not submit a hardcopy of the test data and results to 
the Administrator.
    (ii) Within 45 days after completing all recertification tests under 
Sec. 75.20(b), submit the hardcopy information required by paragraph 
(b)(2) of this section to the applicable EPA Regional Office and the 
appropriate State and/or local air pollution control agency. The 
applicable EPA Regional Office or appropriate State or local air 
pollution control agency may waive the requirement to provide hardcopy 
recertification test and data results. The applicable EPA Regional 
Office or the appropriate State or local air pollution control agency 
may also discontinue the waiver and reinstate the requirement of this 
paragraph to provide a hardcopy report of the recertification test data 
and results.
    (iii) Notwithstanding the requirements of paragraphs (a)(2)(i) and 
(a)(2)(ii) of this section, for an event for which the Administrator 
determines that only diagnostic tests (see Sec. 75.20(b)) are required 
rather than recertification testing, no hardcopy submittal is required; 
however, the results of all diagnostic test(s) shall be submitted prior 
to or concurrent with the electronic quarterly report required under 
Sec. 75.64. Notwithstanding the requirement of Sec. 75.59(e), for DAHS 
(missing data and formula) verifications, no hardcopy submittal is 
required; the owner or operator shall keep these test results on-site in 
a format suitable for inspection.
    (b) Contents. Each application for initial certification or 
recertification shall contain the following information, as applicable:
    (1) Electronic. (i) A complete, up-to-date version of the electronic 
portion of the monitoring plan, according to Sec. 75.53(e) and (f), in 
the format specified in Sec. 75.62(c).
    (ii) The results of the test(s) required by Sec. 75.20, including 
the type of test conducted, testing date, information required by Sec. 
75.59, and the results of any failed tests that affect data validation.
    (2) Hardcopy. (i) Any changed portions of the hardcopy monitoring 
plan information required under Sec. 75.53(e) and (f). Electronic 
submittal of all monitoring plan information, including the hardcopy 
portions, is permissible, provided that a paper copy can be furnished 
upon request.
    (ii) The results of the test(s) required by Sec. 75.20, including 
the type of test conducted, testing date, information required by Sec. 
75.59(a)(9), and the results of any failed tests that affect data 
validation.
    (iii) [Reserved]
    (iv) Designated representative signature certifying the accuracy of 
the submission.
    (c) Format. The electronic portion of each certification or 
recertification application shall be submitted in a format to be 
specified by the Administrator. The hardcopy test results shall

[[Page 329]]

be submitted in a format suitable for review and shall include the 
information in Sec. 75.59(a)(9).
    (d) Consistent with Sec. 72.21 of this chapter, a hardcopy cover 
letter signed by the Designated Representative (DR) shall accompany the 
hardcopy portion of each certification or recertification application. 
The cover letter shall include the certification statement described in 
Sec. 72.21(b) of this chapter, and shall be submitted to the applicable 
EPA Regional Office and to the appropriate State or local air pollution 
control agency. For the electronic portion of a certification or 
recertification application submitted to the Administrator, a cover 
letter is not required. However, at his or her discretion, the DR may 
include important explanatory text or comments with the electronic 
portion of a certification or recertification application, so long as 
the information is provided in an electronic format compatible with the 
other data required to be reported under this section.

[64 FR 28621, May 26, 1999, as amended at 67 FR 40443, June 12, 2002; 73 
FR 4357, Jan. 24, 2008; 76 FR 17317, Mar. 28, 2011]



Sec. 75.64  Quarterly reports.

    (a) Electronic submission. The designated representative for an 
affected unit shall electronically report the data and information in 
paragraphs (a), (b), and (c) of this section to the Administrator 
quarterly, beginning with the data from the earlier of the calendar 
quarter corresponding to the date of provisional certification or the 
calendar quarter corresponding to the relevant deadline for initial 
certification in Sec. 75.4(a), (b), or (c). The initial quarterly 
report shall contain hourly data beginning with the hour of provisional 
certification or the hour corresponding to the relevant certification 
deadline, whichever is earlier. For an affected unit subject to Sec. 
75.4(d) that is shutdown on the relevant compliance date in Sec. 
75.4(a) or has been placed in long-term cold storage (as defined in 
Sec. 72.2 of this chapter), quarterly reports are not required. In such 
cases, the owner or operator shall submit quarterly reports for the unit 
beginning with the data from the quarter in which the unit recommences 
commercial operation (where the initial quarterly report contains hourly 
data beginning with the first hour of recommenced commercial operation 
of the unit). For units placed into long-term cold storage during a 
reporting quarter, the exemption from submitting quarterly reports 
begins with the calendar quarter following the date that the unit is 
placed into long-term cold storage. For any provisionally-certified 
monitoring system, Sec. 75.20(a)(3) shall apply for initial 
certifications, and Sec. 75.20(b)(5) shall apply for recertifications. 
Each electronic report must be submitted to the Administrator within 30 
days following the end of each calendar quarter. Prior to January 1, 
2008, each electronic report shall include for each affected unit (or 
group of units using a common stack), the information provided in 
paragraphs (a)(1), (a)(2), and (a)(8) through (a)(15) of this section. 
During the time period of January 1, 2008 to January 1, 2009, each 
electronic report shall include, either the information provided in 
paragraphs (a)(1), (a)(2), and (a)(8) through (a)(15) of this section or 
the information provided in paragraphs (a)(3) through (a)(15) of this 
section. On and after January 1, 2009, the owner or operator shall meet 
the requirements of paragraphs (a)(3) through (a)(15) of this section 
only. Each electronic report shall also include the date of report 
generation.
    (1) Facility information:
    (i) Identification, including:
    (A) Facility/ORISPL number;
    (B) Calendar quarter and year for the data contained in the report; 
and
    (C) Version of the electronic data reporting format used for the 
report.
    (ii) Location, including:
    (A) Plant name and facility ID;
    (B) EPA AIRS facility system ID;
    (C) State facility ID;
    (D) Source category/type;
    (E) Primary SIC code;
    (F) State postal abbreviation;
    (G) County code; and
    (H) Latitude and longitude.
    (2) The information and hourly data required in Sec. 75.53 and 
Sec. Sec. 75.57 through 75.59, excluding the following:
    (i) Descriptions of adjustments, corrective action, and maintenance;

[[Page 330]]

    (ii) Information which is incompatible with electronic reporting 
(e.g., field data sheets, lab analyses, quality control plan);
    (iii) Opacity data listed in or Sec. 75.57(f), and in Sec. 
75.59(a)(8);
    (iv) For units with SO2 or NOX add-on emission 
controls that do not elect to use the approved site-specific parametric 
monitoring procedures for calculation of substitute data, the 
information in Sec. 75.58(b)(3);
    (v) [Reserved]
    (vi) Information required by Sec. 75.57(h) concerning the causes of 
any missing data periods and the actions taken to cure such causes;
    (vii) Hardcopy monitoring plan information required by Sec. 75.53 
and hardcopy test data and results required by Sec. 75.59;
    (viii) Records of flow monitor and moisture monitoring system 
polynomial equations, coefficients, or ``K'' factors required by Sec. 
75.59(a)(5)(vi) or Sec. 75.59(a)(5)(vii);
    (ix) Daily fuel sampling information required by Sec. 
75.58(c)(3)(i) for units using assumed values under appendix D;
    (x) Information required by Sec. Sec. 75.59(b)(1)(vi), (vii), 
(viii), (ix), and (xiii), and (b)(2)(iii) and (iv) concerning fuel 
flowmeter accuracy tests and transmitter/transducer accuracy tests;
    (xi) Stratification test results required as part of the RATA 
supplementary records under Sec. 75.59(a)(7);
    (xii) Data and results of RATAs that are aborted or invalidated due 
to problems with the reference method or operational problems with the 
unit and data and results of linearity checks that are aborted or 
invalidated due to problems unrelated to monitor performance; and
    (xiii) Supplementary RATA information required under Sec. 
75.59(a)(7), except that:
    (A) The applicable data elements under Sec. 75.59(a)(7)(ii)(A) 
through (T) and under Sec. 75.59(a)(7)(iii)(A) through (M) shall be 
reported for flow RATAs at circular or rectangular stacks (or ducts) in 
which angular compensation for yaw and/or pitch angles is used (i.e., 
Method 2F or 2G in appendices A-1 and A-2 to part 60 of this chapter), 
with or without wall effects adjustments;
    (B) The applicable data elements under Sec. 75.59(a)(7)(ii)(A) 
through (T) and under Sec. 75.59(a)(7)(iii)(A) through (M) shall be 
reported for any flow RATA run at a circular stack in which Method 2 in 
appendices A-1 and A-2 to part 60 of this chapter is used and a wall 
effects adjustment factor is determined by direct measurement;
    (C) The data under Sec. 75.59(a)(7)(ii)(T) shall be reported for 
all flow RATAs at circular stacks in which Method 2 in appendices A-1 
and A-2 to part 60 of this chapter is used and a default wall effects 
adjustment factor is applied; and
    (D) The data under Sec. 75.59(a)(7)(ix)(A) through (F) shall be 
reported for all flow RATAs at rectangular stacks or ducts in which 
Method 2 in appendices A-1 and A-2 to part 60 of this chapter is used 
and a wall effects adjustment factor is applied.
    (3) Facility identification information, including:
    (i) Facility/ORISPL number;
    (ii) Calendar quarter and year for the data contained in the report; 
and
    (iii) Version of the electronic data reporting format used for the 
report.
    (4) In accordance with Sec. 75.62(a)(1), if any monitoring plan 
information required in Sec. 75.53 requires an update, either under 
Sec. 75.53(b) or elsewhere in this part, submission of the electronic 
monitoring plan update shall be completed prior to or concurrent with 
the submittal of the quarterly electronic data report for the 
appropriate quarter in which the update is required.
    (5) The daily calibration error test and daily interference check 
information required in Sec. 75.59(a)(1) and (a)(2) must always be 
included in the electronic quarterly emissions report. All other 
certification, quality assurance, and quality control information in 
Sec. 75.59 that is not excluded from electronic reporting under 
paragraph (a)(2) or (a)(7) of this section shall be submitted 
separately, either prior to or concurrent with the submittal of the 
relevant electronic quarterly emissions report. However, reporting of 
the information in Sec. 75.59(a)(9)(x) is not required until September 
26, 2011, and reporting of the information in Sec. 75.59(a)(15), 
(b)(6), and (d)(4) is not required until March 27, 2012.

[[Page 331]]

    (6) The information and hourly data required in Sec. Sec. 75.57 
through 75.59, and daily calibration error test data, daily interference 
check, and off-line calibration demonstration information required in 
Sec. 75.59(a)(1) and (2).
    (7) Notwithstanding the requirements of paragraphs (a)(4) through 
(a)(6) of this section, the following information is excluded from 
electronic reporting:
    (i) Descriptions of adjustments, corrective action, and maintenance;
    (ii) Information which is incompatible with electronic reporting 
(e.g., field data sheets, lab analyses, quality control plan);
    (iii) Opacity data listed in Sec. 75.57(f), and in Sec. 
75.59(a)(8);
    (iv) For units with SO2 or NOX add-on emission 
controls that do not elect to use the approved site-specific parametric 
monitoring procedures for calculation of substitute data, the 
information in Sec. 75.58(b)(3);
    (v) Information required by Sec. 75.57(h) concerning the causes of 
any missing data periods and the actions taken to cure such causes;
    (vi) Hardcopy monitoring plan information required by Sec. 75.53 
and hardcopy test data and results required by Sec. 75.59;
    (vii) Records of flow monitor and moisture monitoring system 
polynomial equations, coefficients, or ``K'' factors required by Sec. 
75.59(a)(5)(vi) or Sec. 75.59(a)(5)(vii);
    (viii) Daily fuel sampling information required by Sec. 
75.58(c)(3)(i) for units using assumed values under appendix D of this 
part;
    (ix) Information required by Sec. Sec. 75.59(b)(1)(vi), (vii), 
(viii), (ix), and (xiii), and (b)(2)(iii) and (iv) concerning fuel 
flowmeter accuracy tests and transmitter/transducer accuracy tests;
    (x) Stratification test results required as part of the RATA 
supplementary records under Sec. 75.59(a)(7);
    (xi) Data and results of RATAs that are aborted or invalidated due 
to problems with the reference method or operational problems with the 
unit and data and results of linearity checks that are aborted or 
invalidated due to problems unrelated to monitor performance;
    (xii) Supplementary RATA information required under Sec. 
75.59(a)(7)(i) through Sec. 75.59(a)(7)(v), except that:
    (A) The applicable data elements under Sec. 75.59(a)(7)(ii)(A) 
through (T) and under Sec. 75.59(a)(7)(iii)(A) through (M) shall be 
reported for flow RATAs at circular or rectangular stacks (or ducts) in 
which angular compensation for yaw and/or pitch angles is used (i.e., 
Method 2F or 2G in appendices A-1 and A-2 to part 60 of this chapter), 
with or without wall effects adjustments;
    (B) The applicable data elements under Sec. 75.59(a)(7)(ii)(A) 
through (T) and under Sec. 75.59(a)(7)(iii)(A) through (M) shall be 
reported for any flow RATA run at a circular stack in which Method 2 in 
appendices A-1 and A-2 to part 60 of this chapter is used and a wall 
effects adjustment factor is determined by direct measurement;
    (C) The data under Sec. 75.59(a)(7)(ii)(T) shall be reported for 
all flow RATAs at circular stacks in which Method 2 in appendices A-1 
and A-2 to part 60 of this chapter is used and a default wall effects 
adjustment factor is applied; and
    (D) The data under Sec. 75.59(a)(7)(ix)(A) through (F) shall be 
reported for all flow RATAs at rectangular stacks or ducts in which 
Method 2 in appendices A-1 and A-2 to part 60 of this chapter is used 
and a wall effects adjustment factor is applied; and
    (xiii) The certification required by section 6.1.2(b) of appendix A 
to this part and recorded under Sec. 75.57(a)(7).
    (8) Tons (rounded to the nearest tenth) of SO2 emitted 
during the quarter and cumulative SO2 emissions for the 
calendar year.
    (9) Average NOX emission rate (lb/mmBtu, rounded to the 
nearest thousandth) during the quarter and cumulative NOX 
emission rate for the calendar year.
    (10) Tons of CO2 emitted during quarter and cumulative 
CO2 emissions for calendar year.
    (11) Total heat input (mmBtu) for quarter and cumulative heat input 
for calendar year.
    (12) Unit or stack or common pipe header operating hours for quarter 
and cumulative unit or stack or common pipe header operating hours for 
calendar year.
    (13) For low mass emissions units for which the owner or operator is 
using

[[Page 332]]

the optional low mass emissions methodology in Sec. 75.19(c) to 
calculate NOX mass emissions, the designated representative 
must also report tons (rounded to the nearest tenth) of NOX 
emitted during the quarter and cumulative NOX mass emissions 
for the calendar year.
    (14) For low mass emissions units using the optional long term fuel 
flow methodology under Sec. 75.19(c), for each quarter report the long 
term fuel flow for each fuel according to Sec. 75.58(f)(2).
    (15) For units using the optional fuel flow to load procedure in 
section 2.1.7 of appendix D to this part, report both the fuel flow-to-
load baseline data and the results of the fuel flow-to-load test each 
quarter.
    (b) The designated representative shall affirm that the component/
system identification codes and formulas in the quarterly electronic 
reports, submitted to the Administrator pursuant to Sec. 75.53, 
represent current operating conditions.
    (c) Compliance certification. The designated representative shall 
submit a certification in support of each quarterly emissions monitoring 
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 indicate whether 
the monitoring data submitted were recorded in accordance with the 
applicable requirements of this part including the quality control and 
quality assurance procedures and specifications of this part and its 
appendices, and any such requirements, procedures and specifications of 
an applicable excepted or approved alternative monitoring method. For a 
unit with add-on emission controls, the designated representative shall 
also include a certification, for all hours where data are substituted 
following the provisions of Sec. 75.34(a)(1), that the add-on emission 
controls were operating within the range of parameters listed in the 
monitoring plan and that the substitute values recorded during the 
quarter do not systematically underestimate SO2 or 
NOX emissions, pursuant to Sec. 75.34.
    (d) Electronic format. Each quarterly report shall be submitted in a 
format to be specified by the Administrator, including both electronic 
submission of data and (unless otherwise approved by the Administrator) 
electronic submission of compliance certifications.
    (e) [Reserved]
    (f) Method of submission. Beginning with the quarterly report for 
the first quarter of the year 2001, all quarterly reports shall be 
submitted to EPA by direct computer-to-computer electronic transfer via 
EPA-provided software, unless otherwise approved by the Administrator.
    (g) At his or her discretion, the DR may include important 
explanatory text or comments with an electronic quarterly report 
submittal, so long as the information is provided in a format that is 
compatible with the other data required to be reported under this 
section.

[64 FR 28622, May 26, 1999, as amended at 67 FR 40444, June 12, 2002; 73 
FR 4357, Jan. 24, 2008; 76 FR 17317, Mar. 28, 2011]



Sec. 75.65  Opacity reports.

    The owner or operator or designated representative shall report 
excess emissions of opacity recorded under Sec. 75.57(f) to the 
applicable State or local air pollution control agency.

[64 FR 28623, May 26, 1999, as amended at 67 FR 40444, June 12, 2002]



Sec. 75.66  Petitions to the Administrator.

    (a) General. The designated representative for an affected unit 
subject to the requirements of this part may submit a petition to the 
Administrator requesting that the Administrator exercise his or her 
discretion to approve an alternative to any requirement prescribed in 
this part or incorporated by reference in this part. Any such petition 
shall be submitted in accordance with the requirements of this section. 
The designated representative shall comply with the signatory 
requirements of Sec. 72.21 of this chapter for each submission.
    (b) Alternative flow monitoring method petition. In cases where no 
location exists for installation of a flow monitor in either the stack 
or the ducts serving an affected unit that satisfies the minimum 
physical siting criteria in appendix A of this part or where 
installation

[[Page 333]]

of a flow monitor in either the stack or duct is demonstrated to the 
satisfaction of the Administrator to be technically infeasible, the 
designated representative for the affected unit may petition the 
Administrator for an alternative method for monitoring volumetric flow. 
The petition shall, at a minimum, contain the following information:
    (1) Identification of the affected unit(s);
    (2) Description of why the minimum siting criteria cannot be met 
within the existing ductwork or stack(s). This description shall include 
diagrams of the existing ductwork or stack, as well as documentation of 
any attempts to locate a flow monitor; and
    (3) Description of proposed alternative method for monitoring flow.
    (c) Alternative to standards incorporated by reference. The 
designated representative for an affected unit may apply to the 
Administrator for an alternative to any standard incorporated by 
reference and prescribed in this part. The designated representative 
shall include the following information in an application:
    (1) A description of why the prescribed standard is not being used;
    (2) A description and diagram(s) of any equipment and procedures 
used in the proposed alternative;
    (3) Information demonstrating that the proposed alternative produces 
data acceptable for use in the Acid Rain Program, including accuracy and 
precision statements, NIST traceability certificates or protocols, or 
other supporting data, as applicable to the proposed alternative.
    (d) Alternative monitoring system petitions. The designated 
representative for an affected unit may submit a petition to the 
Administrator for approval and certification of an alternative 
monitoring system or component according to the procedure in subpart E 
of this part. Each petition shall contain the information and data 
specified in subpart E, including the information specified in Sec. 
75.48, in a format to be specified by the Administrator.
    (e) Parametric monitoring procedure petitions. The designated 
representative for an affected unit may submit a petition to the 
Administrator, where each petition shall contain the information 
specified in Sec. 75.58(b) for the use of a parametric monitoring 
method. The Administrator will either:
    (1) Publish a notice in the Federal Register indicating receipt of a 
parametric monitoring procedure petition;, or
    (2) Notify interested parties of receipt of a parametric monitoring 
petition.
    (f) [Reserved]
    (g) Petitions for emissions or heat input apportionments. The 
designated representative of an affected unit shall provide information 
to describe a method for emissions or heat input apportionment under 
Sec. Sec. 75.13, 75.16, 75.17, or appendix D of this part. This 
petition may be submitted as part of the monitoring plan. Such a 
petition shall contain, at a minimum, the following information:
    (1) A description of the units, including their fuel type, their 
boiler type, and their categorization as Phase I units, substitution 
units, compensating units, Phase II units, new units, or non-affected 
units;
    (2) A formula describing how the emissions or heat input are to be 
apportioned to which units;
    (3) A description of the methods and parameters used to apportion 
the emissions or heat input; and
    (4) Any other information necessary to demonstrate that the 
apportionment method accurately measures emissions or heat input and 
does not underestimate emissions or heat input from affected units.
    (h) Partial recertification petition. The designated representative 
of an affected unit may provide information and petition the 
Administrator to specify which of the certification tests required by 
Sec. 75.20 apply for partial recertification of the affected unit. Such 
a petition shall include the following information:
    (1) Identification of the monitoring system(s) being changed;
    (2) A description of the changes being made to the system;
    (3) An explanation of why the changes are being made; and
    (4) A description of the possible effect upon the monitoring 
system's ability

[[Page 334]]

to measure, record, and report emissions.
    (i) [Reserved]
    (j) Petition for alternative method of accounting for emissions 
prior to completion of certification tests. The designated 
representative for an affected unit may submit a petition to the 
Administrator to use an alternative to the procedures in Sec. 
75.4(d)(3), (e)(3), (f)(3) or (g)(3) to account for emissions during the 
period between the compliance date for a unit and the completion of 
certification testing for that unit. The designated representative shall 
include:
    (1) Identification of the affected unit(s);
    (2) A detailed explanation of the alternative method to account for 
emissions of the following parameters, as applicable: SO2 
mass emissions (in lbs), NOX emission rate (in lbs/mmBtu), 
CO2 mass emissions (in lbs) and, if the unit is subject to 
the requirements of subpart H of this part, NOX mass 
emissions (in lbs); and
    (3) A demonstration that the proposed alternative does not 
underestimate emissions.
    (k) Petition for an alternative to the stabilization criteria for 
the cycle time test in section 6.4 of appendix A to this part. The 
designated representative for an affected unit may submit a petition to 
the Administrator to use an alternative stabilization criteria for the 
cycle time test in section 6.4 of appendix A to this part, if the 
installed monitoring system does not record data in 1-minute or 3-minute 
intervals. The designated representative shall provide a description of 
the alternative criteria.
    (l) Any other petitions to the Administrator under this part. Except 
for petitions addressed in paragraphs (b) through (k) of this section, 
any petition submitted under this paragraph shall include sufficient 
information for the evaluation of the petition, including, at a minimum, 
the following information:
    (1) Identification of the affected plant and unit(s);
    (2) A detailed explanation of why the proposed alternative is being 
suggested in lieu of the requirement;
    (3) A description and diagram of any equipment and procedures used 
in the proposed alternative, if applicable;
    (4) A demonstration that the proposed alternative is consistent with 
the purposes of the requirement for which the alternative is proposed 
and is consistent with the purposes of this part and of section 412 of 
the Act and that any adverse effect of approving such alternative will 
be de minimis; and
    (5) Any other relevant information that the Administrator may 
require.

[58 FR 3701, Jan. 11, 1993,as amended at 60 FR 26540, 26569, May 17, 
1995; 61 FR 59162, Nov. 20, 1996; 64 FR 28623, May 26, 1999; 67 FR 
40444, June 12, 2002; 73 FR 4358, Jan. 24, 2008]



Sec. 75.67  Retired units petitions.

    (a) [Reserved]
    (b) For combustion sources seeking to enter the Opt-in Program in 
accordance with part 74 of this chapter that will be permanently retired 
and governed upon entry into the Opt-in Program by a thermal energy plan 
in accordance with Sec. 74.47 of this chapter, an exemption from the 
requirements of this part, including the requirement to install and 
certify a continuous emissions monitoring system, may be obtained from 
the Administrator if the designated representative submits to the 
Administrator a petition for such an exemption prior to the deadline in 
Sec. 75.4 by which the continuous emission or opacity monitoring 
systems must complete the required certification tests.

[60 FR 17131, Apr. 4, 1995, as amended at 60 FR 26541, May 17, 1995; 62 
FR 55487, Oct. 24, 1997]



                 Subpart H_NOX Mass Emissions Provisions

    Source: 63 FR 57507, Oct. 27, 1998, unless otherwise noted.



Sec. 75.70  NOX mass emissions provisions.

    (a) Applicability. The owner or operator of a unit shall comply with 
the requirements of this subpart to the extent that compliance is 
required by an applicable State or federal NOX mass emission 
reduction program that incorporates by reference, or otherwise adopts 
the provisions of, this subpart.

[[Page 335]]

    (1) For purposes of this subpart, the term ``affected unit'' shall 
mean any unit that is subject to a State or federal NOX mass 
emission reduction program requiring compliance with this subpart, the 
term ``non-affected unit'' shall mean any unit that is not subject to 
such a program, the term ``permitting authority'' shall mean the 
permitting authority under an applicable State or federal NOX 
mass emission reduction program that adopts the requirements of this 
subpart, and the term ``designated representative'' shall mean the 
responsible party under the applicable State or federal NOX 
mass emission reduction program that adopts the requirements of this 
subpart.
    (2) In addition, the provisions of subparts A, C, D, E, F, and G and 
appendices A through G of this part applicable to NOX 
concentration, flow rate, NOX emission rate and heat input, 
as set forth and referenced in this subpart, shall apply to the owner or 
operator of a unit required to meet the requirements of this subpart by 
a State or federal NOX mass emission reduction program. When 
applying these requirements, the term ``affected unit'' shall mean any 
unit that is subject to a State or federal NOX mass emission 
reduction program requiring compliance with this subpart, the term 
``permitting authority'' shall mean the permitting authority under an 
applicable State or federal NOX mass emission reduction 
program that adopts the requirements of this subpart, and the term 
``designated representative'' shall mean the responsible party under the 
applicable State or federal NOX mass emission reduction 
program that adopts the requirements of this subpart. The requirements 
of this part for SO2, CO2 and opacity monitoring, 
recordkeeping and reporting do not apply to units that are subject to a 
State or federal NOX mass emission reduction program only and 
are not affected units with an Acid Rain emission limitation.
    (b) Compliance dates. The owner or operator of an affected unit 
shall meet the compliance deadlines established by an applicable State 
or federal NOX mass emission reduction program that adopts 
the requirements of this subpart.
    (c) Prohibitions. (1) No owner or operator of an affected unit or a 
non-affected unit 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 
paragraph (h) of this section.
    (2) No owner or operator of an affected unit or a non-affected unit 
under Sec. 75.72(b)(2)(ii) shall operate the unit so as to discharge, 
or allow to be discharged emissions of NOX to the atmosphere 
without accounting for all such emissions in accordance with the 
applicable provisions of this part, except as provided in Sec. 75.74.
    (3) No owner or operator of an affected unit or a non-affected unit 
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 
provisions of this part applicable to monitoring systems under Sec. 
75.71, except as provided in Sec. 75.74.
    (4) No owner or operator of an affected unit or a non-affected unit 
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 part, except 
under any one of the following circumstances:
    (i) During the period that the unit is covered by a retired unit 
exemption that is in effect under the State or federal NOX 
mass emission reduction program that adopts the requirements of this 
subpart;
    (ii) The owner or operator is monitoring NOX mass 
emissions from the affected unit with another certified monitoring 
system approved, in accordance with the provisions of paragraph (d) of 
this section; or

[[Page 336]]

    (iii) The designated representative submits notification of the date 
of certification testing of a replacement monitoring system in 
accordance with Sec. 75.61.
    (d) Initial certification and recertification procedures. (1) The 
owner or operator of an affected unit that is subject to an Acid Rain 
emissions limitation shall comply with the initial certification and 
recertification procedures in Sec. 75.20 of this part, except that the 
owner or operator shall meet any additional requirements set forth in an 
applicable State or federal NOX mass emission reduction 
program that adopts the requirements of this subpart.
    (2) The owner or operator of an affected unit that is not subject to 
an Acid Rain emissions limitation shall comply with the initial 
certification and recertification procedures established by an 
applicable State or federal NOX mass emission reduction 
program that adopts the requirements of this subpart. The owner or 
operator of an affected unit that is subject to an Acid Rain emissions 
limitation shall comply with the initial certification and 
recertification procedures established by an applicable State or federal 
NOX mass emission reduction program that adopts the 
requirements of this subpart for any additional NOX-diluent 
CEMS, flow monitors, diluent monitors or NOX concentration 
monitoring system required under the NOX mass emissions 
provisions of Sec. 75.71 or the common stack provisions in Sec. 75.72.
    (e) Quality assurance and quality control requirements. For units 
that use continuous emission monitoring systems to account for 
NOX mass emissions, the owner or operator shall meet the 
applicable quality assurance and quality control requirements in Sec. 
75.21, appendix B to this part, and Sec. 75.74(c) for the 
NOX-diluent continuous emission monitoring systems, flow 
monitoring systems, NOX concentration monitoring systems, 
moisture monitoring systems, and diluent monitors required under Sec. 
75.71. Units using the low mass emissions excepted methodology under 
Sec. 75.19 shall meet the applicable quality assurance requirements of 
that section, except as otherwise provided in Sec. 75.74(c). Units 
using excepted monitoring methods under appendices D and E to this part 
shall meet the applicable quality assurance requirements of those 
appendices.
    (f) Missing data procedures. Except as provided in Sec. 75.34, 
paragraph (g) of this section, and Sec. 75.74(c)(7), the owner or 
operator shall provide substitute data from monitoring systems required 
under Sec. 75.71 for each affected unit as follows:
    (1) For an owner or operator using a continuous emissions monitoring 
system, substitute for missing data in accordance with the applicable 
missing data procedures in Sec. Sec. 75.31 through 75.37 whenever the 
unit combusts fuel and:
    (i) A valid, quality-assured hour of NOX emission rate 
data (in lb/mmBtu) has not been measured and recorded for a unit by a 
certified NOX-diluent continuous emission monitoring system 
or by an approved monitoring system under subpart E of this part;
    (ii) A valid, quality-assured hour of flow data (in scfh) has not 
been measured and recorded for a unit from a certified flow monitor or 
by an approved alternative monitoring system under subpart E of this 
part;
    (iii) A valid, quality-assured hour of heat input rate data (in 
mmBtu/hr) has not been measured and recorded for a unit from a certified 
flow monitor and a certified diluent (CO2 or O2) 
monitor or by an approved alternative monitoring system under subpart E 
of this part, where heat input is required either for calculating 
NOX mass or allocating allowances under the applicable State 
or federal NOX mass emission reduction program that adopts 
the requirements of this subpart;
    (iv) A valid, quality-assured hour of NOX concentration 
data (in ppm) has not been measured and recorded by a certified 
NOX concentration monitoring system, or by an approved 
alternative monitoring method under subpart E of this part, where the 
owner or operator chooses to use a NOX concentration 
monitoring system with a flow monitor, to calculate NOX mass 
emissions. The initial missing data procedures for determining monitor 
data availability and the standard missing data procedures for a 
NOX concentration monitoring system shall be the same as the 
procedures specified

[[Page 337]]

for a NOX-diluent continuous emission monitoring system under 
Sec. Sec. 75.31, 75.32, and 75.33; or
    (v) A valid, quality-assured hour of moisture data (in percent 
H2O) has not been measured or recorded for an affected unit, 
either by a certified moisture monitoring system or an approved 
alternative monitoring method under subpart E of this part. This 
requirement does not apply when a default percent moisture value, as 
provided in Sec. 75.11(b) or Sec. 75.12(b), is used to account for the 
hourly moisture content of the stack gas.
    (2) For an owner or operator using an excepted monitoring system 
under appendix D or E of this part, substitute for missing data in 
accordance with the missing data procedures in section 2.4 of appendix D 
to this part or in section 2.5 of appendix E to this part whenever the 
unit combusts fuel and:
    (i) A valid, quality-assured hour of fuel flow rate data has not 
been measured and recorded by a certified fuel flowmeter that is part of 
an excepted monitoring system under appendix D or E of this part; or
    (ii) A fuel sample value for gross calorific value, or if necessary, 
density or specific gravity, from a sample taken an analyzed in 
accordance with appendix D of this part is not available; or
    (iii) A valid, quality-assured hour of NOX emission rate 
data has not been obtained according to the procedures and 
specifications of appendix E to this part.
    (g) Reporting data prior to initial certification. If the owner or 
operator of an affected unit has not successfully completed all 
certification tests required by the State or federal NOX mass 
emission reduction program that adopts the requirements of this subpart 
by the applicable date required by that program, he or she shall 
determine, record and report hourly data prior to initial certification 
using one of the following procedures, consistent with the monitoring 
equipment to be certified:
    (1) For units that the owner or operator intends to monitor for 
NOX mass emissions using NOX emission rate and 
heat input rate, the maximum potential NOX emission rate and 
the maximum potential hourly heat input of the unit, as defined in Sec. 
72.2 of this chapter.
    (2) For units that the owner or operator intends to monitor for 
NOX mass emissions using a NOX concentration 
monitoring system and a flow monitoring system, the maximum potential 
concentration of NOX and the maximum potential flow rate, as 
defined in section 2.1.4.1 of appendix A to this part;
    (3) For any unit, the reference methods under Sec. 75.22 of this 
part.
    (4) For any unit using the low mass emission excepted monitoring 
methodology under Sec. 75.19, the procedures in paragraphs (g)(1) or 
(2) of this section.
    (5) Any unit using the procedures in paragraph (g)(2) of this 
section that is required to report heat input for purposes of allocating 
allowances shall also report the maximum potential hourly heat input of 
the unit, as defined in Sec. 72.2 of this chapter.
    (6) For any unit using continuous emissions monitors, the 
conditional data validation procedures in Sec. 75.20(b)(3)(ii) through 
(b)(3)(ix).
    (h) Petitions. (1) The designated representative of an affected unit 
that is subject to an Acid Rain emissions limitation may submit a 
petition to the Administrator requesting an alternative to any 
requirement of this subpart. Such a petition shall meet the requirements 
of Sec. 75.66 and any additional requirements established by an 
applicable State or federal NOX mass emission reduction 
program that adopts the requirements of this subpart. Use of an 
alternative to any requirement of this subpart is in accordance with 
this subpart and with such State or federal NOX mass emission 
reduction program only to the extent that the petition is approved by 
the Administrator, in consultation with the permitting authority.
    (2) Notwithstanding paragraph (h)(1) of this section, petitions 
requesting an alternative to a requirement concerning any additional 
CEMS required solely to meet the common stack provisions of Sec. 75.72 
shall be submitted to the permitting authority and the Administrator and 
shall be governed by paragraph (h)(3)(ii) of this section.

[[Page 338]]

Such a petition shall meet the requirements of Sec. 75.66 and any 
additional requirements established by an applicable State or federal 
NOX mass emission reduction program that adopts the 
requirements of this subpart.
    (3)(i) The designated representative of an affected unit that is not 
subject to an Acid Rain emissions limitation may submit a petition to 
the permitting authority and the Administrator requesting an alternative 
to any requirement of this subpart. Such a petition shall meet the 
requirements of Sec. 75.66 and any additional requirements established 
by an applicable State or federal NOX mass emission reduction 
program that adopts the requirements of this subpart.
    (ii) Use of an alternative to any requirement of this subpart is in 
accordance with this subpart only to the extent that it is approved by 
the Administrator and by the permitting authority if required by an 
applicable State or federal NOX mass emission reduction 
program that adopts the requirements of this subpart.

[63 FR 57507, Oct. 27, 1998, as amended at 64 FR 28624, May 26, 1999; 67 
FR 40444, June 12, 2002]



Sec. 75.71  Specific provisions for monitoring NOX and heat input
for the purpose of calculating NOX mass emissions.

    (a) Coal-fired units. The owner or operator of a coal-fired affected 
unit shall either:
    (1) Meet the general operating requirements in Sec. 75.10 for a 
NOX-diluent continuous emission monitoring system (consisting 
of a NOX pollutant concentration monitor, an O2 or 
CO2 diluent gas monitor, and a data acquisition and handling 
system) to measure NOX emission rate and for a flow 
monitoring system and an O2 or CO2 diluent gas 
monitoring system to measure heat input rate, except as provided in 
accordance with subpart E of this part; or
    (2) Meet the general operating requirements in Sec. 75.10 for a 
NOX concentration monitoring system (consisting of a 
NOX pollutant concentration monitor and a data acquisition 
and handling system) to measure NOX concentration and for a 
flow monitoring system. In addition, if heat input is required to be 
reported under the applicable State or federal NOX mass 
emission reduction program that adopts the requirements of this subpart, 
the owner or operator also must meet the general operating requirements 
for a flow monitoring system and an O2 or CO2 
monitoring system to measure heat input rate. These requirements must be 
met, except as provided in accordance with subpart E of this part.
    (b) Moisture correction. (1) If a correction for the stack gas 
moisture content is needed to properly calculate the NOX 
emission rate in lb/mmBtu (e.g., if the NOX pollutant 
concentration monitor in a NOX-diluent monitoring system 
measures on a different moisture basis from the diluent monitor), or to 
calculate the heat input rate, the owner or operator of an affected unit 
shall account for the moisture content of the flue gas on a continuous 
basis in accordance with Sec. 75.12(b).
    (2) If a correction for the stack gas moisture content is needed to 
properly calculate NOX mass emissions in tons, in the case 
where a NOX concentration monitoring system which measures on 
a dry basis is used with a flow rate monitor to determine NOX 
mass emissions, the owner or operator of an affected unit shall account 
for the moisture content of the flue gas on a continuous basis in 
accordance with Sec. 75.11(b) except that the term ``SO2'' 
shall be replaced by the term ``NOX.''
    (3) If a correction for the stack gas moisture content is needed to 
properly calculate NOX mass emissions, in the case where a 
diluent monitor that measures on a dry basis is used with a flow rate 
monitor to determine heat input rate, which is then multiplied by the 
NOX emission rate, the owner or operator shall install, 
operate, maintain, and quality assure a continuous moisture monitoring 
system, as described in Sec. 75.11(b).
    (c) Gas-fired nonpeaking units or oil-fired nonpeaking units. The 
owner or operator of an affected unit that, based on information 
submitted by the designated representative in the monitoring plan, 
qualifies as a gas-fired or oil-fired unit but not as a peaking unit, as 
defined in Sec. 72.2 of this chapter, shall either:

[[Page 339]]

    (1) Meet the requirements of paragraph (a) of this section and, if 
applicable, paragraph (b) of this section; or
    (2) Meet the general operating requirements in Sec. 75.10 for a 
NOX-diluent continuous emission monitoring system, except as 
provided in accordance with subpart E of this part, and use the 
procedures specified in appendix D to this part for determining hourly 
heat input rate. However, for a common pipe configuration, the heat 
input rate apportionment provisions in section 2.1.2 of appendix D to 
this part shall not be used to meet the NOX mass reporting 
provisions of this subpart, unless all of the units served by the common 
pipe are affected units and have similar efficiencies; or
    (3) Meet the requirements of the low mass emission excepted 
methodology under paragraph (e)(2) of this section and under Sec. 
75.19, if applicable.
    (d) Gas-fired or oil-fired peaking units. The owner or operator of 
an affected unit that qualifies as a peaking unit and as either gas-
fired or oil-fired, as defined in Sec. 72.2 of this chapter, based on 
information submitted by the designated representative in the monitoring 
plan, shall either:
    (1) Meet the requirements of paragraph (c) of this section; or
    (2) Use the procedures in appendix D to this part for determining 
hourly heat input and the procedure specified in appendix E to this part 
for estimating hourly NOX emission rate. However, for a 
common pipe configuration, the heat input apportionment provisions in 
section 2.1.2 of appendix D to this part shall not be used to meet the 
NOX mass reporting provisions of this subpart unless all of 
the units served by the common pipe are affected units and have similar 
efficiencies. In addition, if after certification of an excepted 
monitoring system under appendix E to this part, the operation of a unit 
that reports emissions on an annual basis under Sec. 75.74(a) of this 
part exceeds a capacity factor of 20.0 percent in any calendar year or 
exceeds an annual capacity factor of 10.0 percent averaged over three 
years, or the operation of a unit that reports emissions on an ozone 
season basis under Sec. 75.74(b) of this part exceeds a capacity factor 
of 20.0 percent in any ozone season or exceeds an ozone season capacity 
factor of 10.0 percent averaged over three years, the owner or operator 
shall meet the requirements of paragraph (c)(1) or (c)(2) of this 
section by no later than December 31 of the following calendar year. If 
the required CEMS are not installed and certified by that date, the 
owner or operator shall report hourly NOX mass emissions as 
the product of the maximum potential NOX emission rate (MER) 
and the maximum hourly heat input of the unit (as defined in Sec. 72.2 
of this chapter), starting with the first unit operating hour after the 
deadline and continuing until the CEMS are provisionally certified.
    (e) Low mass emissions units. Notwithstanding the requirements of 
paragraphs (c) and (d) of this section, for an affected unit using the 
low mass emissions (LME) unit under Sec. 75.19 to estimate hourly 
NOX emission rate, heat input and NOX mass 
emissions, the owner or operator shall calculate the ozone season 
NOX mass emissions by summing all of the estimated hourly 
NOX mass emissions in the ozone season, as determined under 
Sec. 75.19 (c)(4)(ii)(A), and dividing this sum by 2000 lb/ton.
    (f) Other units. The owner or operator of an affected unit that 
combusts wood, refuse, or other materials shall comply with the 
monitoring provisions specified in paragraph (a) of this section and, 
where applicable, paragraph (b) of this section.

[63 FR 57508, Oct. 27, 1998, as amended at 64 FR 28624, May 26, 1999; 67 
FR 40444, 40445, June 12, 2002; 67 FR 53505, Aug. 16, 2002; 73 FR 4358, 
Jan. 24, 2008]



Sec. 75.72  Determination of NOX mass emissions for common stack 
and multiple stack configurations.

    The owner or operator of an affected unit shall either: calculate 
hourly NOX mass emissions (in lbs) by multiplying the hourly 
NOX emission rate (in lbs/mmBtu) by the hourly heat input 
rate (in mmBtu/hr) and the unit or stack operating time (as defined in 
Sec. 72.2), or, as provided in paragraph (e) of this section, calculate 
hourly NOX mass emissions from the hourly NOX 
concentration (in ppm) and the hourly stack flow rate (in scfh). Only 
one methodology for determining NOX mass emissions

[[Page 340]]

shall be identified in the monitoring plan for each monitoring location 
at any given time. The owner or operator shall also calculate quarterly 
and cumulative year-to-date NOX mass emissions and cumulative 
NOX mass emissions for the ozone season (in tons) by summing 
the hourly NOX mass emissions according to the procedures in 
section 8 of appendix F to this part.
    (a) Unit utilizing common stack with other affected unit(s). When an 
affected unit utilizes a common stack with one or more affected units, 
but no nonaffected units, the owner or operator shall either:
    (1) Install, certify, operate, and maintain a NOX-diluent 
continuous emissions monitoring system and a flow monitoring system in 
the common stack, record the combined NOX mass emissions for 
the units exhausting to the common stack, and, for purposes of 
determining the hourly unit heat input rates, either:
    (i) Apportion the common stack heat input rate to the individual 
units according to the procedures in Sec. 75.16(e)(3); or
    (ii) Install, certify, operate, and maintain a flow monitoring 
system and diluent monitor in the duct to the common stack from each 
unit; or
    (iii) If any of the units using the common stack are eligible to use 
the procedures in appendix D to this part,
    (A) Use the procedures in appendix D to this part to determine heat 
input rate for that unit; and
    (B) Install, certify, operate, and maintain a flow monitoring system 
and a diluent monitor in the duct to the common stack for each remaining 
unit; or
    (2) Install, certify, operate, and maintain a NOX-diluent 
continuous emissions monitoring system in the duct to the common stack 
from each unit and, for purposes of heat input determination, either:
    (i) Install, certify, operate, and maintain a flow monitoring system 
in the duct to the common stack from each unit; or
    (ii) For any unit using the common stack and eligible to use the 
procedures in appendix D to this part,
    (A) Use the procedures in appendix D to determine heat input rate 
for that unit; and
    (B) Install, certify, operate, and maintain a flow monitoring system 
in the duct to the common stack for each remaining unit.
    (b) Unit utilizing common stack with nonaffected unit(s). When one 
or more affected units utilizes a common stack with one or more 
nonaffected units, the owner or operator shall either:
    (1) Install, certify, operate, and maintain a NOX-diluent 
continuous emission monitoring system in the duct to the common stack 
from each affected unit and, for purposes of heat input determination,
    (i) Install, certify, operate, and maintain a flow monitoring system 
in the duct to the common stack from each affected unit; or
    (ii) For any affected unit using the common stack and eligible to 
use the procedures in appendix D to this part,
    (A) Use the procedures in appendix D to determine heat input for 
that unit; however, for a common pipe configuration, the heat input 
apportionment provisions in section 2.1.2 of appendix D to this part 
shall not be used to meet the NOX mass reporting provisions 
of this subpart unless all of the units served by the common pipe are 
affected units and have similar efficiencies; and
    (B) Install, certify, operate, and maintain a flow monitoring system 
in the duct to the common stack for each remaining affected unit that 
exhausts to the common stack; or
    (2) Install, certify, operate, and maintain a NOX-diluent 
continuous emission monitoring system in the common stack; and
    (i) Designate the nonaffected units as affected units in accordance 
with the applicable State or federal NOX mass emissions 
reduction program and meet the requirements of paragraph (a)(1) of this 
section; or
    (ii) Install, certify, operate, and maintain a flow monitoring 
system in the common stack and a NOX-diluent continuous 
emission monitoring system in the duct to the common stack from each 
nonaffected unit. The designated representative shall submit a petition 
to the permitting authority

[[Page 341]]

and the Administrator to allow a method of calculating and reporting the 
NOX mass emissions from the affected units as the difference 
between NOX mass emissions measured in the common stack and 
NOX mass emissions measured in the ducts of the nonaffected 
units, not to be reported as an hourly value less than zero. The 
permitting authority and the Administrator may approve such a method 
whenever the designated representative demonstrates, to the satisfaction 
of the permitting authority and the Administrator, that the method 
ensures that the NOX mass emissions from the affected units 
are not underestimated. In addition, the owner or operator shall also 
either:
    (A) Install, certify, operate, and maintain a flow monitoring system 
in the duct from each nonaffected unit or,
    (B) For any nonaffected unit exhausting to the common stack and 
otherwise eligible to use the procedures in appendix D to this part, 
determine heat input rate using the procedures in appendix D for that 
unit. However, for a common pipe serving both affected and non-affected 
units, the heat input rate apportionment provisions in section 2.1.2 of 
appendix D to this part shall not be used to meet the NOX 
mass reporting provisions of this subpart. For any remaining nonaffected 
unit that exhausts to the common stack, install, certify, operate, and 
maintain a flow monitoring system in the duct to the common stack; or
    (iii) Install a flow monitoring system in the common stack and 
record the combined emissions from all units as the combined 
NOX mass emissions for the affected units for recordkeeping 
and compliance purposes, in accordance with paragraph (a) of this 
section; or
    (iv) Submit a petition to the permitting authority and the 
Administrator to allow use of a method for apportioning NOX 
mass emissions measured in the common stack to each of the units using 
the common stack and for reporting the NOX mass emissions. 
The permitting authority and the Administrator may approve such a method 
whenever the designated representative demonstrates, to the satisfaction 
of the permitting authority and the Administrator, that the method 
ensures that the NOX mass emissions from the affected units 
are not underestimated.
    (c) Unit with a main stack and a bypass stack. Whenever any portion 
of the flue gases from an affected unit can be routed through a bypass 
stack to avoid the installed NOX-diluent continuous emissions 
monitoring system or NOX concentration monitoring system, the 
owner and operator shall either:
    (1) Install, certify, operate, and maintain separate NOX-
diluent continuous emissions monitoring systems and flow monitoring 
systems on the main stack and the bypass stack and calculate 
NOX mass emissions for the unit as the sum of the 
NOX mass emissions measured at the two stacks;
    (2) Monitor NOX mass emissions at the main stack using a 
NOX-diluent CEMS and a flow monitoring system and measure 
NOX mass emissions at the bypass stack using the reference 
methods in Sec. 75.22(b) for NOX concentration, flow rate, 
and diluent gas concentration, or NOX concentration and flow 
rate, and calculate NOX mass emissions for the unit as the 
sum of the emissions recorded by the installed monitoring systems on the 
main stack and the emissions measured by the reference method monitoring 
systems; or
    (3) Install, certify, operate, and maintain a NOX-diluent 
CEMS and a flow monitoring system only on the main stack. If this option 
is chosen, it is not necessary to designate the exhaust configuration as 
a multiple stack configuration in the monitoring plan required under 
Sec. 75.53, since only the main stack is monitored. For each unit 
operating hour in which the bypass stack is used and the emissions are 
either uncontrolled (or the add-on controls are not documented to be 
operating properly), report NOX mass emissions as follows. If 
the unit heat input is determined using a flow monitor and a diluent 
monitor, report NOX mass emissions using the maximum 
potential NOX emission rate, the maximum potential flow rate, 
and either the maximum potential CO2 concentration or the 
minimum potential O2 concentration (as applicable). The 
maximum potential NOX emission rate may be specific to the 
type of fuel combusted in the unit during the bypass

[[Page 342]]

(see Sec. 75.33(c)(8)). If the unit heat input is determined using a 
fuel flowmeter, in accordance with appendix D to this part, report 
NOX mass emissions as the product of the maximum potential 
NOX emission rate and the actual measured hourly heat input 
rate. Alternatively, for a unit with NOX add-on emission 
controls, for each unit operating hour in which the bypass stack is used 
but the add-on NOX emission controls are not bypassed, the 
owner or operator may report the maximum controlled NOX 
emission rate (MCR) instead of the maximum potential NOX 
emission rate provided that the add-on controls are documented to be 
operating properly, as described in the quality assurance/quality 
control program for the unit, required by section 1 in appendix B of 
this part. To provide the necessary documentation, the owner or operator 
shall record parametric data to verify the proper operation of the 
NOX add-on emission controls as described in Sec. 75.34(d). 
Furthermore, the owner or operator shall calculate the MCR using the 
procedure described in section 2.1.2.1(b) of appendix A to this part by 
replacing the words ``maximum potential NOX emission rate 
(MER)'' with the words ``maximum controlled NOX emission rate 
(MCR)'' and by using the NOX MEC in the calculations instead 
of the NOX MPC.
    (d) Unit with multiple stack or duct configuration. When the flue 
gases from an affected unit discharge to the atmosphere through more 
than one stack, or when the flue gases from an affected unit utilize two 
or more ducts feeding into a single stack and the owner or operator 
chooses to monitor in the ducts rather than in the stack, the owner or 
operator shall either:
    (1) Install, certify, operate, and maintain a NOX-diluent 
continuous emission monitoring system and a flow monitoring system in 
each of the multiple stacks and determine NOX mass emissions 
from the affected unit as the sum of the NOX mass emissions 
recorded for each stack. If another unit also exhausts flue gases into 
one of the monitored stacks, the owner or operator shall comply with the 
applicable requirements of paragraphs (a) and (b) of this section, in 
order to properly determine the NOX mass emissions from the 
units using that stack;
    (2) Install, certify, operate, and maintain a NOX-diluent 
continuous emissions monitoring system and a flow monitoring system in 
each of the ducts that feed into the stack, and determine NOX 
mass emissions from the affected unit using the sum of the 
NOX mass emissions measured at each duct; or
    (3) If the unit is eligible to use the procedures in appendix D to 
this part and if the conditions and restrictions of Sec. 75.17(c)(2) 
are fully met, install, certify, operate, and maintain a NOX-
diluent continuous emissions monitoring system in one of the ducts 
feeding into the stack or in one of the multiple stacks, (as applicable) 
in accordance with Sec. 75.17(c)(2), and use the procedures in appendix 
D to this part to determine heat input rate for the unit.
    (e) Units using a NOX concentration monitoring system and 
a flow monitoring system to determine NOX mass. The owner or 
operator may use a NOX concentration monitoring system and a 
flow monitoring system to determine NOX mass emissions for 
the cases described in paragraphs (a) through (c) of this section and in 
paragraph (d)(1) or paragraph (d)(2) of this section (in place of a 
NOX-diluent continuous emissions monitoring system and a flow 
monitoring system). However, this option may not be used for the case 
described in paragraph (d)(3) of this section. When using this approach, 
calculate NOX mass according to sections 8.2 and 8.3 in 
appendix F to this part. In addition, if an applicable State or federal 
NOX mass reduction program requires determination of a unit's 
heat input, the owner or operator must either:
    (1) Install, certify, operate, and maintain a CO2 or 
O2 diluent monitor in the same location as each flow 
monitoring system. In addition, the owner or operator must provide heat 
input rate values for each unit utilizing a common stack. The owner or 
operator may either:
    (i) Apportion heat input rate from the common stack to each unit 
according to Sec. 75.16(e)(3), where all units utilizing the common 
stack are affected units, or

[[Page 343]]

    (ii) Measure heat input from each affected unit, using a flow 
monitor and a CO2 or O2 diluent monitor in the 
duct from each affected unit; or
    (2) For units that are eligible to use appendix D to this part, use 
the procedures in appendix D to this part to determine heat input rate 
for the unit. However, the use of a fuel flowmeter in a common pipe 
header and the provisions of sections 2.1.2.1 and 2.1.2.2 of appendix D 
of this part are not applicable to any unit that is using the provisions 
of this subpart to monitor, record, and report NOX mass 
emissions under a State or federal NOX mass emission 
reduction program and that shares a common pipe with a nonaffected unit.
    (f) [Reserved]
    (g) Procedures for apportioning heat input to the unit level. If the 
owner or operator of a unit using the common stack monitoring provisions 
in paragraphs (a) or (b) of this section does not monitor and record 
heat input at the unit level and the owner or operator is required to do 
so under an applicable State or federal NOX mass emission 
reduction program, apportion heat input from the common stack to each 
unit according to Sec. 75.16(e)(3).

[63 FR 57507, Oct. 27, 1998, as amended at 67 FR 40445, June 12, 2002; 
73 FR 4358, Jan. 24, 2008]



Sec. 75.73  Recordkeeping and reporting.

    (a) General recordkeeping provisions. The owner or operator of any 
affected unit shall maintain for each affected unit and each non-
affected unit under Sec. 75.72(b)(2)(ii) a file of all measurements, 
data, reports, and other information required by this part at the source 
in a form suitable for inspection for at least three (3) years from the 
date of each record. Except for the certification data required in Sec. 
75.57(a)(4) and the initial submission of the monitoring plan required 
in Sec. 75.57(a)(5), the data shall be collected beginning with the 
earlier of the date of provisional certification or the compliance 
deadline in Sec. 75.70(b). The certification data required in Sec. 
75.57(a)(4) shall be collected beginning with the date of the first 
certification test performed. The file shall contain the following 
information:
    (1) The information required in Sec. Sec. 75.57(a)(2), (a)(4), 
(a)(5), (a)(6), (b), (c)(2), (d), (g), and (h).
    (2) The information required in Sec. Sec. 75.58(b)(2) or (b)(3) 
(for units with add-on NOX emission controls), as applicable, 
(d) (as applicable for units using Appendix E to this part), and (f) (as 
applicable for units using the low mass emissions unit provisions of 
Sec. 75.19).
    (3) For each hour when the unit is operating, NOX mass 
emissions, calculated in accordance with section 8.1 of appendix F to 
this part.
    (4) During the second and third calendar quarters, cumulative ozone 
season heat input and cumulative ozone season operating hours.
    (5) Heat input and NOX methodologies for the hour.
    (6) Specific heat input record provisions for gas-fired or oil-fired 
units using the procedures in appendix D to this part. In lieu of the 
information required in Sec. 75.57(c)(2), the owner or operator shall 
record the information in Sec. 75.58(c) for each affected gas-fired or 
oil-fired unit and each non-affected gas- or oil-fired unit under Sec. 
75.72(b)(2)(ii) for which the owner or operator is using the procedures 
in appendix D to this part for estimating heat input.
    (7) Specific NOX record provisions for gas-fired or oil-fired units 
using the optional low mass emissions excepted methodology in Sec. 
75.19. In lieu of recording the information in Sec. Sec. 75.57(b), 
(c)(2), (d), and (g), the owner or operator shall record, for each hour 
when the unit is operating for any portion of the hour, the following 
information for each affected low mass emissions unit for which the 
owner or operator is using the low mass emissions excepted methodology 
in Sec. 75.19(c):
    (i) Date and hour;
    (ii) If one type of fuel is combusted in the hour, fuel type 
(pipeline natural gas, natural gas, residual oil, or diesel fuel) or, if 
more than one type of fuel is combusted in the hour, the fuel type which 
results in the highest emission factors for NOX;
    (iii) Average hourly NOX emission rate (in lb/mmBtu, 
rounded to the nearest thousandth); and
    (iv) Hourly NOX mass emissions (in lbs, rounded to the 
nearest tenth).

[[Page 344]]

    (8) Formulas from monitoring plan for total NOX mass.
    (b) Certification, quality assurance and quality control record 
provisions. The owner or operator of any affected unit shall record the 
applicable information in Sec. 75.59 for each affected unit or group of 
units monitored at a common stack and each non-affected unit under Sec. 
75.72(b)(2)(ii).
    (c) Monitoring plan recordkeeping provisions--(1) General 
provisions. The owner or operator of an affected unit shall prepare and 
maintain a monitoring plan for each affected unit or group of units 
monitored at a common stack and each non-affected unit under Sec. 
75.72(b)(2)(ii). Except as provided in paragraph (d) or (f) of this 
section, a monitoring plan shall contain sufficient information on the 
continuous emission monitoring systems, excepted methodology under Sec. 
75.19, or excepted monitoring systems under appendix D or E to this part 
and the use of data derived from these systems to demonstrate that all 
the unit's NoX emissions are monitored and reported.
    (2) Whenever the owner or operator makes a replacement, 
modification, or change in the certified continuous emission monitoring 
system, excepted methodology under Sec. 75.19, excepted monitoring 
system under appendix D or E to this part, or alternative monitoring 
system under subpart E of this part, including a change in the automated 
data acquisition and handling system or in the flue gas handling system, 
that affects information reported in the monitoring plan (e.g., a change 
to a serial number for a component of a monitoring system), then the 
owner or operator shall update the monitoring plan.
    (3) Contents of the monitoring plan for units not subject to an Acid 
Rain emissions limitation. Prior to January 1, 2009, each monitoring 
plan shall contain the information in Sec. 75.53(e)(1) or Sec. 
75.53(g)(1) in electronic format and the information in Sec. 
75.53(e)(2) or Sec. 75.53(g)(2) in hardcopy format. On and after 
January 1, 2009, each monitoring plan shall contain the information in 
Sec. 75.53(g)(1) in electronic format and the information in Sec. 
75.53(g)(2) in hardcopy format, only. In addition, to the extent 
applicable, prior to January 1, 2009, each monitoring plan shall contain 
the information in Sec. 75.53(f)(1)(i), (f)(2)(i), and (f)(4) or Sec. 
75.53(h)(1)(i), and (h)(2)(i) in electronic format and the information 
in Sec. 75.53(f)(1)(ii) and (f)(2)(ii) or Sec. 75.53(h)(1)(ii) and 
(h)(2)(ii) in hardcopy format. On and after January 1, 2009, each 
monitoring plan shall contain the information in Sec. 75.53(h)(1)(i), 
and (h)(2)(i) in electronic format and the information in Sec. 
75.53(h)(1)(ii) and (h)(2)(ii) in hardcopy format, only. For units using 
the low mass emissions excepted methodology under Sec. 75.19, prior to 
January 1, 2009, the monitoring plan shall include the additional 
information in Sec. 75.53(f)(5)(i) and (f)(5)(ii) or Sec. 
75.53(h)(4)(i) and (h)(4)(ii). On and after January 1, 2009, for units 
using the low mass emissions excepted methodology under Sec. 75.19 the 
monitoring plan shall include the additional information in Sec. 
75.53(h)(4)(i) and (h)(4)(ii), only. Prior to January 1, 2008, the 
monitoring plan shall also identify, in electronic format, the reporting 
schedule for the affected unit (ozone season or quarterly), and the 
beginning and end dates for the reporting schedule. The monitoring plan 
also shall include a seasonal controls indicator, and an ozone season 
fuel-switching flag.
    (d) General reporting provisions. (1) The designated representative 
for an affected unit shall comply with all reporting requirements in 
this section and with any additional requirements set forth in an 
applicable State or federal NOX mass emission reduction 
program that adopts the requirements of this subpart.
    (2) The designated representative for an affected unit shall submit 
the following for each affected unit or group of units monitored at a 
common stack and each non-affected unit under Sec. 75.72(b)(2)(ii):
    (i) Initial certification and recertification applications in 
accordance with Sec. 75.70(d);
    (ii) Monitoring plans in accordance with paragraph (e) of this 
section; and
    (iii) Quarterly reports in accordance with paragraph (f) of this 
section.
    (3) Other petitions and communications. The designated 
representative for an affected unit shall submit petitions, 
correspondence, application forms, and

[[Page 345]]

petition-related test results in accordance with the provisions in Sec. 
75.70(h).
    (4) Quality assurance RATA reports. If requested by the permitting 
authority, the designated representative of an affected unit shall 
submit the quality assurance RATA report for each affected unit or group 
of units monitored at a common stack and each non-affected unit under 
Sec. 75.72(b)(2)(ii) by the later of 45 days after completing a quality 
assurance RATA according to section 2.3 of appendix B to this part or 15 
days of receiving the request. The designated representative shall 
report the hardcopy information required by Sec. 75.59(a)(9) to the 
permitting authority.
    (5) Notifications. The designated representative for an affected 
unit shall submit written notice to the permitting authority according 
to the provisions in Sec. 75.61 for each affected unit or group of 
units monitored at a common stack and each non-affected unit under Sec. 
75.72(b)(2)(ii).
    (6) Routine appendix E retest reports. If requested by the 
applicable EPA Regional Office, appropriate State, and/or appropriate 
local air pollution control agency, the designated representative shall 
submit a hardcopy report within 45 days after completing a required 
periodic retest according to section 2.2 of appendix E to this part, or 
within 15 days of receiving the request, whichever is later. The 
designated representative shall report the hardcopy information required 
by Sec. 75.59(b)(5) to the applicable EPA Regional Office, appropriate 
State, and/or appropriate local air pollution control agency that 
requested the hardcopy report.
    (e) Monitoring plan reporting--(1) Electronic submission. The 
designated representative for an affected unit shall submit to the 
Administrator a complete, electronic, up-to-date monitoring plan file 
for each affected unit or group of units monitored at a common stack and 
each non-affected unit under Sec. 75.72(b)(2)(ii), no later than 21 
days prior to the initial certification test; at the time of a 
certification or recertification application submission; and whenever an 
update of the electronic monitoring plan is required, either under Sec. 
75.53 or elsewhere in this part.
    (2) Hardcopy submission. The designated representative of an 
affected unit shall submit all of the hardcopy information required 
under Sec. 75.53, for each affected unit or group of units monitored at 
a common stack and each non-affected unit under Sec. 75.72(b)(2)(ii), 
to the permitting authority prior to initial certification. Thereafter, 
the designated representative shall submit hardcopy information only if 
that portion of the monitoring plan is revised. The designated 
representative shall submit the required hardcopy information as 
follows: no later than 21 days prior to the initial certification test; 
with any certification or recertification application, if a hardcopy 
monitoring plan change is associated with the recertification event; and 
within 30 days of any other event with which a hardcopy monitoring plan 
change is associated, pursuant to Sec. 75.53(b). Electronic submittal 
of all monitoring plan information, including hardcopy portions, is 
permissible provided that a paper copy of the hardcopy portions can be 
furnished upon request.
    (f) Quarterly reports--(1) Electronic submission. The designated 
representative for an affected unit shall electronically report the data 
and information in this paragraph (f)(1) and in paragraphs (f)(2) and 
(3) of this section to the Administrator quarterly, unless the unit has 
been placed in long-term cold storage (as defined in Sec. 72.2 of this 
chapter). For units placed into long-term cold storage during a 
reporting quarter, the exemption from submitting quarterly reports 
begins with the calendar quarter following the date that the unit is 
placed into long-term cold storage. In such cases, the owner or operator 
shall submit quarterly reports for the unit beginning with the data from 
the quarter in which the unit recommences operation (where the initial 
quarterly report contains hourly data beginning with the first hour of 
recommenced operation of the unit). Each electronic report must be 
submitted to the Administrator within 30 days following the end of each 
calendar quarter. Except as otherwise provided in Sec. 75.64(a)(4) and 
(a)(5), each electronic report shall include the information provided in 
paragraphs (f)(1)(i) through (1)(vi) of this section, and shall

[[Page 346]]

also include the date of report generation. Prior to January 1, 2009, 
each report shall include the facility information provided in 
paragraphs (f)(1)(i)(A) and (B) of this section, for each affected unit 
or group of units monitored at a common stack. On and after January 1, 
2009, only the facility identification information provided in paragraph 
(f)(1)(i)(A) of this section is required.
    (i) Facility information:
    (A) Identification, including:
    (1) Facility/ORISPL number;
    (2) Calendar quarter and year data contained in the report; and
    (3) Electronic data reporting format version used for the report.
    (B) Location of facility, including:
    (1) Plant name and facility identification code;
    (2) EPA AIRS facility system identification code;
    (3) State facility identification code;
    (4) Source category/type;
    (5) Primary SIC code;
    (6) State postal abbreviation;
    (7) FIPS county code; and
    (8) Latitude and longitude.
    (ii) The information and hourly data required in paragraphs (a) and 
(b) of this section, except for:
    (A) Descriptions of adjustments, corrective action, and maintenance;
    (B) Information which is incompatible with electronic reporting 
(e.g., field data sheets, lab analyses, quality control plan);
    (C) For units with NOX add-on emission controls that do 
not elect to use the approved site-specific parametric monitoring 
procedures for calculation of substitute data, the information in Sec. 
75.58(b)(3);
    (D) Information required by Sec. 75.57(h) concerning the causes of 
any missing data periods and the actions taken to cure such causes;
    (E) Hardcopy monitoring plan information required by Sec. 75.53 and 
hardcopy test data and results required by Sec. 75.59;
    (F) Records of flow polynomial equations and numerical values 
required by Sec. 75.59(a)(5)(vi);
    (G) Daily fuel sampling information required by Sec. 75.58(c)(3)(i) 
for units using assumed values under appendix D;
    (H) Information required by Sec. 75.59(b)(2) concerning transmitter 
or transducer accuracy tests;
    (I) Stratification test results required as part of the RATA 
supplementary records under Sec. 75.59(a)(7);
    (J) Data and results of RATAs that are aborted or invalidated due to 
problems with the reference method or operational problems with the unit 
and data and results of linearity checks that are aborted or invalidated 
due to operational problems with the unit; and
    (K) Supplementary RATA information required under Sec. 75.59(a)(7), 
except that:
    (1) The applicable data elements under Sec. 75.59(a)(7)(ii)(A) 
through (T) and under Sec. 75.59(a)(7)(iii)(A) through (M) shall be 
reported for flow RATAs at circular or rectangular stacks (or ducts) in 
which angular compensation for yaw and/or pitch angles is used (i.e., 
Method 2F or 2G in appendices A-1 and A-2 to part 60 of this chapter), 
with or without wall effects adjustments;
    (2) The applicable data elements under Sec. 75.59(a)(7)(ii)(A) 
through (T) and under Sec. 75.59(a)(7)(iii)(A) through (M) shall be 
reported for any flow RATA run at a circular stack in which Method 2 in 
appendices A-1 and A-2 to part 60 of this chapter is used and a wall 
effects adjustment factor is determined by direct measurement;
    (3) The data under Sec. 75.59(a)(7)(ii)(T) shall be reported for 
all flow RATAs at circular stacks in which Method 2 in appendices A-1 
and A-2 to part 60 of this chapter is used and a default wall effects 
adjustment factor is applied; and
    (4) The data under Sec. 75.59(a)(7)(ix)(A) through (F) shall be 
reported for all flow RATAs at rectangular stacks or ducts in which 
Method 2 in appendices A-1 and A-2 to part 60 of this chapter is used 
and a wall effects adjustment factor is applied.
    (iii) Average NOX emission rate (lb/mmBtu, rounded to the 
nearest thousandth) during the quarter and cumulative NOX 
emission rate for the calendar year.
    (iv) Tons of NOX emitted during quarter, cumulative tons 
of NOX emitted during the year, and, during the second

[[Page 347]]

and third calendar quarters, cumulative tons of NOX emitted 
during the ozone season.
    (v) During the second and third calendar quarters, cumulative heat 
input for the ozone season.
    (vi) Unit or stack or common pipe header operating hours for 
quarter, cumulative unit, stack or common pipe header operating hours 
for calendar year, and, during the second and third calendar quarters, 
cumulative operating hours during the ozone season.
    (vii) Reporting period heat input.
    (viii) New reporting frequency and begin date of the new reporting 
frequency (if applicable).
    (2) The designated representative shall certify that the component 
and system identification codes and formulas in the quarterly electronic 
reports submitted to the Administrator pursuant to paragraph (e) of this 
section represent current operating conditions.
    (3) Compliance certification. The designated representative shall 
submit and sign a compliance certification in support of each quarterly 
emissions monitoring 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 part, including the quality 
assurance procedures and specifications; and
    (ii) With regard to a unit with add-on emission controls and for all 
hours where data are substituted in accordance with Sec. 75.34(a)(1), 
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.
    (4) The designated representative shall comply with all of the 
quarterly reporting requirements in Sec. Sec. 75.64(d), (f), and (g).

[64 FR 28624, May 26, 1999, as amended at 67 FR 40446, June 12, 2002; 73 
FR 4359, Jan. 24, 2008]



Sec. 75.74  Annual and ozone season monitoring and reporting
requirements.

    (a) Annual monitoring requirement. (1) The owner or operator of an 
affected unit subject both to an Acid Rain emission limitation and to a 
State or federal NOX mass reduction program that adopts the 
provisions of this part must meet the requirements of this part during 
the entire calendar year.
    (2) The owner or operator of an affected unit subject to a State or 
federal NOX mass reduction program that adopts the provisions 
of this part and that requires monitoring and reporting of hourly 
emissions on an annual basis must meet the requirements of this part 
during the entire calendar year.
    (b) Ozone season monitoring requirements. The owner or operator of 
an affected unit that is not required to meet the requirements of this 
subpart on an annual basis under paragraph (a) of this section may 
either:
    (1) Meet the requirements of this subpart on an annual basis; or
    (2) Meet the requirements of this subpart during the ozone season, 
except as specified in paragraph (c) of this section.
    (c) If the owner or operator of an affected unit chooses to meet the 
requirements of this subpart on less than an annual basis in accordance 
with paragraph (b)(2) of this section, then:
    (1) The owner or operator of a unit that uses continuous emissions 
monitoring systems or a fuel flowmeter to meet any of the requirements 
of this subpart shall quality assure the hourly ozone season emission 
data required by this subpart. To achieve this, the owner or operator 
shall operate, maintain and calibrate each required CEMS and shall 
perform diagnostic testing and quality assurance testing of each 
required CEMS or fuel flowmeter according to the applicable provisions 
of paragraphs (c)(2) through (c)(5) of this section. Except where 
otherwise noted, the provisions of paragraphs (c)(2) and (c)(3) of this 
section apply instead of the quality assurance provisions in sections 
2.1 through 2.3 of appendix B to this part, and shall be used in lieu of 
those appendix B provisions.
    (2) Quality assurance requirements prior to the ozone season. The 
provisions of this paragraph apply to each ozone

[[Page 348]]

season. The owner or operator shall, at a minimum, perform the following 
diagnostic testing and quality assurance assessments, and shall maintain 
the following records, to ensure that the hourly emission data recorded 
at the beginning of the current ozone season are suitable for reporting 
as quality-assured data:
    (i) For each required gas monitor (i.e., for each NOX 
pollutant concentration monitor and each diluent gas (CO2 or 
O2) monitor, including CO2 and O2 
monitors used exclusively for heat input determination and O2 
monitors used for moisture determination), a linearity check shall be 
performed and passed in the second calendar quarter no later than April 
30.
    (A) Conduct each linearity check in accordance with the general 
procedures in section 6.2 of appendix A to this part, except that the 
data validation procedures in sections 6.2(a) through (f) of appendix A 
do not apply.
    (B) Each linearity check shall be done ``hands-off,'' as described 
in section 2.2.3(c) of appendix B to this part.
    (C) In the time period extending from the date and hour in which the 
linearity check is passed through April 30, the owner or operator shall 
operate and maintain the CEMS and shall perform daily calibration error 
tests of the CEMS in accordance with section 2.1 of appendix B to this 
part. When a calibration error test is failed, as described in section 
2.1.4 of appendix B to this part, corrective actions shall be taken. The 
additional calibration error test provisions of section 2.1.3 of 
appendix B to this part shall be followed.
    (D) If the linearity check is not completed by April 30, data 
validation shall be determined in accordance with paragraph 
(c)(3)(ii)(E) of this section.
    (ii) For each required CEMS (i.e., for each NOX 
concentration monitoring system, each NOX-diluent monitoring 
system, each flow rate monitoring system, each moisture monitoring 
system and each diluent gas CEMS used exclusively for heat input 
determination), a relative accuracy test audit (RATA) shall be performed 
and passed in the first or second calendar quarter, but no later than 
April 30.
    (A) Conduct each RATA in accordance with the applicable procedures 
in sections 6.5 through 6.5.10 of appendix A to this part, except that 
the data validation procedures in sections 6.5(f)(1) through (f)(6) do 
not apply, and, for flow rate monitoring systems, the required RATA load 
level(s) (or operating level(s)) shall be as specified in this 
paragraph.
    (B) Each RATA shall be done ``hands-off,'' as described in section 
2.3.2 (c) of appendix B to this part. The provisions in section 2.3.1.4 
of appendix B to this part, pertaining to the number of allowable RATA 
attempts, shall apply.
    (C) For flow rate monitoring systems installed on peaking units or 
bypass stacks and for flow monitors exempted from multiple-level RATA 
testing under section 6.5.2(e) of appendix A to this part, a single-load 
(or single-level) RATA is required. For all other flow rate monitoring 
systems, a 2-load (or 2-level) RATA is required at the two most 
frequently-used load or operating levels (as defined under section 
6.5.2.1 of appendix A to this part), with the following exceptions. 
Except for flow monitors exempted from 3-level RATA testing under 
section 6.5.2(e) of appendix A to this part, a 3-load flow RATA is 
required at least once every five years and is also required if the flow 
monitor polynomial coefficients or K factor(s) are changed prior to 
conducting the flow RATA required under this paragraph.
    (D) A bias test of each required NOX concentration 
monitoring system, each NOX-diluent monitoring system and 
each flow rate monitoring system shall be performed in accordance with 
section 7.6 of appendix A to this part. If the bias test is failed, a 
bias adjustment factor (BAF) shall be calculated for the monitoring 
system, as described in section 7.6.5 of appendix A to this part and 
shall be applied to the subsequent data recorded by the CEMS.
    (E) In the time period extending from the hour of completion of the 
required RATA through April 30, the owner or operator shall operate and 
maintain the CEMS by performing, at a minimum, the following activities:
    (1) The owner or operator shall perform daily calibration error 
tests and (if applicable) daily flow monitor interference checks, 
according to section 2.1 of appendix B to this part. When a

[[Page 349]]

daily calibration error test or interference check is failed, as 
described in section 2.1.4 of appendix B to this part, corrective 
actions shall be taken. The additional calibration error test provisions 
in section 2.1.3 of appendix B to this part shall be followed. Records 
of the required daily calibration error tests and interference checks 
shall be kept in a format suitable for inspection on a year-round basis.
    (2) If the owner or operator makes a replacement, modification, or 
change in a certified monitoring system that 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 
or appendix B to this part, the owner or operator shall recertify the 
monitoring system according to Sec. 75.20(b).
    (F) Data validation. For each RATA that is performed by April 30, 
data validation shall be done according to sections 2.3.2(a)-(j) of 
appendix B to this part. However, if a required RATA is not completed by 
April 30, data from the monitoring system shall be invalid, beginning 
with the first unit operating hour on or after May 1. The owner or 
operator shall continue to invalidate all data from the CEMS until 
either:
    (1) The required RATA of the CEMS has been performed and passed; or
    (2) A probationary calibration error test of the CEMS is passed in 
accordance with Sec. 75.20(b)(3)(ii). Once the probationary calibration 
error test has been passed, the owner or operator shall perform the 
required RATA in accordance with the conditional data validation 
provisions and within the 720 unit or stack operating hour time frame 
specified in Sec. 75.20(b)(3) (subject to the restrictions in paragraph 
(c)(3)(xii) of this section), and the term ``quality assurance'' shall 
apply instead of the term ``recertification.'' However, in lieu of the 
provisions in Sec. 75.20(b)(3)(ix), the owner or operator shall follow 
the applicable provisions in paragraphs (c)(3)(xi) and (c)(3)(xii) of 
this section.
    (3) Quality assurance requirements within the ozone season. The 
provisions of this paragraph apply to each ozone season. The owner or 
operator shall, at a minimum, perform the following quality assurance 
testing during the ozone season, i.e. in the time period extending from 
May 1 through September 30 of each calendar year:
    (i) Daily calibration error tests and (if applicable) interference 
checks of each CEMS required by this subpart shall be performed in 
accordance with sections 2.1.1 and 2.1.2 of appendix B to this part. The 
applicable provisions in sections 2.1.3, 2.1.4 and 2.1.5 of appendix B 
to this part, pertaining, respectively, to additional calibration error 
tests and calibration adjustments, data validation, and quality 
assurance of data with respect to daily assessments, shall also apply.
    (ii) For each gas monitor required by this subpart, linearity checks 
shall be performed in the second and third calendar quarters, as 
follows:
    (A) For the second calendar quarter, the pre-ozone season linearity 
check required under paragraph (c)(2)(i) of this section shall be 
performed by April 30.
    (B) For the third calendar quarter, a linearity check shall be 
performed and passed no later than July 30.
    (C) Conduct each linearity check in accordance with the general 
procedures in section 6.2 of appendix A to this part, except that the 
data validation procedures in sections 6.2(a) through (f) of appendix A 
do not apply.
    (D) Each linearity check shall be done ``hands-off,'' as described 
in section 2.2.3(c) of appendix B to this part.
    (E) Data Validation. For second and third quarter linearity checks 
performed by the applicable deadline (i.e., April 30 or July 30), data 
validation shall be done in accordance with sections 2.2.3(a), (b), (c), 
(e), and (h) of Appendix B to this part. However, if a required 
linearity check for the second calendar quarter is not completed by 
April 30, or if a required linearity check for the third calendar 
quarter is not completed by July 30, data from the monitoring system (or 
range) shall be invalid, beginning with the first unit operating hour on 
or after May 1 or July 31, respectively. The owner or operator shall 
continue to invalidate all data from the CEMS until either:
    (1) The required linearity check of the CEMS has been performed and 
passed; or

[[Page 350]]

    (2) A probationary calibration error test of the CEMS is passed in 
accordance with Sec. 75.20(b)(3)(ii). Once the probationary calibration 
error test has been passed, the owner or operator shall perform the 
required linearity check in accordance with the conditional data 
validation provisions and within the 168 unit or stack operating hour 
time frame specified in Sec. 75.20(b)(3) (subject to the restrictions 
in paragraph (c)(3)(xii) of this section), and the term ``quality 
assurance'' shall apply instead of the term ``recertification.'' 
However, in lieu of the provisions in Sec. 75.20(b)(3)(ix), the owner 
or operator shall follow the applicable provisions in paragraphs 
(c)(3)(xi) and (c)(3)(xii) of this section.
    (F) A pre-season linearity check performed and passed in April 
satisfies the linearity check requirement for the second quarter.
    (G) The third quarter linearity check requirement in paragraph 
(c)(3)(ii)(B) of this section is waived if:
    (1) Due to infrequent unit operation, the 168 operating hour 
conditional data validation period associated with a pre-season 
linearity check extends into the third quarter; and
    (2) A linearity check is performed and passed within that 
conditional data validation period.
    (iii) For each flow monitoring system required by this subpart, 
except for flow monitors installed on non-load-based units that do not 
produce electrical or thermal output, flow-to-load ratio tests are 
required in the second and third calendar quarters, in accordance with 
section 2.2.5 of appendix B to this part. If the flow-to-load ratio test 
for the second calendar quarter is failed, the owner or operator shall 
follow the procedures in section 2.2.5(c)(8) of appendix B to this part. 
If the flow-to-load ratio test for the third calendar quarter is failed, 
data from the flow monitor shall be considered invalid at the beginning 
of the next ozone season unless, prior to May 1 of the next calendar 
year, the owner or operator has either successfully implemented Option 1 
in section 2.2.5.1 of appendix B to this part or Option 2 in section 
2.2.5.2 of appendix B to this part, or unless a flow RATA has been 
performed and passed in accordance with paragraph (c)(2)(ii) of this 
section.
    (iv) For each differential pressure-type flow monitor used to meet 
the requirements of this subpart, quarterly leak checks are required in 
the second and third calendar quarters, in accordance with section 2.2.2 
of appendix B to this part. For the second calendar quarter of the year, 
only the unit or stack operating hours in the months of May and June 
shall be used to determine whether the second calendar quarter is a QA 
operating quarter (as defined in Sec. 72.2 of this chapter). Data 
validation for quarterly flow monitor leak checks shall be done in 
accordance with section 2.2.3(g) of appendix B to this part. If the leak 
check for the third calendar quarter is failed and a subsequent leak 
check is not passed by the end of the ozone season, then data from the 
flow monitor shall be considered invalid at the beginning of the next 
ozone season unless a leak check is passed prior to May 1 of the next 
calendar year.
    (v) A fuel flow-to-load ratio test in section 2.1.7 of appendix D to 
this part shall be performed in the second and third calendar quarters 
if, for a unit using a fuel flowmeter to determine heat input under this 
subpart, the owner or operator has elected to use the fuel flow-to-load 
ratio test to extend the deadline for the next fuel flowmeter accuracy 
test. Automatic deadline extensions may be claimed for the two calendar 
quarters outside the ozone season (the first and fourth calendar 
quarters), since a fuel flow-to-load ratio test is not required in those 
quarters. If a fuel flow-to-load ratio test is failed, follow the 
applicable procedures and data validation provisions in section 2.1.7.4 
of appendix D to this part. If the fuel flow-to-load ratio test for the 
third calendar quarter is failed, data from the fuel flowmeter shall be 
considered invalid at the beginning of the next ozone season unless the 
requirements of section 2.1.7.4 of appendix D to this part have been 
fully met prior to May 1 of the next calendar year.
    (vi)-(viii) [Reserved]
    (ix) If, for any required CEMS, diagnostic linearity checks or RATAs 
other than those required by this section are

[[Page 351]]

performed during the ozone season, use the applicable data validation 
procedures in section 2.2.3 (for linearity checks) or 2.3.2 (for RATAs) 
of appendix B to this part.
    (x) If any required CEMS is recertified within the ozone season, use 
the data validation provisions in Sec. 75.20(b)(3) and, if applicable, 
paragraphs (c)(3)(xi) and (c)(3)(xii) of this section.
    (xi) If, at the end of the second quarter of any calendar year, a 
required quality assurance, diagnostic, or recertification test of a 
monitoring system has not been completed, and if data contained in the 
quarterly report are conditionally valid pending the results of test(s) 
to be completed in a subsequent quarter, the owner or operator shall 
indicate this by means of a suitable conditionally valid data flag in 
the electronic quarterly report for the second calendar quarter. The 
owner or operator shall resubmit the report for the second quarter if 
the required quality assurance, diagnostic, or recertification test is 
subsequently failed. In the resubmitted report, the owner or operator 
shall use the appropriate missing data routine in Sec. Sec. 75.31 
through Sec. 75.37 to replace with substitute data each hour of 
conditionally valid data that was invalidated by the failed quality 
assurance, diagnostic, or recertification test. Alternatively, if any 
required quality assurance, diagnostic, or recertification test is not 
completed by the end of the second calendar quarter but is completed no 
later than 30 days after the end of that quarter (i.e., prior to the 
deadline for submitting the quarterly report under Sec. 75.73), the 
test data and results may be submitted with the second quarter report 
even though the test date(s) are from the third calendar quarter. In 
such instances, if the quality assurance, diagnostic, or recertification 
test(s) are passed in accordance with the conditional data validation 
provisions of Sec. 75.20(b)(3), conditionally valid data may be 
reported as quality-assured, in lieu of reporting a conditional data 
flag. If the tests are failed and if conditionally valid data are 
replaced, as appropriate, with substitute data, then neither the 
reporting of a conditional data flag nor resubmission is required.
    (xii) If, at the end of the third quarter of any calendar year, a 
required quality assurance, diagnostic or recertification test of a 
monitoring system has not been completed, and if data contained in the 
quarterly report are conditionally valid pending the results of test(s) 
to be completed, the owner or operator shall do one of the following:
    (A) If the results of the required tests are not available within 30 
days of the end of the third calendar quarter and cannot be submitted 
with the quarterly report for the third calendar quarter, then the test 
results are considered to be missing and the owner or operator shall use 
the appropriate missing data routine in Sec. Sec. 75.31 through Sec. 
75.37 to replace with substitute data each hour of conditionally valid 
data in the third quarter report. In addition, if the data in the second 
quarterly report were flagged as conditionally valid at the end of the 
quarter, pending the results of the same missing tests, the owner or 
operator shall resubmit the report for the second quarter and shall use 
the appropriate missing data routine in Sec. Sec. 75.31 through Sec. 
75.37 to replace with substitute data each hour of conditionally valid 
data associated with the missing quality assurance, diagnostic, or 
recertification tests; or
    (B) If the required quality assurance, diagnostic, or 
recertification tests are completed no later than 30 days after the end 
of the third calendar quarter, the test data and results may be 
submitted with the third quarter report even though the test date(s) are 
from the fourth calendar quarter. In this instance, if the required 
tests are passed in accordance with the conditional data validation 
provisions of Sec. 75.20(b)(3), all conditionally valid data associated 
with the tests shall be reported as quality-assured. If the tests are 
failed, the owner or operator shall use the appropriate missing data 
routine in Sec. Sec. 75.31 through Sec. 75.37 to replace with 
substitute data each hour of conditionally valid data associated with 
the failed test(s). In addition, if the data in the second quarterly 
report were flagged as conditionally valid at the end of the quarter, 
pending the results of the same failed test(s), the owner or operator 
shall resubmit the report for the second quarter and shall

[[Page 352]]

use the appropriate missing data routine in Sec. Sec. 75.31 through 
Sec. 75.37 to replace with substitute data each hour of conditionally 
valid data associated with the failed test(s).
    (4) The owner or operator of a unit using the procedures in appendix 
D of this part to determine heat input rate is required to maintain fuel 
flowmeters only during the ozone season, except that for purposes of 
determining the deadline for the next periodic quality assurance test on 
the fuel flowmeter, the owner or operator shall include all fuel 
flowmeter QA operating quarters (as defined in Sec. 72.2) for the 
entire calendar year, not just fuel flowmeter QA operating quarters in 
the ozone season. For each calendar year, the owner or operator shall 
record, for each fuel flowmeter, the number of fuel flowmeter QA 
operating quarters. The owner or operator shall include all calendar 
quarters in the year when determining the deadline for visual inspection 
of the primary fuel flowmeter element, as specified in section 2.1.6(c) 
of appendix D to this part.
    (5) The owner or operator of a unit using the procedures in appendix 
D of this part to determine heat input rate is only required to sample 
fuel for the purposes of determining density and GCV during the ozone 
season, except that:
    (i) The owner or operator of a unit that performs sampling from the 
fuel storage tank upon delivery must sample the tank between the date 
and hour of the most recent delivery before the first date and hour that 
the unit operates in the ozone season and the first date and hour that 
the unit operates in the ozone season.
    (ii) The owner or operator of a unit that performs sampling upon 
delivery from the delivery vehicle must ensure that all shipments 
received during the calendar year are sampled.
    (iii) The owner or operator of a unit that performs sampling on each 
day the unit combusts fuel or that performs fuel sampling continuously 
must sample the fuel starting on the first day the unit operates during 
the ozone season. The owner or operator then shall use that sampled 
value for all hours of combustion during the first day of unit 
operation, continuing until the date and hour of the next sample.
    (6) The owner or operator shall, in accordance with Sec. 75.73, 
record and report the hourly data required by this subpart and shall 
record and report the results of all required quality assurance tests, 
as follows:
    (i) All hourly emission data for the period of time from May 1 
through September 30 of each calendar year shall be recorded and 
reported. For missing data purposes, only the data recorded in the time 
period from May 1 through September 30 shall be considered quality-
assured;
    (ii) The results of all daily calibration error tests and flow 
monitor interference checks performed in the time period from May 1 
through September 30 shall be recorded and reported;
    (iii) For the time periods described in paragraphs (c)(2)(i)(C) and 
(c)(2)(ii)(E) of this section, hourly emission data and the results of 
all daily calibration error tests and flow monitor interference checks 
shall be recorded. The owner or operator may opt to report unit 
operating data, daily calibration error test and flow monitor 
interference check results, and hourly emission data in the time period 
from April 1 through April 30. However, only the data recorded in the 
time period from May 1 through September 30 shall be used for 
NOX mass compliance determination;
    (iv) The results of all required quality assurance tests (RATAs, 
linearity checks, flow-to-load ratio tests and leak checks) performed 
during the ozone season shall be reported in the appropriate ozone 
season quarterly report; and
    (v) The results of RATAs (and any other quality assurance test(s) 
required under paragraph (c)(2) or (c)(3) of this section) which affect 
data validation for the current ozone season, but which were performed 
outside the ozone season (i.e., between January 1 and April 30 of the 
current calendar year), shall be reported in the quarterly report for 
the second quarter of the current calendar year (or in the report for 
the third calendar quarter of the current calendar year, if the unit or 
stack does not operate in the second quarter).

[[Page 353]]

    (7) The owner or operator shall use only quality-assured data from 
within ozone seasons in the substitute data procedures under subpart D 
of this part and section 2.4.2 of appendix D to this part.
    (i) The lookback periods (e.g., 2160 quality-assured monitor 
operating hours for a NOX-diluent continuous emission 
monitoring system, a NOX concentration monitoring system, or 
a flow monitoring system) used to calculate missing data must include 
only quality-assured data from periods within ozone seasons.
    (ii) The applicable missing data procedures of Sec. Sec. 75.31 
through 75.37 shall be used, with one exception. When a fuel which has a 
significantly higher NOX emission rate than any of the 
fuel(s) combusted in prior ozone seasons is combusted in the unit, and 
no quality-assured NOX data have been recorded in the 
current, or any previous, ozone season while combusting the new fuel, 
the owner or operator shall substitute the maximum potential 
NOX emission rate, as defined in Sec. 72.2 of this chapter, 
from a NOX-diluent continuous emission monitoring system, or 
the maximum potential concentration of NOX, as defined in 
section 2.1.2.1 of appendix A to this part, from a NOX 
concentration monitoring system. The maximum potential value used shall 
be specific to the new fuel. The owner or operator shall substitute the 
maximum potential value for each hour of missing NOX data 
until the first hour that quality-assured NOX data are 
obtained while combusting the new fuel, and then shall resume use of the 
missing data routines in Sec. Sec. 75.31 through 75.37; and
    (iii) In order to apply the missing data routines described in 
Sec. Sec. 75.31 through 75.37 on an ozone season-only basis, the 
procedures in those sections shall be modified as follows:
    (A) The use of the initial missing data procedures in Sec. 75.31 
shall commence with the first unit operating hour in the first ozone 
season for which emissions data are required to be reported under Sec. 
75.64.
    (B) In Sec. 75.31(a), the phrases ``During the first 720 quality-
assured monitor operating hours within the ozone season'' and ``during 
the first 2,160 quality-assured monitor operating hours within the ozone 
season'' apply respectively instead of the phrases ``During the first 
720 quality-assured monitor operating hours'' and ``during the first 
2,160 quality-assured monitor operating hours''.
    (C) In Sec. 75.32(a), the phrases ``the first 720 quality-assured 
monitor operating hours within the ozone season'' and ``the first 2,160 
quality-assured monitor operating hours within the ozone season'' apply, 
respectively, instead of the phrases ``the first 720 quality-assured 
monitor operating hours'' and ``the first 2,160 quality-assured monitor 
operating hours''.
    (D) In Sec. 75.32(a)(1), the phrase ``Following initial 
certification, prior to completion of 3,672 unit (or stack) operating 
hours within the ozone season'' applies instead of the phrase ``Prior to 
completion of 8,760 unit (or stack) operating hours following initial 
certification''.
    (E) In Equation 8, the phrase ``Total unit operating hours within 
the ozone season'' applies instead of the phrase ``Total unit operating 
hours''.
    (F) In Sec. 75.32(a)(2), the phrase ``3,672 unit (or stack) 
operating hours within the ozone season'' applies instead of the phrase 
``8,760 unit (or stack) operating hours''.
    (G) In the numerator of Equation 9, the phrase ``Total unit 
operating hours within the ozone season'' applies instead of the phrase 
``Total unit operating hours'', and the phrase ``3,672 unit operating 
hours within the ozone season'' applies instead of the phrase ``8,760 
unit operating hours''. In the denominator of Equation 9, the number 
``3,672'' applies instead of ``8,760''.
    (H) Use the following instead of the first three sentences in Sec. 
75.32(a)(3): ``When calculating percent monitor data availability using 
Equation 8 or 9, the owner or operator shall include all unit or stack 
operating hours within the ozone season, and all monitor operating hours 
within the ozone season for which quality-assured data were recorded by 
a certified primary monitor; a certified redundant or non-redundant 
backup monitor or a reference method for that unit; or by an approved 
alternative monitoring system under subpart E of this part. No hours 
from more than three years (26,280 clock hours)

[[Page 354]]

earlier shall be used in Equation 9. For a unit that has accumulated 
fewer than 3,672 ozone season operating hours in the previous three 
years, use the following: in the numerator of Equation 9 use `Total unit 
operating hours within the ozone season for which quality-assured data 
were recorded in the previous three years'; and in the denominator of 
Equation 9 use `Total unit operating hours within the ozone season, in 
the previous three years' ''
    (I) In Sec. 75.33(a), the phrases ``the first 720 quality-assured 
monitor operating hours within the ozone season'' and ``the first 2,160 
quality-assured monitor operating hours within the ozone season'' apply, 
respectively, instead of the phrases ``the first 720 quality-assured 
monitor operating hours'' and ``the first 2,160 quality-assured monitor 
operating hours''.
    (J) Instead of the last sentence of Sec. 75.33(a), use ``For the 
purposes of missing data substitution, the owner or operator of a unit 
shall use only quality-assured monitor operating hours of data that were 
recorded within the ozone season and no more than three years (26,280 
clock hours) prior to the date and time of the missing data period.''
    (K) In Sec. Sec. 75.33(b), 75.33(c), 75.35, 75.36, and 75.37, the 
phrases ``720 quality-assured monitor operating hours within the ozone 
season'' and ``2,160 quality-assured monitor operating hours within the 
ozone season'' apply, respectively, instead of the phrases ``720 
quality-assured monitor operating hours'' and ``2,160 quality-assured 
monitor operating hours''.
    (L) In Sec. 75.34(a)(3) and (a)(5), the phrases ``720 quality-
assured monitor operating hours within the ozone season'' and ``2160 
quality-assured monitor operating hours within the ozone season'' apply 
instead of ``720 quality-assured monitor operating hours'' and ``2160 
quality-assured monitor operating hours'', respectively.
    (8) The owner or operator of a unit with NOX add-on 
emission controls or a unit capable of combusting more than one fuel 
shall keep records during ozone season in a form suitable for inspection 
to demonstrate that the typical NOX emission rate or 
NOX concentration during the prior ozone season(s) included 
in the missing data lookback period is representative of the ozone 
season in which missing data are substituted and that use of the missing 
data procedures will not systematically underestimate NOX 
mass emissions. These records shall include:
    (i) For units that can combust more than one fuel, the fuel or fuels 
combusted each hour; and
    (ii) For units with add-on emission controls, using the missing data 
options in Sec. Sec. 75.34(a)(1) through 75.34(a)(5), the range of 
operating parameters for add-on emission controls (as defined in the 
quality assurance/quality control program for the unit required by 
section 1 in appendix B to this part) and information for verifying 
proper operation of the add-on emission controls during missing data 
periods, as described in Sec. 75.34(d).
    (9) The designated representative shall certify with each quarterly 
report that NOX emission rate values or NOX 
concentration values substituted for missing data under subpart D of 
this part are calculated using only values from an ozone season, that 
substitute values measured during the prior ozone season(s) included in 
the missing data lookback period are representative of the ozone season 
in which missing data are substituted, and that NOX emissions 
are not systematically underestimated.
    (10) Units may qualify to use the low mass emissions excepted 
monitoring methodology in Sec. 75.19 on an ozone season basis. In order 
to be allowed to use this methodology, a unit may not emit more than 50 
tons of NOX per ozone season, as provided in Sec. 
75.19(a)(1)(i)(A)(3). If any low mass emissions unit fails to provide a 
demonstration that its ozone season NOX mass emissions are 
less than or equal to 50 tons, then the unit is disqualified from using 
the methodology. The owner or operator must install and certify any 
equipment needed to ensure that the unit is monitored using an 
acceptable methodology by December 31 of the following year.
    (11) Units may qualify to use the optional NOX mass 
emissions estimation protocol for gas-fired and oil-fired peaking units 
in appendix E to this part on an ozone season basis. In order to be 
allowed to use this methodology,

[[Page 355]]

the unit must meet the definition of ``peaking unit'' in Sec. 72.2 of 
this chapter, except that the words ``year'', ``calendar year'' and 
``calendar years'' in that definition shall be replaced by the words 
``ozone season'', ``ozone season'', and ``ozone seasons'', respectively. 
In addition, in the definition of the term ``capacity factor'' in Sec. 
72.2 of this chapter, the word ``annual'' shall be replaced by the words 
``ozone season'' and the number ``8,760'' shall be replaced by the 
number ``3,672''.

[63 FR 57507, Oct. 27, 1998, as amended at 64 FR 28627, May 26, 1999; 67 
FR 40446, 40447, June 12, 2002; 67 FR 57274, Sept. 9, 2002; 73 FR 4360, 
Jan. 24, 2008]



Sec. 75.75  Additional ozone season calculation procedures for special
circumstances.

    (a) The owner or operator of a unit that is required to calculate 
ozone season heat input for purposes of providing data needed for 
determining allocations, shall do so by summing the unit's hourly heat 
input determined according to the procedures in this part for all hours 
in which the unit operated during the ozone season.
    (b) The owner or operator of a unit that is required to determine 
ozone season NOX emission rate (in lbs/mmBtu) shall do so by 
dividing ozone season NOX mass emissions(in lbs) determined 
in accordance with this subpart, by heat input determined in accordance 
with paragraph (a) of this section.



     Sec. Appendix A to Part 75--Specifications and Test Procedures

                1. Installation and Measurement Location

                            1.1 Gas Monitors

    (a) Following the procedures in section 8.1.1 of Performance 
Specification 2 in appendix B to part 60 of this chapter, install the 
pollutant concentration monitor or monitoring system at a location where 
the pollutant concentration and emission rate measurements are directly 
representative of the total emissions from the affected unit. Select a 
representative measurement point or path for the monitor probe(s) (or 
for the path from the transmitter to the receiver) such that the 
SO2, CO2, O2, or NOX 
concentration monitoring system or NOX-diluent CEMS 
(NOX pollutant concentration monitor and diluent gas monitor) 
will pass the relative accuracy test (see section 6 of this appendix).
    (b) It is recommended that monitor measurements be made at locations 
where the exhaust gas temperature is above the dew-point temperature. If 
the cause of failure to meet the relative accuracy tests is determined 
to be the measurement location, relocate the monitor probe(s).

                          1.1.1 Point Monitors

    Locate the measurement point (1) within the centroidal area of the 
stack or duct cross section, or (2) no less than 1.0 meter from the 
stack or duct wall.

                           1.1.2 Path Monitors

    Locate the measurement path (1) totally within the inner area 
bounded by a line 1.0 meter from the stack or duct wall, or (2) such 
that at least 70.0 percent of the path is within the inner 50.0 percent 
of the stack or duct cross-sectional area, or (3) such that the path is 
centrally located within any part of the centroidal area.

                            1.2 Flow Monitors

    Install the flow monitor in a location that provides representative 
volumetric flow over all operating conditions. Such a location is one 
that provides an average velocity of the flue gas flow over the stack or 
duct cross section, provides a representative SO2 emission 
rate (in lb/hr), and is representative of the pollutant concentration 
monitor location. Where the moisture content of the flue gas affects 
volumetric flow measurements, use the procedures in both Reference 
Methods 1 and 4 of appendix A to part 60 of this chapter to establish a 
proper location for the flow monitor. The EPA recommends (but does not 
require) performing a flow profile study following the procedures in 40 
CFR part 60, appendix A, method, 1, sections 11.5 or 11.4 for each of 
the three operating or load levels indicated in section 6.5.2.1 of this 
appendix to determine the acceptability of the potential flow monitor 
location and to determine the number and location of flow sampling 
points required to obtain a representative flow value. The procedure in 
40 CFR part 60, appendix A, Test Method 1, section 11.5 may be used even 
if the flow measurement location is greater than or equal to 2 
equivalent stack or duct diameters downstream or greater than or equal 
to \1/2\ duct diameter upstream from a flow disturbance. If a flow 
profile study shows that cyclonic (or swirling) or stratified flow 
conditions exist at the potential flow monitor location that are likely 
to prevent the monitor from meeting the performance specifications of 
this part, then EPA recommends either (1) selecting another location 
where there is no cyclonic (or swirling) or stratified flow condition, 
or (2) eliminating the cyclonic (or swirling) or stratified flow 
condition by straightening the flow, e.g., by installing straightening

[[Page 356]]

vanes. EPA also recommends selecting flow monitor locations to minimize 
the effects of condensation, coating, erosion, or other conditions that 
could adversely affect flow monitor performance.

                 1.2.1 Acceptability of Monitor Location

    The installation of a flow monitor is acceptable if either (1) the 
location satisfies the minimum siting criteria of method 1 in appendix A 
to part 60 of this chapter (i.e., the location is greater than or equal 
to eight stack or duct diameters downstream and two diameters upstream 
from a flow disturbance; or, if necessary, two stack or duct diameters 
downstream and one-half stack or duct diameter upstream from a flow 
disturbance), or (2) the results of a flow profile study, if performed, 
are acceptable (i.e., there are no cyclonic (or swirling) or stratified 
flow conditions), and the flow monitor also satisfies the performance 
specifications of this part. If the flow monitor is installed in a 
location that does not satisfy these physical criteria, but nevertheless 
the monitor achieves the performance specifications of this part, then 
the location is acceptable, notwithstanding the requirements of this 
section.

                  1.2.2 Alternative Monitoring Location

    Whenever the owner or operator successfully demonstrates that 
modifications to the exhaust duct or stack (such as installation of 
straightening vanes, modifications of ductwork, and the like) are 
necessary for the flow monitor to meet the performance specifications, 
the Administrator may approve an interim alternative flow monitoring 
methodology and an extension to the required certification date for the 
flow monitor.
    Where no location exists that satisfies the physical siting criteria 
in section 1.2.1, where the results of flow profile studies performed at 
two or more alternative flow monitor locations are unacceptable, or 
where installation of a flow monitor in either the stack or the ducts is 
demonstrated to be technically infeasible, the owner or operator may 
petition the Administrator for an alternative method for monitoring 
flow.

                       2. Equipment Specifications

                      2.1 Instrument Span and Range

    In implementing sections 2.1.1 through 2.1.6 of this appendix, set 
the measurement range for each parameter (SO2, 
NOX, CO2, O2, or flow rate) high enough 
to prevent full-scale exceedances from occurring, yet low enough to 
ensure good measurement accuracy and to maintain a high signal-to-noise 
ratio. To meet these objectives, select the range such that the majority 
of the readings obtained during typical unit operation are kept, to the 
extent practicable, between 20.0 and 80.0 percent of the full-scale 
range of the instrument. These guidelines do not apply to: (1) 
SO2 readings obtained during the combustion of very low 
sulfur fuel (as defined in Sec. 72.2 of this chapter); (2) 
SO2 or NOX readings recorded on the high 
measurement range, for units with SO2 or NOX 
emission controls and two span values, unless the emission controls are 
operated seasonally (for example, only during the ozone season); or (3) 
SO2 or NOX readings less than 20.0 percent of 
full-scale on the low measurement range for a dual span unit, provided 
that the maximum expected concentration (MEC), low-scale span value, and 
low-scale range settings have been determined according to sections 
2.1.1.2, 2.1.1.4(a), (b), and (g) of this appendix (for SO2), 
or according to sections 2.1.2.2, 2.1.2.4(a) and (f) of this appendix 
(for NOX).

          2.1.1 SO2 Pollutant Concentration Monitors

    Determine, as indicated in sections 2.1.1.1 through 2.1.1.5 of this 
appendix the span value(s) and range(s) for an SO2 pollutant 
concentration monitor so that all potential and expected concentrations 
can be accurately measured and recorded. Note that if a unit exclusively 
combusts fuels that are very low sulfur fuels (as defined in Sec. 72.2 
of this chapter), the SO2 monitor span requirements in Sec. 
75.11(e)(3)(iv) apply in lieu of the requirements of this section.

                 2.1.1.1 Maximum Potential Concentration

    (a) Make an initial determination of the maximum potential 
concentration (MPC) of SO2 by using Equation A-1a or A-1b. 
Base the MPC calculation on the maximum percent sulfur and the minimum 
gross calorific value (GCV) for the highest-sulfur fuel to be burned. 
The maximum sulfur content and minimum GCV shall be determined from all 
available fuel sampling and analysis data for that fuel from the 
previous 12 months (minimum), excluding clearly anomalous fuel sampling 
values. If both the fuel sulfur content and the GCV are routinely 
determined from each fuel sample, the owner or operator may, as an 
alternative to using the highest individual percent sulfur and lowest 
individual GCV values in the MPC calculation, pair the sulfur content 
and GCV values from each sample analysis and calculate the ratio of 
percent sulfur to GCV (i.e., %S/GCV) for each pair of values. If this 
option is selected, the MPC shall be calculated using the highest %S/GCV 
ratio in Equation A-1a or A-1b. If the designated representative 
certifies that the highest-sulfur fuel is never burned alone in the unit 
during normal operation but is always blended or co-fired with other 
fuel(s), the MPC may be calculated using a best estimate of the highest 
sulfur content and lowest gross calorific value expected for the blend 
or fuel mixture and inserting these values into Equation A-1a or A-1b. 
Derive

[[Page 357]]

the best estimate of the highest percent sulfur and lowest GCV for a 
blend or fuel mixture from weighted-average values based upon the 
historical composition of the blend or mixture in the previous 12 (or 
more) months. If insufficient representative fuel sampling data are 
available to determine the maximum sulfur content and minimum GCV, use 
values from contract(s) for the fuel(s) that will be combusted by the 
unit in the MPC calculation.
[GRAPHIC] [TIFF OMITTED] TR26MY99.000

 or
[GRAPHIC] [TIFF OMITTED] TR26MY99.001

Where,

MPC = Maximum potential concentration (ppm, wet basis). (To convert to 
          dry basis, divide the MPC by 0.9.)
MEC = Maximum expected concentration (ppm, wet basis). (To convert to 
          dry basis, divide the MEC by 0.9).
%S = Maximum sulfur content of fuel to be fired, wet basis, weight 
          percent, as determined according to the applicable method in 
          paragraph (c) of section 2.1.1.1.
%O2w = Minimum oxygen concentration, percent wet basis, under 
          typical operating conditions.
%CO2w = Maximum carbon dioxide concentration, percent wet 
          basis, under typical operating conditions.
GCV = Minimum gross calorific value of the fuel or blend to be 
          combusted, based on historical fuel sampling and analysis data 
          or, if applicable, based on the fuel contract specifications 
          (Btu/lb). If based on fuel sampling and analysis, the GCV 
          shall be determined according to the applicable method in 
          paragraph (c) of section 2.1.1.1.
11.32 x 10\6\ = Oxygen-based conversion factor in Btu/lb (ppm)/%.
66.93 x 10\6\ = Carbon dioxide-based conversion factor in Btu/lb (ppm)/
          %.

    Note: All percent values to be inserted in the equations of this 
section are to be expressed as a percentage, not a fractional value 
(e.g., 3, not .03).

    (b) Alternatively, if a certified SO2 CEMS is already 
installed, the owner or operator may make the initial MPC determination 
based upon quality-assured historical data recorded by the CEMS. For the 
purposes of this section, 2.1.1.1, a ``certified'' CEMS means a CEM 
system that has met the applicable certification requirements of either: 
This part, or part 60 of this chapter, or a State CEM program, or the 
source operating permit. If this option is chosen, the MPC shall be the 
maximum SO2 concentration observed during the previous 720 
(or more) quality-assured monitor operating hours when combusting the 
highest-sulfur fuel (or highest-sulfur blend if fuels are always blended 
or co-fired) that is to be combusted in the unit or units monitored by 
the SO2 monitor. For units with SO2 emission 
controls, the certified SO2 monitor used to determine the MPC 
must be located at or before the control device inlet. Report the MPC 
and the method of determination in the monitoring plan required under 
Sec. 75.53. Note that the initial MPC value is subject to periodic 
review under section 2.1.1.5 of this appendix. If an MPC value is found 
to be either inappropriately high or low, the MPC shall be adjusted in 
accordance with section 2.1.1.5, and corresponding span and range 
adjustments shall be made, if necessary.
    (c) When performing fuel sampling to determine the MPC, use ASTM 
Methods: ASTM D129-00, ASTM D240-00, ASTM D1552-01, ASTM D2622-98, ASTM 
D3176-89 (Reapproved 2002), ASTM D3177-02 (Reapproved 2007), ASTM D4239-
02, ASTM D4294-98, ASTM D5865-01a, or ASTM D5865-10 (all incorporated by 
reference under Sec. 75.6).

                 2.1.1.2 Maximum Expected Concentration

    (a) Make an initial determination of the maximum expected 
concentration (MEC) of SO2 whenever: (a) SO2 
emission controls are used; or (b) both high-sulfur and low-sulfur fuels 
(e.g., high-sulfur coal and low-sulfur coal or different grades of fuel 
oil) or high-sulfur and low-sulfur fuel blends are combusted as primary 
or backup fuels in a unit without SO2 emission controls. For 
units with SO2 emission controls, use Equation A-

[[Page 358]]

2 to make the initial MEC determination. When high-sulfur and low-sulfur 
fuels or blends are burned as primary or backup fuels in a unit without 
SO2 controls, use Equation A-1a or A-1b to calculate the 
initial MEC value for each fuel or blend, except for: (1) the highest-
sulfur fuel or blend (for which the MPC was previously calculated in 
section 2.1.1.1 of this appendix); (2) fuels or blends that are very low 
sulfur fuels (as defined in Sec. 72.2 of this chapter); or (3) fuels or 
blends that are used only for unit startup. Each initial MEC value shall 
be documented in the monitoring plan required under Sec. 75.53. Note 
that each initial MEC value is subject to periodic review under section 
2.1.1.5 of this appendix. If an MEC value is found to be either 
inappropriately high or low, the MEC shall be adjusted in accordance 
with section 2.1.1.5, and corresponding span and range adjustments shall 
be made, if necessary.
    (b) For each MEC determination, substitute into Equation A-1a or A-
1b the highest sulfur content and minimum GCV value for that fuel or 
blend, based upon all available fuel sampling and analysis results from 
the previous 12 months (or more), or, if fuel sampling data are 
unavailable, based upon fuel contract(s).
    (c) Alternatively, if a certified SO2 CEMS is already 
installed, the owner or operator may make the initial MEC 
determination(s) based upon historical monitoring data. For the purposes 
of this section, 2.1.1.2, a ``certified'' CEMS means a CEM system that 
has met the applicable certification requirements of either: This part, 
or part 60 of this chapter, or a State CEM program, or the source 
operating permit. If this option is chosen for a unit with 
SO2 emission controls, the MEC shall be the maximum 
SO2 concentration measured downstream of the control device 
outlet by the CEMS over the previous 720 (or more) quality-assured 
monitor operating hours with the unit and the control device both 
operating normally. For units that burn high- and low-sulfur fuels or 
blends as primary and backup fuels and have no SO2 emission 
controls, the MEC for each fuel shall be the maximum SO2 
concentration measured by the CEMS over the previous 720 (or more) 
quality-assured monitor operating hours in which that fuel or blend was 
the only fuel being burned in the unit.
[GRAPHIC] [TIFF OMITTED] TR26MY99.002

Where:

MEC = Maximum expected concentration (ppm).
MPC = Maximum potential concentration (ppm), as determined by Eq. A-1a 
          or A-1b in section 2.1.1.1 of this appendix.
RE = Expected average design removal efficiency of control equipment 
          (%).

                   2.1.1.3 Span Value(s) and Range(s)

    Determine the high span value and the high full-scale range of the 
SO2 monitor as follows. (Note: For purposes of this part, the 
high span and range refer, respectively, either to the span and range of 
a single span unit or to the high span and range of a dual span unit.) 
The high span value shall be obtained by multiplying the MPC by a factor 
no less than 1.00 and no greater than 1.25. Round the span value upward 
to the next highest multiple of 100 ppm. If the SO2 span 
concentration is <=500 ppm, the span value may either be rounded upward 
to the next highest multiple of 10 ppm, or to the next highest multiple 
of 100 ppm. The high span value shall be used to determine 
concentrations of the calibration gases required for daily calibration 
error checks and linearity tests. Select the full-scale range of the 
instrument to be consistent with section 2.1 of this appendix and to be 
greater than or equal to the span value. Report the full-scale range 
setting and calculations of the MPC and span in the monitoring plan for 
the unit. Note that for certain applications, a second (low) 
SO2 span and range may be required (see section 2.1.1.4 of 
this appendix). If an existing State, local, or federal requirement for 
span of an SO2 pollutant concentration monitor requires or 
allows the use of a span value lower than that required by this section 
or by section 2.1.1.4 of this appendix, the State, local, or federal 
span value may be used if a satisfactory explanation is included in the 
monitoring plan, unless span and/or range adjustments become necessary 
in accordance with section 2.1.1.5 of this appendix. Span values higher 
than those required by either this section or section 2.1.1.4 of this 
appendix must be approved by the Administrator.

                2.1.1.4 Dual Span and Range Requirements

    For most units, the high span value based on the MPC, as determined 
under section 2.1.1.3 of this appendix will suffice to measure and 
record SO2 concentrations (unless span and/or range 
adjustments become necessary in accordance with section 2.1.1.5 of this 
appendix). In some instances, however, a second (low) span value based 
on the MEC may be required to ensure accurate measurement of all 
possible or expected SO2 concentrations. To determine whether 
two SO2 span values are required, proceed as follows:
    (a) For units with SO2 emission controls, compare the MEC 
from section 2.1.1.2 of this appendix to the high full-scale range value 
from section 2.1.1.3 of this appendix. If the MEC is =20.0 
percent of the high range value, then the high span value and range 
determined under section 2.1.1.3 of this appendix are sufficient. If the 
MEC is <20.0 percent of the high range value, then a second (low) span 
value is required.

[[Page 359]]

    (b) For units that combust high- and low-sulfur primary and backup 
fuels (or blends) and have no SO2 controls, compare the high 
range value from section 2.1.1.3 of this appendix (for the highest-
sulfur fuel or blend) to the MEC value for each of the other fuels or 
blends, as determined under section 2.1.1.2 of this appendix. If all of 
the MEC values are =20.0 percent of the high range value, the 
high span and range determined under section 2.1.1.3 of this appendix 
are sufficient, regardless of which fuel or blend is burned in the unit. 
If any MEC value is <20.0 percent of the high range value, then a second 
(low) span value must be used when that fuel or blend is combusted.
    (c) When two SO2 spans are required, the owner or 
operator may either use a single SO2 analyzer with a dual 
range (i.e., low- and high-scales) or two separate SO2 
analyzers connected to a common sample probe and sample interface. 
Alternatively, if RATAs are performed and passed on both measurement 
ranges, the owner or operator may use two separate SO2 
analyzers connected to separate probes and sample interfaces. For units 
with SO2 emission controls, the owner or operator may use a 
low range analyzer and a default high range value, as described in 
paragraph (f) of this section, in lieu of maintaining and quality 
assuring a high-scale range. Other monitor configurations are subject to 
the approval of the Administrator.
    (d) The owner or operator shall designate the monitoring systems and 
components in the monitoring plan under Sec. 75.53 as follows: when a 
single probe and sample interface are used, either designate the low and 
high monitor ranges as separate SO2 components of a single, 
primary SO2 monitoring system; designate the low and high 
monitor ranges as the SO2 components of two separate, primary 
SO2 monitoring systems; designate the normal monitor range as 
a primary monitoring system and the other monitor range as a non-
redundant backup monitoring system; or, when a single, dual-range 
SO2 analyzer is used, designate the low and high ranges as a 
single SO2 component of a primary SO2 monitoring 
system (if this option is selected, use a special dual-range component 
type code, as specified by the Administrator, to satisfy the 
requirements of Sec. 75.53(e)(1)(iv)(D)). When two SO2 
analyzers are connected to separate probes and sample interfaces, 
designate the analyzers as the SO2 components of two 
separate, primary SO2 monitoring systems. For units with 
SO2 controls, if the default high range value is used, 
designate the low range analyzer as the SO2 component of a 
primary SO2 monitoring system. Do not designate the default 
high range as a monitoring system or component. Other component and 
system designations are subject to approval by the Administrator. Note 
that the component and system designations for redundant backup 
monitoring systems shall be the same as for primary monitoring systems.
    (e) Each monitoring system designated as primary or redundant backup 
shall meet the initial certification and quality assurance requirements 
for primary monitoring systems in Sec. 75.20(c) or Sec. 75.20(d)(1), 
as applicable, and appendices A and B to this part, with one exception: 
relative accuracy test audits (RATAs) are required only on the normal 
range (for units with SO2 emission controls, the low range is 
considered normal). Each monitoring system designated as a non-redundant 
backup shall meet the applicable quality assurance requirements in Sec. 
75.20(d)(2).
    (f) For dual span units with SO2 emission controls, the 
owner or operator may, as an alternative to maintaining and quality 
assuring a high monitor range, use a default high range value. If this 
option is chosen, the owner or operator shall report a default 
SO2 concentration of 200 percent of the MPC for each unit 
operating hour in which the full-scale of the low range SO2 
analyzer is exceeded.
    (g) The high span value and range shall be determined in accordance 
with section 2.1.1.3 of this appendix. The low span value shall be 
obtained by multiplying the MEC by a factor no less than 1.00 and no 
greater than 1.25, and rounding the result upward to the next highest 
multiple of 10 ppm (or 100 ppm, as appropriate). For units that burn 
high- and low-sulfur primary and backup fuels or blends and have no 
SO2 emission controls, select, as the basis for calculating 
the appropriate low span value and range, the fuel-specific MEC value 
closest to 20.0 percent of the high full-scale range value (from 
paragraph (b) of this section). The low range must be greater than or 
equal to the low span value, and the required calibration gases must be 
selected based on the low span value. However, if the default high range 
option in paragraph (f) of this section is selected, the full-scale of 
the low measurement range shall not exceed five times the MEC value 
(where the MEC is rounded upward to the next highest multiple of 10 
ppm). For units with two SO2 spans, use the low range 
whenever the SO2 concentrations are expected to be 
consistently below 20.0 percent of the high full-scale range value, 
i.e., when the MEC of the fuel or blend being combusted is less than 
20.0 percent of the high full-scale range value. When the full-scale of 
the low range is exceeded, the high range shall be used to measure and 
record the SO2 concentrations; or, if applicable, the default 
high range value in paragraph (f) of this section shall be reported for 
each hour of the full-scale exceedance.

                  2.1.1.5 Adjustment of Span and Range

    For each affected unit or common stack, the owner or operator shall 
make a periodic evaluation of the MPC, MEC, span, and range

[[Page 360]]

values for each SO2 monitor (at a minimum, an annual 
evaluation is required) and shall make any necessary span and range 
adjustments, with corresponding monitoring plan updates, as described in 
paragraphs (a), (b), and (c) of this section. Span and range adjustments 
may be required, for example, as a result of changes in the fuel supply, 
changes in the manner of operation of the unit, or installation or 
removal of emission controls. In implementing the provisions in 
paragraphs (a) and (b) of this section, SO2 data recorded 
during short-term, non-representative process operating conditions 
(e.g., a trial burn of a different type of fuel) shall be excluded from 
consideration. The owner or operator shall keep the results of the most 
recent span and range evaluation on-site, in a format suitable for 
inspection. Make each required span or range adjustment no later than 45 
days after the end of the quarter in which the need to adjust the span 
or range is identified, except that up to 90 days after the end of that 
quarter may be taken to implement a span adjustment if the calibration 
gases currently being used for daily calibration error tests and 
linearity checks are unsuitable for use with the new span value.
    (a) If the fuel supply, the composition of the fuel blend(s), the 
emission controls, or the manner of operation change such that the 
maximum expected or potential concentration changes significantly, 
adjust the span and range setting to assure the continued accuracy of 
the monitoring system. A ``significant'' change in the MPC or MEC means 
that the guidelines in section 2.1 of this appendix can no longer be 
met, as determined by either a periodic evaluation by the owner or 
operator or from the results of an audit by the Administrator. The owner 
or operator should evaluate whether any planned changes in operation of 
the unit may affect the concentration of emissions being emitted from 
the unit or stack and should plan any necessary span and range changes 
needed to account for these changes, so that they are made in as timely 
a manner as practicable to coordinate with the operational changes. 
Determine the adjusted span(s) using the procedures in sections 2.1.1.3 
and 2.1.1.4 of this appendix (as applicable). Select the full-scale 
range(s) of the instrument to be greater than or equal to the new span 
value(s) and to be consistent with the guidelines of section 2.1 of this 
appendix.
    (b) Whenever a full-scale range is exceeded during a quarter and the 
exceedance is not caused by a monitor out-of-control period, proceed as 
follows:
    (1) For exceedances of the high range, report 200.0 percent of the 
current full-scale range as the hourly SO2 concentration for 
each hour of the full-scale exceedance and make appropriate adjustments 
to the MPC, span, and range to prevent future full-scale exceedances.
    (2) For units with two SO2 spans and ranges, if the low 
range is exceeded, no further action is required, provided that the high 
range is available and its most recent calibration error test and 
linearity check have not expired. However, if either of these quality 
assurance tests has expired and the high range is not able to provide 
quality assured data at the time of the low range exceedance or at any 
time during the continuation of the exceedance, report the MPC as the 
SO2 concentration until the readings return to the low range 
or until the high range is able to provide quality assured data (unless 
the reason that the high-scale range is not able to provide quality 
assured data is because the high-scale range has been exceeded; if the 
high-scale range is exceeded follow the procedures in paragraph (b)(1) 
of this section).
    (c) Whenever changes are made to the MPC, MEC, full-scale range, or 
span value of the SO2 monitor, as described in paragraphs (a) 
or (b) of this section, record and report (as applicable) the new full-
scale range setting, the new MPC or MEC and calculations of the adjusted 
span value in an updated monitoring plan. The monitoring plan update 
shall be made in the quarter in which the changes become effective. In 
addition, record and report the adjusted span as part of the records for 
the daily calibration error test and linearity check specified by 
appendix B to this part. Whenever the span value is adjusted, use 
calibration gas concentrations that meet the requirements of section 5.1 
of this appendix, based on the adjusted span value. When a span 
adjustment is so significant that the calibration gases currently being 
used for daily calibration error tests and linearity checks are 
unsuitable for use with the new span value, then a diagnostic linearity 
test using the new calibration gases must be performed and passed. Use 
the data validation procedures in Sec. 75.20(b)(3), beginning with the 
hour in which the span is changed.

          2.1.2 NOX Pollutant Concentration Monitors

    Determine, as indicated in sections 2.1.2.1 through 2.1.2.5 of this 
appendix, the span and range value(s) for the NOX pollutant 
concentration monitor so that all expected NOX concentrations 
can be determined and recorded accurately.

                 2.1.2.1 Maximum Potential Concentration

    (a) The maximum potential concentration (MPC) of NOX for 
each affected unit shall be based upon whichever fuel or blend combusted 
in the unit produces the highest level of NOX emissions. For 
the purposes of this section, 2.1.2.1, and section 2.1.2.2 of this 
appendix, a ``blend'' means a frequently-used fuel mixture having a 
consistent composition (e.g., an oil and gas mixture where the

[[Page 361]]

relative proportions of the two fuels vary by no more than 10%, on 
average). Make an initial determination of the MPC using the appropriate 
option as follows:
    Option 1: Use 800 ppm for coal-fired and 400 ppm for oil- or gas-
fired units as the maximum potential concentration of NOX (if 
an MPC of 1600 ppm for coal-fired units or 480 ppm for oil- or gas-fired 
units was previously selected under this section, that value may still 
be used, provided that the guidelines of section 2.1 of this appendix 
are met); For cement kilns, use 2000 ppm as the MPC. For process 
heaters, use 200 ppm if the unit burns only gaseous fuel and 500 ppm if 
the unit burns oil;
    Option 2: Use the specific values based on boiler type and fuel 
combusted, listed in Table 2-1 or Table 2-2; For a new gas-fired or oil-
fired combustion turbine, if a default MPC value of 50 ppm was 
previously selected from Table 2-2, that value may be used until March 
31, 2003;
    Option 3: Use NOX emission test results;
    Option 4: Use historical CEM data over the previous 720 (or more) 
unit operating hours when combusting the fuel or blend with the highest 
NOX emission rate; or
    Option 5: If a reliable estimate of the uncontrolled NOX 
emissions from the unit is available from the manufacturer, the 
estimated value may be used.
    (b) For the purpose of providing substitute data during 
NOX missing data periods in accordance with Sec. Sec. 75.31 
and 75.33 and as required elsewhere under this part, the owner or 
operator shall also calculate the maximum potential NOX 
emission rate (MER), in lb/mmBtu, by substituting the MPC for 
NOX in conjunction with the minimum expected CO2 
or maximum O2 concentration (under all unit operating 
conditions except for unit startup, shutdown, and upsets) and the 
appropriate F-factor into the applicable equation in appendix F to this 
part. The diluent cap value of 5.0 percent CO2 (or 14.0 
percent O2) for boilers or 1.0 percent CO2 (or 
19.0 percent O2) for combustion turbines may be used in the 
NOX MER calculation. As a second alternative, when the 
NOX MPC is determined from emission test results or from 
historical CEM data, as described in paragraphs (a), (d) and (e) of this 
section, quality-assured diluent gas (i.e., O2 or 
CO2) data recorded concurrently with the MPC may be used to 
calculate the MER.
    (c) Report the method of determining the initial MPC and the 
calculation of the maximum potential NOX emission rate in the 
monitoring plan for the unit. Note that whichever MPC option in 
paragraph 2.1.2.1(a) of this appendix is selected, the initial MPC value 
is subject to periodic review under section 2.1.2.5 of this appendix. If 
an MPC value is found to be either inappropriately high or low, the MPC 
shall be adjusted in accordance with section 2.1.2.5, and corresponding 
span and range adjustments shall be made, if necessary.
    (d) For units with add-on NOX controls (whether or not 
the unit is equipped with low-NOX burner technology), or for 
units equipped with dry low-NOX (DLN) technology, 
NOX emission testing may only be used to determine the MPC if 
testing can be performed either upstream of the add-on controls or 
during a time or season when the add-on controls are not in operation or 
when the DLN controls are not in the premixed (low-NOX) mode. 
If NOX emission testing is performed, use the following 
guidelines. Use Method 7E from appendix A to part 60 of this chapter to 
measure total NOX concentration. (Note: Method 20 from 
appendix A to part 60 may be used for gas turbines, instead of Method 
7E.) Operate the unit, or group of units sharing a common stack, at the 
minimum safe and stable load, the normal load, and the maximum load. If 
the normal load and maximum load are identical, an intermediate level 
need not be tested. Operate at the highest excess O2 level 
expected under normal operating conditions. Make at least three runs of 
20 minutes (minimum) duration with three traverse points per run at each 
operating condition. Select the highest point NOX 
concentration from all test runs as the MPC for NOX.
    (e) If historical CEM data are used to determine the MPC, the data 
must, for uncontrolled units or units equipped with low-NOX 
burner technology and no other NOX controls, represent a 
minimum of 720 quality-assured monitor operating hours from the 
NOX component of a certified monitoring system, obtained 
under various operating conditions including the minimum safe and stable 
load, normal load (including periods of high excess air at normal load), 
and maximum load. For the purposes of this section, 2.1.2.1, a 
``certified'' CEMS means a CEM system that has met the applicable 
certification requirements of either: this part, or part 60 of this 
chapter, or a State CEM program, or the source operating permit. For a 
unit with add-on NOX controls (whether or not the unit is 
equipped with low-NOX burner technology), or for a unit 
equipped with dry low-NOX (DLN) technology, historical CEM 
data may only be used to determine the MPC if the 720 quality-assured 
monitor operating hours of CEM data are collected upstream of the add-on 
controls or if the 720 hours of data include periods when the add-on 
controls are not in operation or when the DLN controls are not in the 
premixed (low-NOX mode). For units that do not produce 
electrical or thermal output, the data must represent the full range of 
normal process operation. The highest hourly NOX 
concentration in ppm shall be the MPC.

[[Page 362]]



  Table 2-1--Maximum Potential Concentration for NOX--Coal-Fired Units
------------------------------------------------------------------------
                                                              Maximum
                                                             potential
                        Unit type                          concentration
                                                           for NOX (ppm)
------------------------------------------------------------------------
Tangentially-fired dry bottom and fluidized bed.........             460
Wall-fired dry bottom, turbo-fired dry bottom, stokers..             675
Roof-fired (vertically-fired) dry bottom, cell burners,              975
 arch-fired.............................................
Cyclone, wall-fired wet bottom, wet bottom turbo-fired..            1200
Others..................................................           (\1\)
------------------------------------------------------------------------
\1\ As approved by the Administrator.

[GRAPHIC] [TIFF OMITTED] TR12JN02.008

                 2.1.2.2 Maximum Expected Concentration

    (a) Make an initial determination of the maximum expected 
concentration (MEC) of NOX during normal operation for 
affected units with add-on NOX controls of any kind (e.g., 
steam injection, water injection, SCR, or SNCR) and for turbines that 
use dry low-NOX technology. Determine a separate MEC value 
for each type of fuel (or blend) combusted in the unit, except for fuels 
that are only used for unit startup and/or flame stabilization. 
Calculate the MEC of NOX using Equation A-2, if applicable, 
inserting the maximum potential concentration, as determined using the 
procedures in section 2.1.2.1 of this appendix. Where Equation A-2 is 
not applicable, set the MEC either by: (1) measuring the NOX 
concentration using the testing procedures in this section; (2) using 
historical CEM data over the previous 720 (or more) quality-assured 
monitor operating hours; or (3) if the unit has add-on NOX 
controls or uses dry low NOX technology, and has a federally-
enforceable permit limit for NOX concentration, the permit 
limit may be used as the MEC. Include in the monitoring plan for the 
unit each MEC value and the method by which the MEC was determined. Note 
that each initial MEC value is subject to periodic review under section 
2.1.2.5 of this appendix. If an MEC value is found to be either 
inappropriately high or low, the MEC shall be adjusted in accordance 
with section 2.1.2.5, and corresponding span and range adjustments shall 
be made, if necessary.
    (b) If NOX emission testing is used to determine the MEC 
value(s), the MEC for each type of fuel (or blend) shall be based upon 
testing at minimum load, normal load, and maximum load. At least three 
tests of 20 minutes (minimum) duration, using at least three traverse 
points, shall be performed at each load, using Method 7E from appendix A 
to part 60 of this chapter (Note: Method 20 from appendix A to part 60 
may be used for gas turbines instead of Method 7E). The test must be 
performed at a time when all NOX control devices and methods 
used to reduce NOX emissions (if applicable) are operating 
properly. The testing shall be conducted downstream of all 
NOX controls. The highest point NOX concentration 
(e.g., the highest one-minute average) recorded during any of the test 
runs shall be the MEC.
    (c)If historical CEM data are used to determine the MEC value(s), 
the MEC for each type of fuel shall be based upon 720 (or more) hours of 
quality-assured data from the NOX component of a certified 
monitoring system representing the entire load range under stable 
operating conditions. For the purposes of this section, 2.1.2.2, a 
``certified'' CEMS means a CEM system that has met the applicable 
certification requirements of either:

[[Page 363]]

this part, or part 60 of this chapter, or a State CEM program, or the 
source operating permit. The data base for the MEC shall not include any 
CEM data recorded during unit startup, shutdown, or malfunction or (for 
units with add-on NOX controls or turbines using dry low 
NOX technology) during any NOX control device 
malfunctions or outages. All NOX control devices and methods 
used to reduce NOX emissions (if applicable) must be 
operating properly during each hour. The CEM data shall be collected 
downstream of all NOX controls. For each type of fuel, the 
highest of the 720 (or more) quality-assured hourly average 
NOX concentrations recorded by the CEMS shall be the MEC.

                   2.1.2.3 Span Value(s) and Range(s)

    (a) Determine the high span value of the NOX monitor as 
follows. The high span value shall be obtained by multiplying the MPC by 
a factor no less than 1.00 and no greater than 1.25. Round the span 
value upward to the next highest multiple of 100 ppm. If the 
NOX span concentration is <=500 ppm, the span value may 
either be rounded upward to the next highest multiple of 10 ppm, or to 
the next highest multiple of 100 ppm. The high span value shall be used 
to determine the concentrations of the calibration gases required for 
daily calibration error checks and linearity tests. Note that for 
certain applications, a second (low) NOX span and range may 
be required (see section 2.1.2.4 of this appendix).
    (b) If an existing State, local, or federal requirement for span of 
a NOX pollutant concentration monitor requires or allows the 
use of a span value lower than that required by this section or by 
section 2.1.2.4 of this appendix, the State, local, or federal span 
value may be used, where a satisfactory explanation is included in the 
monitoring plan, unless span and/or range adjustments become necessary 
in accordance with section 2.1.2.5 of this appendix. Span values higher 
than required by this section or by section 2.1.2.4 of this appendix 
must be approved by the Administrator.
    (c) Select the full-scale range of the instrument to be consistent 
with section 2.1 of this appendix and to be greater than or equal to the 
high span value. Include the full-scale range setting and calculations 
of the MPC and span in the monitoring plan for the unit.

                2.1.2.4 Dual Span and Range Requirements

    For most units, the high span value based on the MPC, as determined 
under section 2.1.2.3 of this appendix will suffice to measure and 
record NOX concentrations (unless span and/or range 
adjustments must be made in accordance with section 2.1.2.5 of this 
appendix). In some instances, however, a second (low) span value based 
on the MEC may be required to ensure accurate measurement of all 
expected and potential NOX concentrations. To determine 
whether two NOX spans are required, proceed as follows:
    (a) Compare the MEC value(s) determined in section 2.1.2.2 of this 
appendix to the high full-scale range value determined in section 
2.1.2.3 of this appendix. If the MEC values for all fuels (or blends) 
are =20.0 percent of the high range value, the high span and 
range values determined under section 2.1.2.3 of this appendix are 
sufficient, irrespective of which fuel or blend is combusted in the 
unit. If any of the MEC values is <20.0 percent of the high range value, 
two spans (low and high) are required, one based on the MPC and the 
other based on the MEC.
    (b) When two NOX spans are required, the owner or 
operator may either use a single NOX analyzer with a dual 
range (low-and high-scales) or two separate NOX analyzers 
connected to a common sample probe and sample interface. Two separate 
NOX analyzers connected to separate probes and sample 
interfaces may be used if RATAs are passed on both ranges. For units 
with add-on NOX emission controls (e.g., steam injection, 
water injection, SCR, or SNCR) or units equipped with dry low-
NOX technology, the owner or operator may use a low range 
analyzer and a ``default high range value,'' as described in paragraph 
2.1.2.4(e) of this section, in lieu of maintaining and quality assuring 
a high-scale range. Other monitor configurations are subject to the 
approval of the Administrator.
    (c) The owner or operator shall designate the monitoring systems and 
components in the monitoring plan under Sec. 75.53 as follows: when a 
single probe and sample interface are used, either designate the low and 
high ranges as separate NOX components of a single, primary 
NOX monitoring system; designate the low and high ranges as 
the NOX components of two separate, primary NOX 
monitoring systems; designate the normal range as a primary monitoring 
system and the other range as a non-redundant backup monitoring system; 
or, when a single, dual-range NOX analyzer is used, designate 
the low and high ranges as a single NOX component of a 
primary NOX monitoring system (if this option is selected, 
use a special dual-range component type code, as specified by the 
Administrator, to satisfy the requirements of Sec. 75.53(e)(1)(iv)(D)). 
When two NOX analyzers are connected to separate probes and 
sample interfaces, designate the analyzers as the NOX 
components of two separate, primary NOX monitoring systems. 
For units with add-on NOX controls or units equipped with dry 
low-NOX technology, if the default high range value is used, 
designate the low range analyzer as the NOX component of the 
primary NOX monitoring system. Do not designate the default 
high range as a monitoring system or component. Other

[[Page 364]]

component and system designations are subject to approval by the 
Administrator. Note that the component and system designations for 
redundant backup monitoring systems shall be the same as for primary 
monitoring systems.
    (d) Each monitoring system designated as primary or redundant backup 
shall meet the initial certification and quality assurance requirements 
in Sec. 75.20(c) (for primary monitoring systems), in Sec. 75.20(d)(1) 
(for redundant backup monitoring systems) and appendices A and B to this 
part, with one exception: relative accuracy test audits (RATAs) are 
required only on the normal range (for dual span units with add-on 
NOX emission controls, the low range is considered normal). 
Each monitoring system designated as non-redundant backup shall meet the 
applicable quality assurance requirements in Sec. 75.20(d)(2).
    (e) For dual span units with add-on NOX emission controls 
(e.g., steam injection, water injection, SCR, or SNCR), or, for units 
that use dry low NOX technology, the owner or operator may, 
as an alternative to maintaining and quality assuring a high monitor 
range, use a default high range value. If this option is chosen, the 
owner or operator shall report a default value of 200.0 percent of the 
MPC for each unit operating hour in which the full-scale of the low 
range NOX analyzer is exceeded.
    (f) The high span and range shall be determined in accordance with 
section 2.1.2.3 of this appendix. The low span value shall be 100.0 to 
125.0 percent of the MEC, rounded up to the next highest multiple of 10 
ppm (or 100 ppm, if appropriate). If more than one MEC value (as 
determined in section 2.1.2.2 of this appendix) is <20.0 percent of the 
high full-scale range value, the low span value shall be based upon 
whichever MEC value is closest to 20.0 percent of the high range value. 
The low range must be greater than or equal to the low span value, and 
the required calibration gases for the low range must be selected based 
on the low span value. However, if the default high range option in 
paragraph (e) of this section is selected, the full-scale of the low 
measurement range shall not exceed five times the MEC value (where the 
MEC is rounded upward to the next highest multiple of 10 ppm). For units 
with two NOX spans, use the low range whenever NOX 
concentrations are expected to be consistently <20.0 percent of the high 
range value, i.e., when the MEC of the fuel being combusted is <20.0 
percent of the high range value. When the full-scale of the low range is 
exceeded, the high range shall be used to measure and record the 
NOX concentrations; or, if applicable, the default high range 
value in paragraph (e) of this section shall be reported for each hour 
of the full-scale exceedance.

                  2.1.2.5 Adjustment of Span and Range

    For each affected unit or common stack, the owner or operator shall 
make a periodic evaluation of the MPC, MEC, span, and range values for 
each NOX monitor (at a minimum, an annual evaluation is 
required) and shall make any necessary span and range adjustments, with 
corresponding monitoring plan updates, as described in paragraphs (a), 
(b), and (c) of this section. Span and range adjustments may be 
required, for example, as a result of changes in the fuel supply, 
changes in the manner of operation of the unit, or installation or 
removal of emission controls. In implementing the provisions in 
paragraphs (a) and (b) of this section, note that NOX data 
recorded during short-term, non-representative operating conditions 
(e.g., a trial burn of a different type of fuel) shall be excluded from 
consideration. The owner or operator shall keep the results of the most 
recent span and range evaluation on-site, in a format suitable for 
inspection. Make each required span or range adjustment no later than 45 
days after the end of the quarter in which the need to adjust the span 
or range is identified, except that up to 90 days after the end of that 
quarter may be taken to implement a span adjustment if the calibration 
gases currently being used for daily calibration error tests and 
linearity checks are unsuitable for use with the new span value.
    (a) If the fuel supply, emission controls, or other process 
parameters change such that the maximum expected concentration or the 
maximum potential concentration changes significantly, adjust the 
NOX pollutant concentration span(s) and (if necessary) 
monitor range(s) to assure the continued accuracy of the monitoring 
system. A ``significant'' change in the MPC or MEC means that the 
guidelines in section 2.1 of this appendix can no longer be met, as 
determined by either a periodic evaluation by the owner or operator or 
from the results of an audit by the Administrator. The owner or operator 
should evaluate whether any planned changes in operation of the unit or 
stack may affect the concentration of emissions being emitted from the 
unit and should plan any necessary span and range changes needed to 
account for these changes, so that they are made in as timely a manner 
as practicable to coordinate with the operational changes. An example of 
a change that may require a span and range adjustment is the 
installation of low-NOX burner technology on a previously 
uncontrolled unit. Determine the adjusted span(s) using the procedures 
in section 2.1.2.3 or 2.1.2.4 of this appendix (as applicable). Select 
the full-scale range(s) of the instrument to be greater than or equal to 
the adjusted span value(s) and to be consistent with the guidelines of 
section 2.1 of this appendix.
    (b) Whenever a full-scale range is exceeded during a quarter and the 
exceedance is not

[[Page 365]]

caused by a monitor out-of-control period, proceed as follows:
    (1) For exceedances of the high range, report 200.0 percent of the 
current full-scale range as the hourly NOX concentration for 
each hour of the full-scale exceedance and make appropriate adjustments 
to the MPC, span, and range to prevent future full-scale exceedances.
    (2) For units with two NOX spans and ranges, if the low 
range is exceeded, no further action is required, provided that the high 
range is available and its most recent calibration error test and 
linearity check have not expired. However, if either of these quality 
assurance tests has expired and the high range is not able to provide 
quality assured data at the time of the low range exceedance or at any 
time during the continuation of the exceedance, report the MPC as the 
NOX concentration until the readings return to the low range 
or until the high range is able to provide quality assured data (unless 
the reason that the high-scale range is not able to provide quality 
assured data is because the high-scale range has been exceeded; if the 
high-scale range is exceeded, follow the procedures in paragraph (b)(1) 
of this section).
    (c) Whenever changes are made to the MPC, MEC, full-scale range, or 
span value of the NOX monitor as described in paragraphs (a) 
and (b) of this section, record and report (as applicable) the new full-
scale range setting, the new MPC or MEC, maximum potential 
NOX emission rate, and the adjusted span value in an updated 
monitoring plan for the unit. The monitoring plan update shall be made 
in the quarter in which the changes become effective. In addition, 
record and report the adjusted span as part of the records for the daily 
calibration error test and linearity check required by appendix B to 
this part. Whenever the span value is adjusted, use calibration gas 
concentrations that meet the requirements of section 5.1 of this 
appendix, based on the adjusted span value. When a span adjustment is 
significant enough that the calibration gases currently being used for 
daily calibration error tests and linearity checks are unsuitable for 
use with the new span value, a diagnostic linearity test using the new 
calibration gases must be performed and passed. Use the data validation 
procedures in Sec. 75.20(b)(3), beginning with the hour in which the 
span is changed.

             2.1.3 CO2 and O2 Monitors

    For an O2 monitor (including O2 monitors used 
to measure CO2 emissions or percentage moisture), select a 
span value between 15.0 and 25.0 percent O2. For a 
CO2 monitor installed on a boiler, select a span value 
between 14.0 and 20.0 percent CO2. For a CO2 
monitor installed on a combustion turbine, an alternative span value 
between 6.0 and 14.0 percent CO2 may be used. An alternative 
CO2 span value below 6.0 percent may be used if an 
appropriate technical justification is included in the hardcopy 
monitoring plan. An alternative O2 span value below 15.0 
percent O2 may be used if an appropriate technical 
justification is included in the monitoring plan (e.g., O2 
concentrations above a certain level create an unsafe operating 
condition). Select the full-scale range of the instrument to be 
consistent with section 2.1 of this appendix and to be greater than or 
equal to the span value. Select the calibration gas concentrations for 
the daily calibration error tests and linearity checks in accordance 
with section 5.1 of this appendix, as percentages of the span value. For 
O2 monitors with span values =21.0 percent 
O2, purified instrument air containing 20.9 percent 
O2 may be used as the high-level calibration material. If a 
dual-range or autoranging diluent analyzer is installed, the analyzer 
may be represented in the monitoring plan as a single component, using a 
special component type code specified by the Administrator to satisfy 
the requirements of Sec. 75.53(e)(1)(iv)(D).

        2.1.3.1 Maximum Potential Concentration of CO2

    The MPC and MEC values for diluent monitors are subject to the same 
periodic review as SO2 and NOX monitors (see 
sections 2.1.1.5 and 2.1.2.5 of this appendix). If an MPC or MEC value 
is found to be either inappropriately high or low, the MPC shall be 
adjusted and corresponding span and range adjustments shall be made, if 
necessary.
    For CO2 pollutant concentration monitors, the maximum 
potential concentration shall be 14.0 percent CO2 for boilers 
and 6.0 percent CO2 for combustion turbines. Alternatively, 
the owner or operator may determine the MPC based on a minimum of 720 
hours of quality-assured historical CEM data representing the full 
operating load range of the unit(s). Note that the MPC for 
CO2 monitors shall only be used for the purpose of providing 
substitute data under this part. The CO2 monitor span and 
range shall be determined according to section 2.1.3 of this appendix.

        2.1.3.2 Minimum Potential Concentration of O2

    The owner or operator of a unit that uses a flow monitor and an 
O2 diluent monitor to determine heat input in accordance with 
Equation F-17 or F-18 in appendix F to this part shall, for the purposes 
of providing substitute data under Sec. 75.36, determine the minimum 
potential O2 concentration. The minimum potential 
O2 concentration shall be based upon 720 hours or more of 
quality-assured CEM data, representing the full operating load range of 
the unit(s). The minimum potential O2 concentration shall be 
the

[[Page 366]]

lowest quality-assured hourly average O2 concentration 
recorded in the 720 (or more) hours of data used for the determination.

                  2.1.3.3 Adjustment of Span and Range

    The MPC and MEC values for diluent monitors are subject to the same 
periodic review as SO2 and NOX monitors (see 
sections 2.1.1.5 and 2.1.2.5 of this appendix). If an MPC or MEC value 
is found to be either inappropriately high or low, the MPC shall be 
adjusted and corresponding span and range adjustments shall be made, if 
necessary. Adjust the span value and range of a CO2 or 
O2 monitor in accordance with section 2.1.1.5 of this 
appendix (insofar as those provisions are applicable), with the term 
``CO2 or O2'' applying instead of the term 
``SO2''. Set the new span and range in accordance with 
section 2.1.3 of this appendix and report the new span value in the 
monitoring plan.

                           2.1.4 Flow Monitors

    Select the full-scale range of the flow monitor so that it is 
consistent with section 2.1 of this appendix and can accurately measure 
all potential volumetric flow rates at the flow monitor installation 
site.

            2.1.4.1 Maximum Potential Velocity and Flow Rate

    For this purpose, determine the span value of the flow monitor using 
the following procedure. Calculate the maximum potential velocity (MPV) 
using Equation A-3a or A-3b or determine the MPV (wet basis) from 
velocity traverse testing using Reference Method 2 (or its allowable 
alternatives) in appendix A to part 60 of this chapter. If using test 
values, use the highest average velocity (determined from the Method 2 
traverses) measured at or near the maximum unit operating load (or, for 
units that do not produce electrical or thermal output, at the normal 
process operating conditions corresponding to the maximum stack gas flow 
rate). Express the MPV in units of wet standard feet per minute (fpm). 
For the purpose of providing substitute data during periods of missing 
flow rate data in accordance with Sec. Sec. 75.31 and 75.33 and as 
required elsewhere in this part, calculate the maximum potential stack 
gas flow rate (MPF) in units of standard cubic feet per hour (scfh), as 
the product of the MPV (in units of wet, standard fpm) times 60, times 
the cross-sectional area of the stack or duct (in ft\2\) at the flow 
monitor location.
[GRAPHIC] [TIFF OMITTED] TR26MY99.003

 or
[GRAPHIC] [TIFF OMITTED] TR26MY99.004

Where:

MPV = maximum potential velocity (fpm, standard wet basis).
Fd = dry-basis F factor (dscf/mmBtu) from Table 1, Appendix F 
          to this part.
Fc = carbon-based F factor (scf CO2/mmBtu) from 
          Table 1, Appendix F to this part.
Hf = maximum heat input (mmBtu/minute) for all units, combined, 
          exhausting to the stack or duct where the flow monitor is 
          located.
A = inside cross sectional area (ft\2\) of the flue at the flow monitor 
          location.
%O2d = maximum oxygen concentration, percent dry basis, under 
          normal operating conditions.
%CO2d = minimum carbon dioxide concentration, percent dry 
          basis, under normal operating conditions.
%H2O = maximum percent flue gas moisture content under normal 
          operating conditions.

                      2.1.4.2 Span Values and Range

    Determine the span and range of the flow monitor as follows. Convert 
the MPV, as determined in section 2.1.4.1 of this appendix, to the same 
measurement units of flow rate that are used for daily calibration error 
tests (e.g., scfh, kscfh, kacfm, or differential pressure (inches of 
water)). Next, determine the ``calibration span value'' by multiplying 
the MPV (converted to equivalent daily calibration error units) by a 
factor no less than 1.00

[[Page 367]]

and no greater than 1.25, and rounding up the result to at least two 
significant figures. For calibration span values in inches of water, 
retain at least two decimal places. Select appropriate reference signals 
for the daily calibration error tests as percentages of the calibration 
span value, as specified in section 2.2.2.1 of this appendix. Finally, 
calculate the ``flow rate span value'' (in scfh) as the product of the 
MPF, as determined in section 2.1.4.1 of this appendix, times the same 
factor (between 1.00 and 1.25) that was used to calculate the 
calibration span value. Round off the flow rate span value to the 
nearest 1000 scfh. Select the full-scale range of the flow monitor so 
that it is greater than or equal to the span value and is consistent 
with section 2.1 of this appendix. Include in the monitoring plan for 
the unit: calculations of the MPV, MPF, calibration span value, flow 
rate span value, and full-scale range (expressed both in scfh and, if 
different, in the measurement units of calibration).

                  2.1.4.3 Adjustment of Span and Range

    For each affected unit or common stack, the owner or operator shall 
make a periodic evaluation of the MPV, MPF, span, and range values for 
each flow rate monitor (at a minimum, an annual evaluation is required) 
and shall make any necessary span and range adjustments with 
corresponding monitoring plan updates, as described in paragraphs (a) 
through (c) of this section 2.1.4.3. Span and range adjustments may be 
required, for example, as a result of changes in the fuel supply, 
changes in the stack or ductwork configuration, changes in the manner of 
operation of the unit, or installation or removal of emission controls. 
In implementing the provisions in paragraphs (a) and (b) of this section 
2.1.4.3, note that flow rate data recorded during short-term, non-
representative operating conditions (e.g., a trial burn of a different 
type of fuel) shall be excluded from consideration. The owner or 
operator shall keep the results of the most recent span and range 
evaluation on-site, in a format suitable for inspection. Make each 
required span or range adjustment no later than 45 days after the end of 
the quarter in which the need to adjust the span or range is identified.
    (a) If the fuel supply, stack or ductwork configuration, operating 
parameters, or other conditions change such that the maximum potential 
flow rate changes significantly, adjust the span and range to assure the 
continued accuracy of the flow monitor. A ``significant'' change in the 
MPV or MPF means that the guidelines of section 2.1 of this appendix can 
no longer be met, as determined by either a periodic evaluation by the 
owner or operator or from the results of an audit by the Administrator. 
The owner or operator should evaluate whether any planned changes in 
operation of the unit may affect the flow of the unit or stack and 
should plan any necessary span and range changes needed to account for 
these changes, so that they are made in as timely a manner as 
practicable to coordinate with the operational changes. Calculate the 
adjusted calibration span and flow rate span values using the procedures 
in section 2.1.4.2 of this appendix.
    (b) Whenever the full-scale range is exceeded during a quarter, 
provided that the exceedance is not caused by a monitor out-of-control 
period, report 200.0 percent of the current full-scale range as the 
hourly flow rate for each hour of the full-scale exceedance. If the 
range is exceeded, make appropriate adjustments to the MPF, flow rate 
span, and range to prevent future full-scale exceedances. Calculate the 
new calibration span value by converting the new flow rate span value 
from units of scfh to units of daily calibration. A calibration error 
test must be performed and passed to validate data on the new range.
    (c) Whenever changes are made to the MPV, MPF, full-scale range, or 
span value of the flow monitor, as described in paragraphs (a) and (b) 
of this section, record and report (as applicable) the new full-scale 
range setting, calculations of the flow rate span value, calibration 
span value, MPV, and MPF in an updated monitoring plan for the unit. The 
monitoring plan update shall be made in the quarter in which the changes 
become effective. Record and report the adjusted calibration span and 
reference values as parts of the records for the calibration error test 
required by appendix B to this part. Whenever the calibration span value 
is adjusted, use reference values for the calibration error test that 
meet the requirements of section 2.2.2.1 of this appendix, based on the 
most recent adjusted calibration span value. Perform a calibration error 
test according to section 2.1.1 of appendix B to this part whenever 
making a change to the flow monitor span or range, unless the range 
change also triggers a recertification under Sec. 75.20(b).

               2.1.5 Minimum Potential Moisture Percentage

    Except as provided in section 2.1.6 of this appendix, the owner or 
operator of a unit that uses a continuous moisture monitoring system to 
correct emission rates and heat inputs from a dry basis to a wet basis 
(or vice-versa) shall, for the purpose of providing substitute data 
under Sec. 75.37, use a default value of 3.0 percent H2O as 
the minimum potential moisture percentage. Alternatively, the minimum 
potential moisture percentage may be based upon 720 hours or more of 
quality-assured CEM data, representing the full operating load range of 
the unit(s). If this option

[[Page 368]]

is chosen, the minimum potential moisture percentage shall be the lowest 
quality-assured hourly average H2O concentration recorded in 
the 720 (or more) hours of data used for the determination.

               2.1.6 Maximum Potential Moisture Percentage

    When Equation 19-3, 19-4 or 19-8 in Method 19 in appendix A to part 
60 of this chapter is used to determine NOX emission rate, 
the owner or operator of a unit that uses a continuous moisture 
monitoring system shall, for the purpose of providing substitute data 
under Sec. 75.37, determine the maximum potential moisture percentage. 
The maximum potential moisture percentage shall be based upon 720 hours 
or more of quality-assured CEM data, representing the full operating 
load range of the unit(s). The maximum potential moisture percentage 
shall be the highest quality-assured hourly average H2O 
concentration recorded in the 720 (or more) hours of data used for the 
determination. Alternatively, a default maximum potential moisture value 
of 15.0 percent H2O may be used.

                 2.2 Design for Quality Control Testing

   2.2.1 Pollutant Concentration and CO2 or O2 
                                Monitors

    (a) Design and equip each pollutant concentration and CO2 
or O2 monitor with a calibration gas injection port that 
allows a check of the entire measurement system when calibration gases 
are introduced. For extractive and dilution type monitors, all 
monitoring components exposed to the sample gas, (e.g., sample lines, 
filters, scrubbers, conditioners, and as much of the probe as 
practicable) are included in the measurement system. For in situ type 
monitors, the calibration must check against the injected gas for the 
performance of all active electronic and optical components (e.g. 
transmitter, receiver, analyzer).
    (b) Design and equip each pollutant concentration or CO2 
or O2 monitor to allow daily determinations of calibration 
error (positive or negative) at the zero- and mid-or high-level 
concentrations specified in section 5.2 of this appendix.

                           2.2.2 Flow Monitors

    Design all flow monitors to meet the applicable performance 
specifications.

                     2.2.2.1 Calibration Error Test

    Design and equip each flow monitor to allow for a daily calibration 
error test consisting of at least two reference values: Zero to 20 
percent of span or an equivalent reference value (e.g., pressure pulse 
or electronic signal) and 50 to 70 percent of span. Flow monitor 
response, both before and after any adjustment, must be capable of being 
recorded by the data acquisition and handling system. Design each flow 
monitor to allow a daily calibration error test of the entire flow 
monitoring system, from and including the probe tip (or equivalent) 
through and including the data acquisition and handling system, or the 
flow monitoring system from and including the transducer through and 
including the data acquisition and handling system.

                       2.2.2.2 Interference Check

    (a) Design and equip each flow monitor with a means to ensure that 
the moisture expected to occur at the monitoring location does not 
interfere with the proper functioning of the flow monitoring system. 
Design and equip each flow monitor with a means to detect, on at least a 
daily basis, pluggage of each sample line and sensing port, and 
malfunction of each resistance temperature detector (RTD), transceiver 
or equivalent.
    (b) Design and equip each differential pressure flow monitor to 
provide an automatic, periodic back purging (simultaneously on both 
sides of the probe) or equivalent method of sufficient force and 
frequency to keep the probe and lines sufficiently free of obstructions 
on at least a daily basis to prevent velocity sensing interference, and 
a means for detecting leaks in the system on at least a quarterly basis 
(manual check is acceptable).
    (c) Design and equip each thermal flow monitor with a means to 
ensure on at least a daily basis that the probe remains sufficiently 
clean to prevent velocity sensing interference.
    (d) Design and equip each ultrasonic flow monitor with a means to 
ensure on at least a daily basis that the transceivers remain 
sufficiently clean (e.g., backpurging system) to prevent velocity 
sensing interference.

                      3. Performance Specifications

                          3.1 Calibration Error

    (a) The calibration error performance specifications in this section 
apply only to 7-day calibration error tests under sections 6.3.1 and 
6.3.2 of this appendix and to the offline calibration demonstration 
described in section 2.1.1.2 of appendix B to this part. The calibration 
error limits for daily operation of the continuous monitoring systems 
required under this part are found in section 2.1.4(a) of appendix B to 
this part.
    (b) The calibration error of SO2 and NOX 
pollutant concentration monitors shall not deviate from the reference 
value of either the zero or upscale calibration gas by more than 2.5 
percent of the span of the instrument, as calculated using Equation A-5 
of this appendix. Alternatively, where the span value is less than 200 
ppm, calibration error

[[Page 369]]

test results are also acceptable if the absolute value of the difference 
between the monitor response value and the reference value, [verbar]R-
A[verbar] in Equation A-5 of this appendix, is <=5 ppm. The calibration 
error of CO2 or O2 monitors (including 
O2 monitors used to measure CO2 emissions or 
percent moisture) shall not deviate from the reference value of the zero 
or upscale calibration gas by 0.5 percent O2 or 
CO2, as calculated using the term [verbar]R-A[verbar] in the 
numerator of Equation A-5 of this appendix. The calibration error of 
flow monitors shall not exceed 3.0 percent of the calibration span value 
of the instrument, as calculated using Equation A-6 of this appendix. 
For differential pressure-type flow monitors, the calibration error test 
results are also acceptable if [verbar]R-A[verbar], the absolute value 
of the difference between the monitor response and the reference value 
in Equation A-6, does not exceed 0.01 inches of water.

                           3.2 Linearity Check

    For SO2 and NOX pollutant concentration 
monitors, the error in linearity for each calibration gas concentration 
(low-, mid-, and high-levels) shall not exceed or deviate from the 
reference value by more than 5.0 percent (as calculated using equation 
A-4 of this appendix). Linearity check results are also acceptable if 
the absolute value of the difference between the average of the monitor 
response values and the average of the reference values, [verbar] R-A 
[verbar] in equation A-4 of this appendix, is less than or equal to 5 
ppm. For CO2 or O2 monitors (including 
O2 monitors used to measure CO2 emissions or 
percent moisture):
    (1) The error in linearity for each calibration gas concentration 
(low-, mid-, and high-levels) shall not exceed or deviate from the 
reference value by more than 5.0 percent as calculated using equation A-
4 of this appendix; or
    (2) The absolute value of the difference between the average of the 
monitor response values and the average of the reference values, 
[verbar] R-A[verbar] in equation A-4 of this appendix, shall be less 
than or equal to 0.5 percent CO2 or O2, whichever 
is less restrictive.

                          3.3 Relative Accuracy

           3.3.1 Relative Accuracy for SO2 Monitors

    (a) The relative accuracy for SO2 pollutant concentration 
monitors shall not exceed 10.0 percent except as provided in this 
section.
    (b) For affected units where the average of the reference method 
measurements of SO2 concentration during the relative 
accuracy test audit is less than or equal to 250.0 ppm, the difference 
between the mean value of the monitor measurements and the reference 
method mean value shall not exceed [15.0 ppm, wherever the relative 
accuracy specification of 10.0 percent is not achieved.

 3.3.2 Relative Accuracy for NOX-Diluent Continuous Emission 
                           Monitoring Systems

    (a) The relative accuracy for NOX-diluent continuous 
emission monitoring systems shall not exceed 10.0 percent.
    (b) For affected units where the average of the reference method 
measurements of NOX emission rate during the relative 
accuracy test audit is less than or equal to 0.200 lb/mmBtu, the 
difference between the mean value of the continuous emission monitoring 
system measurements and the reference method mean value shall not exceed 
[0.020 lb/mmBtu, wherever the relative accuracy specification of 10.0 
percent is not achieved.

  3.3.3 Relative Accuracy for CO2 and O2 Monitors

    The relative accuracy for CO2 and O2 monitors 
shall not exceed 10.0 percent. The relative accuracy test results are 
also acceptable if the difference between the mean value of the 
CO2 or O2 monitor measurements and the 
corresponding reference method measurement mean value, calculated using 
equation A-7 of this appendix, does not exceed [1.0 percent 
CO2 or O2.

                3.3.4 Relative Accuracy for Flow Monitors

    (a) The relative accuracy of flow monitors shall not exceed 10.0 
percent at any load (or operating) level at which a RATA is performed 
(i.e., the low, mid, or high level, as defined in section 6.5.2.1 of 
this appendix).
    (b) For affected units where the average of the flow reference 
method measurements of gas velocity at a particular load (or operating) 
level of the relative accuracy test audit is less than or equal to 10.0 
fps, the difference between the mean value of the flow monitor velocity 
measurements and the reference method mean value in fps at that level 
shall not exceed [2.0 fps, wherever the 10.0 percent relative accuracy 
specification is not achieved.

     3.3.5 Combined SO2/Flow Monitoring System [Reserved]

         3.3.6 Relative Accuracy for Moisture Monitoring Systems

    The relative accuracy of a moisture monitoring system shall not 
exceed 10.0 percent. The relative accuracy test results are also 
acceptable if the difference between the mean value of the reference 
method measurements (in percent H2O) and the corresponding 
mean value of the moisture monitoring system measurements (in percent 
H2O), calculated using Equation A-7 of this appendix does not 
exceed [1.5 percent H2O.

  3.3.7 Relative Accuracy for NOX Concentration Monitoring 
                                 Systems

    (a) The following requirement applies only to NOX 
concentration monitoring systems

[[Page 370]]

(i.e., NOX pollutant concentration monitors) that are used to 
determine NOX mass emissions, where the owner or operator 
elects to monitor and report NOX mass emissions using a 
NOX concentration monitoring system and a flow monitoring 
system.
    (b) The relative accuracy for NOX concentration 
monitoring systems shall not exceed 10.0 percent. Alternatively, for 
affected units where the average of the reference method measurements of 
NOX concentration during the relative accuracy test audit is 
less than or equal to 250.0 ppm, the difference between the mean value 
of the continuous emission monitoring system measurements and the 
reference method mean value shall not exceed [15.0 ppm, wherever the 
10.0 percent relative accuracy specification is not achieved.

                                3.4 Bias

 3.4.1 SO2 Pollutant Concentration Monitors, NOX 
 Concentration Monitoring Systems and NOX-Diluent Continuous 
                       Emission Monitoring Systems

    SO2 pollutant concentration monitors, NOX-
diluent continuous emission monitoring systems and NOX 
concentration monitoring systems used to determine NOX mass 
emissions, as defined in Sec. 75.71(a)(2), shall not be biased low as 
determined by the test procedure in section 7.6 of this appendix. The 
bias specification applies to all SO2 pollutant concentration 
monitors and to all NOX concentration monitoring systems, 
including those measuring an average SO2 or NOX 
concentration of 250.0 ppm or less, and to all NOX-diluent 
continuous emission monitoring systems, including those measuring an 
average NOX emission rate of 0.200 lb/mmBtu or less.

                           3.4.2 Flow Monitors

    Flow monitors shall not be biased low as determined by the test 
procedure in section 7.6 of this appendix. The bias specification 
applies to all flow monitors including those measuring an average gas 
velocity of 10.0 fps or less.

                             3.5 Cycle Time

    The cycle time for pollutant concentration monitors, oxygen monitors 
used to determine percent moisture, and any other monitoring component 
of a continuous emission monitoring system that is required to perform a 
cycle time test shall not exceed 15 minutes.

                4. Data Acquisition and Handling Systems

    (a) Automated data acquisition and handling systems shall read and 
record the entire range of pollutant concentrations and volumetric flow 
from zero through full-scale and provide a continuous, permanent record 
of all measurements and required information in an electronic format. 
These systems also shall have the capability of interpreting and 
converting the individual output signals from an SO2 
pollutant concentration monitor, a flow monitor, a CO2 
monitor, an O2 monitor, a NOX pollutant 
concentration monitor, a NOX-diluent CEMS, and a moisture 
monitoring system to produce a continuous readout of pollutant emission 
rates or pollutant mass emissions (as applicable) in the appropriate 
units (e.g., lb/hr, lb/mmBtu, tons/hr).
    (b) Data acquisition and handling systems shall also compute and 
record: Monitor calibration error; any bias adjustments to 
SO2, NOX, flow rate, or NOX emission 
rate data; and all missing data procedure statistics specified in 
subpart D of this part.
    (c) For an excepted monitoring system under appendix D or E of this 
part, data acquisition and handling systems shall:
    (1) Read and record the full range of fuel flowrate through the 
upper range value;
    (2) Calculate and record intermediate values necessary to obtain 
emissions, such as mass fuel flowrate and heat input rate;
    (3) Calculate and record emissions in the appropriate units (e.g., 
lb/hr of SO2, lb/mmBtu of NOX);
    (4) Predict and record NOX emission rate using the heat 
input rate and the NOX/heat input correlation developed under 
appendix E of this part;
    (5) Calculate and record all missing data substitution values 
specified in appendix D or E of this part; and
    (6) Provide a continuous, permanent record of all measurements and 
required information in an electronic format.

                           5. Calibration Gas

                           5.1 Reference Gases

    For the purposes of part 75, calibration gases include the 
following:

                5.1.1 Standard Reference Materials (SRM)

    These calibration gases may be obtained from the National Institute 
of Standards and Technology (NIST) at the following address: Quince 
Orchard and Cloppers Road, Gaithersburg, MD 20899-0001.

  5.1.2 SRM-Equivalent Compressed Gas Primary Reference Material (PRM)

    Contact the Gas Metrology Team, Analytical Chemistry Division, 
Chemical Science and Technology Laboratory of NIST, at the address in 
section 5.1.1, for a list of vendors and cylinder gases.

                5.1.3 NIST Traceable Reference Materials

    Contact the Gas Metrology Team, Analytical Chemistry Division, 
Chemical Science and Technology Laboratory of NIST, at the

[[Page 371]]

address in section 5.1.1, for a list of vendors and cylinder gases that 
meet the definition for a NIST Traceable Reference Material (NTRM) 
provided in Sec. 72.2.

                        5.1.4 EPA Protocol Gases

    (a) An EPA Protocol gas is a calibration gas mixture prepared and 
analyzed according to Section 2 of the ``EPA Traceability Protocol for 
Assay and Certification of Gaseous Calibration Standards,'' September 
1997, as amended on August 25, 1999, EPA-600/R-97/121 (incorporated by 
reference, see Sec. 75.6) or such revised procedure as approved by the 
Administrator.
    (b) EPA Protocol gas concentrations must be certified by an EPA 
Protocol gas production site to have an analytical uncertainty (95-
percent confidence interval) to be not more than plus or minus 2.0 
percent (inclusive) of the certified concentration (tag value) of the 
gas mixture. The uncertainty must be calculated using the statistical 
procedures (or equivalent statistical techniques) that are listed in 
Section 2.1.8 of the ``EPA Traceability Protocol for Assay and 
Certification of Gaseous Calibration Standards,'' September 1997, as 
amended on August 25, 1999, EPA-600/R-97/121 (incorporated by reference, 
see Sec. 75.6).

                       5.1.5 Research Gas Mixtures

    Concentrations of research gas mixtures, as defined in Sec. 72.2 of 
this chapter, must be certified by the National Institute of Standards 
and Technology to have an analytical uncertainty (95-percent confidence 
interval) calculated using the statistical procedures (or equivalent 
statistical techniques) that are listed in Section 2.1.8 of the ``EPA 
Traceability Protocol for Assay and Certification of Gaseous Calibration 
Standards,'' September 1997, as amended on August 25, 1999, EPA-600/R-
97/121 (incorporated by reference, see Sec. 75.6) to be not more than 
plus or minus 2.0 percent (inclusive) of the concentration specified on 
the cylinder label (i.e., the tag value) in order to be used as 
calibration gas under this part. Inquiries about the RGM program should 
be directed to: National Institute of Standards and Technology, 
Analytical Chemistry Division, Chemical Science and Technology 
Laboratory, B-324 Chemistry, Gaithersburg, MD 20899.

                         5.1.6 Zero Air Material

    Zero air material is defined in Sec. 72.2 of this chapter.

          5.1.7 NIST/EPA-Approved Certified Reference Materials

    Existing certified reference materials (CRMs) that are still within 
their certification period may be used as calibration gas.

             5.1.8 Gas Manufacturer's Intermediate Standards

    Gas manufacturer's intermediate standards is defined in Sec. 72.2 
of this chapter.

                           5.2 Concentrations

    Four concentration levels are required as follows.

                     5.2.1 Zero-level Concentration

    0.0 to 20.0 percent of span, including span for high-scale or both 
low- and high-scale for SO2, NOX, CO2, 
and O2 monitors, as appropriate.

                      5.2.2 Low-level Concentration

    20.0 to 30.0 percent of span, including span for high-scale or both 
low- and high-scale for SO2, NOX, CO2, 
and O2 monitors, as appropriate.

                      5.2.3 Mid-level Concentration

    50.0 to 60.0 percent of span, including span for high-scale or both 
low- and high-scale for SO2, NOX, CO2, 
and O2 monitors, as appropriate.

                     5.2.4 High-level Concentration

    80.0 to 100.0 percent of span, including span for high-scale or both 
low-and high-scale for SO2, NOX, CO2, 
and O2 monitors, as appropriate.

                  6. Certification Tests and Procedures

                        6.1 General Requirements

                        6.1.1 Pretest Preparation

    Install the components of the continuous emission monitoring system 
(i.e., pollutant concentration monitors, CO2 or O2 
monitor, and flow monitor) as specified in sections 1, 2, and 3 of this 
appendix, and prepare each system component and the combined system for 
operation in accordance with the manufacturer's written instructions. 
Operate the unit(s) during each period when measurements are made. Units 
may be tested on non-consecutive days. To the extent practicable, test 
the DAHS software prior to testing the monitoring hardware.

               6.1.2 Requirements for Air Emission Testing

    (a) On and after March 27, 2012, all relative accuracy test audits 
(RATAs) of CEMS under this part, and stack testing under Sec. 75.19 and 
Appendix E to this part shall be conducted by an Air Emission Testing 
Body (AETB) which has provided to the owner or operator of a unit 
subject to this part the documentation required in paragraph (b) of this 
section, demonstrating its conformance to ASTM D7036-04 (incorporated by 
reference, see Sec. 75.6).

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    (b) The owner or operator shall obtain from the AETB a certification 
that as of the time of testing the AETB is operating in conformance with 
ASTM D7036-04 (incorporated by reference, see Sec. 75.6). The AETB's 
certification may be limited in scope to the tests identified under 
paragraph (a). The AETB's certification need not extend to other work it 
may perform. This certification shall be provided in the form of either:
    (1) A certificate of accreditation or interim accreditation for the 
relevant test methods issued by a recognized, national accreditation 
body; or
    (2) A letter of certification for the relevant test methods signed 
by a member of the senior management staff of the AETB.
    (c) The owner or operator shall obtain from the AETB the information 
required under Sec. Sec. 75.59(a)(15), (b)(6), and (d)(4), as 
applicable.
    (d) While under no obligation to request the following information 
from an AETB, to review the information provided by the AETB in response 
to such a request, or to take any other action related to the response, 
the owner or operator may find it useful to request that AETBs complying 
with paragraph (b)(2) of this section provide a copy of the following:
    (1) The AETB's quality manual. For the purpose of application of 40 
CFR part 2, subpart B, AETB's concerned about the potential for public 
access to confidential business information (CBI) may identify any 
information subject to such a claim in the copy provided;
    (2) The results of any internal audits performed by the AETB and any 
external audits of the AETB during the 12 month period through the 
previous calendar quarter;
    (3) Performance data (as defined in ASTM D7036-04 (incorporated by 
reference, see Sec. 75.6)) collected by the AETB, including corrective 
actions implemented, during the 12 month period through the previous 
calendar quarter; and
    (4) Training records for all on-site technical personnel, including 
any Qualified Individuals, for the 12 month period through the previous 
calendar quarter.
    (e) All relative accuracy testing performed pursuant to Sec. 
75.74(c)(2)(ii), section 6.5 of appendix A to this part or section 2.3.1 
of appendix B to this part, and stack testing under Sec. 75.19 and 
Appendix E to this part shall be overseen and supervised on site by at 
least one Qualified Individual, as defined in Sec. 72.2 of this chapter 
with respect to the methods employed in the test project. If the source 
owner or operator, or a State, local, or EPA observer, discovers while 
the test team is still on site, that at least one QI did not oversee and 
supervise the entire test (as qualified by this paragraph (e)), only 
those portions of the test that were overseen and supervised by at least 
one QI as described above may be used under this part. However, 
allowance is made for normal activities of a QI who is overseeing and 
supervising a test, e.g., bathroom breaks, meal breaks, and emergencies 
that may arise during a test.
    (f) Except as provided in paragraph (e), no RATA performed pursuant 
to Sec. 75.74(c)(2)(ii), section 6.5 of appendix A to this part or 
section 2.3.1 of appendix B to this part, and no stack test under Sec. 
75.19 or Appendix E to this part (or portion of such a RATA or stack 
test) conducted by an AETB (as defined in Sec. 72.2) shall be 
invalidated under this part as a result of the failure of the AETB to 
conform to ASTM D7036-04 (incorporated by reference, see Sec. 75.6). 
Validation of such tests is determined based on the other part 75 
testing requirements. EPA recommends that proper observation of tests 
and review of test results continue, regardless of whether an AETB fully 
conforms to ASTM D7036-04.
    (g) An owner or operator who has requested information from an AETB 
under paragraph (d) of this part who believes that the information 
provided by the AETB was either incomplete or inaccurate may request the 
Administrator's assistance in remedying the alleged deficiencies. Upon 
such a request, if the Administrator concurs that the information 
submitted to a source subject to part 75 by an AETB under this section 
is either incomplete or inaccurate, the Administrator will provide the 
AETB a description of the deficiencies to be remedied. The 
Administrator's determination of completeness and accuracy of 
information will be solely based on the provisions of ASTM D7036-04 
(incorporated by reference, see Sec. 75.6) and this part. The 
Administrator may post the name of the offending AETB on Agency Web 
sites (including the CAMD Web site http://www.epa.gov/airmarkets/
emissions/aetb.html) if within 30 days of the Administrator having 
provided the AETB a description of the deficiencies to be remedied, the 
AETB does not satisfactorily respond to the source and notify the 
Administrator of the response by submitting the notification to 
[email protected], unless otherwise provided by the Administrator. The AETB 
need not submit the information it provides to the owner or operator to 
the Administrator, unless specifically requested by the Administrator. 
If after the AETB's name is posted, the Administrator, in consultation 
with the source, determines that the AETB's response is sufficient, the 
AETB's name will be removed from the EPA Web sites.

                6.2 Linearity Check (General Procedures)

    Check the linearity of each SO2, NOX, 
CO2, and O2 monitor while the unit, or group of 
units for a common stack, is combusting fuel at conditions of typical 
stack temperature and pressure; it is not necessary for the unit to be 
generating electricity during this test. Notwithstanding these 
requirements, if the

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SO2 or NOX span value for a particular monitor 
range is <=30 ppm, that range is exempted from the linearity check 
requirements of this part, for initial certification, recertification, 
and for on-going quality-assurance. For units with two measurement 
ranges (high and low) for a particular parameter, perform a linearity 
check on both the low scale (except for SO2 or NOX 
span values <=30 ppm) and the high scale. Note that for a 
NOX-diluent monitoring system with two NOX 
measurement ranges, if the low NOX scale has a span value 
<=30 ppm and is exempt from linearity checks, this does not exempt 
either the diluent monitor or the high NOX scale (if the span 
is 30 ppm) from linearity check requirements. For on-going 
quality assurance of the CEMS, perform linearity checks, using the 
procedures in this section, on the range(s) and at the frequency 
specified in section 2.2.1 of appendix B to this part. Challenge each 
monitor with calibration gas, as defined in section 5.1 of this 
appendix, at the low-, mid-, and high-range concentrations specified in 
section 5.2 of this appendix. Introduce the calibration gas at the gas 
injection port, as specified in section 2.2.1 of this appendix. Operate 
each monitor at its normal operating temperature and conditions. For 
extractive and dilution type monitors, pass the calibration gas through 
all filters, scrubbers, conditioners, and other monitor components used 
during normal sampling and through as much of the sampling probe as is 
practical. For in-situ type monitors, perform calibration checking all 
active electronic and optical components, including the transmitter, 
receiver, and analyzer. Challenge the monitor three times with each 
reference gas (see example data sheet in Figure 1). Do not use the same 
gas twice in succession. To the extent practicable, the duration of each 
linearity test, from the hour of the first injection to the hour of the 
last injection, shall not exceed 24 unit operating hours. Record the 
monitor response from the data acquisition and handling system. For each 
concentration, use the average of the responses to determine the error 
in linearity using Equation A-4 in this appendix. Linearity checks are 
acceptable for monitor or monitoring system certification, 
recertification, or quality assurance if none of the test results exceed 
the applicable performance specifications in section 3.2 of this 
appendix. The status of emission data from a CEMS prior to and during a 
linearity test period shall be determined as follows:
    (a) For the initial certification of a CEMS, data from the 
monitoring system are considered invalid until all certification tests, 
including the linearity test, have been successfully completed, unless 
the conditional data validation procedures in Sec. 75.20(b)(3) are 
used. When the procedures in Sec. 75.20(b)(3) are followed, the words 
``initial certification'' apply instead of ``recertification,'' and 
complete all of the initial certification tests by the applicable 
deadline in Sec. 75.4, rather than within the time periods specified in 
Sec. 75.20(b)(3)(iv) for the individual tests.
    (b) For the routine quality assurance linearity checks required by 
section 2.2.1 of appendix B to this part, use the data validation 
procedures in section 2.2.3 of appendix B to this part.
    (c) When a linearity test is required as a diagnostic test or for 
recertification, use the data validation procedures in Sec. 
75.20(b)(3).
    (d) For linearity tests of non-redundant backup monitoring systems, 
use the data validation procedures in Sec. 75.20(d)(2)(iii).
    (e) For linearity tests performed during a grace period and after 
the expiration of a grace period, use the data validation procedures in 
sections 2.2.3 and 2.2.4, respectively, of appendix B to this part.
    (f) For all other linearity checks, use the data validation 
procedures in section 2.2.3 of appendix B to this part.

                    6.3 7-Day Calibration Error Test

             6.3.1 Gas Monitor 7-Day Calibration Error Test

    The following monitors and ranges are exempted from the 7-day 
calibration error test requirements of this part: the SO2, 
NOX, CO2 and O2 monitors installed on 
peaking units (as defined in Sec. 72.2 of this chapter); and any 
SO2 or NOX measurement range with a span value of 
50 ppm or less. In all other cases, measure the calibration error of 
each SO2 monitor, each NOX monitor, and each 
CO2 or O2 monitor while the unit is combusting 
fuel (but not necessarily generating electricity) once each day for 7 
consecutive operating days according to the following procedures. (In 
the event that unit outages occur after the commencement of the test, 
the 7 consecutive unit operating days need not be 7 consecutive calendar 
days). Units using dual span monitors must perform the calibration error 
test on both high- and low-scales of the pollutant concentration 
monitor. The calibration error test procedures in this section and in 
section 6.3.2 of this appendix shall also be used to perform the daily 
assessments and additional calibration error tests required under 
sections 2.1.1 and 2.1.3 of appendix B to this part. Do not make manual 
or automatic adjustments to the monitor settings until after taking 
measurements at both zero and high concentration levels for that day 
during the 7-day test. If automatic adjustments are made following both 
injections, conduct the calibration error test such that the magnitude 
of the adjustments can be determined and recorded. Record and report 
test results for each day using the unadjusted concentration measured in 
the calibration error test prior to making any

[[Page 374]]

manual or automatic adjustments (i.e., resetting the calibration). The 
calibration error tests should be approximately 24 hours apart, (unless 
the 7-day test is performed over nonconsecutive days). Perform 
calibration error tests at both the zero-level concentration and high-
level concentration, as specified in section 5.2 of this appendix. 
Alternatively, a mid-level concentration gas (50.0 to 60.0 percent of 
the span value) may be used in lieu of the high-level gas, provided that 
the mid-level gas is more representative of the actual stack gas 
concentrations. A calibration gas blend may be used as both a zero-level 
gas and an upscale (mid- or high-level) gas, where appropriate. In 
addition, repeat the procedure for SO2 and NOX 
pollutant concentration monitors using the low-scale for units equipped 
with emission controls or other units with dual span monitors. Use only 
calibration gas, as specified in section 5.1 of this appendix. Introduce 
the calibration gas at the gas injection port, as specified in section 
2.2.1 of this appendix. Operate each monitor in its normal sampling 
mode. For extractive and dilution type monitors, pass the calibration 
gas through all filters, scrubbers, conditioners, and other monitor 
components used during normal sampling and through as much of the 
sampling probe as is practical. For in-situ type monitors, perform 
calibration, checking all active electronic and optical components, 
including the transmitter, receiver, and analyzer. Challenge the 
pollutant concentration monitors and CO2 or O2 
monitors once with each calibration gas. Record the monitor response 
from the data acquisition and handling system. Using Equation A-5 of 
this appendix, determine the calibration error at each concentration 
once each day (at approximately 24-hour intervals) for 7 consecutive 
days according to the procedures given in this section. The results of a 
7-day calibration error test are acceptable for monitor or monitoring 
system certification, recertification or diagnostic testing if none of 
these daily calibration error test results exceed the applicable 
performance specifications in section 3.1 of this appendix. The status 
of emission data from a gas monitor prior to and during a 7-day 
calibration error test period shall be determined as follows:
    (a) For initial certification, data from the monitor are considered 
invalid until all certification tests, including the 7-day calibration 
error test, have been successfully completed, unless the conditional 
data validation procedures in Sec. 75.20(b)(3) are used. When the 
procedures in Sec. 75.20(b)(3) are followed, the words ``initial 
certification'' apply instead of ``recertification,'' and complete all 
of the initial certification tests by the applicable deadline in Sec. 
75.4, rather than within the time periods specified in Sec. 
75.20(b)(3)(iv) for the individual tests.
    (b) When a 7-day calibration error test is required as a diagnostic 
test or for recertification, use the data validation procedures in Sec. 
75.20(b)(3).

             6.3.2 Flow Monitor 7-day Calibration Error Test

    Flow monitors installed on peaking units (as defined in Sec. 72.2 
of this chapter) are exempted from the 7-day calibration error test 
requirements of this part. In all other cases, perform the 7-day 
calibration error test of a flow monitor, when required for 
certification, recertification or diagnostic testing, according to the 
following procedures. Introduce the reference signal corresponding to 
the values specified in section 2.2.2.1 of this appendix to the probe 
tip (or equivalent), or to the transducer. During the 7-day 
certification test period, conduct the calibration error test while the 
unit is operating once each unit operating day (as close to 24-hour 
intervals as practicable). In the event that unit outages occur after 
the commencement of the test, the 7 consecutive operating days need not 
be 7 consecutive calendar days. Record the flow monitor responses by 
means of the data acquisition and handling system. Calculate the 
calibration error using Equation A-6 of this appendix. Do not perform 
any corrective maintenance, repair, or replacement upon the flow monitor 
during the 7-day test period other than that required in the quality 
assurance/quality control plan required by appendix B to this part. Do 
not make adjustments between the zero and high reference level 
measurements on any day during the 7-day test. If the flow monitor 
operates within the calibration error performance specification (i.e., 
less than or equal to 3.0 percent error each day and requiring no 
corrective maintenance, repair, or replacement during the 7-day test 
period), the flow monitor passes the calibration error test. Record all 
maintenance activities and the magnitude of any adjustments. Record 
output readings from the data acquisition and handling system before and 
after all adjustments. Record and report all calibration error test 
results using the unadjusted flow rate measured in the calibration error 
test prior to resetting the calibration. Record all adjustments made 
during the 7-day period at the time the adjustment is made, and report 
them in the certification or recertification application. The status of 
emissions data from a flow monitor prior to and during a 7-day 
calibration error test period shall be determined as follows:
    (a) For initial certification, data from the monitor are considered 
invalid until all certification tests, including the 7-day calibration 
error test, have been successfully completed, unless the conditional 
data validation procedures in Sec. 75.20(b)(3) are used. When the 
procedures in Sec. 75.20(b)(3) are followed,

[[Page 375]]

the words ``initial certification'' apply instead of 
``recertification,'' and complete all of the initial certification tests 
by the applicable deadline in Sec. 75.4, rather than within the time 
periods specified in Sec. 75.20(b)(3)(iv) for the individual tests.
    (b) When a 7-day calibration error test is required as a diagnostic 
test or for recertification, use the data validation procedures in Sec. 
75.20(b)(3).
    6.3.3 For gas or flow monitors installed on peaking units, the 
exemption from performing the 7-day calibration error test applies as 
long as the unit continues to meet the definition of a peaking unit in 
Sec. 72.2 of this chapter. However, if at the end of a particular 
calendar year or ozone season, it is determined that peaking unit status 
has been lost, the owner or operator shall perform a diagnostic 7-day 
calibration error test of each monitor installed on the unit, by no 
later than December 31 of the following calendar year.

                           6.4 Cycle Time Test

    Perform cycle time tests for each pollutant concentration monitor 
and continuous emission monitoring system while the unit is operating, 
according to the following procedures. Use a zero-level and a high-level 
calibration gas (as defined in section 5.2 of this appendix) 
alternately. To determine the downscale cycle time, measure the 
concentration of the flue gas emissions until the response stabilizes. 
Record the stable emissions value. Inject a zero-level concentration 
calibration gas into the probe tip (or injection port leading to the 
calibration cell, for in situ systems with no probe). Record the time of 
the zero gas injection, using the data acquisition and handling system 
(DAHS). Next, allow the monitor to measure the concentration of the zero 
gas until the response stabilizes. Record the stable ending calibration 
gas reading. Determine the downscale cycle time as the time it takes for 
95.0 percent of the step change to be achieved between the stable stack 
emissions value and the stable ending zero gas reading. Then repeat the 
procedure, starting with stable stack emissions and injecting the high-
level gas, to determine the upscale cycle time, which is the time it 
takes for 95.0 percent of the step change to be achieved between the 
stable stack emissions value and the stable ending high-level gas 
reading. Use the following criteria to assess when a stable reading of 
stack emissions or calibration gas concentration has been attained. A 
stable value is equivalent to a reading with a change of less than 2.0 
percent of the span value for 2 minutes, or a reading with a change of 
less than 6.0 percent from the measured average concentration over 6 
minutes. Alternatively, the reading is considered stable if it changes 
by no more than 0.5 ppm or 0.2% CO2 or O2 (as 
applicable) for two minutes. (Owners or operators of systems which do 
not record data in 1-minute or 3-minute intervals may petition the 
Administrator under Sec. 75.66 for alternative stabilization criteria). 
For monitors or monitoring systems that perform a series of operations 
(such as purge, sample, and analyze), time the injections of the 
calibration gases so they will produce the longest possible cycle time. 
Refer to Figures 6a and 6b in this appendix for example calculations of 
upscale and downscale cycle times. Report the slower of the two cycle 
times (upscale or downscale) as the cycle time for the analyzer. Prior 
to January 1, 2009 for the NOX-diluent continuous emission 
monitoring system test, either record and report the longer cycle time 
of the two component analyzers as the system cycle time or record the 
cycle time for each component analyzer separately (as applicable). On 
and after January 1, 2009, record the cycle time for each component 
analyzer separately. For time-shared systems, perform the cycle time 
tests at each probe locations that will be polled within the same 15-
minute period during monitoring system operations. To determine the 
cycle time for time-shared systems, at each monitoring location, report 
the sum of the cycle time observed at that monitoring location plus the 
sum of the time required for all purge cycles (as determined by the 
continuous emission monitoring system manufacturer) at each of the probe 
locations of the time-shared systems. For monitors with dual ranges, 
report the test results for each range separately. Cycle time test 
results are acceptable for monitor or monitoring system certification, 
recertification or diagnostic testing if none of the cycle times exceed 
15 minutes. The status of emissions data from a monitor prior to and 
during a cycle time test period shall be determined as follows:
    (a) For initial certification, data from the monitor are considered 
invalid until all certification tests, including the cycle time test, 
have been successfully completed, unless the conditional data validation 
procedures in Sec. 75.20(b)(3) are used. When the procedures in Sec. 
75.20(b)(3) are followed, the words ``initial certification'' apply 
instead of ``recertification,'' and complete all of the initial 
certification tests by the applicable deadline in Sec. 75.4, rather 
than within the time periods specified in Sec. 75.20(b)(3)(iv) for the 
individual tests.
    (b) When a cycle time test is required as a diagnostic test or for 
recertification, use the data validation procedures in Sec. 
75.20(b)(3).

        6.5 Relative Accuracy and Bias Tests (General Procedures)

    Perform the required relative accuracy test audits (RATAs) as 
follows for each CO2 emissions concentration monitor 
(including O2 monitors used to determine CO2 
emissions

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concentration), each SO2 pollutant concentration monitor, 
each NOX concentration monitoring system used to determine 
NOX mass emissions, each flow monitor, each NOX-
diluent CEMS, each O2 or CO2 diluent monitor used 
to calculate heat input, and each moisture monitoring system. For 
NOX concentration monitoring systems used to determine 
NOX mass emissions, as defined in Sec. 75.71(a)(2), use the 
same general RATA procedures as for SO2 pollutant 
concentration monitors; however, use the reference methods for 
NOX concentration specified in section 6.5.10 of this 
appendix:
    (a) Except as otherwise provided in this paragraph or in Sec. 
75.21(a)(5), perform each RATA while the unit (or units, if more than 
one unit exhausts into the flue) is combusting the fuel that is a normal 
primary or backup fuel for that unit (for some units, more than one type 
of fuel may be considered normal, e.g., a unit that combusts gas or oil 
on a seasonal basis). For units that co-fire fuels as the predominant 
mode of operation, perform the RATAs while co-firing. For Hg monitoring 
systems, perform the RATAs while the unit is combusting coal. When 
relative accuracy test audits are performed on CEMS installed on bypass 
stacks/ducts, use the fuel normally combusted by the unit (or units, if 
more than one unit exhausts into the flue) when emissions exhaust 
through the bypass stack/ducts.
    (b) Perform each RATA at the load (or operating) level(s) specified 
in section 6.5.1 or 6.5.2 of this appendix or in section 2.3.1.3 of 
appendix B to this part, as applicable.
    (c) For monitoring systems with dual ranges, perform the relative 
accuracy test on the range normally used for measuring emissions. For 
units with add-on SO2 or NOX controls that operate 
continuously rather than seasonally, or for units that need a dual range 
to record high concentration ``spikes'' during startup conditions, the 
low range is considered normal. However, for some dual span units (e.g., 
for units that use fuel switching or for which the emission controls are 
operated seasonally), provided that both monitor ranges are connected to 
a common probe and sample interface, either of the two measurement 
ranges may be considered normal; in such cases, perform the RATA on the 
range that is in use at the time of the scheduled test. If the low and 
high measurement ranges are connected to separate sample probes and 
interfaces, RATA testing on both ranges is required.
    (d) Record monitor or monitoring system output from the data 
acquisition and handling system.
    (e) Complete each single-load relative accuracy test audit within a 
period of 168 consecutive unit operating hours, as defined in Sec. 72.2 
of this chapter (or, for CEMS installed on common stacks or bypass 
stacks, 168 consecutive stack operating hours, as defined in Sec. 72.2 
of this chapter). For 2-level and 3-level flow monitor RATAs, complete 
all of the RATAs at all levels, to the extent practicable, within a 
period of 168 consecutive unit (or stack) operating hours; however, if 
this is not possible, up to 720 consecutive unit (or stack) operating 
hours may be taken to complete a multiple-load flow RATA.
    (f) The status of emission data from the CEMS prior to and during 
the RATA test period shall be determined as follows:
    (1) For the initial certification of a CEMS, data from the 
monitoring system are considered invalid until all certification tests, 
including the RATA, have been successfully completed, unless the 
conditional data validation procedures in Sec. 75.20(b)(3) are used. 
When the procedures in Sec. 75.20(b)(3) are followed, the words 
``initial certification'' apply instead of ``recertification,'' and 
complete all of the initial certification tests by the applicable 
deadline in Sec. 75.4, rather than within the time periods specified in 
Sec. 75.20(b)(3)(iv) for the individual tests.
    (2) For the routine quality assurance RATAs required by section 
2.3.1 of appendix B to this part, use the data validation procedures in 
section 2.3.2 of appendix B to this part.
    (3) For recertification RATAs, use the data validation procedures in 
Sec. 75.20(b)(3).
    (4) For quality assurance RATAs of non-redundant backup monitoring 
systems, use the data validation procedures in Sec. Sec. 75.20(d)(2)(v) 
and (vi).
    (5) For RATAs performed during and after the expiration of a grace 
period, use the data validation procedures in sections 2.3.2 and 2.3.3, 
respectively, of appendix B to this part.
    (6) For all other RATAs, use the data validation procedures in 
section 2.3.2 of appendix B to this part.
    (g) For each SO2 or CO2 emissions 
concentration monitor, each flow monitor, each CO2 or 
O2 diluent monitor used to determine heat input, each 
NOX concentration monitoring system used to determine 
NOX mass emissions, as defined in Sec. 75.71(a)(2), each 
moisture monitoring system, and each NOX-diluent CEMS, 
calculate the relative accuracy, in accordance with section 7.3 or 7.4 
of this appendix, as applicable. In addition (except for CO2, 
O2, or moisture monitors), test for bias and determine the 
appropriate bias adjustment factor, in accordance with sections 7.6.4 
and 7.6.5 of this appendix, using the data from the relative accuracy 
test audits.

       6.5.1 Gas Monitoring System RATAs (Special Considerations)

    (a) Perform the required relative accuracy test audits for each 
SO2 or CO2 emissions concentration monitor, each 
CO2 or O2 diluent monitor used to determine heat 
input,

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each NOX-diluent CEMS, and each NOX concentration 
monitoring system used to determine NOX mass emissions, as 
defined in Sec. 75.71(a)(2), at the normal load level or normal 
operating level for the unit (or combined units, if common stack), as 
defined in section 6.5.2.1 of this appendix. If two load levels or 
operating levels have been designated as normal, the RATAs may be done 
at either load (or operating) level.
    (b) For the initial certification of a gas monitoring system and for 
recertifications in which, in addition to a RATA, one or more other 
tests are required (i.e., a linearity test, cycle time test, or 7-day 
calibration error test), EPA recommends that the RATA not be commenced 
until the other required tests of the CEMS have been passed.

            6.5.2 Flow Monitor RATAs (Special Considerations)

    (a) Except as otherwise provided in paragraph (b) or (e) of this 
section, perform relative accuracy test audits for the initial 
certification of each flow monitor at three different exhaust gas 
velocities (low, mid, and high), corresponding to three different load 
levels or operating levels within the range of operation, as defined in 
section 6.5.2.1 of this appendix. For a common stack/duct, the three 
different exhaust gas velocities may be obtained from frequently used 
unit/load or operating level combinations for the units exhausting to 
the common stack. Select the three exhaust gas velocities such that the 
audit points at adjacent load or operating levels (i.e., low and mid or 
mid and high), in megawatts (or in thousands of lb/hr of steam 
production or in ft/sec, as applicable), are separated by no less than 
25.0 percent of the range of operation, as defined in section 6.5.2.1 of 
this appendix.
    (b) For flow monitors on bypass stacks/ducts and peaking units, the 
flow monitor relative accuracy test audits for initial certification and 
recertification shall be single-load tests, performed at the normal 
load, as defined in section 6.5.2.1(d) of this appendix.
    (c) Flow monitor recertification RATAs shall be done at three load 
level(s) (or three operating levels), unless otherwise specified in 
paragraph (b) or (e) of this section or unless otherwise specified or 
approved by the Administrator.
    (d) The semiannual and annual quality assurance flow monitor RATAs 
required under appendix B to this part shall be done at the load 
level(s) (or operating levels) specified in section 2.3.1.3 of appendix 
B to this part.
    (e) For flow monitors installed on units that do not produce 
electrical or thermal output, the flow RATAs for initial certification 
or recertification may be done at fewer than three operating levels, if:
    (1) The owner or operator provides a technical justification in the 
hardcopy portion of the monitoring plan for the unit required under 
Sec. 75.53(e)(2), demonstrating that the unit operates at only one 
level or two levels during normal operation (excluding unit startup and 
shutdown). Appropriate documentation and data must be provided to 
support the claim of single-level or two-level operation; and
    (2) The justification provided in paragraph (e)(1) of this section 
is deemed to be acceptable by the permitting authority.

   6.5.2.1 Range of Operation and Normal Load (or Operating) Level(s)

    (a) The owner or operator shall determine the upper and lower 
boundaries of the ``range of operation'' as follows for each unit (or 
combination of units, for common stack configurations):
    (1) For affected units that produce electrical output (in megawatts) 
or thermal output (in klb/hr of steam production or mmBtu/hr), the lower 
boundary of the range of operation of a unit shall be the minimum safe, 
stable loads for any of the units discharging through the stack. 
Alternatively, for a group of frequently-operated units that serve a 
common stack, the sum of the minimum safe, stable loads for the 
individual units may be used as the lower boundary of the range of 
operation. The upper boundary of the range of operation of a unit shall 
be the maximum sustainable load. The ``maximum sustainable load'' is the 
higher of either: the nameplate or rated capacity of the unit, less any 
physical or regulatory limitations or other deratings; or the highest 
sustainable load, based on at least four quarters of representative 
historical operating data. For common stacks, the maximum sustainable 
load is the sum of all of the maximum sustainable loads of the 
individual units discharging through the stack, unless this load is 
unattainable in practice, in which case use the highest sustainable 
combined load for the units that discharge through the stack. Based on 
at least four quarters of representative historical operating data. The 
load values for the unit(s) shall be expressed either in units of 
megawatts of thousands of lb/hr of steam load or mmBtu/hr of thermal 
output; or
    (2) For affected units that do not produce electrical or thermal 
output, the lower boundary of the range of operation shall be the 
minimum expected flue gas velocity (in ft/sec) during normal, stable 
operation of the unit. The upper boundary of the range of operation 
shall be the maximum potential flue gas velocity (in ft/sec) as defined 
in section 2.1.4.1 of this appendix. The minimum expected and maximum 
potential velocities may be derived from the results of reference method 
testing or by using Equation A-3a or A-3b (as applicable) in section 
2.1.4.1 of this appendix. If Equation A-3a or A-3b is used to determine 
the minimum expected velocity, replace the word ``maximum'' with the 
word

[[Page 378]]

``minimum'' in the definitions of ``MPV,'' ``Hf,'' ``% 
O2d,'' and ``% H2O,'' and replace the word 
``minimum'' with the word ``maximum'' in the definition of 
``CO2d.'' Alternatively, 0.0 ft/sec may be used as the lower 
boundary of the range of operation.
    (b) The operating levels for relative accuracy test audits shall, 
except for peaking units, be defined as follows: the ``low'' operating 
level shall be the first 30.0 percent of the range of operation; the 
``mid'' operating level shall be the middle portion (30.0 
percent, but <=60.0 percent) of the range of operation; and the ``high'' 
operating level shall be the upper end (60.0 percent) of the 
range of operation. For example, if the upper and lower boundaries of 
the range of operation are 100 and 1100 megawatts, respectively, then 
the low, mid, and high operating levels would be 100 to 400 megawatts, 
400 to 700 megawatts, and 700 to 1100 megawatts, respectively.
    (c) Units that do not produce electrical or thermal output are 
exempted from the requirements of this paragraph, (c). The owner or 
operator shall identify, for each affected unit or common stack (except 
for peaking units and units using the low mass emissions (LME) excepted 
methodology under Sec. 75.19), the ``normal'' load level or levels 
(low, mid or high), based on the operating history of the unit(s). To 
identify the normal load level(s), the owner or operator shall, at a 
minimum, determine the relative number of operating hours at each of the 
three load levels, low, mid and high over the past four representative 
operating quarters. The owner or operator shall determine, to the 
nearest 0.1 percent, the percentage of the time that each load level 
(low, mid, high) has been used during that time period. A summary of the 
data used for this determination and the calculated results shall be 
kept on-site in a format suitable for inspection. For new units or 
newly-affected units, the data analysis in this paragraph may be based 
on fewer than four quarters of data if fewer than four representative 
quarters of historical load data are available. Or, if no historical 
load data are available, the owner or operator may designate the normal 
load based on the expected or projected manner of operating the unit. 
However, in either case, once four quarters of representative data 
become available, the historical load analysis shall be repeated.
    (d) Determination of normal load (or operating level)
    (1) Based on the analysis of the historical load data described in 
paragraph (c) of this section, the owner or operator shall, for units 
that produce electrical or thermal output, designate the most frequently 
used load level as the normal load level for the unit (or combination of 
units, for common stacks). The owner or operator may also designate the 
second most frequently used load level as an additional normal load 
level for the unit or stack. For peaking units and LME units, normal 
load designations are unnecessary; the entire operating load range shall 
be considered normal. If the manner of operation of the unit changes 
significantly, such that the designated normal load(s) or the two most 
frequently used load levels change, the owner or operator shall repeat 
the historical load analysis and shall redesignate the normal load(s) 
and the two most frequently used load levels, as appropriate. A minimum 
of two representative quarters of historical load data are required to 
document that a change in the manner of unit operation has occurred. 
Update the electronic monitoring plan whenever the normal load level(s) 
and the two most frequently-used load levels are redesignated.
    (2) For units that do not produce electrical or thermal output, the 
normal operating level(s) shall be determined using sound engineering 
judgment, based on knowledge of the unit and operating experience with 
the industrial process.
    (e) The owner or operator shall report the upper and lower 
boundaries of the range of operation for each unit (or combination of 
units, for common stacks), in units of megawatts or thousands of lb/hr 
or mmBtu/hr of steam production or ft/sec (as applicable), in the 
electronic monitoring plan required under Sec. 75.53. Except for 
peaking units and LME units, the owner or operator shall indicate, in 
the electronic monitoring plan, the load level (or levels) designated as 
normal under this section and shall also indicate the two most 
frequently used load levels.

          6.5.2.2 Multi-Load (or Multi-Level) Flow RATA Results

    For each multi-load (or multi-level) flow RATA, calculate the flow 
monitor relative accuracy at each operating level. If a flow monitor 
relative accuracy test is failed or aborted due to a problem with the 
monitor on any level of a 2-level (or 3-level) relative accuracy test 
audit, the RATA must be repeated at that load (or operating) level. 
However, the entire 2-level (or 3-level) relative accuracy test audit 
does not have to be repeated unless the flow monitor polynomial 
coefficients or K-factor(s) are changed, in which case a 3-level RATA is 
required (or, a 2-level RATA, for units demonstrated to operate at only 
two levels, under section 6.5.2(e) of this appendix).

                            6.5.3 [Reserved]

                           6.5.4 Calculations

    Using the data from the relative accuracy test audits, calculate 
relative accuracy and bias in accordance with the procedures and 
equations specified in section 7 of this appendix.

[[Page 379]]

               6.5.5 Reference Method Measurement Location

    Select a location for reference method measurements that is (1) 
accessible; (2) in the same proximity as the monitor or monitoring 
system location; and (3) meets the requirements of Performance 
Specification 2 in appendix B of part 60 of this chapter for 
SO2 and NOX continuous emission monitoring 
systems, Performance Specification 3 in appendix B of part 60 of this 
chapter for CO2 or O2 monitors, or method 1 (or 
1A) in appendix A of part 60 of this chapter for volumetric flow, except 
as otherwise indicated in this section or as approved by the 
Administrator.

             6.5.6 Reference Method Traverse Point Selection

    Select traverse points that ensure acquisition of representative 
samples of pollutant and diluent concentrations, moisture content, 
temperature, and flue gas flow rate over the flue cross section. To 
achieve this, the reference method traverse points shall meet the 
requirements of section 8.1.3 of Performance Specification 2 (``PS No. 
2'') in appendix B to part 60 of this chapter (for SO2, 
NOX, and moisture monitoring system RATAs), Performance 
Specification 3 in appendix B to part 60 of this chapter (for 
O2 and CO2 monitor RATAs), Method 1 (or 1A) (for 
volumetric flow rate monitor RATAs), Method 3 (for molecular weight), 
and Method 4 (for moisture determination) in appendix A to part 60 of 
this chapter. The following alternative reference method traverse point 
locations are permitted for moisture and gas monitor RATAs:
    (a) For moisture determinations where the moisture data are used 
only to determine stack gas molecular weight, a single reference method 
point, located at least 1.0 meter from the stack wall, may be used. For 
moisture monitoring system RATAs and for gas monitor RATAs in which 
moisture data are used to correct pollutant or diluent concentrations 
from a dry basis to a wet basis (or vice-versa), single-point moisture 
sampling may only be used if the 12-point stratification test described 
in section 6.5.6.1 of this appendix is performed prior to the RATA for 
at least one pollutant or diluent gas, and if the test is passed 
according to the acceptance criteria in section 6.5.6.3(b) of this 
appendix.
    (b) For gas monitoring system RATAs, the owner or operator may use 
any of the following options:
    (1) At any location (including locations where stratification is 
expected), use a minimum of six traverse points along a diameter, in the 
direction of any expected stratification. The points shall be located in 
accordance with Method 1 in appendix A to part 60 of this chapter.
    (2) At locations where section 8.1.3 of PS No. 2 allows the use of a 
short reference method measurement line (with three points located at 
0.4, 1.2, and 2.0 meters from the stack wall), the owner or operator may 
use an alternative 3-point measurement line, locating the three points 
at 4.4, 14.6, and 29.6 percent of the way across the stack, in 
accordance with Method 1 in appendix A to part 60 of this chapter.
    (3) At locations where stratification is likely to occur (e.g., 
following a wet scrubber or when dissimilar gas streams are combined), 
the short measurement line from section 8.1.3 of PS No. 2 (or the 
alternative line described in paragraph (b)(2) of this section) may be 
used in lieu of the prescribed ``long'' measurement line in section 
8.1.3 of PS No. 2, provided that the 12-point stratification test 
described in section 6.5.6.1 of this appendix is performed and passed 
one time at the location (according to the acceptance criteria of 
section 6.5.6.3(a) of this appendix) and provided that either the 12-
point stratification test or the alternative (abbreviated) 
stratification test in section 6.5.6.2 of this appendix is performed and 
passed prior to each subsequent RATA at the location (according to the 
acceptance criteria of section 6.5.6.3(a) of this appendix).
    (4) A single reference method measurement point, located no less 
than 1.0 meter from the stack wall and situated along one of the 
measurement lines used for the stratification test, may be used at any 
sampling location if the 12-point stratification test described in 
section 6.5.6.1 of this appendix is performed and passed prior to each 
RATA at the location (according to the acceptance criteria of section 
6.5.6.3(b) of this appendix).
    (5) If Method 7E is used as the reference method for the RATA of a 
NOX CEMS installed on a combustion turbine, the reference 
method measurements may be made at the sampling points specified in 
section 6.1.2 of Method 20 in appendix A to part 60 of this chapter.

                       6.5.6.1 Stratification Test

    (a) With the unit(s) operating under steady-state conditions at the 
normal load level (or normal operating level), as defined in section 
6.5.2.1 of this appendix, use a traversing gas sampling probe to measure 
the pollutant (SO2 or NOX) and diluent 
(CO2 or O2) concentrations at a minimum of twelve 
(12) points, located according to Method 1 in appendix A to part 60 of 
this chapter.
    (b) Use Methods 6C, 7E, and 3A in appendix A to part 60 of this 
chapter to make the measurements. Data from the reference method 
analyzers must be quality-assured by performing analyzer calibration 
error and system bias checks before the series of measurements and by 
conducting system bias and

[[Page 380]]

calibration drift checks after the measurements, in accordance with the 
procedures of Methods 6C, 7E, and 3A.
    (c) Measure for a minimum of 2 minutes at each traverse point. To 
the extent practicable, complete the traverse within a 2-hour period.
    (d) If the load has remained constant ([3.0 percent) during the 
traverse and if the reference method analyzers have passed all of the 
required quality assurance checks, proceed with the data analysis.
    (e) Calculate the average NOX, SO2, and 
CO2 (or O2) concentrations at each of the 
individual traverse points. Then, calculate the arithmetic average 
NOX, SO2, and CO2 (or O2) 
concentrations for all traverse points.

          6.5.6.2 Alternative (Abbreviated) Stratification Test

    (a) With the unit(s) operating under steady-state conditions at 
normal load level (or normal operating level), as defined in section 
6.5.2.1 of this appendix, use a traversing gas sampling probe to measure 
the pollutant (SO2 or NOX) and diluent 
(CO2 or O2) concentrations at three points. The 
points shall be located according to the specifications for the long 
measurement line in section 8.1.3 of PS No. 2 (i.e., locate the points 
16.7 percent, 50.0 percent, and 83.3 percent of the way across the 
stack). Alternatively, the concentration measurements may be made at six 
traverse points along a diameter. The six points shall be located in 
accordance with Method 1 in appendix A to part 60 of this chapter.
    (b) Use Methods 6C, 7E, and 3A in appendix A to part 60 of this 
chapter to make the measurements. Data from the reference method 
analyzers must be quality-assured by performing analyzer calibration 
error and system bias checks before the series of measurements and by 
conducting system bias and calibration drift checks after the 
measurements, in accordance with the procedures of Methods 6C, 7E, and 
3A.
    (c) Measure for a minimum of 2 minutes at each traverse point. To 
the extent practicable, complete the traverse within a 1-hour period.
    (d) If the load has remained constant ([3.0 percent) during the 
traverse and if the reference method analyzers have passed all of the 
required quality assurance checks, proceed with the data analysis.
    (e) Calculate the average NOX, SO2, and 
CO2 (or O2) concentrations at each of the 
individual traverse points. Then, calculate the arithmetic average 
NOX, SO2, and CO2 (or O2) 
concentrations for all traverse points.

       6.5.6.3 Stratification Test Results and Acceptance Criteria

    (a) For each pollutant or diluent gas, the short reference method 
measurement line described in section 8.1.3 of PS No. 2 may be used in 
lieu of the long measurement line prescribed in section 8.1.3 of PS No. 
2 if the results of a stratification test, conducted in accordance with 
section 6.5.6.1 or 6.5.6.2 of this appendix (as appropriate; see section 
6.5.6(b)(3) of this appendix), show that the concentration at each 
individual traverse point differs by no more than [10.0 percent from the 
arithmetic average concentration for all traverse points. The results 
are also acceptable if the concentration at each individual traverse 
point differs by no more than [5ppm or [0.5 percent CO2 (or 
O2) from the arithmetic average concentration for all 
traverse points.
    (b) For each pollutant or diluent gas, a single reference method 
measurement point, located at least 1.0 meter from the stack wall and 
situated along one of the measurement lines used for the stratification 
test, may be used for that pollutant or diluent gas if the results of a 
stratification test, conducted in accordance with section 6.5.6.1 of 
this appendix, show that the concentration at each individual traverse 
point differs by no more than [5.0 percent from the arithmetic average 
concentration for all traverse points. The results are also acceptable 
if the concentration at each individual traverse point differs by no 
more than [3 ppm or [0.3 percent CO2 (or O2) from 
the arithmetic average concentration for all traverse points.
    (c) The owner or operator shall keep the results of all 
stratification tests on-site, in a format suitable for inspection, as 
part of the supplementary RATA records required under Sec. 75.59(a)(7).

                         6.5.7 Sampling Strategy

    (a) Conduct the reference method tests allowed in section 6.5.10 of 
this appendix so they will yield results representative of the pollutant 
concentration, emission rate, moisture, temperature, and flue gas flow 
rate from the unit and can be correlated with the pollutant 
concentration monitor, CO2 or O2 monitor, flow 
monitor, and SO2 or NOX CEMS measurements. The 
minimum acceptable time for a gas monitoring system RATA run or for a 
moisture monitoring system RATA run is 21 minutes. For each run of a gas 
monitoring system RATA, all necessary pollutant concentration 
measurements, diluent concentration measurements, and moisture 
measurements (if applicable) must, to the extent practicable, be made 
within a 60-minute period. For NOX-diluent monitoring system 
RATAs, the pollutant and diluent concentration measurements must be made 
simultaneously. For flow monitor RATAs, the minimum time per run shall 
be 5 minutes. Flow rate reference method measurements allowed in section 
6.5.10 of this appendix may be made either sequentially from port-to-
port or simultaneously at

[[Page 381]]

two or more sample ports. The velocity measurement probe may be moved 
from traverse point to traverse point either manually or automatically. 
If, during a flow RATA, significant pulsations in the reference method 
readings are observed, be sure to allow enough measurement time at each 
traverse point to obtain an accurate average reading when a manual 
readout method is used (e.g., a ``sight-weighted'' average from a 
manometer). Also, allow sufficient measurement time to ensure that 
stable temperature readings are obtained at each traverse point, 
particularly at the first measurement point at each sample port, when a 
probe is moved sequentially from port-to-port. A minimum of one set of 
auxiliary measurements for stack gas molecular weight determination 
(i.e., diluent gas data and moisture data) is required for every clock 
hour of a flow RATA or for every three test runs (whichever is less 
restrictive). Alternatively, moisture measurements for molecular weight 
determination may be performed before and after a series of flow RATA 
runs at a particular load level (low, mid, or high), provided that the 
time interval between the two moisture measurements does not exceed 
three hours. If this option is selected, the results of the two moisture 
determinations shall be averaged arithmetically and applied to all RATA 
runs in the series. Successive flow RATA runs may be performed without 
waiting in between runs. If an O2 diluent monitor is used as 
a CO2 continuous emission monitoring system, perform a 
CO2 system RATA (i.e., measure CO2, rather than 
O2, with the applicable reference method allowed in section 
6.5.10 of this appendix). For moisture monitoring systems, an 
appropriate coefficient, ``K'' factor or other suitable mathematical 
algorithm may be developed prior to the RATA, to adjust the monitoring 
system readings with respect to the applicable reference method allowed 
in section 6.5.10 of this appendix. If such a coefficient, K-factor or 
algorithm is developed, it shall be applied to the CEMS readings during 
the RATA and (if the RATA is passed), to the subsequent CEMS data, by 
means of the automated data acquisition and handling system. The owner 
or operator shall keep records of the current coefficient, K factor or 
algorithm, as specified in Sec. 75.59(a)(5)(vii). Whenever the 
coefficient, K factor or algorithm is changed, a RATA of the moisture 
monitoring system is required.
    (b) To properly correlate individual SO2 or 
NOX CEMS data (in lb/mmBtu) and volumetric flow rate data 
with the applicable reference method data, annotate the beginning and 
end of each reference method test run (including the exact time of day) 
on the individual chart recorder(s) or other permanent recording 
device(s).

6.5.8 Correlation of Reference Method and Continuous Emission Monitoring 
                                 System

    Confirm that the monitor or monitoring system and reference method 
test results are on consistent moisture, pressure, temperature, and 
diluent concentration basis (e.g., since the flow monitor measures flow 
rate on a wet basis, method 2 test results must also be on a wet basis). 
Compare flow-monitor and reference method results on a scfh basis. Also, 
consider the response times of the pollutant concentration monitor, the 
continuous emission monitoring system, and the flow monitoring system to 
ensure comparison of simultaneous measurements.
    For each relative accuracy test audit run, compare the measurements 
obtained from the monitor or continuous emission monitoring system (in 
ppm, percent CO2, lb/mmBtu, or other units) against the 
corresponding reference method values. Tabulate the paired data in a 
table such as the one shown in Figure 2.

                 6.5.9 Number of Reference Method Tests

    Perform a minimum of nine sets of paired monitor (or monitoring 
system) and reference method test data for every required (i.e., 
certification, recertification, diagnostic, semiannual, or annual) 
relative accuracy test audit. For 2-level and 3-level relative accuracy 
test audits of flow monitors, perform a minimum of nine sets at each of 
the operating levels.

    Note: The tester may choose to perform more than nine sets of 
reference method tests. If this option is chosen, the tester may reject 
a maximum of three sets of the test results, as long as the total number 
of test results used to determine the relative accuracy or bias is 
greater than or equal to nine. Report all data, including the rejected 
CEMS data and corresponding reference method test results.

                        6.5.10 Reference Methods

    The following methods are from appendix A to part 60 of this 
chapter, and are the reference methods for performing relative accuracy 
test audits under this part: Method 1 or 1A in appendix A-1 to part 60 
of this chapter for siting; Method 2 in appendix A-1 to part 60 of this 
chapter or its allowable alternatives in appendices A-1 and A-2 to part 
60 of this chapter (except for Methods 2B and 2E in appendix A-1 to part 
60 of this chapter) for stack gas velocity and volumetric flow rate; 
Methods 3, 3A or 3B in appendix A-2 to part 60 of this chapter for 
O2 and CO2; Method 4 in appendix A-3 to part 60 of 
this chapter for moisture; Methods 6, 6A or 6C in appendix A-4 to part 
60 of this chapter for SO2; and Methods 7, 7A, 7C, 7D or 7E 
in appendix A-4 to part 60 of this chapter for NOX, excluding 
the exceptions to Method 7E identified in

[[Page 382]]

Sec. 75.22(a)(5). When using Method 7E for measuring NOX 
concentration, total NOX, including both NO and 
NO2, must be measured. When using EPA Protocol gas with 
Methods 3A, 6C, and 7E, the gas must be from an EPA Protocol gas 
production site that is participating in the EPA Protocol Gas 
Verification Program, pursuant to Sec. 75.21(g)(6). An EPA Protocol gas 
cylinder certified by or ordered from a non-participating production 
site no later than May 27, 2011 may be used for the purposes of this 
part until the earlier of the cylinder's expiration date or the date on 
which the cylinder gas pressure reaches 150 psig; however, in no case 
shall the cylinder be recertified by a non-participating EPA Protocol 
gas production site to extend its useful life and be used by a source 
subject to this part. In the event that an EPA Protocol gas production 
site is removed from the list of PGVP participants on the same date as 
or after the date on which a particular cylinder is certified or 
ordered, that gas cylinder may continue to be used for the purposes of 
this part until the earlier of the cylinder's expiration date or the 
date on which the cylinder gas pressure reaches 150 psig; however, in no 
case shall the cylinder be recertified by a non-participating EPA 
Protocol gas production site to extend its useful life and be used by a 
source subject to this part.

                             7. Calculations

                           7.1 Linearity Check

    Analyze the linearity data for pollutant concentration and 
CO2 or O2 monitors as follows. Calculate the 
percentage error in linearity based upon the reference value at the low-
level, mid-level, and high-level concentrations specified in section 6.2 
of this appendix. Perform this calculation once during the certification 
test. Use the following equation to calculate the error in linearity for 
each reference value.
[GRAPHIC] [TIFF OMITTED] TC01SE92.114

(Eq. A-4)
where,

LE = Percentage Linearity error, based upon the reference value.
R = Reference value of Low-, mid-, or high-level calibration gas 
          introduced into the monitoring system.
A = Average of the monitoring system responses.

                          7.2 Calibration Error

           7.2.1 Pollutant Concentration and Diluent Monitors

    For each reference value, calculate the percentage calibration error 
based upon instrument span for daily calibration error tests using the 
following equation:
[GRAPHIC] [TIFF OMITTED] TC01SE92.115

(Eq. A-5)
where,

CE = Calibration error as a percentage of the span of the instrument.
R = Reference value of zero or upscale (high-level or mid-level, as 
          applicable) calibration gas introduced into the monitoring 
          system.
A = Actual monitoring system response to the calibration gas.
S = Span of the instrument, as specified in section 2 of this appendix.

                  7.2.2 Flow Monitor Calibration Error

    For each reference value, calculate the percentage calibration error 
based upon span using the following equation:
[GRAPHIC] [TIFF OMITTED] TR17MY95.007

where:

CE = Calibration error as a percentage of span.
R = Low or high level reference value specified in section 2.2.2.1 of 
          this appendix.
A = Actual flow monitor response to the reference value.
S = Flow monitor calibration span value as determined under section 
          2.1.4.2 of this appendix.

 7.3 Relative Accuracy for SO2 and CO2 Emissions 
     Concentration Monitors, O2 Monitors, NOX 
           Concentration Monitoring Systems, and Flow Monitors

    Analyze the relative accuracy test audit data from the reference 
method tests for SO2 and CO2 emissions 
concentration monitors, CO2 or O2 monitors used 
for heat input rate determination, NOX concentration 
monitoring systems used to determine NOX mass emissions under 
subpart H of this part, and

[[Page 383]]

flow monitors using the following procedures. Summarize the results on a 
data sheet. An example is shown in Figure 2. Calculate the mean of the 
monitor or monitoring system measurement values. Calculate the mean of 
the reference method values. Using data from the automated data 
acquisition and handling system, calculate the arithmetic differences 
between the reference method and monitor measurement data sets. Then 
calculate the arithmetic mean of the difference, the standard deviation, 
the confidence coefficient, and the monitor or monitoring system 
relative accuracy using the following procedures and equations.

                          7.3.1 Arithmetic Mean

    Calculate the arithmetic mean of the differences of a data set as 
follows:
[GRAPHIC] [TIFF OMITTED] TR28MR11.000

                        7.3.2 Standard Deviation

    Calculate the standard deviation, Sd, of a data set as 
follows:
[GRAPHIC] [TIFF OMITTED] TC01SE92.117

(Eq. A-8)

                      7.3.3 Confidence Coefficient

    Calculate the confidence coefficient (one-tailed), cc, of a data set 
as follows.
[GRAPHIC] [TIFF OMITTED] TC01SE92.118

(eq. A-9)

where,

t0.025 = t value (see table 7-1).

                           Table 7-1--t-Values
------------------------------------------------------------------------
                n-1                   t0.025  n-1  t0.025   n-1   t0.025
------------------------------------------------------------------------
1..................................   12.706   12   2.179     23   2.069
2..................................    4.303   13   2.160     24   2.064
3..................................    3.182   14   2.145     25   2.060
4..................................    2.776   15   2.131     26   2.056
5..................................    2.571   16   2.120     27   2.052
6..................................    2.447   17   2.110     28   2.048
7..................................    2.365   18   2.101     29   2.045
8..................................    2.306   19   2.093     30   2.042
9..................................    2.262   20   2.086     40   2.021
10.................................    2.228   21   2.080     60   2.000
11.................................    2.201   22   2.074  X-diluent Continuous Emission 
                           Monitoring Systems

    Analyze the relative accuracy test audit data from the reference 
method tests for NOX-diluent continuous emissions monitoring 
system as follows.

                         7.4.1 Data Preparation

    If CNOx, the NOX concentration, is in ppm, 
multiply it by 1.194 x 10-7 (lb/dscf)/ppm to convert it to 
units of lb/dscf. If CNOx is in mg/dscm, multiply it by 6.24 
x 10-8 (lb/dscf)/(mg/dscm) to convert it to lb/dscf. Then, 
use the diluent (O2 or CO2) reference method 
results for the run and the appropriate F or Fc factor from 
table 1 in appendix F of this part to convert CNOx from lb/
dscf to lb/mmBtu units. Use the equations and procedure in section 3 of 
appendix F to this part, as appropriate.

                   7.4.2 NOX Emission Rate

    For each test run in a data set, calculate the average 
NOX emission rate (in lb/mmBtu), by means of the data 
acquisition and handling system, during the time period of the test run. 
Tabulate the results as shown in example Figure 4.

                         7.4.3 Relative Accuracy

    Use the equations and procedures in section 7.3 above to calculate 
the relative accuracy for the NOX continuous emission 
monitoring system. In using equation A-7, ``d'' is, for each run, the 
difference between the NOX emission rate values (in lb/mmBtu) 
obtained from the reference method data and the NOX 
continuous emission monitoring system.

    7.5 Relative Accuracy for Combined SO2/Flow [Reserved]

                   7.6 Bias Test and Adjustment Factor

    Test the following relative accuracy test audit data sets for bias: 
SO2 pollutant concentration monitors; flow monitors; 
NOX concentration monitoring systems used to determine 
NOX mass emissions, as defined in 75.71(a)(2); and 
NOX-diluent CEMS using the procedures outlined in sections 
7.6.1 through 7.6.5 of this appendix. For multiple-load flow RATAs, 
perform a bias test at each load level designated as normal under 
section 6.5.2.1 of this appendix.

                          7.6.1 Arithmetic Mean

    Calculate the arithmetic mean of the differences of the data set 
using Equation A-7 of this appendix. To calculate bias for an 
SO2 or NOX pollutant concentration monitor, 
``di'' is, for each paired data point, the difference between 
the SO2 or NOX concentration value (in ppm) 
obtained from the reference method and the monitor. To calculate bias 
for a flow monitor, ``di'' is, for each paired data point, 
the difference between the flow rate values (in scfh) obtained from the 
reference method and the monitor. To calculate bias for a 
NOX-diluent continuous emission monitoring system, 
``di'' is, for each paired data point, the difference between 
the NOX emission rate values (in lb/mmBtu) obtained from the 
reference method and the monitoring system.

                        7.6.2 Standard Deviation

    Calculate the standard deviation, Sd, of the data set 
using equation A-8.

                      7.6.3 Confidence Coefficient

    Calculate the confidence coefficient, cc, of the data set using 
equation A-9.

                             7.6.4 Bias Test

    If, for the relative accuracy test audit data set being tested, the 
mean difference, d, is less than or equal to the absolute value of the 
confidence coefficient, [verbar] cc [verbar], the monitor or monitoring 
system has passed the bias test. If the mean difference, d, is greater 
than the absolute value of the confidence coefficient, [radic] cc 
[radic], the monitor or monitoring system has failed to meet the bias 
test requirement.

                          7.6.5 Bias Adjustment

    (a) If the monitor or monitoring system fails to meet the bias test 
requirement, adjust the value obtained from the monitor using the 
following equation:
[GRAPHIC] [TIFF OMITTED] TR26MY99.005

Where:

CEMi\Monitor\ = Data (measurement) provided by the monitor at 
          time i.

[[Page 385]]

CEMi\Adjusted\ = Data value, adjusted for bias, at time i.
BAF = Bias adjustment factor, defined by:
[GRAPHIC] [TIFF OMITTED] TR26MY99.006

Where:

BAF = Bias adjustment factor, calculated to the nearest thousandth.
d= Arithmetic mean of the difference obtained during the failed bias 
          test using Equation A-7.
CEMavg = Mean of the data values provided by the monitor 
          during the failed bias test.

    (b) For single-load RATAs of SO2 pollutant concentration 
monitors, NOX concentration monitoring systems, and 
NOX-diluent monitoring systems, and for the single-load flow 
RATAs required or allowed under section 6.5.2 of this appendix and 
sections 2.3.1.3(b) and 2.3.1.3(c) of appendix B to this part, the 
appropriate BAF is determined directly from the RATA results at normal 
load, using Equation A-12. Notwithstanding, when a NOX 
concentration CEMS or an SO2 CEMS or a NOX-diluent 
CEMS installed on a low-emitting affected unit (i.e., average 
SO2 or NOX concentration during the RATA <=250 ppm 
or average NOX emission rate <=0.200 lb/mmBtu) meets the 
normal 10.0 percent relative accuracy specification (as calculated using 
Equation A-10) or the alternate relative accuracy specification in 
section 3.3 of this appendix for low-emitters, but fails the bias test, 
the BAF may either be determined using Equation A-12, or a default BAF 
of 1.111 may be used.
    (c) For 2-load or 3-load flow RATAs, when only one load level (low, 
mid or high) has been designated as normal under section 6.5.2.1 of this 
appendix and the bias test is passed at the normal load level, apply a 
BAF of 1.000 to the subsequent flow rate data. If the bias test is 
failed at the normal load level, use Equation A-12 to calculate the 
normal load BAF and then perform an additional bias test at the second 
most frequently-used load level, as determined under section 6.5.2.1 of 
this appendix. If the bias test is passed at this second load level, 
apply the normal load BAF to the subsequent flow rate data. If the bias 
test is failed at this second load level, use Equation A-12 to calculate 
the BAF at the second load level and apply the higher of the two BAFs 
(either from the normal load level or from the second load level) to the 
subsequent flow rate data.
    (d) For 2-load or 3-load flow RATAs, when two load levels have been 
designated as normal under section 6.5.2.1 of this appendix and the bias 
test is passed at both normal load levels, apply a BAF of 1.000 to the 
subsequent flow rate data. If the bias test is failed at one of the 
normal load levels but not at the other, use Equation A-12 to calculate 
the BAF for the normal load level at which the bias test was failed and 
apply that BAF to the subsequent flow rate data. If the bias test is 
failed at both designated normal load levels, use Equation A-12 to 
calculate the BAF at each normal load level and apply the higher of the 
two BAFs to the subsequent flow rate data.
    (e) Each time a RATA is passed and the appropriate bias adjustment 
factor has been determined, apply the BAF prospectively to all 
monitoring system data, beginning with the first clock hour following 
the hour in which the RATA was completed. For a 2-load flow RATA, the 
``hour in which the RATA was completed'' refers to the hour in which the 
testing at both loads was completed; for a 3-load RATA, it refers to the 
hour in which the testing at all three loads was completed.
    (f) Use the bias-adjusted values in computing substitution values in 
the missing data procedure, as specified in subpart D of this part, and 
in reporting the concentration of SO2, the flow rate, the 
average NOX emission rate, the unit heat input, and the 
calculated mass emissions of SO2 and CO2 during 
the quarter and calendar year, as specified in subpart G of this part. 
In addition, when using a NOX concentration monitoring system 
and a flow monitor to calculate NOX mass emissions under 
subpart H of this part, use bias-adjusted values for NOX 
concentration and flow rate in the mass emission calculations and use 
bias-adjusted NOX concentrations to compute the appropriate 
substitution values for NOX concentration in the missing data 
routines under subpart D of this part.
    (g) For units that do not produce electrical or thermal output, the 
provisions of paragraphs (a) through (f) of this section apply, except 
that the terms, ``single-load'', ``2-load'', ``3-load'', and ``load 
level'' shall be replaced, respectively, with the terms, ``single-
level'', ``2-level'', ``3-level'', and ``operating level''.

           7.7 Reference Flow-to-Load Ratio or Gross Heat Rate

    (a) Except as provided in section 7.8 of this appendix, the owner or 
operator shall determine Rref, the reference value of the 
ratio of flow rate to unit load, each time that a passing flow RATA is 
performed at a load level designated as normal in section 6.5.2.1 of 
this appendix. The owner or operator shall report the current value of 
Rref in the electronic quarterly report required under Sec. 
75.64 and shall also report the completion date of the associated RATA. 
If two load levels have been designated as normal under section 6.5.2.1 
of this appendix, the owner or operator shall determine a separate 
Rref value for each

[[Page 386]]

of the normal load levels. The reference flow-to-load ratio shall be 
calculated as follows:
[GRAPHIC] [TIFF OMITTED] TR26MY99.007

Where:

Rref = Reference value of the flow-to-load ratio, from the 
          most recent normal-load flow RATA, scfh/megawatts, scfh/1000 
          lb/hr of steam, or scfh/(mmBtu/hr of steam output).
Qref = Average stack gas volumetric flow rate measured by the 
          reference method during the normal-load RATA, scfh.
Lavg = Average unit load during the normal-load flow RATA, 
          megawatts, 1000 lb/hr of steam, or mmBtu/hr of thermal output.

    (b) In Equation A-13, for a common stack, determine Lavg 
by summing, for each RATA run, the operating loads of all units 
discharging through the common stack, and then taking the arithmetic 
average of the summed loads. For a unit that discharges its emissions 
through multiple stacks, either determine a single value of 
Qref for the unit or a separate value of Qref for 
each stack. In the former case, calculate Qref by summing, 
for each RATA run, the volumetric flow rates through the individual 
stacks and then taking the arithmetic average of the summed RATA run 
flow rates. In the latter case, calculate the value of Qref 
for each stack by taking the arithmetic average, for all RATA runs, of 
the flow rates through the stack. For a unit with a multiple stack 
discharge configuration consisting of a main stack and a bypass stack 
(e.g., a unit with a wet SO2 scrubber), determine 
Qref separately for each stack at the time of the normal load 
flow RATA. Round off the value of Rref to two decimal places.
    (c) In addition to determining Rref or as an alternative 
to determining Rref, a reference value of the gross heat rate 
(GHR) may be determined. In order to use this option, quality-assured 
diluent gas (CO2 or O2) must be available for each 
hour of the most recent normal-load flow RATA. The reference value of 
the GHR shall be determined as follows:
[GRAPHIC] [TIFF OMITTED] TR26MY99.008

Where:

(GHR)ref = Reference value of the gross heat rate at the time 
          of the most recent normal-load flow RATA, Btu/kwh, Btu/lb 
          steam load, or Btu heat input/mmBtu steam output.
(Heat Input)avg = Average hourly heat input during the 
          normal-load flow RATA, as determined using the applicable 
          equation in appendix F to this part, mmBtu/hr. For multiple 
          stack configurations, if the reference GHR value is determined 
          separately for each stack, use the hourly heat input measured 
          at each stack. If the reference GHR is determined at the unit 
          level, sum the hourly heat inputs measured at the individual 
          stacks.
Lavg = Average unit load during the normal-load flow RATA, 
          megawatts, 1000 lb/hr of steam, or mmBtu/hr thermal output.

    (d) In the calculation of (Heat Input)avg, use 
Qref, the average volumetric flow rate measured by the 
reference method during the RATA, and use the average diluent gas 
concentration measured during the flow RATA (i.e., the arithmetic 
average of the diluent gas concentrations for all clock hours in which a 
RATA run was performed).

                    7.8 Flow-to-Load Test Exemptions

    (a) For complex stack configuations (e.g., when the effluent from a 
unit is divided and discharges through multiple stacks in such a manner 
that the flow rate in the individual stacks cannot be correlated with 
unit load), the owner or operator may petition the Administrator under 
Sec. 75.66 for an exemption from the requirements of section 7.7 of 
this appendix and section 2.2.5 fo appendix B to this part. The petition 
must include sufficient information and data to demonstrate that a flow-
to-load or gross heat rate evaluation is infeasible for the complex 
stack configuration.
    (b) Units that do not produce electrical output (in megawatts) or 
thermal output (in klb of steam per hour) are exempted from the flow-to-
load ratio test requirements of section 7.7 of this appendix and section 
2.2.5 of appendix B to this part.

[[Page 387]]



                                                  Figure 1 to Appendix A--Linearity Error Determination
--------------------------------------------------------------------------------------------------------------------------------------------------------
                   Day                       Date and time     Reference value     Monitor value        Difference         Percent of reference value
--------------------------------------------------------------------------------------------------------------------------------------------------------
Low-level:
 
--------------------------------------------------------------------------------------------------------------------------------------------------------
 
--------------------------------------------------------------------------------------------------------------------------------------------------------
 
--------------------------------------------------------------------------------------------------------------------------------------------------------
 
--------------------------------------------------------------------------------------------------------------------------------------------------------
 
--------------------------------------------------------------------------------------------------------------------------------------------------------
 
========================================================================================================================================================
Mid-level:
 
--------------------------------------------------------------------------------------------------------------------------------------------------------
 
--------------------------------------------------------------------------------------------------------------------------------------------------------
 
--------------------------------------------------------------------------------------------------------------------------------------------------------
 
--------------------------------------------------------------------------------------------------------------------------------------------------------
 
--------------------------------------------------------------------------------------------------------------------------------------------------------
 
========================================================================================================================================================
High-level:
 
--------------------------------------------------------------------------------------------------------------------------------------------------------
 
--------------------------------------------------------------------------------------------------------------------------------------------------------
 
--------------------------------------------------------------------------------------------------------------------------------------------------------
 
--------------------------------------------------------------------------------------------------------------------------------------------------------
 
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                           .................
--------------------------------------------------------------------------------------------------------------------------------------------------------


           Figure 2 to Appendix A--Relative Accuracy Determination (Pollutant Concentration Monitors)
----------------------------------------------------------------------------------------------------------------
                                              SO2 (ppm \c\)                         CO2 (Pollutant) (ppm \c\)
         Run No.           Date and ---------------------------------  Date and --------------------------------
                             time      RM \a\     M \b\       Diff       time      RM \a\     M \b\       Diff
----------------------------------------------------------------------------------------------------------------
 1......................
----------------------------------------------------------------------------------------------------------------
 2......................
----------------------------------------------------------------------------------------------------------------
 3......................
----------------------------------------------------------------------------------------------------------------
 4......................
----------------------------------------------------------------------------------------------------------------
 5......................
----------------------------------------------------------------------------------------------------------------
 6......................
----------------------------------------------------------------------------------------------------------------
 7......................
----------------------------------------------------------------------------------------------------------------
 8......................
----------------------------------------------------------------------------------------------------------------
 9......................
----------------------------------------------------------------------------------------------------------------
10......................
----------------------------------------------------------------------------------------------------------------
11......................
----------------------------------------------------------------------------------------------------------------
12......................
----------------------------------------------------------------------------------------------------------------
 
 
[[Page 388]]

 
Arithmetic Mean Difference (Eq. A-7). Confidence Coefficient (Eq. A-
                  9). Relative Accuracy (Eq. A-10).
----------------------------------------------------------------------------------------------------------------
\a\ RM means ``reference method data.''
\b\ M means ``monitor data.''
\c\ Make sure the RM and M data are on a consistent basis, either wet or dry.


                                         Figure 3 to Appendix A--Relative Accuracy Determination (Flow Monitors)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                       Flow rate (Low) (scf/hr)*            Flow rate (Normal) (scf/             Flow rate (High) (scf/
                                                Date  ---------------------------   Date              hr)*              Date              hr)*
                   Run No.                      and                                 and   ---------------------------   and   --------------------------
                                                time      RM       M       Diff     time      RM       M       Diff     time      RM       M       Diff
--------------------------------------------------------------------------------------------------------------------------------------------------------
 1..........................................
--------------------------------------------------------------------------------------------------------------------------------------------------------
 2..........................................
--------------------------------------------------------------------------------------------------------------------------------------------------------
 3..........................................
--------------------------------------------------------------------------------------------------------------------------------------------------------
 4..........................................
--------------------------------------------------------------------------------------------------------------------------------------------------------
 5..........................................
--------------------------------------------------------------------------------------------------------------------------------------------------------
 6..........................................
--------------------------------------------------------------------------------------------------------------------------------------------------------
 7..........................................
--------------------------------------------------------------------------------------------------------------------------------------------------------
 8..........................................
--------------------------------------------------------------------------------------------------------------------------------------------------------
 9..........................................
--------------------------------------------------------------------------------------------------------------------------------------------------------
10..........................................
--------------------------------------------------------------------------------------------------------------------------------------------------------
11..........................................
--------------------------------------------------------------------------------------------------------------------------------------------------------
12..........................................
--------------------------------------------------------------------------------------------------------------------------------------------------------
 
     Arithmetic Mean Difference (Eq. A-7). Confidence Coefficient (Eq. A-9). Relative
                                   Accuracy (Eq. A-10).
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Make sure the RM and M data are on a consistent basis, either wet or dry.


              Figure 4 to Appendix A--Relative Accuracy Determination (NOX/Diluent Combined System)
----------------------------------------------------------------------------------------------------------------
                                       Reference method data                   NOX system (lb/mmBtu)
     Run No.       Date and time -------------------------------------------------------------------------------
                                    NOX( ) \a\        O2/CO2%           RM               M          Difference
----------------------------------------------------------------------------------------------------------------
 1..............
----------------------------------------------------------------------------------------------------------------
 2..............
----------------------------------------------------------------------------------------------------------------
 3..............
----------------------------------------------------------------------------------------------------------------
 4..............
----------------------------------------------------------------------------------------------------------------
 5..............
----------------------------------------------------------------------------------------------------------------
 6..............
----------------------------------------------------------------------------------------------------------------
 7..............
----------------------------------------------------------------------------------------------------------------
 8..............
----------------------------------------------------------------------------------------------------------------
 9..............
----------------------------------------------------------------------------------------------------------------
 10.............
----------------------------------------------------------------------------------------------------------------

[[Page 389]]

 
 11.............
----------------------------------------------------------------------------------------------------------------
 12.............
----------------------------------------------------------------------------------------------------------------
  Arithmetic Mean Difference (Eq. A-7). Confidence Coefficient
            (Eq. A-9). Relative Accuracy (Eq. A-10).
----------------------------------------------------------------------------------------------------------------
\a\ Specify units: ppm, lb/dscf, mg/dscm.

                          Figure 5--Cycle Time

Date of test____________________________________________________________
Component/system ID:___________________________________________
Analyzer type___________________________________________________________
Serial Number___________________________________________________________
High level gas concentration: ------ ppm/% (circle one)
Zero level gas concentration: ------ ppm/% (circle one)
Analyzer span setting: ------ ppm/% (circle one)
Upscale:
    Stable starting monitor value: ------ ppm/% (circle one)
    Stable ending monitor reading: ------ ppm/% (circle one)
    Elapsed time: ------ seconds
Downscale:
    Stable starting monitor value: ------ ppm/% (circle one)
    Stable ending monitor value: ------ ppm/% (circle one)
    Elapsed time: ------ seconds
Component cycle time= ------ seconds
System cycle time= ------ seconds
[GRAPHIC] [TIFF OMITTED] TR24JA08.000


[[Page 390]]


[GRAPHIC] [TIFF OMITTED] TR24JA08.001

    A. To determine the upscale cycle time (Figure 6a), measure the flue 
gas emissions until the response stabilizes. Record the stabilized value 
(see section 6.4 of this appendix for the stability criteria).
    B. Inject a high-level calibration gas into the port leading to the 
calibration cell or thimble (Point B). Allow the analyzer to stabilize. 
Record the stabilized value.
    C. Determine the step change. The step change is equal to the 
difference between the final stable calibration gas value (Point D) and 
the stabilized stack emissions value (Point A).
    D. Take 95% of the step change value and add the result to the 
stabilized stack emissions value (Point A). Determine the time at which 
95% of the step change occurred (Point C).
    E. Calculate the upscale cycle time by subtracting the time at which 
the calibration gas was injected (Point B) from the time at which 95% of 
the step change occurred (Point C). In this example, upscale cycle time 
= (11-5) = 6 minutes.
    F. To determine the downscale cycle time (Figure 6b) repeat the 
procedures above, except that a zero gas is injected when the flue gas 
emissions have stabilized, and 95% of the step change in concentration 
is subtracted from the stabilized stack emissions value.
    G. Compare the upscale and downscale cycle time values. The longer 
of these two times is the cycle time for the analyzer.

    Editorial Note: For Federal Register citations affecting part 75, 
Appendix A, see the List of CFR Sections Affected, which appears in the 
Finding Aids section of the printed volume and at www.fdsys.gov.



   Sec. Appendix B to Part 75--Quality Assurance and Quality Control 
                               Procedures

              1. Quality Assurance/Quality Control Program

    Develop and implement a quality assurance/quality control (QA/QC) 
program for the continuous emission monitoring systems, excepted 
monitoring systems approved under appendix D or E to this part, and 
alternative monitoring systems under subpart E of this part, and their 
components. At a minimum, include in each QA/QC program a written plan 
that describes in detail (or that refers to separate documents 
containing) complete, step-by-step procedures and operations for each of 
the following activities. Upon request from regulatory authorities, the 
source shall make all procedures, maintenance records, and ancillary 
supporting documentation from the manufacturer (e.g., software 
coefficients and troubleshooting diagrams) available for review during 
an audit. Electronic storage of the information in the QA/QC plan is 
permissible, provided that the information can be made available in 
hardcopy upon request during an audit.

[[Page 391]]

               1.1 Requirements for All Monitoring Systems

                      1.1.1 Preventive Maintenance

    Keep a written record of procedures needed to maintain the 
monitoring system in proper operating condition and a schedule for those 
procedures. This shall, at a minimum, include procedures specified by 
the manufacturers of the equipment and, if applicable, additional or 
alternate procedures developed for the equipment.

                    1.1.2 Recordkeeping and Reporting

    Keep a written record describing procedures that will be used to 
implement the recordkeeping and reporting requirements in subparts E, F, 
and G and appendices D and E to this part, as applicable.

                        1.1.3 Maintenance Records

    Keep a record of all testing, maintenance, or repair activities 
performed on any monitoring system or component in a location and format 
suitable for inspection. A maintenance log may be used for this purpose. 
The following records should be maintained: date, time, and description 
of any testing, adjustment, repair, replacement, or preventive 
maintenance action performed on any monitoring system and records of any 
corrective actions associated with a monitor's outage period. 
Additionally, any adjustment that recharacterizes a system's ability to 
record and report emissions data must be recorded (e.g., changing of 
flow monitor or moisture monitoring system polynomial coefficients, K 
factors or mathematical algorithms, changing of temperature and pressure 
coefficients and dilution ratio settings), and a written explanation of 
the procedures used to make the adjustment(s) shall be kept.
    1.1.4 The provisions in section 6.1.2 of appendix A to this part 
shall apply to the annual RATAs described in Sec. 75.74(c)(2)(ii) and 
to the semiannual and annual RATAs described in section 2.3 of this 
appendix.

  1.2 Specific Requirements for Continuous Emissions Monitoring Systems

       1.2.1 Calibration Error Test and Linearity Check Procedures

    Keep a written record of the procedures used for daily calibration 
error tests and linearity checks (e.g., how gases are to be injected, 
adjustments of flow rates and pressure, introduction of reference 
values, length of time for injection of calibration gases, steps for 
obtaining calibration error or error in linearity, determination of 
interferences, and when calibration adjustments should be made). 
Identify any calibration error test and linearity check procedures 
specific to the continuous emission monitoring system that vary from the 
procedures in appendix A to this part.

               1.2.2 Calibration and Linearity Adjustments

    Explain how each component of the continuous emission monitoring 
system will be adjusted to provide correct responses to calibration 
gases, reference values, and/or indications of interference both 
initially and after repairs or corrective action. Identify equations, 
conversion factors and other factors affecting calibration of each 
continuous emission monitoring system.

              1.2.3 Relative Accuracy Test Audit Procedures

    Keep a written record of procedures and details peculiar to the 
installed continuous emission monitoring systems that are to be used for 
relative accuracy test audits, such as sampling and analysis methods.

   1.2.4 Parametric Monitoring for Units With Add-on Emission Controls

    The owner or operator shall keep a written (or electronic) record 
including a list of operating parameters for the add-on SO2 
or NOX emission controls, including parameters in Sec. 
75.55(b) or Sec. 75.58(b), as applicable, and the range of each 
operating parameter that indicates the add-on emission controls are 
operating properly. The owner or operator shall keep a written (or 
electronic) record of the parametric monitoring data during each 
SO2 or NOX missing data period.

1.3 Specific Requirements for Excepted Systems Approved Under Appendices 
                                 D and E

              1.3.1 Fuel Flowmeter Accuracy Test Procedures

    Keep a written record of the specific fuel flowmeter accuracy test 
procedures. These may include: standard methods or specifications listed 
in and of appendix D to this part and incorporated by reference under 
Sec. 75.6; the procedures of sections 2.1.5.2 or 2.1.7 of appendix D to 
this part; or other methods approved by the Administrator through the 
petition process of Sec. 75.66(c).

        1.3.2 Transducer or Transmitter Accuracy Test Procedures

    Keep a written record of the procedures for testing the accuracy of 
transducers or transmitters of an orifice-, nozzle-, or venturi-type 
fuel flowmeter under section 2.1.6 of appendix D to this part. These 
procedures should include a description of equipment used, steps in 
testing, and frequency of testing.

[[Page 392]]

    1.3.3 Fuel Flowmeter, Transducer, or Transmitter Calibration and 
                           Maintenance Records

    Keep a record of adjustments, maintenance, or repairs performed on 
the fuel flowmeter monitoring system. Keep records of the data and 
results for fuel flowmeter accuracy tests and transducer accuracy tests, 
consistent with appendix D to this part.

               1.3.4 Primary Element Inspection Procedures

    Keep a written record of the standard operating procedures for 
inspection of the primary element (i.e., orifice, venturi, or nozzle) of 
an orifice-, venturi-, or nozzle-type fuel flowmeter. Examples of the 
types of information to be included are: what to examine on the primary 
element; how to identify if there is corrosion sufficient to affect the 
accuracy of the primary element; and what inspection tools (e.g., 
baroscope), if any, are used.

             1.3.5 Fuel Sampling Method and Sample Retention

    Keep a written record of the standard procedures used to perform 
fuel sampling, either by utility personnel or by fuel supply company 
personnel. These procedures should specify the portion of the ASTM 
method used, as incorporated by reference under Sec. 75.6, or other 
methods approved by the Administrator through the petition process of 
Sec. 75.66(c). These procedures should describe safeguards for ensuring 
the availability of an oil sample (e.g., procedure and location for 
splitting samples, procedure for maintaining sample splits on site, and 
procedure for transmitting samples to an analytical laboratory). These 
procedures should identify the ASTM analytical methods used to analyze 
sulfur content, gross calorific value, and density, as incorporated by 
reference under Sec. 75.6, or other methods approved by the 
Administrator through the petition process of Sec. 75.66(c).

    1.3.6 Appendix E Monitoring System Quality Assurance Information

    Identify the recommended range of quality assurance- and quality 
control-related operating parameters. Keep records of these operating 
parameters for each hour of unit operation (i.e., fuel combustion). Keep 
a written record of the procedures used to perform NOX 
emission rate testing. Keep a copy of all data and results from the 
initial and from the most recent NOX emission rate testing, 
including the values of quality assurance parameters specified in 
section 2.3 of appendix E to this part.

    1.4 Requirements for Alternative Systems Approved Under Subpart E

                   1.4.1 Daily Quality Assurance Tests

    Explain how the daily assessment procedures specific to the 
alternative monitoring system are to be performed.

             1.4.2 Daily Quality Assurance Test Adjustments

    Explain how each component of the alternative monitoring system will 
be adjusted in response to the results of the daily assessments.

              1.4.3 Relative Accuracy Test Audit Procedures

    Keep a written record of procedures and details peculiar to the 
installed alternative monitoring system that are to be used for relative 
accuracy test audits, such as sampling and analysis methods.

                         2. Frequency of Testing

    A summary chart showing each quality assurance test and the 
frequency at which each test is required is located at the end of this 
appendix in Figure 1.

                          2.1 Daily Assessments

    Perform the following daily assessments to quality-assure the hourly 
data recorded by the monitoring systems during each period of unit 
operation, or, for a bypass stack or duct, each period in which 
emissions pass through the bypass stack or duct. These requirements are 
effective as of the date when the monitor or continuous emission 
monitoring system completes certification testing.

                      2.1.1 Calibration Error Test

    Except as provided in section 2.1.1.2 of this appendix, perform the 
daily calibration error test of each gas monitoring system (including 
moisture monitoring systems consisting of wet- and dry-basis 
O2 analyzers) according to the procedures in section 6.3.1 of 
appendix A to this part, and perform the daily calibration error test of 
each flow monitoring system according to the procedure in section 6.3.2 
of appendix A to this part. When two measurement ranges (low and high) 
are required for a particular parameter, perform sufficient calibration 
error tests on each range to validate the data recorded on that range, 
according to the criteria in section 2.1.5 of this appendix.
    2.1.1.1 On-line Daily Calibration Error Tests. Except as provided in 
section 2.1.1.2 of this appendix, all daily calibration error tests must 
be performed while the unit is in operation at normal, stable conditions 
(i.e. ``on-line'').

[[Page 393]]

    2.1.1.2 Off-line Daily Calibration Error Tests. Daily calibrations 
may be performed while the unit is not operating (i.e., ``off-line'') 
and may be used to validate data for a monitoring system that meets the 
following conditions:
    (1) An initial demonstration test of the monitoring system is 
successfully completed and the results are reported in the quarterly 
report required under Sec. 75.64 of this part. The initial 
demonstration test, hereafter called the ``off-line calibration 
demonstration'', consists of an off-line calibration error test followed 
by an on-line calibration error test. Both the off-line and on-line 
portions of the off-line calibration demonstration must meet the 
calibration error performance specification in section 3.1 of appendix A 
of this part. Upon completion of the off-line portion of the 
demonstration, the zero and upscale monitor responses may be adjusted, 
but only toward the true values of the calibration gases or reference 
signals used to perform the test and only in accordance with the routine 
calibration adjustment procedures specified in the quality control 
program required under section 1 of appendix B to this part. Once these 
adjustments are made, no further adjustments may be made to the 
monitoring system until after completion of the on-line portion of the 
off-line calibration demonstration. Within 26 clock hours of the 
completion hour of the off-line portion of the demonstration, the 
monitoring system must successfully complete the first attempted 
calibration error test, i.e., the on-line portion of the demonstration.
    (2) For each monitoring system that has passed the off-line 
calibration demonstration, off-line calibration error tests may be used 
on a limited basis to validate data, in accordance with paragraph (2) in 
section 2.1.5.1 of this appendix.

                   2.1.2 Daily Flow Interference Check

    Perform the daily flow monitor interference checks specified in 
section 2.2.2.2 of appendix A of this part while the unit is in 
operation at normal, stable conditions.

  2.1.3 Additional Calibration Error Tests and Calibration Adjustments

    (a) In addition to the daily calibration error tests required under 
section 2.1.1 of this appendix, a calibration error test of a monitor 
shall be performed in accordance with section 2.1.1 of this appendix, as 
follows: whenever a daily calibration error test is failed; whenever a 
monitoring system is returned to service following repair or corrective 
maintenance that could affect the monitor's ability to accurately 
measure and record emissions data; or after making certain calibration 
adjustments, as described in this section. Except in the case of the 
routine calibration adjustments described in this section, data from the 
monitor are considered invalid until the required additional calibration 
error test has been successfully completed.
    (b) Routine calibration adjustments of a monitor are permitted after 
any successful calibration error test. These routine adjustments shall 
be made so as to bring the monitor readings as close as practicable to 
the known tag values of the calibration gases or to the actual value of 
the flow monitor reference signals. An additional calibration error test 
is required following routine calibration adjustments where the 
monitor's calibration has been physically adjusted (e.g., by turning a 
potentiometer) to verify that the adjustments have been made properly. 
An additional calibration error test is not required, however, if the 
routine calibration adjustments are made by means of a mathematical 
algorithm programmed into the data acquisition and handling system. The 
EPA recommends that routine calibration adjustments be made, at a 
minimum, whenever the daily calibration error exceeds the limits of the 
applicable performance specification in appendix A to this part for the 
pollutant concentration monitor, CO2 or O2 
monitor, or flow monitor.
    (c) Additional (non-routine) calibration adjustments of a monitor 
are permitted prior to (but not during) linearity checks and RATAs and 
at other times, provided that an appropriate technical justification is 
included in the quality control program required under section 1 of this 
appendix. The allowable non-routine adjustments are as follows. The 
owner or operator may physically adjust the calibration of a monitor 
(e.g., by means of a potentiometer), provided that the post-adjustment 
zero and upscale responses of the monitor are within the performance 
specifications of the instrument given in section 3.1 of appendix A to 
this part. An additional calibration error test is required following 
such adjustments to verify that the monitor is operating within the 
performance specifications at both the zero and upscale calibration 
levels.

                          2.1.4 Data Validation

    (a) An out-of-control period occurs when the calibration error of an 
SO2 or NOX pollutant concentration monitor exceeds 
5.0 percent of the span value, when the calibration error of a 
CO2 or O2 monitor (including O2 
monitors used to measure CO2 emissions or percent moisture) 
exceeds 1.0 percent O2 or CO2, or when the 
calibration error of a flow monitor exceeds 6.0 percent of the span 
value, which is twice the applicable specification of appendix A to this 
part. Notwithstanding, a differential pressure-type flow monitor for 
which the calibration error exceeds 6.0 percent of the span value shall 
not

[[Page 394]]

be considered out-of-control if [verbar]R-A[verbar], the absolute value 
of the difference between the monitor response and the reference value 
in Equation A-6 of appendix A to this part, is <0.02 inches of water. In 
addition, an SO2 or NOX monitor for which the 
calibration error exceeds 5.0 percent of the span value shall not be 
considered out-of-control if [verbar]R-A[verbar] in Equation A-6 does 
not exceed 5.0 ppm (for span values <=50 ppm), or if [verbar]R-
A[verbar]; does not exceed 10.0 ppm (for span values 50 ppm, 
but <=200 ppm). The out-of-control period begins upon failure of the 
calibration error test and ends upon completion of a successful 
calibration error test. Note, that if a failed calibration, corrective 
action, and successful calibration error test occur within the same 
hour, emission data for that hour recorded by the monitor after the 
successful calibration error test may be used for reporting purposes, 
provided that two or more valid readings are obtained as required by 
Sec. 75.10. A NOX-diluent CEMS is considered out-of-control 
if the calibration error of either component monitor exceeds twice the 
applicable performance specification in appendix A to this part. 
Emission data shall not be reported from an out-of-control monitor.
    (b) An out-of-control period also occurs whenever interference of a 
flow monitor is identified. The out-of-control period begins with the 
hour of completion of the failed interference check and ends with the 
hour of completion of an interference check that is passed.
    (c) The results of any certification, recertification, diagnostic, 
or quality assurance test required under this part may not be used to 
validate the emissions data required under this part, if the test is 
performed using EPA Protocol gas from a production site that is not 
participating in the PGVP, except as provided in Sec. 75.21(g)(7) or if 
the cylinder(s) are analyzed by an independent laboratory and shown to 
meet the requirements of section 5.1.4(b) of appendix A to this part.

    2.1.5 Quality Assurance of Data With Respect to Daily Assessments

    When a monitoring system passes a daily assessment (i.e., daily 
calibration error test or daily flow interference check), data from that 
monitoring system are prospectively validated for 26 clock hours (i.e., 
24 hours plus a 2-hour grace period) beginning with the hour in which 
the test is passed, unless another assessment (i.e. a daily calibration 
error test, an interference check of a flow monitor, a quarterly 
linearity check, a quarterly leak check, or a relative accuracy test 
audit) is failed within the 26-hour period.
    2.1.5.1 Data Invalidation with Respect to Daily Assessments. The 
following specific rules apply to the invalidation of data with respect 
to daily assessments:
    (1) Data from a monitoring system are invalid, beginning with the 
first hour following the expiration of a 26-hour data validation period 
or beginning with the first hour following the expiration of an 8-hour 
start-up grace period (as provided under section 2.1.5.2 of this 
appendix), if the required subsequent daily assessment has not been 
conducted.
    (2) For a monitor that has passed the off-line calibration 
demonstration, a combination of on-line and off-line calibration error 
tests may be used to validate data from the monitor, as follows. For a 
particular unit (or stack) operating hour, data from a monitor may be 
validated using a successful off-line calibration error test if: (a) An 
on-line calibration error test has been passed within the previous 26 
unit (or stack) operating hours; and (b) the 26 clock hour data 
validation window for the off-line calibration error test has not 
expired. If either of these conditions is not met, then the data from 
the monitor are invalid with respect to the daily calibration error test 
requirement. Data from the monitor shall remain invalid until the 
appropriate on-line or off-line calibration error test is successfully 
completed so that both conditions (a) and (b) are met.
    (3) For units with two measurement ranges (low and high) for a 
particular parameter, when separate analyzers are used for the low and 
high ranges, a failed or expired calibration on one of the ranges does 
not affect the quality-assured data status on the other range. For a 
dual-range analyzer (i.e., a single analyzer with two measurement 
scales), a failed calibration error test on either the low or high scale 
results in an out-of-control period for the monitor. Data from the 
monitor remain invalid until corrective actions are taken and ``hands-
off'' calibration error tests have been passed on both ranges. However, 
if the most recent calibration error test on the high scale was passed 
but has expired, while the low scale is up-to-date on its calibration 
error test requirements (or vice-versa), the expired calibration error 
test does not affect the quality-assured status of the data recorded on 
the other scale.
    2.1.5.2 Daily Assessment Start-Up Grace Period. For the purpose of 
quality assuring data with respect to a daily assessment (i.e. a daily 
calibration error test or a flow interference check), a start-up grace 
period may apply when a unit begins to operate after a period of non-
operation. The start-up grace period for a daily calibration error test 
is independent of the start-up grace period for a daily flow 
interference check. To qualify for a start-up grace period for a daily 
assessment, there are two requirements:
    (1) The unit must have resumed operation after being in outage for 1 
or more hours (i.e., the unit must be in a start-up condition) as 
evidenced by a change in unit operating time from zero in one clock hour 
to an operating time greater than zero in the next clock hour.

[[Page 395]]

    (2) For the monitoring system to be used to validate data during the 
grace period, the previous daily assessment of the same kind must have 
been passed on-line within 26 clock hours prior to the last hour in 
which the unit operated before the outage. In addition, the monitoring 
system must be in-control with respect to quarterly and semi-annual or 
annual assessments.
    If both of the above conditions are met, then a start-up grace 
period of up to 8 clock hours applies, beginning with the first hour of 
unit operation following the outage. During the start-up grace period, 
data generated by the monitoring system are considered quality-assured. 
For each monitoring system, a start-up grace period for a calibration 
error test or flow interference check ends when either: (1) a daily 
assessment of the same kind (i.e., calibration error test or flow 
interference check) is performed; or (2) 8 clock hours have elapsed 
(starting with the first hour of unit operation following the outage), 
whichever occurs first.

                          2.1.6 Data Recording

    Record and tabulate all calibration error test data according to 
month, day, clock-hour, and magnitude in either ppm, percent volume, or 
scfh. Program monitors that automatically adjust data to the corrected 
calibration values (e.g., microprocessor control) to record either: (1) 
The unadjusted concentration or flow rate measured in the calibration 
error test prior to resetting the calibration, or (2) the magnitude of 
any adjustment. Record the following applicable flow monitor 
interference check data: (1) Sample line/sensing port pluggage, and (2) 
malfunction of each RTD, transceiver, or equivalent.

                        2.2 Quarterly Assessments

    For each primary and redundant backup monitor or monitoring system, 
perform the following quarterly assessments. This requirement is applies 
as of the calendar quarter following the calendar quarter in which the 
monitor or continuous emission monitoring system is provisionally 
certified.

                          2.2.1 Linearity Check

    Unless a particular monitor (or monitoring range) is exempted under 
this paragraph or under section 6.2 of appendix A to this part, perform 
a linearity check, in accordance with the procedures in section 6.2 of 
appendix A to this part, for each primary and redundant backup 
SO2, and NOx pollutant concentration monitor and each primary 
and redundant backup CO2 or O2 monitor (including 
O2 monitors used to measure CO2 emissions or to 
continuously monitor moisture) at least once during each QA operating 
quarter, as defined in Sec. 72.2 of this chapter. For units using both 
a low and high span value, a linearity check is required only on the 
range(s) used to record and report emission data during the QA operating 
quarter. Conduct the linearity checks no less than 30 days apart, to the 
extent practicable. The data validation procedures in section 2.2.3(e) 
of this appendix shall be followed.

                            2.2.2 Leak Check

    For differential pressure flow monitors, perform a leak check of all 
sample lines (a manual check is acceptable) at least once during each QA 
operating quarter. For this test, the unit does not have to be in 
operation. Conduct the leak checks no less than 30 days apart, to the 
extent practicable. If a leak check is failed, follow the applicable 
data validation procedures in section 2.2.3(g) of this appendix.

                          2.2.3 Data Validation

    (a) A linearity check shall not be commenced if the monitoring 
system is operating out-of-control with respect to any of the daily or 
semiannual quality assurance assessments required by sections 2.1 and 
2.3 of this appendix or with respect to the additional calibration error 
test requirements in section 2.1.3 of this appendix.
    (b) Each required linearity check shall be done according to 
paragraph (b)(1), (b)(2) or (b)(3) of this section:
    (1) The linearity check may be done ``cold,'' i.e., with no 
corrective maintenance, repair, calibration adjustments, re-
linearization or reprogramming of the monitor prior to the test.
    (2) The linearity check may be done after performing only the 
routine or non-routine calibration adjustments described in section 
2.1.3 of this appendix at the various calibration gas levels (zero, low, 
mid or high), but no other corrective maintenance, repair, re-
linearization or reprogramming of the monitor. Trial gas injection runs 
may be performed after the calibration adjustments and additional 
adjustments within the allowable limits in section 2.1.3 of this 
appendix may be made prior to the linearity check, as necessary, to 
optimize the performance of the monitor. The trial gas injections need 
not be reported, provided that they meet the specification for trial gas 
injections in Sec. 75.20(b)(3)(vii)(E)(1). However, if, for any trial 
injection, the specification in Sec. 75.20(b)(3)(vii)(E)(1) is not met, 
the trial injection shall be counted as an aborted linearity check.
    (3) The linearity check may be done after repair, corrective 
maintenance or reprogramming of the monitor. In this case, the monitor 
shall be considered out-of-control from the hour in which the repair, 
corrective maintenance or reprogramming is commenced until the linearity 
check has

[[Page 396]]

been passed. Alternatively, the data validation procedures and 
associated timelines in Sec. Sec. 75.20(b)(3)(ii) through (ix) may be 
followed upon completion of the necessary repair, corrective 
maintenance, or reprogramming. If the procedures in Sec. 75.20(b)(3) 
are used, the words ``quality assurance'' apply instead of the word 
``recertification''.
    (c) Once a linearity check has been commenced, the test shall be 
done hands-off. That is, no adjustments of the monitor are permitted 
during the linearity test period, other than the routine calibration 
adjustments following daily calibration error tests, as described in 
section 2.1.3 of this appendix. If a routine daily calibration error 
test is performed and passed just prior to a linearity test (or during a 
linearity test period) and a mathematical correction factor is 
automatically applied by the DAHS, the correction factor shall be 
applied to all subsequent data recorded by the monitor, including the 
linearity test data.
    (d) If a daily calibration error test is failed during a linearity 
test period, prior to completing the test, the linearity test must be 
repeated. Data from the monitor are invalidated prospectively from the 
hour of the failed calibration error test until the hour of completion 
of a subsequent successful calibration error test. The linearity test 
shall not be commenced until the monitor has successfully completed a 
calibration error test.
    (e) An out-of-control period occurs when a linearity test is failed 
(i.e., when the error in linearity at any of the three concentrations in 
the quarterly linearity check (or any of the six concentrations, when 
both ranges of a single analyzer with a dual range are tested) exceeds 
the applicable specification in section 3.2 of appendix A to this part) 
or when a linearity test is aborted due to a problem with the monitor or 
monitoring system. For a NOX-diluent continuous emission 
monitoring system, the system is considered out-of-control if either of 
the component monitors exceeds the applicable specification in section 
3.2 of appendix A to this part or if the linearity test of either 
component is aborted due to a problem with the monitor. The out-of-
control period begins with the hour of the failed or aborted linearity 
check and ends with the hour of completion of a satisfactory linearity 
check following corrective action and/or monitor repair, unless the 
option in paragraph (b)(3) of this section to use the data validation 
procedures and associated timelines in Sec. 75.20(b)(3)(ii) through 
(ix) has been selected, in which case the beginning and end of the out-
of-control period shall be determined in accordance with Sec. Sec. 
75.20(b)(3)(vii)(A) and (B). For a dual-range analyzer, ``hands-off'' 
linearity checks must be passed on both measurement scales to end the 
out-of-control period. Note that a monitor shall not be considered out-
of-control when a linearity test is aborted for a reason unrelated to 
the monitor's performance (e.g., a forced unit outage).
    (f) No more than four successive calendar quarters shall elapse 
after the quarter in which a linearity check of a monitor or monitoring 
system (or range of a monitor or monitoring system) was last performed 
without a subsequent linearity test having been conducted. If a 
linearity test has not been completed by the end of the fourth calendar 
quarter since the last linearity test, then the linearity test must be 
completed within a 168 unit operating hour or stack operating hour 
``grace period'' (as provided in section 2.2.4 of this appendix) 
following the end of the fourth successive elapsed calendar quarter, or 
data from the CEMS (or range) will become invalid.
    (g) An out-of-control period also occurs when a flow monitor sample 
line leak is detected. The out-of-control period begins with the hour of 
the failed leak check and ends with the hour of a satisfactory leak 
check following corrective action.
    (h) For each monitoring system, report the results of all completed 
and partial linearity tests that affect data validation (i.e., all 
completed, passed linearity checks; all completed, failed linearity 
checks; and all linearity checks aborted due to a problem with the 
monitor, including trial gas injections counted as failed test attempts 
under paragraph (b)(2) of this section or under Sec. 
75.20(b)(3)(vii)(F)), in the quarterly report required under Sec. 
75.64. Note that linearity attempts which are aborted or invalidated due 
to problems with the reference calibration gases or due to operational 
problems with the affected unit(s) need not be reported. Such partial 
tests do not affect the validation status of emission data recorded by 
the monitor. A record of all linearity tests, trial gas injections and 
test attempts (whether reported or not) must be kept on-site as part of 
the official test log for each monitoring system.
    (i) The results of any certification, recertification, diagnostic, 
or quality assurance test required under this part may not be used to 
validate the emissions data required under this part, if the test is 
performed using EPA Protocol gas that was not from an EPA Protocol gas 
production site participating in the PGVP on the date the gas was 
procured either by the tester or by a reseller that sold to the tester 
the unaltered EPA Protocol gas, except as provided in Sec. 75.21(g)(7) 
or if the cylinder(s) are analyzed by an independent laboratory and 
shown to meet the requirements of section 5.1.4(b) of appendix A to this 
part.

               2.2.4 Linearity and Leak Check Grace Period

    (a) When a required linearity test or flow monitor leak check has 
not been completed by the end of the QA operating quarter in

[[Page 397]]

which it is due or if, due to infrequent operation of a unit or 
infrequent use of a required high range of a monitor or monitoring 
system, four successive calendar quarters have elapsed after the quarter 
in which a linearity check of a monitor or monitoring system (or range) 
was last performed without a subsequent linearity test having been done, 
the owner or operator has a grace period of 168 consecutive unit 
operating hours, as defined in Sec. 72.2 of this chapter (or, for 
monitors installed on common stacks or bypass stacks, 168 consecutive 
stack operating hours, as defined in Sec. 72.2 of this chapter) in 
which to perform a linearity test or leak check of that monitor or 
monitoring system (or range). The grace period begins with the first 
unit or stack operating hour following the calendar quarter in which the 
linearity test was due. Data validation during a linearity or leak check 
grace period shall be done in accordance with the applicable provisions 
in section 2.2.3 of this appendix.
    (b) If, at the end of the 168 unit (or stack) operating hour grace 
period, the required linearity test or leak check has not been 
completed, data from the monitoring system (or range) shall be invalid, 
beginning with the first unit operating hour following the expiration of 
the grace period. Data from the monitoring system (or range) remain 
invalid until the hour of completion of a subsequent successful hands-
off linearity test or leak check of the monitor or monitoring system (or 
range). Note that when a linearity test or a leak check is conducted 
within a grace period for the purpose of satisfying the linearity test 
or leak check requirement from a previous QA operating quarter, the 
results of that linearity test or leak check may only be used to meet 
the linearity check or leak check requirement of the previous quarter, 
not the quarter in which the missed linearity test or leak check is 
completed.

         2.2.5 Flow-to-Load Ratio or Gross Heat Rate Evaluation

    (a) Applicability and methodology. Unless exempted from the flow-to-
load ratio test under section 7.8 of appendix A to this part, the owner 
or operator shall, for each flow rate monitoring system installed on 
each unit, common stack or multiple stack, evaluate the flow-to-load 
ratio quarterly, i.e., for each QA operating quarter (as defined in 
Sec. 72.2 of this chapter). At the end of each QA operating quarter, 
the owner or operator shall use Equation B-1 to calculate the flow-to-
load ratio for every hour during the quarter in which: the unit (or 
combination of units, for a common stack) operated within [10.0 percent 
of Lavg, the average load during the most recent normal-load 
flow RATA; and a quality-assured hourly average flow rate was obtained 
with a certified flow rate monitor. Alternatively, for the reasons 
stated in paragraphs (c)(1) through (c)(6) of this section, the owner or 
operator may exclude from the data analysis certain hours within [10.0 
percent of Lavg and may calculate Rh values for 
only the remaining hours.
[GRAPHIC] [TIFF OMITTED] TR26MY99.009

Where:

Rh = Hourly value of the flow-to-load ratio, scfh/megawatts, 
          scfh/1000 lb/hr of steam, or scfh/(mmBtu/hr thermal output).
Qh = Hourly stack gas volumetric flow rate, as measured by 
          the flow rate monitor, scfh.
Lh = Hourly unit load, megawatts, 1000 lb/hr of steam, or 
          mmBtu/hr thermal output; must be within + 10.0 percent of 
          Lavg during the most recent normal-load flow RATA.

    (1) In Equation B-1, the owner or operator may use either bias-
adjusted flow rates or unadjusted flow rates, provided that all of the 
ratios are calculated the same way. For a common stack, Lh 
shall be the sum of the hourly operating loads of all units that 
discharge through the stack. For a unit that discharges its emissions 
through multiple stacks or that monitors its emissions in multiple 
breechings, Qh will be either the combined hourly volumetric 
flow rate for all of the stacks or ducts (if the test is done on a unit 
basis) or the hourly flow rate through each stack individually (if the 
test is performed separately for each stack). For a unit with a multiple 
stack discharge configuration consisting of a main stack and a bypass 
stack, each of which has a certified flow monitor (e.g., a unit with a 
wet SO2 scrubber), calculate the hourly flow-to-load ratios 
separately for each stack. Round off each value of Rh to two 
decimal places.
    (2) Alternatively, the owner or operator may calculate the hourly 
gross heat rates (GHR) in lieu of the hourly flow-to-load ratios. The 
hourly GHR shall be determined only for those hours in which quality-
assured flow rate data and diluent gas (CO2 or O2) 
concentration data are both available

[[Page 398]]

from a certified monitor or monitoring system or reference method. If 
this option is selected, calculate each hourly GHR value as follows:
[GRAPHIC] [TIFF OMITTED] TR26MY99.010

where:

(GHR)h = Hourly value of the gross heat rate, Btu/kwh, Btu/lb 
          steam load, or 1000 mmBtu heat input/mmBtu thermal output.
(Heat Input)h = Hourly heat input, as determined from the 
          quality-assured flow rate and diluent data, using the 
          applicable equation in appendix F to this part, mmBtu/hr.
Lh = Hourly unit load, megawatts, 1000 lb/hr of steam, or 
          mmBtu/hr thermal output; must be within + 10.0 percent of 
          Lavg during the most recent normal-load flow RATA.

    (3) In Equation B-1a, the owner or operator may either use bias-
adjusted flow rates or unadjusted flow rates in the calculation of (Heat 
Input)h, provided that all of the heat input rate values are 
determined in the same manner.
    (4) The owner or operator shall evaluate the calculated hourly flow-
to-load ratios (or gross heat rates) as follows. A separate data 
analysis shall be performed for each primary and each redundant backup 
flow rate monitor used to record and report data during the quarter. 
Each analysis shall be based on a minimum of 168 acceptable recorded 
hourly average flow rates (i.e., at loads within [10 percent of 
Lavg). When two RATA load levels are designated as normal, 
the analysis shall be performed at the higher load level, unless there 
are fewer than 168 acceptable data points available at that load level, 
in which case the analysis shall be performed at the lower load level. 
If, for a particular flow monitor, fewer than 168 acceptable hourly 
flow-to-load ratios (or GHR values) are available at any of the load 
levels designated as normal, a flow-to-load (or GHR) evaluation is not 
required for that monitor for that calendar quarter.
    (5) For each flow monitor, use Equation B-2 in this appendix to 
calculate Eh, the absolute percentage difference between each 
hourly Rh value and Rref, the reference value of 
the flow-to-load ratio, as determined in accordance with section 7.7 of 
appendix A to this part. Note that Rref shall always be based 
upon the most recent normal-load RATA, even if that RATA was performed 
in the calendar quarter being evaluated.
[GRAPHIC] [TIFF OMITTED] TR26MY99.011

where:

Eh = Absolute percentage difference between the hourly 
          average flow-to-load ratio and the reference value of the 
          flow-to-load ratio at normal load.
Rh = The hourly average flow-to-load ratio, for each flow 
          rate recorded at a load level within [10.0 percent of 
          Lavg.
Rref = The reference value of the flow-to-load ratio from the 
          most recent normal-load flow RATA, determined in accordance 
          with section 7.7 of appendix A to this part.

    (6) Equation B-2 shall be used in a consistent manner. That is, use 
Rref and Rh if the flow-to-load ratio is being 
evaluated, and use (GHR)ref and (GHR)h if the 
gross heat rate is being evaluated. Finally, calculate Ef, 
the arithmetic average of all of the hourly Eh values. The 
owner or operator shall report the results of each quarterly flow-to-
load (or gross heat rate) evaluation, as determined from Equation B-2, 
in the electronic quarterly report required under Sec. 75.64.
    (b) Acceptable results. The results of a quarterly flow-to-load (or 
gross heat rate) evaluation are acceptable, and no further action is 
required, if the calculated value of Ef is less than or equal 
to: (1) 15.0 percent, if Lavg for the most recent normal-load 
flow RATA is =60 megawatts (or =500 klb/hr of 
steam) and if unadjusted flow rates were used in the calculations; or 
(2) 10.0 percent, if Lavg for the most recent normal-load 
flow RATA is =60 megawatts (or =500 klb/hr of 
steam) and if bias-adjusted flow rates were used in the calculations; or 
(3) 20.0 percent, if Lavg for the most recent normal-load 
flow RATA is <60

[[Page 399]]

megawatts (or <500 klb/hr of steam) and if unadjusted flow rates were 
used in the calculations; or (4) 15.0 percent, if Lavg for 
the most recent normal-load flow RATA is <60 megawatts (or <500 klb/hr 
of steam) and if bias-adjusted flow rates were used in the calculations. 
If Ef is above these limits, the owner or operator shall 
either: implement Option 1 in section 2.2.5.1 of this appendix; or 
perform a RATA in accordance with Option 2 in section 2.2.5.2 of this 
appendix; or re-examine the hourly data used for the flow-to-load or GHR 
analysis and recalculate Ef, after excluding all non-
representative hourly flow rates. If Ef is above these 
limits, the owner or operator shall either: implement Option 1 in 
section 2.2.5.1 of this appendix; perform a RATA in accordance with 
Option 2 in section 2.2.5.2 of this appendix; or (if applicable) re-
examine the hourly data used for the flow-to-load or GHR analysis and 
recalculate Ef, after excluding all non-representative hourly 
flow rates, as provided in paragraph (c) of this section.
    (c) Recalculation of Ef. If the owner or operator did not exclude 
any hours within [10 percent of Lavg from the original data 
analysis and chooses to recalculate Ef, the flow rates for 
the following hours are considered non-representative and may be 
excluded from the data analysis:
    (1) Any hour in which the type of fuel combusted was different from 
the fuel burned during the most recent normal-load RATA. For purposes of 
this determination, the type of fuel is different if the fuel is in a 
different state of matter (i.e., solid, liquid, or gas) than is the fuel 
burned during the RATA or if the fuel is a different classification of 
coal (e.g., bituminous versus sub-bituminous). Also, for units that co-
fire different types of fuels, if the reference RATA was done while co-
firing, then hours in which a single fuel was combusted may be excluded 
from the data analysis as different fuel hours (and vice-versa for co-
fired hours, if the reference RATA was done while combusting only one 
type of fuel);
    (2) For a unit that is equipped with an SO2 scrubber and 
which always discharges its flue gases to the atmosphere through a 
single stack, any hour in which the SO2 scrubber was 
bypassed;
    (3) Any hour in which ``ramping'' occurred, i.e., the hourly load 
differed by more than [15.0 percent from the load during the preceding 
hour or the subsequent hour;
    (4) For a unit with a multiple stack discharge configuration 
consisting of a main stack and a bypass stack, any hour in which the 
flue gases were discharged through both stacks;
    (5) If a normal-load flow RATA was performed and passed during the 
quarter being analyzed, any hour prior to completion of that RATA; and
    (6) If a problem with the accuracy of the flow monitor was 
discovered during the quarter and was corrected (as evidenced by passing 
the abbreviated flow-to-load test in section 2.2.5.3 of this appendix), 
any hour prior to completion of the abbreviated flow-to-load test.
    (7) After identifying and excluding all non-representative hourly 
data in accordance with paragraphs (c)(1) through (6) of this section, 
the owner or operator may analyze the remaining data a second time. At 
least 168 representative hourly ratios or GHR values must be available 
to perform the analysis; otherwise, the flow-to-load (or GHR) analysis 
is not required for that monitor for that calendar quarter.
    (8) If, after re-analyzing the data, Ef meets the 
applicable limit in paragraph (b)(1), (b)(2), (b)(3), or (b)(4) of this 
section, no further action is required. If, however, Ef is 
still above the applicable limit, data from the monitor shall be 
declared out-of-control, beginning with the first unit operating hour 
following the quarter in which Ef exceeded the applicable 
limit. Alternatively, if a probationary calibration error test is 
performed and passed according to Sec. 75.20(b)(3)(ii), data from the 
monitor may be declared conditionally valid following the quarter in 
which Ef exceeded the applicable limit. The owner or operator 
shall then either implement Option 1 in section 2.2.5.1 of this appendix 
or Option 2 in section 2.2.5.2 of this appendix.

                            2.2.5.1 Option 1

    Within 14 unit operating days of the end of the calendar quarter for 
which the Ef value is above the applicable limit, investigate 
and troubleshoot the applicable flow monitor(s). Evaluate the results of 
each investigation as follows:
    (a) If the investigation fails to uncover a problem with the flow 
monitor, a RATA shall be performed in accordance with Option 2 in 
section 2.2.5.2 of this appendix.
    (b) If a problem with the flow monitor is identified through the 
investigation (including the need to re-linearize the monitor by 
changing the polynomial coefficients or K factor(s)), data from the 
monitor are considered invalid back to the first unit operating hour 
after the end of the calendar quarter for which Ef was above 
the applicable limit. If the option to use conditional data validation 
was selected under section 2.2.5(c)(8) of this appendix, all 
conditionally valid data shall be invalidated, back to the first unit 
operating hour after the end of the calendar quarter for which 
Ef was above the applicable limit. Corrective actions shall 
be taken. All corrective actions (e.g., non-routine maintenance, 
repairs, major component replacements, re-linearization of the monitor, 
etc.) shall be documented in the operation and maintenance records for 
the monitor.

[[Page 400]]

The owner or operator then shall either complete the abbreviated flow-
to-load test in section 2.2.5.3 of this appendix, or, if the corrective 
action taken has required relinearization of the flow monitor, shall 
perform a 3-load RATA. The conditional data validation procedures in 
Sec. 75.20(b)(3) may be applied to the 3-load RATA.

                            2.2.5.2 Option 2

    Perform a single-load RATA (at a load designated as normal under 
section 6.5.2.1 of appendix A to this part) of each flow monitor for 
which Ef is outside of the applicable limit. If the RATA is 
passed hands-off, in accordance with section 2.3.2(c) of this appendix, 
no further action is required and the out-of-control period for the 
monitor ends at the date and hour of completion of a successful RATA, 
unless the option to use conditional data validation was selected under 
section 2.2.5(c)(8) of this appendix. In that case, all conditionally 
valid data from the monitor are considered to be quality-assured, back 
to the first unit operating hour following the end of the calendar 
quarter for which the Ef value was above the applicable 
limit. If the RATA is failed, all data from the monitor shall be 
invalidated, back to the first unit operating hour following the end of 
the calendar quarter for which the Ef value was above the 
applicable limit. Data from the monitor remain invalid until the 
required RATA has been passed. Alternatively, following a failed RATA 
and corrective actions, the conditional data validation procedures of 
Sec. 75.20(b)(3) may be used until the RATA has been passed. If the 
corrective actions taken following the failed RATA included adjustment 
of the polynomial coefficients or K-factor(s) of the flow monitor, a 3-
level RATA is required, except as otherwise specified in section 2.3.1.3 
of this appendix.

                  2.2.5.3 Abbreviated Flow-to-Load Test

    (a) The following abbreviated flow-to-load test may be performed 
after any documented repair, component replacement, or other corrective 
maintenance to a flow monitor (except for changes affecting the 
linearity of the flow monitor, such as adjusting the flow monitor 
coefficients or K factor(s)) to demonstrate that the repair, 
replacement, or other maintenance has not significantly affected the 
monitor's ability to accurately measure the stack gas volumetric flow 
rate. Data from the monitoring system are considered invalid from the 
hour of commencement of the repair, replacement, or maintenance until 
either the hour in which the abbraviated flow-to-load test is passed, or 
the hour in which a probationary calibration error test is passed 
following completion of the repair, replacement, or maintenance and any 
associated adjustments to the monitor. If the latter option is selected, 
the abbreviated flow-to-load test shall be completed within 168 unit 
operating hours of the probationary calibration error test (or, for 
peaking units, within 30 unit operating days, if that is less 
restrictive). Data from the monitor are considered to be conditionally 
valid (as defined in Sec. 72.2 of this chapter), beginning with the 
hour of the probationary calibration error test.
    (b) Operate the unit(s) in such a way as to reproduce, as closely as 
practicable, the exact conditions at the time of the most recent normal-
load flow RATA. To achieve this, it is recommended that the load be held 
constant to within [10.0 percent of the average load during the RATA and 
that the diluent gas (CO2 or O2) concentration be 
maintained within [0.5 percent CO2 or O2 of the 
average diluent concentration during the RATA. For common stacks, to the 
extent practicable, use the same combination of units and load levels 
that were used during the RATA. When the process parameters have been 
set, record a minimum of six and a maximum of 12 consecutive hourly 
average flow rates, using the flow monitor(s) for which Ef 
was outside the applicable limit. For peaking units, a minimum of three 
and a maximum of 12 consecutive hourly average flow rates are required. 
Also record the corresponding hourly load values and, if applicable, the 
hourly diluent gas concentrations. Calculate the flow-to-load ratio (or 
GHR) for each hour in the test hour period, using Equation B-1 or B-1a. 
Determine Eh for each hourly flow-to-load ratio (or GHR), 
using Equation B-2 of this appendix and then calculate Ef, 
the arithmetic average of the Eh values.
    (c) The results of the abbreviated flow-to-load test shall be 
considered acceptable, and no further action is required if the value of 
Ef does not exceed the applicable limit specified in section 
2.2.5 of this appendix. All conditionally valid data recorded by the 
flow monitor shall be considered quality-assured, beginning with the 
hour of the probationary calibration error test that preceded the 
abbreviated flow-to-load test (if applicable). However, if Ef 
is outside the applicable limit, all conditionally valid data recorded 
by the flow monitor (if applicable) shall be considered invalid back to 
the hour of the probationary calibration error test that preceded the 
abbreviated flow-to-load test, and a single-load RATA is required in 
accordance with section 2.2.5.2 of this appendix. If the flow monitor 
must be re-linearized, however, a 3-load RATA is required.

                  2.3 Semiannual and Annual Assessments

    For each primary and redundant backup monitoring system, perform 
relative accuracy assessments either semiannually or annually, as 
specified in section 2.3.1.1 or 2.3.1.2 of this appendix, for the type 
of test and the

[[Page 401]]

performance achieved. This requirement applies as of the calendar 
quarter following the calendar quarter in which the monitoring system is 
provisionally certified. A summary chart showing the frequency with 
which a relative accuracy test audit must be performed, depending on the 
accuracy achieved, is located at the end of this appendix in Figure 2.

                2.3.1 Relative Accuracy Test Audit (RATA)

                    2.3.1.1 Standard RATA Frequencies

    (a) Except as otherwise specified in Sec. 75.21(a)(6) or (a)(7) or 
in section 2.3.1.2 of this appendix, perform relative accuracy test 
audits semiannually, i.e., once every two successive QA operating 
quarters (as defined in Sec. 72.2 of this chapter) for each primary and 
redundant backup SO2 pollutant concentration monitor, flow 
monitor, CO2 emissions concentration monitor (including 
O2 monitors used to determine CO2 emissions), 
CO2 or O2 diluent monitor used to determine heat 
input, moisture monitoring system, NOX concentration 
monitoring system, or NOX-diluent CEMS. A calendar quarter 
that does not qualify as a QA operating quarter shall be excluded in 
determining the deadline for the next RATA. No more than eight 
successive calendar quarters shall elapse after the quarter in which a 
RATA was last performed without a subsequent RATA having been conducted. 
If a RATA has not been completed by the end of the eighth calendar 
quarter since the quarter of the last RATA, then the RATA must be 
completed within a 720 unit (or stack) operating hour grace period (as 
provided in section 2.3.3 of this appendix) following the end of the 
eighth successive elapsed calendar quarter, or data from the CEMS will 
become invalid.
    (b) The relative accuracy test audit frequency of a CEMS may be 
reduced, as specified in section 2.3.1.2 of this appendix, for primary 
or redundant backup monitoring systems which qualify for less frequent 
testing. Perform all required RATAs in accordance with the applicable 
procedures and provisions in sections 6.5 through 6.5.2.2 of appendix A 
to this part and sections 2.3.1.3 and 2.3.1.4 of this appendix.

                    2.3.1.2 Reduced RATA Frequencies

    Relative accuracy test audits of primary and redundant backup 
SO2 pollutant concentration monitors, CO2 
pollutant concentration monitors (including O2 monitors used 
to determine CO2 emissions), CO2 or O2 
diluent monitors used to determine heat input, moisture monitoring 
systems, NOX concentration monitoring systems, flow monitors, 
NOX-diluent monitoring systems or SO2-diluent 
monitoring systems may be performed annually (i.e., once every four 
successive QA operating quarters, rather than once every two successive 
QA operating quarters) if any of the following conditions are met for 
the specific monitoring system involved:
    (a) The relative accuracy during the audit of an SO2 or 
CO2 pollutant concentration monitor (including an 
O2 pollutant monitor used to measure CO2 using the 
procedures in appendix F to this part), or of a CO2 or 
O2 diluent monitor used to determine heat input, or of a 
NOX concentration monitoring system, or of a NOX-
diluent monitoring system, or of an SO2-diluent continuous 
emissions monitoring system is <=7.5 percent;
    (b) [Reserved]
    (c) The relative accuracy during the audit of a flow monitor is 
<=7.5 percent at each operating level tested;
    (d) For low flow (<=10.0 fps, as measured by the reference method 
during the RATA) stacks/ducts, when the flow monitor fails to achieve a 
relative accuracy <=7.5 percent during the audit, but the monitor mean 
value, calculated using Equation A-7 in appendix A to this part and 
converted back to an equivalent velocity in standard feet per second 
(fps), is within [1.5 fps of the reference method mean value, converted 
to an equivalent velocity in fps;
    (e) For low SO2 or NOX emitting units (average 
SO2 or NOX reference method concentrations <=250 
ppm) during the RATA, when an SO2 pollutant concentration 
monitor or NOX concentration monitoring system fails to 
achieve a relative accuracy <=7.5 percent during the audit, but the 
monitor mean value from the RATA is within [12 ppm of the reference 
method mean value;
    (f) For units with low NOX emission rates (average 
NOX emission rate measured by the reference method during the 
RATA <=0.200 lb/mmBtu), when a NOX-diluent continuous 
emission monitoring system fails to achieve a relative accuracy <=7.5 
percent, but the monitoring system mean value from the RATA, calculated 
using Equation A-7 in appendix A to this part, is within [0.015 lb/mmBtu 
of the reference method mean value;
    (g) [Reserved]
    (h) For a CO2 or O2 monitor, when the mean 
difference between the reference method values from the RATA and the 
corresponding monitor values is within [0.7 percent CO2 or 
O2; and
    (i) When the relative accuracy of a continuous moisture monitoring 
system is <=7.5 percent or when the mean difference between the 
reference method values from the RATA and the corresponding monitoring 
system values is within [1.0 percent H2O.

2.3.1.3 RATA Load (or Operating) Levels and Additional RATA Requirements

    (a) For SO2 pollutant concentration monitors, 
CO2 emissions concentration monitors (including O2 
monitors used to determine CO2 emissions), CO2 or 
O2 diluent monitors

[[Page 402]]

used to determine heat input, NOX concentration monitoring 
systems, and NOX-diluent monitoring systems, the required 
semiannual or annual RATA tests shall be done at the load level (or 
operating level) designated as normal under section 6.5.2.1(d) of 
appendix A to this part. If two load levels (or operating levels) are 
designated as normal, the required RATA(s) may be done at either load 
level (or operating level).
    (b) For flow monitors installed on peaking units and bypass stacks, 
and for flow monitors that qualify to perform only single-level RATAs 
under section 6.5.2(e) of appendix A to this part, all required 
semiannual or annual relative accuracy test audits shall be single-load 
(or single-level) audits at the normal load (or operating level), as 
defined in section 6.5.2.1(d) of appendix A to this part.
    (c) For all other flow monitors, the RATAs shall be performed as 
follows:
    (1) An annual 2-load (or 2-level) flow RATA shall be done at the two 
most frequently used load levels (or operating levels), as determined 
under section 6.5.2.1(d) of appendix A to this part, or (if applicable) 
at the operating levels determined under section 6.5.2(e) of appendix A 
to this part. Alternatively, a 3-load (or 3-level) flow RATA at the low, 
mid, and high load levels (or operating levels), as defined under 
section 6.5.2.1(b) of appendix A to this part, may be performed in lieu 
of the 2-load (or 2-level) annual RATA.
    (2) If the flow monitor is on a semiannual RATA frequency, 2-load 
(or 2-level) flow RATAs and single-load (or single-level) flow RATAs at 
the normal load level (or normal operating level) may be performed 
alternately.
    (3) A single-load (or single-level) annual flow RATA may be 
performed in lieu of the 2-load (or 2-level) RATA if the results of an 
historical load data analysis show that in the time period extending 
from the ending date of the last annual flow RATA to a date that is no 
more than 21 days prior to the date of the current annual flow RATA, the 
unit (or combination of units, for a common stack) has operated at a 
single load level (or operating level) (low, mid, or high), for 
=85.0 percent of the time. Alternatively, a flow monitor may 
qualify for a single-load (or single-level) RATA if the 85.0 percent 
criterion is met in the time period extending from the beginning of the 
quarter in which the last annual flow RATA was performed through the end 
of the calendar quarter preceding the quarter of current annual flow 
RATA.
    (4) A 3-load (or 3-level) RATA, at the low-, mid-, and high-load 
levels (or operating levels), as determined under section 6.5.2.1 of 
appendix A to this part, shall be performed at least once every twenty 
consecutive calendar quarters, except for flow monitors that are 
exempted from 3-load (or 3-level) RATA testing under section 6.5.2(b) or 
6.5.2(e) of appendix A to this part.
    (5) A 3-load (or 3-level) RATA is required whenever a flow monitor 
is re-linearized, i.e., when its polynomial coefficients or K factor(s) 
are changed, except for flow monitors that are exempted from 3-load (or 
3-level) RATA testing under section 6.5.2(b) or 6.5.2(e) of appendix A 
to this part. For monitors so exempted under section 6.5.2(b), a single-
load flow RATA is required. For monitors so exempted under section 
6.5.2(e), either a single-level RATA or a 2-level RATA is required, 
depending on the number of operating levels documented in the monitoring 
plan for the unit.
    (6) For all multi-level flow audits, the audit points at adjacent 
load levels or at adjacent operating levels (e.g., mid and high) shall 
be separated by no less than 25.0 percent of the ``range of operation,'' 
as defined in section 6.5.2.1 of appendix A to this part.
    (d) A RATA of a moisture monitoring system shall be performed 
whenever the coefficient, K factor or mathematical algorithm determined 
under section 6.5.7 of appendix A to this part is changed.

                     2.3.1.4 Number of RATA Attempts

    The owner or operator may perform as many RATA attempts as are 
necessary to achieve the desired relative accuracy test audit 
frequencies and/or bias adjustment factors. However, the data validation 
procedures in section 2.3.2 of this appendix must be followed.

                          2.3.2 Data Validation

    (a) A RATA shall not commence if the monitoring system is operating 
out-of-control with respect to any of the daily and quarterly quality 
assurance assessments required by sections 2.1 and 2.2 of this appendix 
or with respect to the additional calibration error test requirements in 
section 2.1.3 of this appendix.
    (b) Each required RATA shall be done according to paragraphs (b)(1), 
(b)(2) or (b)(3) of this section:
    (1) The RATA may be done ``cold,'' i.e., with no corrective 
maintenance, repair, calibration adjustments, re-linearization or 
reprogramming of the monitoring system prior to the test.
    (2) The RATA may be done after performing only the routine or non-
routine calibration adjustments described in section 2.1.3 of this 
appendix at the zero and/or upscale calibration gas levels, but no other 
corrective maintenance, repair, re-linearization or reprogramming of the 
monitoring system. Trial RATA runs may be performed after the 
calibration adjustments and additional adjustments within the allowable 
limits in section 2.1.3 of this appendix may be made prior to the RATA, 
as necessary, to

[[Page 403]]

optimize the performance of the CEMS. The trial RATA runs need not be 
reported, provided that they meet the specification for trial RATA runs 
in Sec. 75.20(b)(3)(vii)(E)(2). However, if, for any trial run, the 
specification in Sec. 75.20(b)(3)(vii)(E)(2) is not met, the trial run 
shall be counted as an aborted RATA attempt.
    (3) The RATA may be done after repair, corrective maintenance, re-
linearization or reprogramming of the monitoring system. In this case, 
the monitoring system shall be considered out-of-control from the hour 
in which the repair, corrective maintenance, re-linearization or 
reprogramming is commenced until the RATA has been passed. 
Alternatively, the data validation procedures and associated timelines 
in Sec. Sec. 75.20(b)(3)(ii) through (ix) may be followed upon 
completion of the necessary repair, corrective maintenance, re-
linearization or reprogramming. If the procedures in Sec. 75.20(b)(3) 
are used, the words ``quality assurance'' apply instead of the word 
``recertification.''
    (c) Once a RATA is commenced, the test must be done hands-off. No 
adjustment of the monitor's calibration is permitted during the RATA 
test period, other than the routine calibration adjustments following 
daily calibration error tests, as described in section 2.1.3 of this 
appendix. If a routine daily calibration error test is performed and 
passed just prior to a RATA (or during a RATA test period) and a 
mathematical correction factor is automatically applied by the DAHS, the 
correction factor shall be applied to all subsequent data recorded by 
the monitor, including the RATA test data. For 2-level and 3-level flow 
monitor audits, no linearization or reprogramming of the monitor is 
permitted in between load levels.
    (d) For single-load (or single-level) RATAs, if a daily calibration 
error test is failed during a RATA test period, prior to completing the 
test, the RATA must be repeated. Data from the monitor are invalidated 
prospectively from the hour of the failed calibration error test until 
the hour of completion of a subsequent successful calibration error 
test. The subsequent RATA shall not be commenced until the monitor has 
successfully passed a calibration error test in accordance with section 
2.1.3 of this appendix. For multiple-load (or multiple-level) flow 
RATAs, each load level (or operating level) is treated as a separate 
RATA (i.e., when a calibration error test is failed prior to completing 
the RATA at a particular load level (or operating level), only the RATA 
at that load level (or operating level) must be repeated; the results of 
any previously-passed RATA(s) at the other load level(s) (or operating 
level(s)) are unaffected, unless the monitor's polynomial coefficients 
or K-factor(s) must be changed to correct the problem that caused the 
calibration failure, in which case a subsequent 3-load (or 3-level) RATA 
is required), except as otherwise provided in section 2.3.1.3 (c)(5) of 
this appendix.
    (e) For a RATA performed using the option in paragraph (b)(1) or 
(b)(2) of this section, if the RATA is failed (that is, if the relative 
accuracy exceeds the applicable specification in section 3.3 of appendix 
A to this part) or if the RATA is aborted prior to completion due to a 
problem with the CEMS, then the CEMS is out-of-control and all emission 
data from the CEMS are invalidated prospectively from the hour in which 
the RATA is failed or aborted. Data from the CEMS remain invalid until 
the hour of completion of a subsequent RATA that meets the applicable 
specification in section 3.3 of appendix A to this part. If the option 
in paragraph (b)(3) of this section to use the data validation 
procedures and associated timelines in Sec. Sec. 75.20(b)(3)(ii) 
through(b)(3)(ix) has been selected, the beginning and end of the out-
of-control period shall be determined in accordance with Sec. 
75.20(b)(3)(vii)(A) and (B). Note that when a RATA is aborted for a 
reason other than monitoring system malfunction (see paragraph (h) of 
this section), this does not trigger an out-of-control period for the 
monitoring system.
    (f) For a 2-level or 3-level flow RATA, if, at any load level (or 
operating level), a RATA is failed or aborted due to a problem with the 
flow monitor, the RATA at that load level (or operating level) must be 
repeated. The flow monitor is considered out-of-control and data from 
the monitor are invalidated from the hour in which the test is failed or 
aborted and remain invalid until the passing of a RATA at the failed 
load level (or operating level), unless the option in paragraph (b)(3) 
of this section to use the data validation procedures and associated 
timelines in Sec. 75.20(b)(3)(ii) through (b)(3)(ix) has been selected, 
in which case the beginning and end of the out-of-control period shall 
be determined in accordance with Sec. 75.20(b)(3)(vii)(A) and (B). Flow 
RATA(s) that were previously passed at the other load level(s) (or 
operating level(s)) do not have to be repeated unless the flow monitor 
must be re-linearized following the failed or aborted test. If the flow 
monitor is re-linearized, a subsequent 3-load (or 3-level) RATA is 
required, except as otherwise provided in section 2.3.1.3(c)(5) of this 
appendix.
    (g) Data validation for failed RATAs for a CO2 pollutant 
concentration monitor (or an O2 monitor used to measure 
CO2 emissions), a NOX pollutant concentration 
monitor, and a NOX-diluent monitoring system shall be done 
according to paragraphs (g)(1) and (g)(2) of this section:
    (1) For a CO2 pollutant concentration monitor (or an 
O2 monitor used to measure CO2 emissions) which 
also serves as the diluent component in a NOX-diluent 
monitoring system, if the CO2 (or O2) RATA is 
failed, then

[[Page 404]]

both the CO2 (or O2) monitor and the associated 
NOX-diluent system are considered out-of-control, beginning 
with the hour of completion of the failed CO2 (or 
O2) monitor RATA, and continuing until the hour of completion 
of subsequent hands-off RATAs which demonstrate that both systems have 
met the applicable relative accuracy specifications in sections 3.3.2 
and 3.3.3 of appendix A to this part, unless the option in paragraph 
(b)(3) of this section to use the data validation procedures and 
associated timelines in Sec. 75.20(b)(3)(ii) through (b)(3)(ix) has 
been selected, in which case the beginning and end of the out-of-control 
period shall be determined in accordance with Sec. 75.20(b)(3)(vii)(A) 
and (B).
    (2) This paragraph (g)(2) applies only to a NOX pollutant 
concentration monitor that serves both as the NOX component 
of a NOX concentration monitoring system (to measure 
NOX mass emissions) and as the NOX component in a 
NOX-diluent monitoring system (to measure NOX 
emission rate in lb/mmBtu). If the RATA of the NOX 
concentration monitoring system is failed, then both the NOX 
concentration monitoring system and the associated NOX-
diluent monitoring system are considered out-of-control, beginning with 
the hour of completion of the failed NOX concentration RATA, 
and continuing until the hour of completion of subsequent hands-off 
RATAs which demonstrate that both systems have met the applicable 
relative accuracy specifications in sections 3.3.2 and 3.3.7 of appendix 
A to this part, unless the option in paragraph (b)(3) of this section to 
use the data validation procedures and associated timelines in Sec. 
75.20(b)(3)(ii) through (b)(3)(ix) has been selected, in which case the 
beginning and end of the out-of-control period shall be determined in 
accordance with Sec. 75.20(b)(3)(vii)(A) and (B).
    (h) For each monitoring system, report the results of all completed 
and partial RATAs that affect data validation (i.e., all completed, 
passed RATAs; all completed, failed RATAs; and all RATAs aborted due to 
a problem with the CEMS, including trial RATA runs counted as failed 
test attempts under paragraph (b)(2) of this section or under Sec. 
75.20(b)(3)(vii)(F)) in the quarterly report required under Sec. 75.64. 
Note that RATA attempts that are aborted or invalidated due to problems 
with the reference method or due to operational problems with the 
affected unit(s) need not be reported. Such runs do not affect the 
validation status of emission data recorded by the CEMS. However, a 
record of all RATAs, trial RATA runs and RATA attempts (whether reported 
or not) must be kept on-site as part of the official test log for each 
monitoring system.
    (i) Each time that a hands-off RATA of an SO2 pollutant 
concentration monitor, a NOx-diluent monitoring system, a 
NOX concentration monitoring system, or a flow monitor is 
passed, perform a bias test in accordance with section 7.6.4 of appendix 
A to this part. Apply the appropriate bias adjustment factor to the 
reported SO2, NOX, or flow rate data, in 
accordance with section 7.6.5 of appendix A to this part.
    (j) Failure of the bias test does not result in the monitoring 
system being out-of-control.
    (k) The results of any certification, recertification, diagnostic, 
or quality assurance test required under this part may not be used to 
validate the emissions data required under this part, if the test is 
performed using EPA Protocol gas from a production site that is not 
participating in the PGVP, except as provided in Sec. 75.21(g)(7) or if 
the cylinder(s) are analyzed by an independent laboratory and shown to 
meet the requirements of section 5.1.4(b) of appendix A to this part.

                         2.3.3 RATA Grace Period

    (a) The owner or operator has a grace period of 720 consecutive unit 
operating hours, as defined in Sec. 72.2 of this chapter (or, for CEMS 
installed on common stacks or bypass stacks, 720 consecutive stack 
operating hours, as defined in Sec. 72.2 of this chapter), in which to 
complete the required RATA for a particular CEMS whenever:
    (1) A required RATA has not been performed by the end of the QA 
operating quarter in which it is due; or
    (2) A required 3-load flow RATA has not been performed by the end of 
the calendar quarter in which it is due; or
    (3) For a unit which is conditionally exempted under Sec. 
75.21(a)(7) from the SO2 RATA requirements of this part, an 
SO2 RATA has not been completed by the end of the calendar 
quarter in which the annual usage of fuel(s) with a sulfur content 
higher than very low sulfur fuel (as defined in Sec. 72.2 of this 
chapter) exceeds 480 hours; or
    (4) Eight successive calendar quarters have elapsed, following the 
quarter in which a RATA was last performed, without a subsequent RATA 
having been done, due either to infrequent operation of the unit(s) or 
frequent combustion of very low sulfur fuel, as defined in Sec. 72.2 of 
this chapter (SO2 monitors, only), or a combination of these 
factors.
    (b) Except for SO2 monitoring system RATAs, the grace 
period shall begin with the first unit (or stack) operating hour 
following the calendar quarter in which the required RATA was due. For 
SO2 monitor RATAs, the grace period shall begin with the 
first unit (or stack) operating hour in which fuel with a total sulfur 
content higher than that of very low sulfur fuel (as defined in Sec. 
72.2 of this chapter) is burned in the unit(s), following the quarter in 
which the required RATA is due. Data validation during a RATA grace 
period shall be done in accordance with

[[Page 405]]

the applicable provisions in section 2.3.2 of this appendix.
    (c) If, at the end of the 720 unit (or stack) operating hour grace 
period, the RATA has not been completed, data from the monitoring system 
shall be invalid, beginning with the first unit operating hour following 
the expiration of the grace period. Data from the CEMS remain invalid 
until the hour of completion of a subsequent hands-off RATA. The 
deadline for the next test shall be either two QA operating quarters (if 
a semiannual RATA frequency is obtained) or four QA operating quarters 
(if an annual RATA frequency is obtained) after the quarter in which the 
RATA is completed, not to exceed eight calendar quarters.
    (d) When a RATA is done during a grace period in order to satisfy a 
RATA requirement from a previous quarter, the deadline for the next RATA 
shall determined as follows:
    (1) If the grace period RATA qualifies for a reduced, (i.e., 
annual), RATA frequency the deadline for the next RATA shall be set at 
three QA operating quarters after the quarter in which the grace period 
test is completed.
    (2) If the grace period RATA qualifies for the standard, (i.e., 
semiannual), RATA frequency the deadline for the next RATA shall be set 
at two QA operating quarters after the quarter in which the grace period 
test is completed.
    (3) Notwithstanding these requirements, no more than eight 
successive calendar quarters shall elapse after the quarter in which the 
grace period test is completed, without a subsequent RATA having been 
conducted.

                      2.3.4 Bias Adjustment Factor

    Except as otherwise specified in section 7.6.5 of appendix A to this 
part, if an SO2 pollutant concentration monitor, a flow 
monitor, a NOX-diluent CEMS, or a NOX 
concentration monitoring system used to calculate NOX mass 
emissions fails the bias test specified in section 7.6 of appendix A to 
this part, use the bias adjustment factor given in Equations A-11 and A-
12 of appendix A to this part or the allowable alternative BAF specified 
in section 7.6.5(b) of appendix A of this part, to adjust the monitored 
data.

    2.4 Recertification, Quality Assurance, RATA Frequency and Bias 
               Adjustment Factors (Special Considerations)

    (a) When a significant change is made to a monitoring system such 
that recertification of the monitoring system is required in accordance 
with Sec. 75.20(b), a recertification test (or tests) must be performed 
to ensure that the CEMS continues to generate valid data. In all 
recertifications, a RATA will be one of the required tests; for some 
recertifications, other tests will also be required. A recertification 
test may be used to satisfy the quality assurance test requirement of 
this appendix. For example, if, for a particular change made to a CEMS, 
one of the required recertification tests is a linearity check and the 
linearity check is successful, then, unless another such recertification 
event occurs in that same QA operating quarter, it would not be 
necessary to perform an additional linearity test of the CEMS in that 
quarter to meet the quality assurance requirement of section 2.2.1 of 
this appendix. For this reason, EPA recommends that owners or operators 
coordinate component replacements, system upgrades, and other events 
that may require recertification, to the extent practicable, with the 
periodic quality assurance testing required by this appendix. When a 
quality assurance test is done for the dual purpose of recertification 
and routine quality assurance, the applicable data validation procedures 
in Sec. 75.20(b)(3) shall be followed.
    (b) Except as provided in section 2.3.3 of this appendix, whenever a 
passing RATA of a gas monitor is performed, or a passing 2-load (or 2-
level) RATA or a passing 3-load (or 3-level) RATA of a flow monitor is 
performed (irrespective of whether the RATA is done to satisfy a 
recertification requirement or to meet the quality assurance 
requirements of this appendix, or both), the RATA frequency (semi-annual 
or annual) shall be established based upon the date and time of 
completion of the RATA and the relative accuracy percentage obtained. 
For 2-load (or 2-level) and 3-load (or 3-level) flow RATAs, use the 
highest percentage relative accuracy at any of the loads (or levels) to 
determine the RATA frequency. The results of a single-load (or single-
level) flow RATA may be used to establish the RATA frequency when the 
single-load (or single-level) flow RATA is specifically required under 
section 2.3.1.3(b) of this appendix or when the single-load (or single-
level) RATA is allowed under section 2.3.1.3(c) of this appendix for a 
unit that has operated at one load level (or operating level) for 
=85.0 percent of the time since the last annual flow RATA. No 
other single-load (or single-level) flow RATA may be used to establish 
an annual RATA frequency; however, a 2-load or 3-load (or a 2-level or 
3-level) flow RATA may be performed at any time or in place of any 
required single-load (or single-level) RATA, in order to establish an 
annual RATA frequency.

                            2.5 Other Audits

    Affected units may be subject to relative accuracy test audits at 
any time. If a monitor or continuous emission monitoring system fails 
the relative accuracy test during the audit, the monitor or continuous 
emission monitoring system shall be considered to be out-of-control 
beginning with the date

[[Page 406]]

and time of completion of the audit, and continuing until a successful 
audit test is completed following corrective action. If a monitor or 
monitoring system fails the bias test during an audit, use the bias 
adjustment factor given by equations A-11 and A-12 in appendix A to this 
part to adjust the monitored data. Apply this adjustment factor from the 
date and time of completion of the audit until the date and time of 
completion of a relative accuracy test audit that does not show bias.

 Figure 1 to Appendix B of Part 75--Quality Assurance Test Requirements
------------------------------------------------------------------------
                                  Basic QA test frequency requirements
                               -----------------------------------------
             Test                                            Semiannual
                                   Daily *     Quarterly *   or annual *
------------------------------------------------------------------------
Calibration Error Test (2 pt.)            X   ............
Interference Check (flow).....            X   ............
Flow-to-Load Ratio............  ............            X
Leak Check (DP flow monitors).  ............            X
Linearity Check * (3 pt.).....  ............            X
RATA (SO2, NOX, CO2, O2,        ............  ............            X
 H2O)\1\......................
RATA (flow) \1\ \2\...........  ............  ............            X
------------------------------------------------------------------------
* ``Daily'' means operating days, only. ``Quarterly'' means once every
  QA operating quarter. ``Semiannual'' means once every two QA operating
  quarters. ``Annual'' means once every four QA operating quarters.
\1\ Conduct RATA annually (i.e., once every four QA operating quarters)
  rather than semiannually, if monitor meets accuracy requirements to
  qualify for less frequent testing.
\2\ For flow monitors installed on peaking units, bypass stacks, or
  units that qualify for single-level RATA testing under section
  6.5.2(e) of this part, conduct all RATAs at a single, normal load (or
  operating level). For other flow monitors, conduct annual RATAs at two
  load levels (or operating levels). Alternating single-load and 2-load
  (or single-level and 2-level) RATAs may be done if a monitor is on a
  semiannual frequency. A single-load (or single-level) RATA may be done
  in lieu of a 2-load (or 2-level) RATA if, since the last annual flow
  RATA, the unit has operated at one load level (or operating level) for
  =85.0 percent of the time. A 3-level RATA is required at
  least once every five years (20 calendar quarters) and whenever a flow
  monitor is re-characterized, except for flow monitors exempted from 3-
  level RATA testing under section 6.5.2(b) or 6.5.2(e) of appendix A to
  this part.


   Figure 2 to Appendix B of Part 75--Relative Accuracy Test Frequency
                            Incentive System
------------------------------------------------------------------------
            RATA                 Semiannual \W\          Annual \W\
------------------------------------------------------------------------
SO2 or NOX\Y\...............  7.5% 
     Sec. Appendix C to Part 75--Missing Data Estimation Procedures

     1. Parametric Monitoring Procedure for Missing SO2 
           Concentration or NOX Emission Rate Data

                            1.1 Applicability

    The owner or operator of any affected unit equipped with post-
combustion SO2 or NOX emission controls and 
SO2 pollutant concentration monitors and/or NOX 
continuous emission monitoring systems at the inlet and outlet of the 
emission control system may apply to the Administrator for approval and 
certification of a parametric, empirical, or process simulation method 
or model for calculating substitute data for missing data periods. Such 
methods may be used to parametrically estimate the removal efficiency of 
the SO2 of postcombustion NOX emission controls 
which, with the monitored inlet concentration or emission rate data, may 
be used to estimate the average concentration of SO2 
emissions or average emission rate of NOX discharged to the 
atmosphere. After approval by the Administrator, such method or model 
may be used for filling in missing SO2 concentration or 
NOX emission rate data when data from the outlet 
SO2 pollutant concentration monitor or outlet NOX 
continuous emission monitoring system have been reported with an annual 
monitor data availability of 90.0 percent or more.
    Base the empirical and process simulation methods or models on the 
fundamental chemistry and engineering principles involved in the 
treatment of pollutant gas. On a case-by-case basis, the Administrator 
may pre-certify commercially available process simulation methods and 
models.

                        1.2 Petition Requirements

    Continuously monitor, determine, and record hourly averages of the 
estimated SO2 or NOX removal efficiency and of the 
parameters specified below, at a minimum. The affected facility shall 
supply additional parametric information where appropriate. Measure the 
SO2 concentration or NOX emission rate, removal 
efficiency of the add-on emission controls, and the parameters for at 
least 2160 unit operating hours. Provide information for all expected 
operating conditions and removal efficiencies. At least 4 evenly spaced 
data points are required for a valid hourly average, except during 
periods of calibration, maintenance, or quality assurance activities, 
during which 2 data points per hour are sufficient. The Administrator 
will review all applications on a case-by-case basis.
    1.2.1 Parameters for Wet Flue Gas Desulfurization System
    1.2.1.1 Number of scrubber modules in operation.
    1.2.1.2 Total slurry rate to each scrubber module (gal per min).
    1.2.1.3 In-line absorber pH of each scrubber module.
    1.2.1.4 Pressure differential across each scrubber module (inches of 
water column).
    1.2.1.5 Unit load (MWe).
    1.2.1.6 Inlet and outlet SO2 concentration as determined 
by the monitor or missing data substitution procedures.
    1.2.1.7 Percent solids in slurry for each scrubber module.
    1.2.1.8 Any other parameters necessary to verify scrubber removal 
efficiency, if the Administrator determines the parameters above are not 
sufficient.
    1.2.2 Parameters for Dry Flue Gas Desulfurization System
    1.2.2.1 Number of scrubber modules in operation.
    1.2.2.2 Atomizer slurry flow rate to each scrubber module (gal per 
min).
    1.2.2.3 Inlet and outlet temperature for each scrubber module (F).
    1.2.2.4 Pressure differential across each scrubber module (inches of 
water column).
    1.2.2.5 Unit load (MWe).
    1.2.2.6 Inlet and outlet SO2 concentration as determined 
by the monitor or missing data substitution procedures.
    1.2.2.7 Any other parameters necessary to verify scrubber removal 
efficiency, if the Administrator determines the parameters above are not 
sufficient.

       1.2.3 Parameters for Other Flue Gas Desulfurization Systems

    If SO2 control technologies other than wet or dry lime or 
limestone scrubbing are selected for flue gas desulfurization, a 
corresponding empirical correlation or process simulation parametric 
method using appropriate parameters may be developed by the owner or 
operator of the affected unit, and then reviewed and approved or 
modified by the Administrator on a case-by-case basis.

  1.2.4 Parameters for Post-Combustion NOX Emission Controls

    1.2.4.1 Inlet air flow rate to the unit (boiler) (mcf/hr).
    1.2.4.2 Excess oxygen concentration of flue gas at stack outlet 
(percent).
    1.2.4.3 Carbon monoxide concentration of flue gas at stack outlet 
(ppm).
    1.2.4.4 Temperature of flue gas at outlet of the unit (F).
    1.2.4.5 Inlet and outlet NOX emission rate as determined 
by the NOX continuous emission monitoring system or missing 
data substitution procedures.
    1.2.4.6 Any other parameters specific to the emission reduction 
process necessary to verify the NOX control removal 
efficiency, (e.g., reagent feedrate in gal/mi).

[[Page 409]]

              1.3 Correlation of Emissions With Parameters

    Establish a method for correlating hourly averages of the parameters 
identified above with the percent removal efficiency of the 
SO2 or post-combustion NOX emission controls under 
varying unit operating loads. Equations 1-7 in Sec. 75.15 may be used 
to estimate the percent removal efficiency of the SO2 
emission controls on an hourly basis.
    Each parametric data substitution procedure should develop a data 
correlation procedure to verify the performance of the SO2 
emission controls or post-combustion NOX emission controls, 
along with the SO2 pollutant concentration monitor and 
NOX continuous emission monitoring system values for varying 
unit load ranges.
    For NOX emission rate data, and wherever the performance 
of the emission controls varies with the load, use the load range 
procedure provided in section 2.2 of this appendix.

                            1.4 Calculations

    1.4.1 Use the following equation to calculate substitute data for 
filling in missing (outlet) SO2 pollutant concentration 
monitor data.

Mo = Ic (1-E)
(Eq. C-1)

where,

Mo = Substitute data for outlet SO2 concentration, 
          ppm.
Ic = Recorded inlet SO2 concentration, ppm.
E = Removal efficiency of SO2 emission controls as determined 
          by the correlation procedure described in section 1.3 of this 
          appendix.

    1.4.2 Use the following equation to calculate substitute data for 
filling in missing (outlet) NOX emission rate data.

Mo = Ic (1-E)
(Eq. C-2)

where,
Mo = Substitute data for outlet NOX emission rate, 
          lb/mmBtu.
Ic = Recorded inlet NOX emission rate, lb/mmBtu.
E = Removal efficiency of post-combustion NOX emission 
          controls determined by the correlation procedure described in 
          section 1.3 of this appendix.

                            1.5 Missing Data

    1.5.1 If both the inlet and the outlet SO2 pollutant 
concentration monitors are unavailable simultaneously, use the maximum 
inlet SO2 concentration recorded by the inlet SO2 
pollutant concentration monitor during the previous 720 quality-assured 
monitor operating hours to substitute for the inlet SO2 
concentration in equation C-1 of this appendix.
    1.5.2 If both the inlet and outlet NOX continuous 
emission monitoring systems are unavailable simultaneously, use the 
maximum inlet NOX emission rate for the corresponding unit 
load recorded by the NOX continuous emission monitoring 
system at the inlet during the previous 2160 quality-assured monitor 
operating hours to substitute for the inlet NOX emission rate 
in equation C-2 of this appendix.

                             1.6 Application

    Apply to the Administrator for approval and certification of the 
parametric substitution procedure for filling in missing SO2 
concentration or NOX emission rate data using the established 
criteria and information identified above. DO not use this procedure 
until approved by the Administrator.

     2. Load-based Procedure for Missing Flow Rate, NOX 
          Concentration, and NOX Emission Rate Data

                            2.1 Applicability

    This procedure is applicable for data from all affected units for 
use in accordance with the provisions of this part to provide substitute 
data for volumetric flow rate (scfh), NOX emission rate (in 
lb/mmBtu) from NOX-diluent continuous emission monitoring 
systems, and NOX concentration data (in ppm) from NOx 
concentration monitoring systems used to determine NOX mass 
emissions.

                              2.2 Procedure

    2.2.1 For a single unit, establish ten operating load ranges defined 
in terms of percent of the maximum hourly average gross load of the 
unit, in gross megawatts (MWge), as shown in Table C-1. (Do not use 
integrated hourly gross load in MW-hr.) For units sharing a common stack 
monitored with a single flow monitor, the load ranges for flow (but not 
for NOX) may be broken down into 20 operating load ranges in 
increments of 5.0 percent of the combined maximum hourly average gross 
load of all units utilizing the common stack. If this option is 
selected, the twentieth (uppermost) operating load range shall include 
all values greater than 95.0 percent of the maximum hourly average gross 
load. For a cogenerating unit or other unit at which some portion of the 
heat input is not used to produce electricity or for a unit for which 
hourly average gross load in MWge is not recorded separately, use the 
hourly gross steam load of the unit, in pounds of steam per hour at the 
measured temperature (F) and pressure (psia) instead of MWge. Indicate 
a change in the number of load ranges or the units of loads to be used 
in the precertification section of the monitoring plan.

[[Page 410]]



      Table C-1--Definition of Operating Load Ranges for Load-based
                      Substitution Data Procedures
------------------------------------------------------------------------
                                                             Percent of
                                                               maximum
                                                            hourly gross
                                                               load or
                   Operating load range                        maximum
                                                            hourly gross
                                                             steam load
                                                              (percent)
------------------------------------------------------------------------
1.........................................................       0-10
2.........................................................  1
                                                                 0-20
3.........................................................  2
                                                                 0-30
4.........................................................  3
                                                                 0-40
5.........................................................  4
                                                                 0-50
6.........................................................  5
                                                                 0-60
7.........................................................  6
                                                                 0-70
8.........................................................  7
                                                                 0-80
9.........................................................  8
                                                                 0-90
10........................................................  9
                                                                    0
------------------------------------------------------------------------

    2.2.2 Beginning with the first hour of unit operation after 
installation and certification of the flow monitor or the 
NOX-diluent continuous emission monitoring system (or a 
NOX concentration monitoring system used to determine 
NOX mass emissions, as defined in Sec. 75.71(a)(2)), for 
each hour of unit operation record a number, 1 through 10, (or 1 through 
20 for flow at common stacks) that identifies the operating load range 
corresponding to the integrated hourly gross load of the unit(s) 
recorded for each unit operating hour.
    2.2.3 Beginning with the first hour of unit operation after 
installation and certification of the flow monitor or the 
NOX-diluent continuous emission monitoring system (or a 
NOX concentration monitoring system used to determine 
NOX mass emissions, as defined in Sec. 75.71(a)(2)) and 
continuing thereafter, the data acquisition and handling system must be 
capable of calculating and recording the following information for each 
unit operating hour of missing flow or NOX data within each 
identified load range during the shorter of: (a) the previous 2,160 
quality-assured monitor operating hours (on a rolling basis), or (b) all 
previous quality-assured monitor operating hours.
    2.2.3.1 Average of the hourly flow rates reported by a flow monitor, 
in scfh.
    2.2.3.2 The 90th percentile value of hourly flow rates, in scfh.
    2.2.3.3 The 95th percentile value of hourly flow rates, in scfh.
    2.2.3.4 The maximum value of hourly flow rates, in scfh.
    2.2.3.5 Average of the hourly NOX emission rate, in lb/
mmBtu, reported by a NOX continuous emission monitoring 
system.
    2.2.3.6 The 90th percentile value of hourly NOX emission 
rates, in lb/mmBtu.
    2.2.3.7 The 95th percentile value of hourly NOX emission 
rates, in lb/mmBtu.
    2.2.3.8 The maximum value of hourly NOX emission rates, 
in lb/mmBtu.
    2.2.3.9 Average of the hourly NOX pollutant 
concentrations, in ppm, reported by a NOX concentration 
monitoring system used to determine NOX mass emissions, as 
defined in Sec. 75.71(a)(2).
    2.2.3.10 The 90th percentile value of hourly NOX 
pollutant concentration, in ppm.
    2.2.3.11 The 95th percentile value of hourly NOX 
pollutant concentration, in ppm.
    2.2.3.12 The maximum value of hourly NOX pollutant 
concentration, in ppm.
    2.2.4 Calculate all monitor or continuous emission monitoring system 
data averages, maximum values, and percentile values determined by this 
procedure using bias adjusted values in the load ranges.
    2.2.5 When a bias adjustment is necessary for the flow monitor and/
or the NOX-diluent continuous emission monitoring system 
(and/or the NOX concentration monitoring system used to 
determine NOX mass emissions, as defined in Sec. 
75.71(a)(2)), apply the adjustment factor to all monitor or continuous 
emission monitoring system data values placed in the load ranges.
    2.2.6 Use the calculated monitor or monitoring system data averages, 
maximum values, and percentile values to substitute for missing flow 
rate and NOX emission rate data (and where applicable, 
NOX concentration data) according to the procedures in 
subpart D of this part.

 3. Non-load-based Procedure for Missing Flow Rate, NOX Concentration, 
                  and NOX Emission Rate Data (Optional)

                            3.1 Applicability

    For affected units that do not produce electrical output in 
megawatts or thermal output in klb/hr of steam, this procedure may be 
used in accordance with the provisions of this part to provide 
substitute data for volumetric flow rate (scfh), NOX emission 
rate (in lb/mmBtu) from NOX-diluent continuous emission 
monitoring systems, and NOX concentration data (in ppm) from 
NOX concentration monitoring systems used to determine 
NOX mass emissions.

                              3.2 Procedure

    3.2.1 For each monitored parameter (flow rate, NOX 
emission rate, or NOX concentration), establish at least two, 
but no more than ten operational bins, corresponding to various 
operating conditions and parameters (or combinations of these) that 
affect volumetric flow rate or NOX emissions. Include a 
complete description of each operational bin in the hardcopy portion of 
the monitoring plan required under Sec. 75.53(e)(2), identifying the 
unique combination of parameters and operating conditions associated 
with the bin and explaining the relationship between these parameters 
and conditions and the magnitude of the stack gas flow rate or 
NOX emissions. Assign a unique number, 1

[[Page 411]]

through 10, to each operational bin. Examples of conditions and 
parameters that may be used to define operational bins include unit heat 
input, type of fuel combusted, specific stages of an industrial process, 
or (for common stacks), the particular combination of units that are in 
operation.
    3.2.2 In the electronic quarterly report required under Sec. 75.64, 
indicate for each hour of unit operation the operational bin associated 
with the NOX or flow rate data, by recording the number 
assigned to the bin under section 3.2.1 of this appendix.
    3.2.3 The data acquisition and handling system must be capable of 
properly identifying and recording the operational bin number for each 
unit operating hour. The DAHS must also be capable of calculating and 
recording the following information (as applicable) for each unit 
operating hour of missing flow or NOX data within each 
identified operational bin during the shorter of:
    (a) The previous 2,160 quality-assured monitor operating hours (on a 
rolling basis), or
    (b) All previous quality-assured monitor operating hours in the 
previous 3 years:
    3.2.3.1 Average of the hourly flow rates reported by a flow monitor 
(scfh).
    3.2.3.2 The 90th percentile value of hourly flow rates (scfh).
    3.2.3.3 The 95th percentile value of hourly flow rates (scfh).
    3.2.3.4 The maximum value of hourly flow rates (scfh).
    3.2.3.5 Average of the hourly NOX emission rates, in lb/
mmBtu, reported by a NOX-diluent continuous emission 
monitoring system.
    3.2.3.6 The 90th percentile value of hourly NOX emission 
rates (lb/mmBtu).
    3.2.3.7 The 95th percentile value of hourly NOX emission 
rates (lb/mmBtu).
    3.2.3.8 The maximum value of hourly NOX emission rates, 
in (lb/mmBtu).
    3.2.3.9 Average of the hourly NOX pollutant 
concentrations (ppm), reported by a NOX concentration 
monitoring system used to determine NOX mass emissions, as 
defined in Sec. 75.71(a)(2).
    3.2.3.10 The 90th percentile value of hourly NOX 
pollutant concentration (ppm).
    3.2.3.11 The 95th percentile value of hourly NOX 
pollutant concentration (ppm).
    3.2.3.12 The maximum value of hourly NOX pollutant 
concentration (ppm).
    3.2.4 When a bias adjustment is necessary for the flow monitor and/
or the NOX-diluent continuous emission monitoring system 
(and/or the NOX concentration monitoring system), apply the 
bias adjustment factor to all data values placed in the operational 
bins.
    3.2.5 Calculate all CEMS data averages, maximum values, and 
percentile values determined by this procedure using bias-adjusted 
values.
    3.2.6 Use the calculated monitor or monitoring system data averages, 
maximum values, and percentile values to substitute for missing flow 
rate and NOX emission rate data (and where applicable, 
NOX concentration data) according to the procedures in 
subpart D of this part.

[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26547, 26548, May 17, 
1995; 63 FR 57313, Oct. 27, 1998; 64 FR 28652, May 26, 1999; 67 FR 
40459, June 12, 2002]



   Sec. Appendix D to Part 75--Optional SO2 Emissions Data 
               Protocol for Gas-Fired and Oil-Fired Units

                            1. Applicability

    1.1 This protocol may be used in lieu of continuous SO2 
pollutant concentration and flow monitors for the purpose of determining 
hourly SO2 mass emissions and heat input from: gas-fired 
units, as defined in Sec. 72.2 of this chapter, or oil-fired units, as 
defined in Sec. 72.2 of this chapter. Section 2.1 of this appendix 
provides procedures for measuring oil or gaseous fuel flow using a fuel 
flowmeter, section 2.2 of this appendix provides procedures for 
conducting oil sampling and analysis to determine sulfur content and 
gross calorific value (GCV) of fuel oil, and section 2.3 of this 
appendix provides procedures for determining the sulfur content and GCV 
of gaseous fuels.
    1.2 Pursuant to the procedures in Sec. 75.20, complete all testing 
requirements to certify use of this protocol in lieu of a flow monitor 
and an SO2 continuous emission monitoring system. Complete 
all testing requirements no later than the applicable deadline specified 
in Sec. 75.4. Apply to the Administrator for initial certification to 
use this protocol no later than 45 days after the completion of all 
certification tests.

                              2. Procedure

                     2.1 Fuel Flowmeter Measurements

    For each hour when the unit is combusting fuel, measure and record 
the flow rate of fuel combusted by the unit, except as provided in 
section 2.1.4 of this appendix. Measure the flow rate of fuel with an 
in-line fuel flowmeter, and automatically record the data with a data 
acquisition and handling system, except as provided in section 2.1.4 of 
this appendix.
    2.1.1 Measure the flow rate of each fuel entering and being 
combusted by the unit. If, on an annual basis, more than 5.0 percent of 
the fuel from the main pipe is diverted from the unit without being 
burned and that diversion occurs downstream of the fuel flowmeter, an 
additional in-line fuel flowmeter is required to account for the 
unburned fuel. In this case, record the flow rate of each fuel

[[Page 412]]

combusted by the unit as the difference between the flow measured in the 
pipe leading to the unit and the flow in the pipe diverting fuel away 
from the unit. However, the additional fuel flowmeter is not required 
if, on an annual basis, the total amount of fuel diverted away from the 
unit, expressed as a percentage of the total annual fuel usage by the 
unit is demonstrated to be less than or equal to 5.0 percent. The owner 
or operator may make this demonstration in the following manner:
    2.1.1.1 For existing units with fuel usage data from fuel 
flowmeters, if data are submitted from a previous year demonstrating 
that the total diverted yearly fuel does not exceed 5% of the total fuel 
used; or
    2.1.1.2 For new units which do not have historical data, if a letter 
is submitted signed by the designated representative certifying that, in 
the future, the diverted fuel will not exceed 5.0% of the total annual 
fuel usage; or
    2.1.1.3 By using a method approved by the Administrator under Sec. 
75.66(d).
    2.1.2 Install and use fuel flowmeters meeting the requirements of 
this appendix in a pipe going to each unit, or install and use a fuel 
flowmeter in a common pipe header (as defined in Sec. 72.2). However, 
the use of a fuel flowmeter in a common pipe header and the provisions 
of sections 2.1.2.1 and 2.1.2.2 of this appendix shall not apply to any 
unit that is using the provisions of subpart H of this part to monitor, 
record, and report NOX mass emissions under a State or 
federal NOX mass emission reduction program, unless both of 
the following are true: all of the units served by the common pipe are 
affected units, and all of the units have similar efficiencies. When a 
fuel flowmeter is installed in a common pipe header, proceed as follows:
    2.1.2.1 Measure the fuel flow rate in the common pipe, and combine 
SO2 mass emissions (Acid Rain Program units only) for the 
affected units for recordkeeping and compliance purposes; and
    2.1.2.2 Apportion the heat input rate measured at the common pipe to 
the individual units, using Equation F-21a, F-21b, or F-21d in appendix 
F to this part.
    2.1.3 For a gas-fired unit or an oil-fired unit that continuously or 
frequently combusts a supplemental fuel for flame stabilization or 
safety purposes, measure the flow rate of the supplemental fuel with a 
fuel flowmeter meeting the requirements of this appendix.

      2.1.4 Situations in Which Certified Flowmeter is Not Required

                    2.1.4.1 Start-up or Ignition Fuel

    For an oil-fired unit that uses gas solely for start-up or burner 
ignition, a gas-fired unit that uses oil solely for start-up or burner 
ignition, or an oil-fired unit that uses a different grade of oil solely 
for start-up or burner ignition, a fuel flowmeter for the start-up fuel 
is permitted but not required. Estimate the volume of oil combusted for 
each start-up or ignition either by using a fuel flowmeter or by using 
the dimensions of the storage container and measuring the depth of the 
fuel in the storage container before and after each start-up or 
ignition. A fuel flowmeter used solely for start-up or ignition fuel is 
not subject to the calibration requirements of sections 2.1.5 and 2.1.6 
of this appendix. Gas combusted solely for start-up or burner ignition 
does not need to be measured separately.

        2.1.4.2 Gas or Oil Flowmeter Used for Commercial Billing

    A gas or oil flowmeter used for commercial billing of natural gas or 
oil may be used to measure, record, and report hourly fuel flow rate. A 
gas or oil flowmeter used for commercial billing of natural gas or oil 
is not required to meet the certification requirements of section 2.1.5 
of this appendix or the quality assurance requirements of section 2.1.6 
of this appendix under the following circumstances:
    (a) The gas or oil flowmeter is used for commercial billing under a 
contract, provided that the company providing the gas or oil under the 
contract and each unit combusting the gas or oil do not have any common 
owners and are not owned by subsidiaries or affiliates of the same 
company;
    (b) The designated representative reports hourly records of gas or 
oil flow rate, heat input rate, and emissions due to combustion of 
natural gas or oil;
    (c) The designated representative also reports hourly records of 
heat input rate for each unit, if the gas or oil flowmeter is on a 
common pipe header, consistent with section 2.1.2 of this appendix;
    (d) The designated representative reports hourly records directly 
from the gas or oil flowmeter used for commercial billing if these 
records are the values used, without adjustment, for commercial billing, 
or reports hourly records using the missing data procedures of section 
2.4 of this appendix if these records are not the values used, without 
adjustment, for commercial billing; and
    (e) The designated representative identifies the gas or oil 
flowmeter in the unit's monitoring plan.

                         2.1.4.3 Emergency Fuel

    The designated representative of a unit that is restricted by its 
Federal, State or local permit to combusting a particular fuel only 
during emergencies where the primary fuel is not available is exempt 
from certifying a fuel flowmeter for use during combustion of the 
emergency fuel. During any

[[Page 413]]

hour in which the emergency fuel is combusted, report the hourly heat 
input to be the maximum rated heat input of the unit for the fuel. Use 
the maximum potential sulfur content for the fuel (from Table D-6 of 
this appendix) and the fuel flow rate corresponding to the maximum 
hourly heat input to calculate the hourly SO2 mass emission 
rate, using Equations D-2 through D-4 (as applicable). Alternatively, if 
a certified fuel flowmeter is available for the emergency fuel, you may 
use the measured hourly fuel flow rates in the calculations. Also, if 
daily samples or weekly composite samples (fuel oil, only) of the fuel's 
total sulfur content, GCV, and (if applicable) density are taken during 
the combustion of the emergency fuel, as described in section 2.2 or 2.3 
of this appendix, the sample results may be used to calculate the hourly 
SO2 emissions and heat input rates, in lieu of using maximum 
potential values. The designated representative shall also provide 
notice under Sec. 75.61(a)(6) for each period when the emergency fuel 
is combusted.

     2.1.5 Initial Certification Requirement for all Fuel Flowmeters

    For the purposes of initial certification, each fuel flowmeter used 
to meet the requirements of this protocol shall meet a flowmeter 
accuracy of 2.0 percent of the upper range value (i.e. maximum fuel flow 
rate measurable by the flowmeter) across the range of fuel flow rate to 
be measured at the unit. Flowmeter accuracy may be determined under 
section 2.1.5.1 of this appendix for initial certification in any of the 
following ways (as applicable): by design (orifice, nozzle, and venturi-
type flowmeters, only) or by measurement under laboratory conditions; by 
the manufacturer; by an independent laboratory; or by the owner or 
operator. Flowmeter accuracy may also be determined under section 
2.1.5.2 of this appendix by in-line comparison against a reference 
flowmeter.
    2.1.5.1 Use the procedures in the following standards to verify 
flowmeter accuracy or design, as appropriate to the type of flowmeter: 
ASME MFC-3M-2004, Measurement of Fluid Flow in Pipes Using Orifice, 
Nozzle, and Venturi; ASME MFC-4M-1986 (Reaffirmed 1997), Measurement of 
Gas Flow by Turbine Meters; American Gas Association Report No. 3, 
Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids 
Part 1: General Equations and Uncertainty Guidelines (October 1990 
Edition), Part 2: Specification and Installation Requirements (February 
1991 Edition), and Part 3: Natural Gas Applications (August 1992 
edition) (excluding the modified flow-calculation method in part 3); 
Section 8, Calibration from American Gas Association Transmission 
Measurement Committee Report No. 7: Measurement of Gas by Turbine Meters 
(Second Revision, April 1996); ASME-MFC-5M-1985 (Reaffirmed 1994), 
Measurement of Liquid Flow in Closed Conduits Using Transit-Time 
Ultrasonic Flowmeters; ASME MFC-6M-1998, Measurement of Fluid Flow in 
Pipes Using Vortex Flowmeters; ASME MFC-7M-1987 (Reaffirmed 1992), 
Measurement of Gas Flow by Means of Critical Flow Venturi Nozzles; ISO 
8316: 1987(E) Measurement of Liquid Flow in Closed Conduits--Method by 
Collection of the Liquid in a Volumetric Tank; American Petroleum 
Institute (API) Manual of Petroleum Measurement Standards, Chapter 4--
Proving Systems, Section 2--Pipe Provers (Provers Accumulating at Least 
10,000 Pulses), Second Edition, March 2001, Section 3--Small Volume 
Provers, First Edition, July 1988, Reaffirmed October 1993, and Section 
5--Master-Meter Provers, Second Edition, May 2000; American Petroleum 
Institute (API) Manual of Petroleum Measurement Standards, Chapter 22--
Testing Protocol, Section 2--Differential Pressure Flow Measurement 
Devices, First Edition, August 2005; or ASME MFC-9M-1988 (Reaffirmed 
2001), Measurement of Liquid Flow in Closed Conduits by Weighing Method, 
for all other flowmeter types (all incorporated by reference under Sec. 
75.6 of this part). The Administrator may also approve other procedures 
that use equipment traceable to National Institute of Standards and 
Technology standards. Document such procedures, the equipment used, and 
the accuracy of the procedures in the monitoring plan for the unit, and 
submit a petition signed by the designated representative under Sec. 
75.66(c). If the flowmeter accuracy exceeds 2.0 percent of the upper 
range value, the flowmeter does not qualify for use under this part.
    2.1.5.2 (a) Alternatively, determine the flowmeter accuracy of a 
fuel flowmeter used for the purposes of this part by comparing it to the 
measured flow from a reference flowmeter which has been either designed 
according to the specifications of American Gas Association Report No. 3 
or ASME MFC-3M-1989, as cited in section 2.1.5.1 of this appendix, or 
tested for accuracy during the previous 365 days, using a standard 
listed in section 2.1.5.1 of this appendix or other procedure approved 
by the Administrator under Sec. 75.66 (all standards incorporated by 
reference under Sec. 75.6). Any secondary elements, such as pressure 
and temperature transmitters, must be calibrated immediately prior to 
the comparison. Perform the comparison over a period of no more than 
seven consecutive unit operating days. Compare the average of three fuel 
flow rate readings over 20 minutes or longer for each meter at each of 
three different flow rate levels. The three flow rate levels shall 
correspond to:
    (1) Normal full unit operating load,
    (2) Normal minimum unit operating load,

[[Page 414]]

    (3) A load point approximately equally spaced between the full and 
minimum unit operating loads, and
    (b) Calculate the flowmeter accuracy at each of the three flow 
levels using the following equation:
[GRAPHIC] [TIFF OMITTED] TR26MY99.012

Where:

ACC = Flowmeter accuracy at a particular load level, as a percentage of 
          the upper range value.
R = Average of the three flow measurements of the reference flowmeter.
A = Average of the three measurements of the flowmeter being tested.
URV = Upper range value of fuel flowmeter being tested (i.e. maximum 
          measurable flow).
    (c) Notwithstanding the requirement for calibration of the reference 
flowmeter within 365 days prior to an accuracy test, when an in-place 
reference meter or prover is used for quality assurance under section 
2.1.6 of this appendix, the reference meter calibration requirement may 
be waived if, during the previous in-place accuracy test with that 
reference meter, the reference flowmeter and the flowmeter being tested 
agreed to within [1.0 percent of each other at all levels tested. This 
exception to calibration and flowmeter accuracy testing requirements for 
the reference flowmeter shall apply for periods of no longer than five 
consecutive years (i.e., 20 consecutive calendar quarters).
    2.1.5.3 If the flowmeter accuracy exceeds the specification in 
section 2.1.5 of this appendix, the flowmeter does not qualify for use 
for this appendix. Either recalibrate the flowmeter until the flowmeter 
accuracy is within the performance specification, or replace the 
flowmeter with another one that is demonstrated to meet the performance 
specification. Substitute for fuel flow rate using the missing data 
procedures in section 2.4.2 of this appendix until quality-assured fuel 
flow data become available.
    2.1.5.4 For purposes of initial certification, when a flowmeter is 
tested against a reference fuel flow rate (i.e., fuel flow rate from 
another fuel flowmeter under section 2.1.5.2 of this appendix or flow 
rate from a procedure performed according to a standard incorporated by 
reference under section 2.1.5.1 of this appendix), report the results of 
flowmeter accuracy tests in a manner consistent with Table D-1.

             Table D-1--Table of Flowmeter Accuracy Results
------------------------------------------------------------------------
 
-------------------------------------------------------------------------
Test number:-------- Test completion date \1\:-------------------- Test
 completion time \1\:------------
Reinstallation date \2\ (for testing under 2.1.5.1 only):----------------
 ---- Reinstallation time \2\:------------
Unit or pipe ID: Component/System ID:
Flowmeter serial number: Upper range value:
Units of measure for flowmeter and reference flow readings:
------------------------------------------------------------------------


 
                                                                                                       Percent
                                                              Time of run   Candidate    Reference     accuracy
 Measurement level (percent of URV)          Run No.             (HHMM)     flowmeter       flow     (percent of
                                                                             reading      reading        URV)
----------------------------------------------------------------------------------------------------------------
Low (Minimum) level................  1                        ...........  ...........  ...........  ...........
---- percent \3\ of URV............  2                        ...........  ...........  ...........  ...........
                                     3                        ...........  ...........  ...........  ...........
                                     Average                  ...........  ...........  ...........  ...........
Mid-level..........................  1                        ...........  ...........  ...........  ...........
---- percent \3\ of URV............  2                        ...........  ...........  ...........  ...........
                                     3                        ...........  ...........  ...........  ...........
                                     Average                  ...........  ...........  ...........  ...........
High (Maximum) level...............  1                        ...........  ...........  ...........  ...........
---- percent \3\ of URV............  2                        ...........  ...........  ...........  ...........
                                     3                        ...........  ...........  ...........  ...........
                                     Average                  ...........  ...........  ...........  ...........
----------------------------------------------------------------------------------------------------------------
\1\ Report the date, hour, and minute that all test runs were completed.
\2\ For laboratory tests not performed inline, report the date and hour that the fuel flowmeter was reinstalled
  following the test.
\3\ It is required to test at least at three different levels: (1) normal full unit operating load, (2) normal
  minimum unit operating load, and (3) a load point approximately equally spaced between the full and minimum
  unit operating loads.

                         2.1.6 Quality Assurance

    (a) Test the accuracy of each fuel flowmeter prior to use under this 
part and at least once every four fuel flowmeter QA operating quarters, 
as defined in Sec. 72.2 of this chapter, thereafter. Notwithstanding 
these requirements, no more than 20 successive calendar quarters shall 
elapse after the quarter in which a fuel flowmeter was last tested for 
accuracy without a subsequent flowmeter accuracy test having been 
conducted. Test

[[Page 415]]

the flowmeter accuracy more frequently if required by manufacturer 
specifications.
    (b) Except for orifice-, nozzle-, and venturi-type flowmeters, 
perform the required flowmeter accuracy testing using the procedures in 
either section 2.1.5.1 or section 2.1.5.2 of this appendix. Each fuel 
flowmeter must meet the accuracy specification in section 2.1.5 of this 
appendix.
    (c) For orifice-, nozzle-, and venturi-type flowmeters, either 
perform the required flowmeter accuracy testing using the procedures in 
section 2.1.5.2 of this appendix or perform a transmitter accuracy test 
for the initial certification and once every four fuel flowmeter QA 
operating quarters thereafter. Perform a primary element visual 
inspection for the initial certification and once every 12 calendar 
quarters thereafter, according to the procedures in sections 2.1.6.1 
through 2.1.6.4 of this appendix for periodic quality assurance.
    (d) Notwithstanding the requirements of this section, if the 
procedures of section 2.1.7 (fuel flow-to-load test) of this appendix 
are performed during each fuel flowmeter QA operating quarter, 
subsequent to a required flowmeter accuracy test or (if applicable) 
transmitter accuracy test and primary element inspection, those 
procedures may be used to meet the requirement for periodic quality 
assurance testing for a period of up to 20 calendar quarters from the 
previous accuracy test or (if applicable) transmitter accuracy test and 
primary element inspection.
    (e) When accuracy testing of the orifice, nozzle, or venturi meter 
is performed according to section 2.1.5.2 of this appendix, record the 
information displayed in Table D-1 in this section. At a minimum, record 
the overall accuracy results for the fuel flowmeter at the three flow 
rate levels specified in section 2.1.5.2 of this appendix.
    (f) Report the results of all fuel flowmeter accuracy tests, 
transmitter or transducer accuracy tests, and primary element 
inspections, as applicable, in the emissions report for the quarter in 
which the quality assurance tests are performed, using the electronic 
format specified by the Administrator under Sec. 75.64.

 2.1.6.1 Transmitter or Transducer Accuracy Test for Orifice-, Nozzle-, 
                       and Venturi-Type Flowmeters

    (a) Calibrate the differential pressure transmitter or transducer, 
static pressure transmitter or transducer, and temperature transmitter 
or transducer, as applicable, using equipment that has a current 
certificate of traceability to NIST standards. Check the calibration of 
each transmitter or transducer by comparing its readings to that of the 
NIST traceable equipment at least once at each of the following levels: 
the zero-level and at least two other upscale levels (e.g., ``mid'' and 
``high''), such that the full range of transmitter or transducer 
readings corresponding to normal unit operation is represented. For 
temperature transmitters, the zero and upscale levels may correspond to 
fixed reference points, such as the freezing point or boiling point of 
water.
    (b) Calculate the accuracy of each transmitter or transducer at each 
level tested, using the following equation:
[GRAPHIC] [TIFF OMITTED] TR26MY99.013

Where:

ACC = Accuracy of the transmitter or transducer as a percentage of full-
          scale.
R = Reading of the NIST traceable reference value (in milliamperes, 
          inches of water, psi, or degrees).
T = Reading of the transmitter or transducer being tested (in 
          milliamperes, inches of water, psi, or degrees, consistent 
          with the units of measure of the NIST traceable reference 
          value).
FS = Full-scale range of the transmitter or transducer being tested (in 
          milliamperes, inches of water, psi, or degrees, consistent 
          with the units of measure of the NIST traceable reference 
          value).

    (c) If each transmitter or transducer meets an accuracy of 1.0 
percent of its full-scale range at each level tested, the fuel flowmeter 
accuracy of 2.0 percent is considered to be met at all levels. If, 
however, one or more of the transmitters or transducers does not meet an 
accuracy of 1.0 percent of full-scale at a particular level, then the 
owner or operator may demonstrate that the fuel flowmeter meets the 
total accuracy specification of 2.0 percent at that level by using one 
of the following alternative methods. If, at a particular level, the sum 
of the individual accuracies of the three transducers is less than or 
equal to 4.0 percent, the fuel flowmeter accuracy specification of 2.0 
percent is considered to be met for that level. Or, if at a particular 
level, the total fuel flowmeter accuracy is 2.0 percent or less, when 
calculated in accordance with Part 1 of American Gas Association Report 
No. 3, General Equations and Uncertainty Guidelines, the flowmeter 
accuracy requirement is considered to be met for that level.

  2.1.6.2 Recordkeeping for Transmitter or Transducer Accuracy Results

    (a) Record the accuracy of the orifice, nozzle, or venturi meter or 
its individual transmitters or transducers and keep this information in 
a file at the site or other location suitable for inspection.

[[Page 416]]



Table D-2--Table of Flowmeter Transmitter or Transducer Accuracy Results
Test number:-------- Test completion date: -------------------- Unit or
 pipe ID: ------------
Flowmeter serial number: Component/System ID:
Full-scale value: Units of measure: \3\
Transducer/Transmitter Type (check one):
    ---- Differential Pressure
    ---- Static Pressure
    ---- Temperature
------------------------------------------------------------------------


 
                                                                           Expected
                                  Run number               Transmitter/  transmitter/     Actual       Percent
 Measurement level (percent of       (if        Run time    transducer    transducer   transmitter/    accuracy
          full-scale)              multiple      (HHMM)     input (pre-     output      transducer   (percent of
                                  runs) \2\                calibration)   (reference)   output \3\   full-scale)
----------------------------------------------------------------------------------------------------------------
Low (Minimum) level
    ---- percent \1\ of full-    ...........
     scale
Mid-level
    ---- percent\1\ of full-     ...........
     scale
(If tested at more than 3
 levels)
2nd Mid-level
    ---- percent \1\ of full-    ...........
     scale
(If tested at more than 3
 levels)
3rd Mid-level
    ---- percent \1\ of full-    ...........
     scale
High (Maximum) level
    ---- percent \1\ of full-    ...........
     scale
----------------------------------------------------------------------------------------------------------------
\1\ At a minimum, it is required to test at zero-level and at least two other levels across the range of the
  transmitter or transducer readings corresponding to normal unit operation.
\2\ It is required to test at least once at each level.
\3\ Use the same units of measure for all readings (e.g., use degrees (), inches of water (in H2O), pounds per
  square inch (psi), or milliamperes (ma) for both transmitter or transducer readings and reference readings).

    (b)-(c) [Reserved]

           2.1.6.3 Failure of Transducer(s) or Transmitter(s)

    If, during a transmitter or transducer accuracy test conducted 
according to section 2.1.6.1 of this appendix, the flowmeter accuracy 
specification of 2.0 percent is not met at any of the levels tested, 
repair or replace transmitter(s) or transducer(s) as necessary until the 
flowmeter accuracy specification has been achieved at all levels. (Note 
that only transmitters or transducers which are repaired or replaced 
need to be re-tested; however, the re-testing is required at all three 
measurement levels, to ensure that the flowmeter accuracy specification 
is met at each level). The fuel flowmeter is ``out-of-control'' and data 
from the flowmeter are considered invalid, beginning with the date and 
hour of the failed accuracy test and continuing until the date and hour 
of completion of a successful transmitter or transducer accuracy test at 
all levels. In addition, if, during normal operation of the fuel 
flowmeter, one or more transmitters or transducers malfunction, data 
from the fuel flowmeter shall be considered invalid from the hour of the 
transmitter or transducer failure until the hour of completion of a 
successful 3-level transmitter or transducer accuracy test. During fuel 
flowmeter out-of-control periods, provide data from another fuel 
flowmeter that meets the requirements of Sec. 75.20(d) and section 
2.1.5 of this appendix, or substitute for fuel flow rate using the 
missing data procedures in section 2.4.2 of this appendix. Record and 
report test data and results, consistent with sections 2.1.6.1 and 
2.1.6.2 of this appendix and Sec. 75.59.

                   2.1.6.4 Primary Element Inspection

    (a) Conduct a visual inspection of the orifice, nozzle, or venturi 
meter at least once every twelve calendar quarters. Notwithstanding this 
requirement, the procedures of section 2.1.7 of this appendix may be 
used to reduce the inspection frequency of the orifice, nozzle, or 
venturi meter to at least once every twenty calendar quarters. The 
inspection may be performed using a baroscope. If the visual inspection 
is failed (if the orifice, nozzle, or venturi meter has become damaged 
or corroded), then:
    (1) Replace the primary element with another primary element meeting 
the requirements of American Gas Association Report No. 3 or ASME MFC-
3M-1989, as cited in section 2.1.5.1 of this appendix (both standards 
incorporated by reference under Sec. 75.6). If the primary element size 
is changed, also calibrate the transmitters or transducers, consistent 
with the new primary element size;
    (2) Replace the primary element with another primary element, and 
demonstrate that the overall flowmeter accuracy meets the accuracy 
specification in section 2.1.5 of

[[Page 417]]

this appendix, using the procedures of section 2.1.5.2 of this appendix; 
or
    (3) Restore the damaged or corroded primary element to ``as new'' 
condition; determine the overall accuracy of the flowmeter, using either 
the specifications of American Gas Association Report No. 3 or ASME MFC-
3M-1989, as cited in section 2.1.5.1 of this appendix (both standards 
incorporated by reference under Sec. 75.6); and retest the transmitters 
or transducers prior to providing quality-assured data from the 
flowmeter.
    (b) Data from the fuel flowmeter are considered invalid, beginning 
with the date and hour of a failed visual inspection and continuing 
until the date and hour when:
    (1) The damaged or corroded primary element is replaced with another 
primary element meeting the requirements of American Gas Association 
Report No. 3 or ASME MFC-3M-1989, as cited in section 2.1.5.1 of this 
appendix (both standards incorporated by reference under Sec. 75.6) 
and, if applicable, the transmitters have been successfully 
recalibrated;
    (2) The damaged or corroded primary element is replaced, and the 
overall accuracy of the flowmeter is demonstrated to meet the accuracy 
specification in section 2.1.5 of this appendix, using the procedures of 
section 2.1.5.2 of this appendix; or
    (3) The restored primary element is installed to meet the 
requirements of American Gas Association Report No. 3 or ASME MFC-3M-
1989, as cited in section 2.1.5.1 of this appendix (both standards 
incorporated by reference under Sec. 75.6) and its transmitters or 
transducers are retested to meet the accuracy specification in section 
2.1.6.1 of this appendix.
    (c) During each period of invalid fuel flowmeter data described in 
paragraph (b) of this section, provide data from another fuel flowmeter 
that meets the requirements of Sec. 75.20(d) and section 2.1.5 of this 
appendix, or substitute for fuel flow rate using the missing data 
procedures in section 2.4.2 of this appendix.

  2.1.7 Fuel Flow-to-Load Quality Assurance Testing for Certified Fuel 
                               Flowmeters

    The procedures of this section may be used as an optional supplement 
to the quality assurance procedures in section 2.1.5.1, 2.1.5.2, 
2.1.6.1, or 2.1.6.4 of this appendix when conducting periodic quality 
assurance testing of a certified fuel flowmeter. Note, however, that 
these procedures may not be used unless the 168-hour baseline data 
requirement of section 2.1.7.1 of this appendix has been met. If, 
following a flowmeter accuracy test or (if applicable) a flowmeter 
transmitter test and primary element inspection, the procedures of this 
section are performed during each subsequent fuel flowmeter QA operating 
quarter, as defined in Sec. 72.2 of this chapter (excluding the 
quarter(s) in which the baseline data are collected), then these 
procedures may be used to meet the requirement for periodic quality 
assurance for a period of up to 20 calendar quarters from the previous 
periodic quality assurance procedure(s) performed according to sections 
2.1.5.1, 2.1.5.2, or 2.1.6.1 through 2.1.6.4 of this appendix. The 
procedures of this section are not required for any quarter in which a 
flowmeter accuracy test or (if applicable) a transmitter accuracy test 
and a primary element inspection, are conducted. Notwithstanding the 
requirements of Sec. 75.57(a), when using the procedures of this 
section, keep records of the test data and results from the previous 
flowmeter accuracy test under section 2.1.5.1 or 2.1.5.2 of this 
appendix, records of the test data and results from the previous 
transmitter or transducer accuracy test under section 2.1.6.1 of this 
appendix for orifice-, nozzle-, and venturi-type fuel flowmeters, and 
records of the previous visual inspection of the primary element 
required under section 2.1.6.4 of this appendix for orifice-, nozzle-, 
and venturi-type fuel flowmeters until the next flowmeter accuracy test, 
transmitter accuracy test, or visual inspection is performed, even if 
the previous flowmeter accuracy test, transmitter accuracy test, or 
visual inspection was performed more than three years previously.

  2.1.7.1 Baseline Flow Rate-to-Load Ratio or Heat Input-to-Load Ratio

    (a) Determine Rbase, the baseline value of the ratio of 
fuel flow rate to unit load, following each successful periodic quality 
assurance procedure performed according to sections 2.1.5.1, 2.1.5.2, or 
2.1.6.1 and 2.1.6.4 of this appendix. Establish a baseline period of 
data consisting, at a minimum, of 168 hours of quality-assured fuel 
flowmeter data. Baseline data collection shall begin with the first hour 
of fuel flowmeter operation following completion of the most recent 
quality assurance procedure(s), during which only the fuel measured by 
the fuel flowmeter is combusted (e.g., only gas, only residual oil, or 
only diesel fuel is combusted by the unit). During the baseline data 
collection period, the owner or operator may exclude as non-
representative any hour in which the unit is ``ramping'' up or down, 
(i.e., the load during the hour differs by more than 15.0 percent from 
the load in the previous or subsequent hour) and may exclude any hour in 
which the unit load is in the lower 25.0 percent of the range of 
operation, as defined in section 6.5.2.1 of appendix A to this part 
(unless operation in this lower 25.0 percent of the range is considered 
normal for the unit). The baseline data must be obtained no later than 
the end of the fourth calendar quarter following the calendar quarter of 
the most recent quality assurance procedure for that fuel flowmeter. For 
orifice-, nozzle-, and venturi-type

[[Page 418]]

fuel flowmeters, if the fuel flow-to-load ratio is to be used as a 
supplement both to the transmitter accuracy test under section 2.1.6.1 
of this appendix and to primary element inspections under section 
2.1.6.4 of this appendix, then the baseline data must be obtained after 
both procedures are completed and no later than the end of the fourth 
calendar quarter following the calendar quarter in which both procedures 
were completed. From these 168 (or more) hours of baseline data, 
calculate the baseline fuel flow rate-to-load ratio as follows:
[GRAPHIC] [TIFF OMITTED] TR26MY99.014

where:

Rbase = Value of the fuel flow rate-to-load ratio during the 
          baseline period; 100 scfh/MWe, 100 scfh/klb per hour steam 
          load, or 100 scfh/mmBtu per hour thermal output for gas-
          firing; (lb/hr)/MWe, (lb/hr)/klb per hour steam load, or (lb/
          hr)/mmBtu per hour thermal output for oil-firing.
Qbase = Arithmetic average fuel flow rate measured by the 
          fuel flowmeter during the baseline period, 100 scfh for gas-
          firing and lb/hr for oil-firing.
Lavg = Arithmetic average unit load during the baseline 
          period, megawatts, 1000 lb/hr of steam, or mmBtu/hr thermal 
          output.

    (b) In Equation D-1b, for a fuel flowmeter installed on a common 
pipe header, Lavg is the sum of the operating loads of all 
units that received fuel through the common pipe header during the 
baseline period, divided by the total number of hours of fuel flow rate 
data collected during the baseline period. For a unit that receives the 
same type of fuel through multiple pipes, Qbase is the sum of 
the fuel flow rates during the baseline period from all of the pipes, 
divided by the total number of hours of fuel flow rate data collected 
during the baseline period. Round off the value of Rbase to 
the nearest tenth.
    (c) Alternatively, a baseline value of the gross heat rate (GHR) may 
be determined in lieu of Rbase. The baseline value of the 
GHR, GHRbase, shall be determined as follows:
[GRAPHIC] [TIFF OMITTED] TR26MY99.015

Where:

(GHR)base = Baseline value of the gross heat rate during the 
          baseline period, Btu/kwh, Btu/lb steam load, or 1000mmBtu heat 
          input/mmBtu thermal output.
(Heat Input)avg = Average (mean) hourly heat input rate 
          recorded by the fuel flowmeter during the baseline period, as 
          determined using the average fuel flow rate and the fuel GCV 
          in the applicable equation in appendix F to this part, mmBtu/
          hr.
Lavg = Average (mean) unit load during the baseline period, 
          megawatts, 1000 lb/hr of steam, or mmBtu/hr thermal output.

    (d) Report the current value of Rbase (or 
GHRbase) and the completion date of the associated quality 
assurance procedure in each electronic quarterly report required under 
Sec. 75.64.
    (e) If a unit co-fires different fuels (e.g., oil and natural gas) 
as its normal mode of operation, the gross heat rate option in paragraph 
(c) of this section may be used to determine a value of 
(GHR)base, as follows. Derive the baseline data during co-
fired hours. Then, use Equation D-1c to calculate (GHR)base, 
making sure that each hourly unit heat input rate used to calculate 
(Heat Input)avg includes the contribution of each type of 
fuel.

                  2.1.7.2 Data Preparation and Analysis

    (a) Evaluate the fuel flow rate-to-load ratio (or GHR) for each fuel 
flowmeter QA operating quarter, as defined in Sec. 72.2 of this 
chapter. At the end of each fuel flowmeter QA operating quarter, use 
Equation D-1d in this appendix to calculate Rh, the hourly 
fuel flow-to-load ratio, for every quality-assured hourly average fuel 
flow rate obtained with a certified fuel flowmeter. Alternatively, the 
owner or operator may exclude non-representative hours from the data 
analysis, as described in section 2.1.7.3 of this appendix, prior to 
calculating the values of Rh.
[GRAPHIC] [TIFF OMITTED] TR26MY99.016

where:

Rh = Hourly value of the fuel flow rate-to-load ratio; 100 
          scfh/MWe, (lb/hr)/MWe, 100 scfh/1000 lb/hr of steam load, (lb/
          hr)/1000 lb/hr of steam load, 100 scfh/(mmBtu/hr of steam 
          load), or (lb/hr)/(mmBtu/hr thermal output).
Qh = Hourly fuel flow rate, as measured by the fuel 
          flowmeter, 100 scfh for gas-firing or lb/hr for oil-firing.
Lh = Hourly unit load, megawatts, 1000 lb/hr of steam, or 
          mmBtu/hr thermal output.


[[Page 419]]


    (b) For a fuel flowmeter installed on a common pipe header, Lh shall 
be the sum of the hourly operating loads of all units that receive fuel 
through the common pipe header. For a unit that receives the same type 
of fuel through multiple pipes, Qh will be the sum of the 
fuel flow rates from all of the pipes. Round off each value of 
Rh to the nearest tenth.
    (c) Alternatively, calculate the hourly gross heat rates (GHR) in 
lieu of the hourly flow-to-load ratios. If this option is selected, 
calculate each hourly GHR value as follows:
[GRAPHIC] [TIFF OMITTED] TR26MY99.017

Where:

(GHR)h = Hourly value of the gross heat rate, Btu/kwh, Btu/lb 
          steam load, or mmBtu heat input/mmBtu thermal output.
(Heat Input)h = Hourly heat input rate, as determined using 
          the hourly fuel flow rate and the fuel GCV in the applicable 
          equation in appendix F to this part, mmBtu/hr.
Lh = Hourly unit load, megawatts, 1000 lb/hr of steam, or 
          mmBtu/hr thermal output.

    (d) Evaluate the calculated flow rate-to-load ratios (or gross heat 
rates) as follows.
    (1) Perform a separate data analysis for each fuel flowmeter system 
following the procedures of this section. Base each analysis on a 
minimum of 168 hours of data. If, for a particular fuel flowmeter 
system, fewer than 168 hourly flow-to-load ratios (or GHR values) are 
available, or, if the baseline data collection period is still in 
progress at the end of the quarter and fewer than four calendar quarters 
have elapsed since the quarter in which the last successful fuel 
flowmeter system accuracy test was performed, a flow-to-load (or GHR) 
evaluation is not required for that flowmeter system for that calendar 
quarter. A one-quarter extension of the deadline for the next fuel 
flowmeter system accuracy test may be claimed for a quarter in which 
there is insufficient hourly data available to analyze or a quarter that 
ends with the baseline data collection period still in progress.
    (2) For a unit that normally co-fires different types of fuel (e.g., 
oil and natural gas), include the contribution of each type of fuel in 
the value of (Heat Input)h, when using Equation D-1e.
    (e) For each hourly flow-to-load ratio or GHR value, calculate the 
percentage difference (percent Dh) from the baseline fuel 
flow-to-load ratio using Equation D-1f.
[GRAPHIC] [TIFF OMITTED] TR26MY99.018

Where:

%Dh = Absolute value of the percentage difference between the 
          hourly fuel flow rate-to-load ratio and the baseline value of 
          the fuel flow rate-to-load ratio (or hourly and baseline GHR).
Rh = The hourly fuel flow rate-to-load ratio (or GHR).
Rbase = The value of the fuel flow rate-to-load ratio (or 
          GHR) from the baseline period, determined in accordance with 
          section 2.1.7.1 of this appendix.

    (f) Consistently use Rbase and Rh in Equation 
D-1f if the fuel flow-to-load ratio is being evaluated, and consistently 
use (GHR)base and (GHR)h in Equation D-1f if the 
gross heat rate is being evaluated.
    (g) Next, determine the arithmetic average of all of the hourly 
percent difference (percent Dh) values using Equation D-1g, 
as follows:
[GRAPHIC] [TIFF OMITTED] TR26MY99.019

Where:

Ef = Quarterly average percentage difference between hourly 
          flow rate-to-load ratios and the baseline value of the fuel 
          flow rate-to-load ratio (or hourly and baseline GHR).
%Dh = Percentage difference between the hourly fuel flow 
          rate-to-load ratio and the baseline value of the fuel flow 
          rate-to-load ratio (or hourly and baseline GHR).
q = Number of hours used in fuel flow-to-load (or GHR) evaluation.

    (h) When the quarterly average load value used in the data analysis 
is greater than 50 MWe (or 500 klb steam per hour), the results of a 
quarterly fuel flow rate-to-load (or GHR) evaluation are acceptable and 
no further action is required if the quarterly average percentage 
difference (Ef) is no greater than 10.0 percent. When the 
arithmetic average of the hourly load values used in the data analysis 
is <=50 MWe (or 500 klb steam per hour), the results of the analysis are 
acceptable if the value of Ef is no greater than 15.0 
percent. For units that normally co-fire different types of fuel, if the 
GHR option is used,

[[Page 420]]

apply the test results to each fuel flowmeter system used during the 
quarter.

                    2.1.7.3 Optional Data Exclusions

    (a) If Ef is outside the limits in section 2.1.7.2(h) of 
this appendix, the owner or operator may re-examine the hourly fuel flow 
rate-to-load ratios (or GHRs) that were used for the data analysis and 
may identify and exclude fuel flow-to-load ratios or GHR values for any 
non-representative hours, provided that such data exclusions were not 
previously made under section 2.1.7.2(a) of this appendix. Specifically, 
the Rh or (GHR)h values for the following hours 
may be considered non-representative:
    (1) For units that do not normally co-fire fuels, any hour in which 
the unit combusted another fuel in addition to the fuel measured by the 
fuel flowmeter being tested; or
    (2) Any hour for which the load differed by more than [15.0 percent 
from the load during either the preceding hour or the subsequent hour; 
or
    (3) For units that normally co-fire different fuels, any hour in 
which the unit burned only one type of fuel; or
    (4) Any hour for which the unit load was in the lower 25.0 percent 
of the range of operation, as defined in section 6.5.2.1 of appendix A 
to this part (unless operation in the lower 25.0 percent of the range is 
considered normal for the unit).
    (b) After identifying and excluding all non-representative hourly 
fuel flow-to-load ratios or GHR values, analyze the quarterly fuel flow 
rate-to-load data a second time. If fewer than 168 hourly fuel flow-to-
load ratio or GHR values remain after the allowable data exclusions, a 
fuel flow-to-load ratio or GHR analysis is not required for that 
quarter, and a one-quarter extension of the fuel flowmeter accuracy test 
deadline may be claimed.

       2.1.7.4 Consequences of Failed Fuel Flow-to-Load Ratio Test

    (a) If Ef is outside the applicable limit in section 
2.1.7.2(h) of this appendix (after analysis using any optional data 
exclusions under section 2.1.7.3 of this appendix), perform transmitter 
accuracy tests according to section 2.1.6.1 of this appendix for 
orifice-, nozzle-, and venturi-type flowmeters, or perform a fuel 
flowmeter accuracy test, in accordance with section 2.1.5.1 or 2.1.5.2 
of this appendix, for each fuel flowmeter for which Ef is 
outside of the applicable limit. In addition, for an orifice-, nozzle-, 
or venturi-type fuel flowmeter, repeat the fuel flow-to-load ratio 
comparison of section 2.1.7.2 of this appendix using six to twelve hours 
of data following a passed transmitter accuracy test in order to verify 
that no significant corrosion has affected the primary element. If, for 
the abbreviated 6-to-12 hour test, the orifice-, nozzle-, or venturi-
type fuel flowmeter is not able to meet the limit in section 2.1.7.2 of 
this appendix, then perform a visual inspection of the primary element 
according to section 2.1.6.4 of this appendix, and repair or replace the 
primary element, as necessary.
    (b) Substitute for fuel flow rate, for any hour when that fuel is 
combusted, using the missing data procedures in section 2.4.2 of this 
appendix, beginning with the first hour of the calendar quarter 
following the quarter for which Ef was found to be outside 
the applicable limit and continuing until quality-assured fuel flow data 
become available. Following a failed flow rate-to-load or GHR 
evaluation, data from the flowmeter shall not be considered quality-
assured until the hour in which all required flowmeter accuracy tests, 
transmitter accuracy tests, visual inspections and diagnostic tests have 
been passed. Additionally, a new value of Rbase or 
(GHR)base shall be established no later than two fuel 
flowmeter QA operating quarters (as defined in Sec. 72.2 of this 
chapter) after the quarter in which the required quality assurance tests 
are completed (note that for orifice-, nozzle-, or venturi-type fuel 
flowmeters, establish a new value of Rbase or 
(GHR)base only if both a transmitter accuracy test and a 
primary element inspection have been performed).

                          2.1.7.5 Test Results

    Report the results of each quarterly flow rate-to-load (or GHR) 
evaluation, as determined from Equation D-1g, in the electronic 
quarterly report required under Sec. 75.64. Table D-3 is provided as a 
reference on the type of information to be recorded under Sec. 75.59 
and reported under Sec. 75.64.

 Table D-3--Baseline Information and Test Results For Fuel Flow-to-Load 
                                  Test

[[Page 421]]

[GRAPHIC] [TIFF OMITTED] TR12JN02.012

                      2.2 Oil Sampling and Analysis

    Perform sampling and analysis of oil to determine the following fuel 
properties for each type of oil combusted by a unit: percentage of 
sulfur by weight in the oil; gross calorific value (GCV) of the oil; 
and, if necessary, the density of the oil. Use the sulfur content, 
density, and gross calorific value, determined under the provisions of 
this section, to calculate SO2 mass emission rate and heat 
input rate for each fuel using the applicable procedures of section 3 of 
this appendix. The designated representative may petition for reduced 
GCV and or density sampling under Sec. 75.66 if the fuel combusted has 
a consistent and relatively non-variable GCV or density.

[[Page 422]]

[GRAPHIC] [TIFF OMITTED] TR12JN02.013

    2.2.1 When combusting oil, use one of the following methods to 
sample the oil (see Table D-4): sample from the storage tank for the 
unit after each addition of oil to the storage tank, in accordance with 
section 2.2.4.2 of this appendix; or sample from the fuel lot in the 
shipment tank or container upon receipt of each oil delivery or from the 
fuel lot in the oil supplier's storage container, in accordance with 
section 2.2.4.3 of this appendix; or use the flow proportional sampling 
methodology in section 2.2.3 of this appendix; or use the daily manual 
sampling methodology in section 2.2.4.1 of this appendix. For purposes 
of this appendix, a fuel lot of oil is the mass or volume of product oil

[[Page 423]]

from one source (supplier or pretreatment facility), intended as one 
shipment or delivery (e.g., ship load, barge load, group of trucks, 
discrete purchase of diesel fuel through pipeline, etc.). A storage tank 
is a container at a plant holding oil that is actually combusted by the 
unit, such that no blending of any other fuel with the fuel in the 
storage tank occurs from the time that the fuel lot is transferred to 
the storage tank to the time when the fuel is combusted in the unit.

                            2.2.2 [Reserved]

                    2.2.3 Flow Proportional Sampling

    Conduct flow proportional oil sampling or continuous drip oil 
sampling in accordance with ASTM D4177-95 (Reapproved 2000), ``Standard 
Practice for Automatic Sampling of Petroleum and Petroleum Products'' 
(incorporated by reference under Sec. 75.6), every day the unit is 
combusting oil. Extract oil at least once every hour and blend into a 
composite sample. The sample compositing period may not exceed 7 
calendar days (168 hrs). Use the actual sulfur content (and where 
density data are required, the actual density) from the composite sample 
to calculate the hourly SO2 mass emission rates for each 
operating day represented by the composite sample. Calculate the hourly 
heat input rates for each operating day represented by the composite 
sample, using the actual gross calorific value from the composite 
sample.

                          2.2.4 Manual Sampling

                          2.2.4.1 Daily Samples

    Representative oil samples may be taken from the storage tank or 
fuel flow line manually every day that the unit combusts oil according 
to ASTM ASTM D4057-95 (Reapproved 2000), Standard Practice for Manual 
Sampling of Petroleum and Petroleum Products (incorporated by reference 
under Sec. 75.6 of this part). Use either the actual daily sulfur 
content or the highest fuel sulfur content recorded at that unit from 
the most recent 30 daily samples for the purpose of calculating 
SO2 emissions under section 3 of this appendix. Use either 
the gross calorific value measured from that day's sample or the highest 
GCV from the previous 30 days' samples to calculate heat input. If oil 
supplies with different sulfur contents are combusted on the same day, 
sample the highest sulfur fuel combusted that day.

               2.2.4.2 Sampling From a Unit's Storage Tank

    Take a manual sample after each addition of oil to the storage tank. 
Do not blend additional fuel with the sampled fuel prior to combustion. 
Sample according to the single tank composite sampling procedure or all-
levels sampling procedure in ASTM ASTM D4057-95 (Reapproved 2000), 
Standard Practice for Manual Sampling of Petroleum and Petroleum 
Products (incorporated by reference under Sec. 75.6 of this part). Use 
the sulfur content and GCV value (and where required, the density) of 
either the most recent sample or one of the conservative assumed values 
described in section 2.2.4.3(c) of this appendix to calculate 
SO2 mass emission rate. Calculate heat input rate using the 
gross calorific value from either:
    (a) The most recent oil sample taken or
    (b) One of the conservative assumed values described in section 
2.2.4.3(c) of this appendix. Follow the applicable provisions in section 
2.2.4.3(d) of this appendix, regarding the use of assumed values.

                   2.2.4.3 Sampling From Each Delivery

    (a) Alternatively, an oil sample may be taken from--
    (1) The shipment tank or container upon receipt of each lot of fuel 
oil or
    (2) The supplier's storage container which holds the lot of fuel 
oil. (Note: a supplier need only sample the storage container once for 
sulfur content, GCV and, where required, the density so long as the fuel 
sulfur content and GCV do not change and no fuel is added to the 
supplier's storage container.)
    (b) For the purpose of this section, a lot is defined as a shipment 
or delivery (e.g., ship load, barge load, group of trucks, discrete 
purchase of diesel fuel through a pipeline, etc.) of a single fuel.
    (c) Oil sampling may be performed either by the owner or operator of 
an affected unit, an outside laboratory, or a fuel supplier, provided 
that samples are representative and that sampling is performed according 
to either the single tank composite sampling procedure or the all-levels 
sampling procedure in ASTM ASTM D4057-95 (Reapproved 2000), Standard 
Practice for Manual Sampling of Petroleum and Petroleum Products 
(incorporated by reference under Sec. 75.6 of this part). Except as 
otherwise provided in this section, calculate SO2 mass 
emission rate using the sulfur content (and where required, the density) 
from one of the two following conservative assumed values, and calculate 
heat input using the gross calorific value from one of the assumed 
values:
    (1) The highest value sampled during the previous calendar year 
(this option is allowed for any consistent fuel which comes from a 
single source whether or not the fuel is supplied under a contractual 
agreement) or
    (2) The maximum value indicated in the contract with the fuel 
supplier. Continue to use this assumed contract value unless and until 
the actual sampled sulfur content, density, or gross calorific value of 
a delivery exceeds the assumed value.

[[Page 424]]

    (d) Continue using the assumed value(s), so long as the sample 
results do not exceed the assumed value(s). However, if the actual 
sampled sulfur content, gross calorific value, or density of an oil 
sample is greater than the assumed value for that parameter, then, 
consistent with section 2.3.7 of this appendix, begin to use the actual 
sampled value for sulfur content, gross calorific value, or density of 
fuel to calculate SO2 mass emission rate or heat input rate. Consider 
the sampled value to be the new assumed sulfur content, gross calorific 
value, or density. Continue using this new assumed value to calculate 
SO2 mass emission rate or heat input rate unless and until: it is 
superseded by a higher value from an oil sample; or (if applicable) it 
is superseded by a new contract in which case the new contract value 
becomes the assumed value at the time the fuel specified under the new 
contract begins to be combusted in the unit; or (if applicable) both the 
calendar year in which the sampled value exceeded the assumed value and 
the subsequent calendar year have elapsed.
    2.2.5 For each oil sample that is taken on-site at the affected 
facility, split and label the sample and maintain a portion (at least 
200 cc) of it throughout the calendar year and in all cases for not less 
than 90 calendar days after the end of the calendar year allowance 
accounting period. This requirement does not apply to oil samples taken 
from the fuel supplier's storage container, as described in section 
2.2.4.3 of this appendix. Analyze oil samples for percent sulfur content 
by weight in accordance with ASTM D129-00, Standard Test Method for 
Sulfur in Petroleum Products (General Bomb Method), ASTM D1552-01, 
Standard Test Method for Sulfur in Petroleum Products (High-Temperature 
Method), ASTM D2622-98, Standard Test Method for Sulfur in Petroleum 
Products by Wavelength Dispersive X-ray Fluorescence Spectrometry, ASTM 
D4294-98, Standard Test Method for Sulfur in Petroleum and Petroleum 
Products by Energy-Dispersive X-ray Fluorescence Spectrometry, or ASTM 
D5453-06, Standard Test Method for Determination of Total Sulfur in 
Light Hydrocarbons, Spark Ignition Engine Fuel, Diesel Engine Fuel, and 
Engine Oil by Ultraviolet Fluorescence (all incorporated by reference 
under Sec. 75.6 of this part). Alternatively, the oil samples may be 
analyzed for percent sulfur by any consensus standard method prescribed 
for the affected unit under part 60 of this chapter.
    2.2.6 Where the flowmeter records volumetric flow rate rather than 
mass flow rate, analyze oil samples to determine the density or specific 
gravity of the oil. Determine the density or specific gravity of the oil 
sample in accordance with ASTM D287-92 (Reapproved 2000), Standard Test 
Method for API Gravity of Crude Petroleum and Petroleum Products 
(Hydrometer Method), ASTM D1217-93 (Reapproved 1998), Standard Test 
Method for Density and Relative Density (Specific Gravity) of Liquids by 
Bingham Pycnometer, ASTM D1481-93 (Reapproved 1997), Standard Test 
Method for Density and Relative Density (Specific Gravity) of Viscous 
Materials by Lipkin Bicapillary Pycnometer, ASTM D1480-93 (Reapproved 
1997), Standard Test Method for Density and Relative Density (Specific 
Gravity) of Viscous Materials by Bingham Pycnometer, ASTM D1298-99, 
Standard Test Method for Density, Relative Density (Specific Gravity), 
or API Gravity of Crude Petroleum and Liquid Petroleum Products by 
Hydrometer Method, or ASTM D4052-96 (Reapproved 2002), Standard Test 
Method for Density and Relative Density of Liquids by Digital Density 
Meter (all incorporated by reference under Sec. 75.6 of this part). 
Alternatively, the oil samples may be analyzed for density or specific 
gravity by any consensus standard method prescribed for the affected 
unit under part 60 of this chapter.
    2.2.7 Analyze oil samples to determine the heat content of the fuel. 
Determine oil heat content in accordance with ASTM D240-00, ASTM D4809-
00, ASTM D5865-01a, or D5865-10 (all incorporated by reference under 
Sec. 75.6) or any other procedures listed in section 5.5 of appendix F 
of this part. Alternatively, the oil samples may be analyzed for heat 
content by any consensus standard method prescribed for the affected 
unit under part 60 of this chapter.
    2.2.8 Results from the oil sample analysis must be available no 
later than thirty calendar days after the sample is composited or taken. 
However, during an audit, the Administrator may require that the results 
of the analysis be available as soon as practicable, and no later than 5 
business days after receipt of a request from the Administrator.

      2.3 SO2 Emissions From Combustion of Gaseous Fuels

    (a) Account for the hourly SO2 mass emissions due to 
combustion of gaseous fuels for each hour when gaseous fuels are 
combusted by the unit using the procedures in this section.
    (b) The procedures in sections 2.3.1 and 2.3.2 of this appendix, 
respectively, may be used to determine SO2 mass emissions 
from combustion of pipeline natural gas and natural gas, as defined in 
Sec. 72.2 of this chapter. The procedures in section 2.3.3 of this 
appendix may be used to account for SO2 mass emissions from 
any gaseous fuel combusted by a unit. For each type of gaseous fuel, the 
appropriate sampling frequency and the sulfur content and GCV values 
used for calculations of SO2 mass emission rates are 
summarized in the following Table D-5.

[[Page 425]]

[GRAPHIC] [TIFF OMITTED] TR12JN02.014


[[Page 426]]


[GRAPHIC] [TIFF OMITTED] TR12JN02.015


[[Page 427]]


[GRAPHIC] [TIFF OMITTED] TR12JN02.016

                  2.3.1 Pipeline Natural Gas Combustion

    The owner or operator may determine the SO2 mass 
emissions from the combustion of a fuel that meets the definition of 
pipeline natural gas, in Sec. 72.2 of this chapter, using the 
procedures of this section.

                  2.3.1.1 SO2 Emission Rate

    For a fuel that meets the definition of pipeline natural gas under 
Sec. 72.2 of this chapter, the owner or operator may determine the 
SO2 mass emissions using either a default SO2 
emission rate of 0.0006 lb/mmBtu and the procedures of this section, the 
procedures in section 2.3.2 for natural gas, or the procedures of 
section 2.3.3 for any gaseous fuel. For each affected unit using the 
default rate of 0.0006 lb/mmBtu, the owner or operator must document 
that the fuel combusted is actually pipeline natural gas, using the 
procedures in section 2.3.1.4 of this appendix.

                     2.3.1.2 Hourly Heat Input Rate

    Calculate hourly heat input rate, in mmBtu/hr, for a unit combusting 
pipeline natural gas, using the procedures of section 3.4.1 of this 
appendix. Use the measured fuel flow rate from section 2.1 of this 
appendix and the gross calorific value from section 2.3.4.1 of this 
appendix in the calculations.

    2.3.1.3 SO2 Hourly Mass Emission Rate and Hourly Mass 
                                Emissions

    For pipeline natural gas combustion, calculate the SO2 mass emission 
rate, in lb/hr, using Equation D-5 in section 3.3.2 of this appendix 
(when the default SO2 emission rate is used) or Equation D-4 
(if daily or hourly fuel sampling is used). Then, use the calculated 
SO2 mass emission rate and the unit operating time to 
determine the hourly SO2 mass emissions from pipeline natural 
gas combustion, in lb, using Equation D-12 in section 3.5.1 of this 
appendix.

        2.3.1.4 Documentation that a Fuel is Pipeline Natural Gas

    (a) A fuel may initially qualify as pipeline natural gas, if 
information is provided in the monitoring plan required under Sec. 
75.53, demonstrating that the definition of pipeline natural gas in 
Sec. 72.2 of this chapter has been met. The information must 
demonstrate that the fuel meets either the percent methane or GCV 
requirement and has a total sulfur content of 0.5 grains/100scf or less. 
The demonstration must be made using one of the following sources of 
information:
    (1) The gas quality characteristics specified by a purchase 
contract, tariff sheet, or by a pipeline transportation contract; or
    (2) Historical fuel sampling data for the previous 12 months, 
documenting the total sulfur content of the fuel and the GCV and/or 
percentage by volume of methane. The results of all sample analyses 
obtained by or provided to the owner or operator in the previous 12 
months shall be used in the demonstration, and each sample result must 
meet the definition of pipeline natural gas in Sec. 72.2 of this 
chapter, except where the results of at least 100 daily (or more 
frequent) total sulfur samples are provided by the fuel supplier. In 
that case you may opt to convert these data to monthly averages and then 
if, for each month, the average total sulfur content is 0.5 grains/100 
scf or less, and if the GCV or percent methane requirement is also met, 
the fuel qualifies as pipeline natural

[[Page 428]]

gas. Alternatively, the fuel qualifies as pipeline natural gas if 
[gteqt]98 percent of the 100 (or more) samples have a total sulfur 
content of 0.5 grains/100 scf or less and if the GCV or percent methane 
requirement is also met; or
    (3) If the requirements of paragraphs (a)(1) and (a)(2) of this 
section cannot be met, a fuel may initially qualify as pipeline natural 
gas if at least one representative sample of the fuel is obtained and 
analyzed for total sulfur content and for either the gross calorific 
value (GCV) or percent methane, and the results of the sample analysis 
show that the fuel meets the definition of pipeline natural gas in Sec. 
72.2 of this chapter. Use the sampling methods specified in sections 
2.3.3.1.2 and 2.3.4 of this appendix. The required fuel sample may be 
obtained and analyzed by the owner or operator, by an independent 
laboratory, or by the fuel supplier. If multiple samples are taken, each 
sample must meet the definition of pipeline natural gas in Sec. 72.2 of 
this chapter.
    (b) If the results of the fuel sampling under paragraph (a)(2) or 
(a)(3) of this section show that the fuel does not meet the definition 
of pipeline natural gas in Sec. 72.2 of this chapter, but those results 
are believed to be anomalous, the owner or operator may document the 
reasons for believing this in the monitoring plan for the unit, and may 
immediately perform additional sampling. In such cases, a minimum of 
three additional samples must be obtained and analyzed, and the results 
of each sample analysis must meet the definition of pipeline natural 
gas.
    (c) If several affected units are supplied by a common source of 
gaseous fuel, a single sampling result may be applied to all of the 
units and it is not necessary to obtain a separate sample for each unit, 
provided that the composition of the fuel is not altered by blending or 
mixing it with other gaseous fuel(s) when it is transported from the 
sampling location to the affected units. For the purposes of this 
paragraph, the term ``other gaseous fuel(s)'' excludes compounds such as 
mercaptans when they are added in trace quantities for safety reasons.
    (d) If the results of fuel sampling and analysis under paragraph 
(a)(2), (a)(3), or (b) of this section show that the fuel does not 
qualify as pipeline natural gas, proceed as follows:
    (1) If the fuel still qualifies as natural gas under section 2.3.2.4 
of this appendix, re-classify the fuel as natural gas and determine the 
appropriate default SO2 emission rate for the fuel, according 
to section 2.3.2.1.1 of this appendix; or
    (2) If the fuel does not qualify either as pipeline natural gas or 
natural gas, re-classify the fuel as ``other gaseous fuel'' and 
implement the procedures of section 2.3.3 of this appendix, within 180 
days of the end of the quarter in which the disqualifying sample was 
taken. In addition, the owner or operator shall use Equation D-1h in 
this appendix to calculate a default SO2 emission rate for 
the fuel, based on the results of the sample analysis that exceeded 20 
grains/100 scf of total sulfur, and shall use that default emission rate 
to report SO2 mass emissions under this part until section 
2.3.3 of this appendix has been fully implemented.
    (e) If a fuel qualifies as pipeline natural gas based on the 
specifications in a fuel contract or tariff sheet, no additional, on-
going sampling of the fuel's total sulfur content is required, provided 
that the contract or tariff sheet is current, valid and representative 
of the fuel combusted in the unit. If the fuel qualifies as pipeline 
natural gas based on fuel sampling and analysis, on-going sampling of 
the fuel's sulfur content is required annually and whenever the fuel 
supply source changes. For the purposes of this paragraph (e), sampling 
``annually'' means that at least one sample is taken in each calendar 
year. If the results of at least 100 daily (or more frequent) total 
sulfur samples have been provided by the fuel supplier since the last 
annual assessment of the fuel's sulfur content, the data may be used as 
follows to satisfy the annual sampling requirement for the current year. 
If this option is chosen, all of the data provided by the fuel supplier 
shall be used. First, convert the data to monthly averages. Then, if, 
for each month, the average total sulfur content is 0.5 grains/100 scf 
or less, and if the GCV or percent methane requirement is also met, the 
fuel qualifies as pipeline natural gas. Alternatively, the fuel 
qualifies as pipeline natural gas if the analysis of the 100 (or more) 
total sulfur samples since the last annual assessment shows that 
[gteqt]98 percent of the samples have a total sulfur content of 0.5 
grains/100 scf or less and if the GCV or percent methane requirement is 
also met. The effective date of the annual total sulfur sampling 
requirement is January 1, 2003.
    (f) On-going sampling of the GCV of the pipeline natural gas is 
required under section 2.3.4.1 of this appendix.
    (g) For units that are required to monitor and report NOX 
mass emissions and heat input under subpart H of this part, but which 
are not affected units under the Acid Rain Program, the owner or 
operator is exempted from the requirements in paragraphs (a) and (e) of 
this section to document the total sulfur content of the pipeline 
natural gas.

                      2.3.2 Natural Gas Combustion

    The owner or operator may determine the SO2 mass 
emissions from the combustion of a fuel that meets the definition of 
natural gas, in Sec. 72.2 of this chapter, using the procedures of this 
section.

[[Page 429]]

                  2.3.2.1 SO2 Emission Rate

    The owner or operator may account for SO2 emissions 
either by using a default SO2 emission rate, as determined 
under section 2.3.2.1.1 of this appendix, or by daily sampling of the 
gas sulfur content using the procedures of section 2.3.3 of this 
appendix. For each affected unit using a default SO2 emission 
rate, the owner or operator must provide documentation that the fuel 
combusted is actually natural gas according to the procedures in section 
2.3.2.4 of this appendix.
    2.3.2.1.1 In lieu of daily sampling of the sulfur content of the 
natural gas, the owner or operator may either use the total sulfur 
content specified in a contract or tariff sheet as the SO2 
default emission rate or may calculate the default SO2 
emission rate based on fuel sampling results, using Equation D-1h. In 
Equation D-1h, the total sulfur content and GCV values shall be 
determined in accordance with Table D-5 of this appendix. Round off the 
calculated SO2 default emission rate to the nearest 0.0001 
lb/mmBtu.
[GRAPHIC] [TIFF OMITTED] TR12JN02.017

Where:

ER = Default SO2 emission rate for natural gas combustion, 
          lb/mmBtu.
Stotal = Total sulfur content of the natural gas, gr/100scf.
GCV = Gross calorific value of the natural gas, Btu/100scf.
7000 = Conversion of grains/100scf to lb/100scf.
2.0 = Ratio of lb SO2/lb S.
10\6\ = Conversion factor (Btu/mmBtu).

                          2.3.2.1.2 [Reserved]

                     2.3.2.2 Hourly Heat Input Rate

    Calculate hourly heat input rate for natural gas combustion, in 
mmBtu/hr, using the procedures in section 3.4.1 of this appendix. Use 
the measured fuel flow rate from section 2.1 of this appendix and the 
gross calorific value from section 2.3.4.2 of this appendix in the 
calculations.

   2.3.2.3 SO2 Mass Emission Rate and Hourly Mass Emissions

    For natural gas combustion, calculate the SO2 mass 
emission rate, in lb/hr, using Equation D-5 in section 3.3.2 of this 
appendix, when the default SO2 emission rate is used. Then, 
use the calculated SO2 mass emission rate and the unit 
operating time to determine the hourly SO2 mass emissions 
from natural gas combustion, in lb, using Equation D-12 in section 3.5.1 
of this appendix.

            2.3.2.4 Documentation that a Fuel Is Natural Gas

    (a) A fuel may initially qualify as natural gas, if information is 
provided in the monitoring plan required under Sec. 75.53, 
demonstrating that the definition of natural gas in Sec. 72.2 of this 
chapter has been met. The information must demonstrate that the fuel 
meets either the percent methane or GCV requirement and has a total 
sulfur content of 20.0 grains/100 scf or less. This demonstration must 
be made using one of the following sources of information:
    (1) The gas quality characteristics specified by a purchase 
contract, tariff sheet, or by a transportation contract; or
    (2) Historical fuel sampling data for the previous 12 months, 
documenting the total sulfur content of the fuel and the GCV and/or 
percentage by volume of methane. The results of all sample analyses 
obtained by or provided to the owner or operator in the previous 12 
months shall be used in the demonstration, and each sample result must 
meet the definition of natural gas in Sec. 72.2 of this chapter; or
    (3) If the requirements of paragraphs (a)(1) and (a)(2) of this 
section cannot be met, a fuel may initially qualify as natural gas if at 
least one representative sample of the fuel is obtained and analyzed for 
total sulfur content and for either the gross calorific value (GCV) or 
percent methane, and the results of the sample analysis show that the 
fuel meets the definition of natural gas in Sec. 72.2 of this chapter. 
Use the sampling methods specified in sections 2.3.3.1.2 and 2.3.4 of 
this appendix. The required fuel sample may be obtained and analyzed by 
the owner or operator, by an independent laboratory, or by the fuel 
supplier. If multiple samples are taken, each sample must meet the 
definition of natural gas in Sec. 72.2 of this chapter.
    (b) If the results of the fuel sampling under paragraph (a)(2) or 
(a)(3) of this section show that the fuel does not meet the definition 
of natural gas in Sec. 72.2 of this chapter, but those results are 
believed to be anomalous, the owner or operator may document the reasons 
for believing this in the monitoring plan for the unit, and may 
immediately perform additional sampling. In such cases, a minimum of 
three additional samples must be obtained and analyzed, and the results 
of each sample analysis must meet the definition of natural gas.

[[Page 430]]

    (c) If several affected units are supplied by a common source of 
gaseous fuel, a single sampling result may be applied to all of the 
units and it is not necessary to obtain a separate sample for each unit, 
provided that the composition of the fuel is not altered by blending or 
mixing it with other gaseous fuel(s) when it is transported from the 
sampling location to the affected units. For the purposes of this 
paragraph, the term ``other gaseous fuel(s)'' excludes compounds such as 
mercaptans when they are added in trace quantities for safety reasons.
    (d) If the results of fuel sampling and analysis under paragraph 
(a)(2), (a)(3), or (b) of this section show that the fuel does not 
qualify as natural gas, the owner or operator shall re-classify the fuel 
as ``other gaseous fuel'' and shall implement the procedures of section 
2.3.3 of this appendix, within 180 days of the end of the quarter in 
which the disqualifying sample was taken. In addition, the owner or 
operator shall use Equation D-1h in this appendix to calculate a default 
SO2 emission rate for the fuel, based on the results of the 
sample analysis that exceeded 20 grains/100 scf of total sulfur, and 
shall use that default emission rate to report SO2 mass 
emissions under this part until section 2.3.3 of this appendix has been 
fully implemented.
    (e) If a fuel qualifies as natural gas based on the specifications 
in a fuel contract or tariff sheet, no additional, on-going sampling of 
the fuel's total sulfur content is required, provided that the contract 
or tariff sheet is current, valid and representative of the fuel 
combusted in the unit. If the fuel qualifies as natural gas based on 
fuel sampling and analysis, the owner or operator shall sample the fuel 
for total sulfur content at least annually and when the fuel supply 
source changes. For the purposes of this paragraph, (e), sampling 
``annually'' means that at least one sample is taken in each calendar 
year. The effective date of the annual total sulfur sampling requirement 
is January 1, 2003.
    (f) On-going sampling of the GCV of the natural gas is required 
under section 2.3.4.2 of this appendix.
    (g) For units that are required to monitor and report NOX 
mass emissions and heat input under subpart H of this part, but which 
are not affected units under the Acid Rain Program, the owner or 
operator is exempted from the requirements in paragraphs (a) and (e) of 
this section to document the total sulfur content of the natural gas.

        2.3.3 SO2 Mass Emissions From Any Gaseous Fuel

    The owner or operator of a unit may determine SO2 mass 
emissions using this section for any gaseous fuel (including fuels such 
as refinery gas, landfill gas, digester gas, coke oven gas, blast 
furnace gas, coal-derived gas, producer gas or any other gas which may 
have a variable sulfur content).

                  2.3.3.1 Sulfur Content Determination

    2.3.3.1.1 Analyze the total sulfur content of the gaseous fuel in 
grains/100 scf, at the frequency specified in Table D-5 of this 
appendix. That is: for fuel delivered in discrete shipments or lots, 
sample each shipment or lot. For fuel transmitted by pipeline, sample 
hourly unless a demonstration is provided under section 2.3.6 of this 
appendix showing that the gaseous fuel qualifies for less frequent 
(i.e., daily or annual) sampling. If daily sampling is required, 
determine the sulfur content using either manual sampling or a gas 
chromatograph. If hourly sampling is required, determine the sulfur 
content using a gas chromatograph. For units that are required to 
monitor and report NOX mass emissions and heat input under 
subpart H of this part, but which are not affected units under the Acid 
Rain Program, the owner or operator is exempted from the requirements of 
this section to document the total sulfur content of the gaseous fuel.
    2.3.3.1.2 Use one of the following methods when using manual 
sampling (as applicable to the type of gas combusted) to determine the 
sulfur content of the fuel: ASTM D1072-06, Standard Test Method for 
Total Sulfur in Fuel Gases by Combustion and Barium Chloride Titration, 
ASTM D4468-85 (Reapproved 2006), Standard Test Method for Total Sulfur 
in Gaseous Fuels by Hydrogenolysis and Rateometric Colorimetry, ASTM 
D5504-01, Standard Test Method for Determination of Sulfur Compounds in 
Natural Gas and Gaseous Fuels by Gas Chromatography and 
Chemiluminescence, ASTM D6667-04, Standard Test Method for Determination 
of Total Volatile Sulfur in Gaseous Hydrocarbons and Liquefied Petroleum 
Gases by Ultraviolet Fluorescence, or ASTM D3246-96, Standard Test 
Method for Sulfur in Petroleum Gas by Oxidative Microcoulometry, (all 
incorporated by reference under Sec. 75.6 of this part). Alternatively, 
the gas samples may be analyzed for percent sulfur by any consensus 
standard method prescribed for the affected unit under part 60 of this 
chapter.
    2.3.3.1.3 The sampling and analysis of daily manual samples may be 
performed by the owner or operator, an outside laboratory, or the gas 
supplier. If hourly sampling with a gas chromatograph is required, or a 
source chooses to use an online gas chromatograph to determine daily 
fuel sulfur content, the owner or operator shall develop and implement a 
program to quality assure the data from the gas chromatograph, in 
accordance with the manufacturer's recommended procedures. The quality 
assurance procedures shall be kept on-site, in a form suitable for 
inspection.

[[Page 431]]

    2.3.3.1.4 Results of all sample analyses must be available no later 
than thirty calendar days after the sample is taken.

                2.3.3.2 SO2 Mass Emission Rate

    Calculate the SO2 mass emission rate for the gaseous 
fuel, in lb/hr, using Equation D-4 or D-5 (as applicable) in section 
3.3.1 of this appendix. Equation D-5 may only be used if a demonstration 
is performed under section 2.3.6 of this appendix, showing that the fuel 
qualifies to use a default SO2 emission rate to account for 
SO2 mass emissions under this part. Use the appropriate 
sulfur content or default SO2 emission rate in Equation D-4 
or D-5, as specified in Table D-5 of this appendix. If the fuel 
qualifies to use Equation D-5, the default SO2 emission rate 
shall be calculated using Equation D-1h in section 2.3.2.1.1 of this 
appendix, replacing the words ``natural gas'' in the equation 
nomenclature with the words, ``gaseous fuel''. In all cases, for 
reporting purposes, apply the results of the required periodic total 
sulfur samples in accordance with the provisions of section 2.3.7 of 
this appendix.

                     2.3.3.3 Hourly Heat Input Rate

    Calculate the hourly heat input rate for combustion of the gaseous 
fuel, using the provisions in section 3.4.1 of this appendix. Use the 
measured fuel flow rate from section 2.1 of this appendix and the gross 
calorific value from section 2.3.4.3 of this appendix in the 
calculations.

             2.3.4 Gross Calorific Values for Gaseous Fuels

    Determine the GCV of each gaseous fuel at the frequency specified in 
this section, using one of the following methods: ASTM D1826-94 
(Reapproved 1998), ASTM D3588-98, ASTM D4891-89 (Reapproved 2006), GPA 
Standard 2172-96, Calculation of Gross Heating Value, Relative Density 
and Compressibility Factor for Natural Gas Mixtures from Compositional 
Analysis, or GPA Standard 2261-00, Analysis for Natural Gas and Similar 
Gaseous Mixtures by Gas Chromatography (all incorporated by reference 
under Sec. 75.6 of this part). Use the appropriate GCV value, as 
specified in section 2.3.4.1, 2.3.4.2, or 2.3.4.3 of this appendix, in 
the calculation of unit hourly heat input rates. Alternatively, the gas 
samples may be analyzed for heat content by any consensus standard 
method prescribed for the affected unit under part 60 of this chapter.

                   2.3.4.1 GCV of Pipeline Natural Gas

    Determine the GCV of fuel that is pipeline natural gas, as defined 
in Sec. 72.2 of this chapter, at least once per calendar month. For GCV 
used in calculations use the specifications in Table D-5: either the 
value from the most recent monthly sample, the highest value specified 
in a contract or tariff sheet, or the highest value from the previous 
year. The fuel GCV value from the most recent monthly sample shall be 
used for any month in which that value is higher than a contract limit. 
If a unit combusts pipeline natural gas for less than 48 hours during a 
calendar month, the sampling and analysis requirement for GCV is waived 
for that calendar month. The preceding waiver is limited by the 
condition that at least one analysis for GCV must be performed for each 
quarter the unit operates for any amount of time. If multiple GCV 
samples are taken and analyzed in a particular month, the GCV values 
from all samples shall be averaged arithmetically to obtain the monthly 
GCV. Then, apply the monthly average GCV value as described in paragraph 
(c) in section 2.3.7 of this appendix.

                       2.3.4.2 GCV of Natural Gas

    Determine the GCV of fuel that is natural gas, as defined in Sec. 
72.2 of this chapter, on a monthly basis, in the same manner as 
described for pipeline natural gas in section 2.3.4.1 of this appendix.

                   2.3.4.3 GCV of Other Gaseous Fuels

    For gaseous fuels other than natural gas or pipeline natural gas, 
determine the GCV as specified in section 2.3.4.3.1, 2.3.4.3.2 or 
2.3.4.3.3, as applicable. For reporting purposes, apply the results of 
the required periodic GCV samples in accordance with the provisions of 
section 2.3.7 of this appendix.
    2.3.4.3.1 For a gaseous fuel that is delivered in discrete shipments 
or lots, determine the GCV for each shipment or lot. The determination 
may be made by sampling each delivery or by sampling the supply tank 
after each delivery. For sampling of each delivery, use the highest GCV 
in the previous year's samples. For sampling from the tank after each 
delivery, use either the most recent GCV sample, the maximum GCV 
specified in the fuel contract or tariff sheet, or the highest GCV from 
the previous year's samples.
    2.3.4.3.2 For any gaseous fuel that does not qualify as pipeline 
natural gas or natural gas, which is not delivered in shipments or lots, 
and for which the owner or operator performs the 720 hour test under 
section 2.3.5 of this appendix, if the results of the test demonstrate 
that the gaseous fuel has a low GCV variability, determine the GCV at 
least monthly (as described in section 2.3.4.1 of this appendix). In 
calculations of hourly heat input for a unit, use either the most recent 
monthly sample, the maximum GCV specified in the fuel contract or tariff 
sheet, or the highest fuel GCV from the previous year's samples.
    2.3.4.3.3 For any other gaseous fuel, determine the GCV at least 
daily and use the actual fuel GCV in calculations of unit hourly

[[Page 432]]

heat input. If an online gas chromatograph or on-line calorimeter is 
used to determine fuel GCV each day, the owner or operator shall develop 
and implement a program to quality assure the data from the gas 
chromatograph or on-line calorimeter, in accordance with the 
manufacturer's recommended procedures. The quality assurance procedures 
shall be kept on-site, in a form suitable for inspection.

               2.3.5 Demonstration of Fuel GCV Variability

    (a) This optional demonstration may be made for any fuel which does 
not qualify as pipeline natural gas or natural gas, and is not delivered 
only in shipments or lots. The demonstration data may be used to show 
that monthly sampling of the GCV of the gaseous fuel or blend is 
sufficient, in lieu of daily GCV sampling.
    (b) To make this demonstration, proceed as follows. Provide a 
minimum of 720 hours of data, indicating the GCV of the gaseous fuel or 
blend (in Btu/100 scf). The demonstration data shall be obtained using 
either: hourly sampling and analysis using the methods in section 2.3.4 
to determine GCV of the fuel; an on-line gas chromatograph capable of 
determining fuel GCV on an hourly basis; or an on-line calorimeter. For 
gaseous fuel produced by a variable process, the data shall be 
representative of and include all process operating conditions including 
seasonal and yearly variations in process which may affect fuel GCV.
    (c) The data shall be reduced to hourly averages. The mean GCV value 
and the standard deviation from the mean shall be calculated from the 
hourly averages. Specifically, the gaseous fuel is considered to have a 
low GCV variability, and monthly gas sampling for GCV may be used, if 
the mean value of the GCV multiplied by 1.075 is greater than the sum of 
the mean value and one standard deviation. If the gaseous fuel or blend 
does not meet this requirement, then daily fuel sampling and analysis 
for GCV, using manual sampling, a gas chromatograph or an on-line 
calorimeter is required.

             2.3.6 Demonstration of Fuel Sulfur Variability

    (a) This demonstration may be made for any fuel which does not 
qualify as pipeline natural gas or natural gas, and is not delivered 
only in shipments or lots. The results of the demonstration may be used 
to show that daily sampling for sulfur in the fuel is sufficient, rather 
than hourly sampling. The procedures in this section may also be used to 
demonstrate that a particular gaseous fuel qualifies to use a default 
SO2 emission rate (calculated using Equation D-1h in section 
2.3.2.1.1 of this appendix) for the purpose of reporting hourly 
SO2 mass emissions under this part. To make this 
demonstration, proceed as follows. Provide a minimum of 720 hours of 
data, indicating the total sulfur content of the gaseous fuel (in gr/100 
scf). The demonstration data shall be obtained using either manual 
hourly sampling or an on-line gas chromatograph (GC) capable of 
determining fuel total sulfur content on an hourly basis. For gaseous 
fuel produced by a variable process, the data shall be representative of 
all process operating conditions including seasonal or annual variations 
which may affect fuel sulfur content.
    (b) If the data are collected with an on-line GC, reduce the data to 
hourly average values of the total sulfur content of the fuel. If manual 
hourly sampling is used, the results of each hourly sample analysis 
shall be the total sulfur value for that hour. Express all hourly 
average values of total sulfur content in units of grains/100 scf. Use 
all of the hourly average values of total sulfur content in grains/100 
scf to calculate the mean value and the standard deviation. Also 
determine the 90th percentile and maximum hourly values of the total 
sulfur content for the data set. If the standard deviation of the hourly 
values from the mean does not exceed 5.0 grains/100 scf, the fuel has a 
low sulfur variability. If the standard deviation exceeds 5.0 grains/100 
scf, the fuel has a high sulfur variability. Based on the results of 
this determination, establish the required sampling frequency and 
SO2 mass emissions methodology for the gaseous fuel, as 
follows:
    (1) If the gaseous fuel has a low sulfur variability (irrespective 
of the total sulfur content), the owner or operator may either perform 
daily sampling of the fuel's total sulfur content using manual sampling 
or a GC, or may report hourly SO2 mass emissions data using a 
default SO2 emission rate calculated by substituting the 90th 
percentile value of the total sulfur content in Equation D-1h.
    (2) If the gaseous fuel has a high sulfur variability, but the 
maximum hourly value of the total sulfur content does not exceed 20 
grains/100 scf, the owner or operator may either perform hourly sampling 
of the fuel's total sulfur content using an on-line GC, or may report 
hourly SO2 mass emissions data using a default SO2 
emission rate calculated by substituting the maximum value of the total 
sulfur content in Equation D-1h.
    (3) If the gaseous fuel has a high sulfur variability and the 
maximum hourly value of the total sulfur content exceeds 20 grains/100 
scf, the owner or operator shall perform hourly sampling of the fuel's 
total sulfur content, using an on-line GC.
    (4) Any gaseous fuel under paragraph (b)(1) or (b)(2) of this 
section, for which the owner or operator elects to use a default 
SO2 emission rate for reporting purposes is subject to the 
annual total sulfur sampling requirement under section 2.3.2.4(e) of 
this appendix.

[[Page 433]]

               2.3.7 Application of Fuel Sampling Results

    For reporting purposes, apply the results of the required periodic 
fuel samples described in Tables D-4 and D-5 of this appendix as 
follows. Use Equation D-1h to recalculate the SO2 emission 
rate, as necessary.
    (a) For daily samples of total sulfur content or GCV:
    (1) If the actual value is to be used in the calculations, apply the 
results of each daily sample to all hours in the day on which the sample 
is taken; or
    (2) If the highest value in the previous 30 daily samples is to be 
used in the calculations, apply that value to all hours in the current 
day. If, for a particular unit, fewer than 30 daily samples have been 
collected, use the highest value from all available samples until 30 
days of historical sampling results have been obtained.
    (b) For annual samples of total sulfur content:
    (1) For pipeline natural gas, use the results of annual sample 
analyses in the calculations only if the results exceed 0.5 grains/100 
scf. In that case, if the fuel still qualifies as natural gas, follow 
the procedures in paragraph (b)(2) of this section. If the fuel does not 
qualify as natural gas, the owner or operator shall implement the 
procedures in section 2.3.3 of this appendix, in the time frame 
specified in sections 2.3.1.4(d) and 2.3.2.4(d) of this appendix;
    (2) For natural gas, if only one sample is taken, apply the results 
beginning at the date on which the sample was taken. If multiple samples 
are taken and averaged, apply the results beginning at the date on which 
the last sample used in the annual assessment was taken;
    (3) For other gaseous fuels with an annual sampling requirement 
under section 2.3.6(b)(4) of this appendix, use the sample results in 
the calculations only if the results exceed the 90th percentile value or 
maximum value (as applicable) from the 720-hour demonstration of fuel 
sulfur content and variability under section 2.3.6 of this appendix.
    (c) For monthly samples of the fuel GCV:
    (1) If the actual monthly value is to be used in the calculations 
and only one sample is taken, apply the results starting from the date 
on which the sample was taken. If multiple samples are taken and 
averaged, apply the monthly average GCV value to the entire month; or
    (2) If an assumed value (contract maximum or highest value from 
previous year's samples) is to be used in the calculations, apply the 
assumed value to all hours in each month of the quarter unless a higher 
value is obtained in a monthly GCV sample (or, if multiple samples are 
taken and averaged, if the monthly average exceeds the assumed value). 
In that case, if only one monthly sample is taken, use the sampled 
value, starting from the date on which the sample was taken. If multiple 
samples are taken and averaged, use the average value for the entire 
month in which the assumed value was exceeded. Consider the sample (or, 
if applicable, monthly average) results to be the new assumed value. 
Continue using the new assumed value unless and until one of the 
following occurs (as applicable to the reporting option selected): The 
assumed value is superseded by a higher value from a subsequent monthly 
sample (or by a higher monthly average); or the assumed value is 
superseded by a new contract in which case the new contract value 
becomes the assumed value at the time the fuel specified under the new 
contract begins to be combusted in the unit; or both the calendar year 
in which the new sampled value (or monthly average) exceeded the assumed 
value and the subsequent calendar year have elapsed.
    (d) For samples of gaseous fuel delivered in shipments or lots:
    (1) If the actual value for the most recent shipment is to be used 
in the calculations, apply the results of the most recent sample, from 
the date on which the sample was taken until the date on which the next 
sample is taken; or
    (2) If an assumed value (contract maximum or highest value from 
previous year's samples) is to be used in the calculations, apply the 
assumed value unless a higher value is obtained in a sample of a 
shipment. In that case, use the sampled value, starting from the date on 
which the sample was taken. Consider the sample results to be the new 
assumed value. Continue using the new assumed value unless and until: it 
is superseded by a higher value from a sample of a subsequent shipment; 
or (if applicable) it is superseded by a new contract in which case the 
new contract value becomes the assumed value at the time the fuel 
specified under the new contract begins to be combusted in the unit; or 
(if applicable) both the calendar year in which the sampled value 
exceeded the assumed value and the subsequent calendar year have 
elapsed.
    (e) When the owner or operator elects to use assumed values in the 
calculations, the results of periodic samples of sulfur content and GCV 
which show that the assumed value has not been exceeded need not be 
reported. Keep these sample results on file, in a format suitable for 
inspection.
    (f) Notwithstanding the requirements of paragraphs (b) through (d) 
of this section, in cases where the sample results are provided to the 
owner or operator by the supplier of the fuel, the owner or operator 
shall begin using the sampling results on the date of receipt of those 
results, rather than on the date that the sample was taken.

[[Page 434]]

                      2.4 Missing Data Procedures.

    When data from the procedures of this part are not available, 
provide substitute data using the following procedures.

               2.4.1 Missing Data for Oil and Gas Samples

    When fuel sulfur content, gross calorific value or, when necessary, 
density data are missing or invalid for an oil or gas sample taken 
according to the procedures in section 2.2.3, 2.2.4.1, 2.2.4.2, 2.2.4.3, 
2.2.5, 2.2.6, 2.2.7, 2.3.3.1.2, or 2.3.4 of this appendix, then 
substitute the maximum potential sulfur content, density, or gross 
calorific value of that fuel from Table D-6 of this appendix. Except for 
the annual samples of fuel sulfur content required under sections 
2.3.1.4(e), 2.3.2.4(e) and 2.3.6(b)(5) of this appendix, the missing 
data values in Table D-6 shall be reported whenever the results of a 
required sample of sulfur content, GCV or density is missing or invalid 
in the current calendar year, irrespective of which reporting option is 
selected (i.e., actual value, contract value or highest value from the 
previous year). For the annual samples of fuel sulfur content required 
under sections 2.3.1.4(e), 2.3.2.4(e) and 2.3.6(b)(5) of this appendix, 
if a valid annual sample has not been obtained by the end of a 
particular calendar year, the appropriate missing data value in Table D-
6 shall be reported, beginning with the first unit operating hour in the 
next calendar year. The substitute data value(s) shall be used until the 
next valid sample for the missing parameter(s) is obtained. Note that 
only actual sample results shall be used to determine the ``highest 
value from the previous year'' when that reporting option is used; 
missing data values shall not be used in the determination.
[GRAPHIC] [TIFF OMITTED] TR12JN02.018

    2.4.2 Missing Data Procedures for Fuel Flow Rate
    Whenever data are missing from any primary fuel flowmeter system (as 
defined in Sec. 72.2 of this chapter) and there is no backup system 
available to record the fuel flow rate, use the procedures in sections 
2.4.2.2 and 2.4.2.3 of this appendix to account for the flow rate of 
fuel combusted at the unit for each hour during the missing data period. 
Alternatively, for a fuel flowmeter system used to measure the fuel 
combusted by a

[[Page 435]]

peaking unit, the simplified fuel flow missing data procedure in section 
2.4.2.1 of this appendix may be used. Before using the procedures in 
sections 2.4.2.2 and 2.4.2.3 of this appendix, establish load ranges for 
the unit using the procedures of section 2 in appendix C to this part, 
except for units that do not produce electrical output (i.e., megawatts) 
or thermal output (e.g., klb of steam per hour). The owner or operator 
of a unit that does not produce electrical or thermal output shall 
either perform missing data substitution without segregating the fuel 
flow rate data into bins, or may petition the Administrator under Sec. 
75.66 for permission to segregate the data into operational bins. When 
load ranges are used for fuel flow rate missing data purposes, separate, 
fuel-specific databases shall be created and maintained. A database 
shall be kept for each type of fuel combusted in the unit, for the hours 
in which the fuel is combusted alone in the unit. An additional database 
shall be kept for each type of fuel, for the hours in which it is co-
fired with any other type(s) of fuel(s).

  2.4.2.1 Simplified Fuel Flow Rate Missing Data Procedure for Peaking 
                                  Units

    If no fuel flow rate data are available for a fuel flowmeter system 
installed on a peaking unit (as defined in Sec. 72.2 of this chapter), 
then substitute for each hour of missing data using the maximum 
potential fuel flow rate. The maximum potential fuel flow rate is the 
lesser of the following:
    (a) The maximum fuel flow rate the unit is capable of combusting or
    (b) The maximum flow rate that the fuel flowmeter can measure (i.e., 
the upper range value of the flowmeter).

       2.4.2.2 Standard Missing Data Procedures--Single Fuel Hours

    For missing data periods that occur when only one type of fuel is 
being combusted, provide substitute data for each hour in the missing 
data period as follows.
    2.4.2.2.1 If load-based missing data procedures are used, substitute 
the arithmetic average of the hourly fuel flow rate(s) measured and 
recorded by a certified fuel flowmeter system at the corresponding 
operating unit load range during the previous 720 operating hours in 
which the unit combusted only that same fuel. If no fuel flow rate data 
are available at the corresponding load range, use data from the next 
higher load range, if such data are available. If no quality-assured 
fuel flow rate data are available at either the corresponding load range 
or a higher load range, substitute the maximum potential fuel flow rate 
(as defined in section 2.4.2.1 of this appendix) for each hour of the 
missing data period.
    2.4.2.2.2 For units that do not produce electrical or thermal output 
and therefore cannot use load-based missing data procedures, provide 
substitute data for each hour of the missing data period as follows. 
Substitute the arithmetic average of the hourly fuel flow rates measured 
and recorded by a certified fuel flowmeter system during the previous 
720 operating hours in which the unit combusted only that same fuel. If 
no quality-assured fuel flow rate data are available, substitute the 
maximum potential fuel flow rate (as defined in section 2.4.2.1 of this 
appendix) for each hour of the missing data period.

      2.4.2.3 Standard Missing Data Procedures--Multiple Fuel Hours

    For missing data periods that occur when two or more different types 
of fuel are being co-fired, provide substitute fuel flow rate data for 
each hour of the missing data period as follows.
    2.4.2.3.1 If load-based missing data procedures are used, substitute 
the maximum hourly fuel flow rate measured and recorded by a certified 
fuel flowmeter system at the corresponding load range during the 
previous 720 operating hours when the fuel for which the flow rate data 
are missing was co-fired with any other type of fuel. If no such 
quality-assured fuel flow rate data are available at the corresponding 
load range, use data from the next higher load range (if available). If 
no quality-assured fuel flow rate data are available for co-fired hours, 
either at the corresponding load range or a higher load range, 
substitute the maximum potential fuel flow rate (as defined in section 
2.4.2.1 of this appendix) for each hour of the missing data period.
    2.4.2.3.2 For units that do not produce electrical or thermal output 
and therefore cannot use load-based missing data procedures, provide 
substitute fuel flow rate data for each hour of the missing data period 
as follows. Substitute the maximum hourly fuel flow rate measured and 
recorded by a certified fuel flowmeter system during the previous 720 
operating hours in which the fuel for which the flow rate data are 
missing was co-fired with any other type of fuel. If no quality-assured 
fuel flow rate data for co-fired hours are available, substitute the 
maximum potential fuel flow rate (as defined in section 2.4.2.1 of this 
appendix) for each hour of the missing data period.
    2.4.2.3.3 If, during an hour in which different types of fuel are 
co-fired, quality-assured fuel flow rate data are missing for two or 
more of the fuels being combusted, apply the procedures in section 
2.4.2.3.1 or 2.4.2.3.2 of this appendix (as applicable) separately for 
each type of fuel.
    2.4.2.3.4 If the missing data substitution required in section 
2.4.2.3.1 or 2.4.2.3.2 causes the reported hourly heat input rate based 
on the combined fuel usage to exceed the maximum rated hourly heat input 
of the unit,

[[Page 436]]

adjust the substitute fuel flow rate value(s) so that the reported heat 
input rate equals the unit's maximum rated hourly heat input. Manual 
entry of the adjusted substitute data values is permitted.
    2.4.3. In any case where the missing data provisions of this section 
require substitution of data measured and recorded more than three years 
(26,280 clock hours) prior to the date and time of the missing data 
period, use three years (26,280 clock hours) in place of the prescribed 
lookback period. In addition, for a new or newly-affected unit, until 
720 hours of quality-assured fuel flowmeter data are available for the 
lookback periods described in sections 2.4.2.2 and 2.4.2.3 of this 
appendix, use all of the available fuel flowmeter data to determine the 
appropriate substitute data values.

                             3. Calculations

    Calculate hourly SO2 mass emission rate from combustion 
of oil fuel using the procedures in section 3.1 of this appendix. 
Calculate hourly SO2 mass emission rate from combustion of 
gaseous fuel using the procedures in section 3.3 of this appendix. 
(Note: the SO2 mass emission rates in sections 3.1 and 3.3 
are calculated such that the rate, when multiplied by unit operating 
time, yields the hourly SO2 mass emissions for a particular 
fuel for the unit.) Calculate hourly heat input rate for both oil and 
gaseous fuels using the procedures in section 3.4 of this appendix. 
Calculate total SO2 mass emissions and heat input for each 
hour, each quarter and the year to date using the procedures under 
section 3.5 of this appendix. Where an oil flowmeter records volumetric 
flow rate, use the calculation procedures in section 3.2 of this 
appendix to calculate the mass flow rate of oil.

        3.1 SO2 Mass Emission Rate Calculation for Oil

    3.1.1 Use Equation D-2 to calculate SO2 mass emission 
rate per hour (lb/hr):
[GRAPHIC] [TIFF OMITTED] TR26MY99.021

Where:

SO2rate-oil = Hourly mass emission rate of SO2 
          emitted from combustion of oil, lb/hr.
OILrate = Mass rate of oil consumed per hr during combustion, 
          lb/hr.
%Soil = Percentage of sulfur by weight in the oil.
2.0 = Ratio of lb SO 2/lb S.

    3.1.2 Record the SO2 mass emission rate from oil for each 
hour that oil is combusted.

      3.2 Mass Flow Rate Calculation for Volumetric Oil Flowmeters

    3.2.1 Where the oil flowmeter records volumetric flow rate rather 
than mass flow rate, calculate and record the oil mass flow rate for 
each hourly period using hourly oil flow rate measurements and the 
density or specific gravity of the oil sample.
    3.2.2 Convert density, specific gravity, or API gravity of the oil 
sample to density of the oil sample at the sampling location's 
temperature using ASTM D1250-07, Standard Guide for Use of the Petroleum 
Measurement Tables (incorporated by reference under (Sec. 75.6 of this 
part).
    3.2.3 Where density of the oil is determined by the applicable ASTM 
procedures from section 2.2.6 of this appendix, use Equation D-3 to 
calculate the rate of the mass of oil consumed (in lb/hr):
[GRAPHIC] [TIFF OMITTED] TR26MY99.022

Where:

OILrate = Mass rate of oil consumed per hr, lb/hr.
Voil-rate = Volume rate of oil consumed per hr, measured in 
          scf/hr, gal/hr, barrels/hr, or m \3\/hr.
Doil = Density of oil, measured in lb/scf, lb/gal, lb/barrel, 
          or lb/m\3\.

   3.3 SO2 Mass Emission Rate Calculation for Gaseous Fuels

    3.3.1 Use Equation D-4 to calculate the SO2 mass emission 
rate when using the optional gas sampling and analysis procedures in 
sections 2.3.1 and 2.3.2 of this appendix, or the required gas sampling 
and analysis procedures in section 2.3.3 of this appendix. Total sulfur 
content of a fuel must be determined using the procedures of 2.3.3.1.2 
of this appendix:
[GRAPHIC] [TIFF OMITTED] TR12JN02.019


[[Page 437]]


Where:

SO2rate-gas = Hourly mass rate of SO2 emitted due to 
          combustion of gaseous fuel, lb/hr.
GASrate = Hourly metered flow rate of gaseous fuel combusted, 100 scf/
          hr.
Sgas = Sulfur content of gaseous fuel, in grain/100 scf.
2.0 = Ratio of lb SO2/lb S.
7000 = Conversion of grains/100 scf to lb/100 scf.

    3.3.2 Use Equation D-5 to calculate the SO2 mass emission 
rate when using a default emission rate from section 2.3.1.1 or 
2.3.2.1.1 of this appendix:
[GRAPHIC] [TIFF OMITTED] TR26MY99.024

where:

SO2rate = Hourly mass emission rate of SO2 from 
          combustion of a gaseous fuel, lb/hr.
ER = SO2 emission rate from section 2.3.1.1 or 2.3.2.1.1, of 
          this appendix, lb/mmBtu.
HIrate = Hourly heat input rate of a gaseous fuel, calculated 
          using procedures in section 3.4.1 of this appendix, in mmBtu/
          hr.

    3.3.3 Record the SO2 mass emission rate for each hour 
when the unit combusts a gaseous fuel.

                   3.4 Calculation of Heat Input Rate

                 3.4.1 Heat Input Rate for Gaseous Fuels

    (a) Determine total hourly gas flow or average hourly gas flow rate 
with a fuel flowmeter in accordance with the requirements of section 2.1 
of this appendix and the fuel GCV in accordance with the requirements of 
section 2.3.4 of this appendix. If necessary perform the 720-hour test 
under section 2.3.5 to determine the appropriate fuel GCV sampling 
frequency.
    (b) Then, use Equation D-6 to calculate heat input rate from gaseous 
fuels for each hour.
[GRAPHIC] [TIFF OMITTED] TR26MY99.025

Where:

HIrate-gas = Hourly heat input rate from combustion of the 
          gaseous fuel, mmBtu/hr.
GASrate = Average volumetric flow rate of fuel, for the 
          portion of the hour in which the unit operated, 100 scf/hr.
GCVgas = Gross calorific value of gaseous fuel, Btu/100 scf.
10 \6\ = Conversion of Btu to mmBtu.

    (c) Note that when fuel flow is measured on an hourly totalized 
basis (e.g. a fuel flowmeter reports totalized fuel flow for each hour), 
before Equation D-6 can be used, the total hourly fuel usage must be 
converted from units of 100 scf to units of 100 scf/hr using Equation D-
7:
[GRAPHIC] [TIFF OMITTED] TR26MY99.026

Where:

GASrate = Average volumetric flow rate of fuel for the 
          portion of the hour in which the unit operated, 100 scf/hr.
GASunit = Total fuel combusted during the hour, 100 scf.
t = Unit operating time, hour or fraction of an hour (in equal 
          increments that can range from one hundredth to one quarter of 
          an hour, at the option of the owner or operator).

            3.4.2 Heat Input Rate From the Combustion of Oil

    (a) Determine total hourly oil flow or average hourly oil flow rate 
with a fuel flowmeter, in accordance with the requirements of section 
2.1 of this appendix. Determine oil GCV according to the requirements of 
section 2.2 of this appendix.
    Then, use Equation D-8 to calculate hourly heat input rate from oil 
for each hour:
[GRAPHIC] [TIFF OMITTED] TR26MY99.027

Where:

HIrate-oil = Hourly heat input rate from combustion of oil, 
          mmBtu/hr.
OILrate = Mass rate of oil consumed per hour, as determined 
          using procedures in section 3.2.3 of this appendix, in lb/hr, 
          tons/hr, or kg/hr.
GCVoil = Gross calorific value of oil, Btu/lb, Btu/ton, or 
          Btu/kg.
10\6\ = Conversion of Btu to mmBtu.
    (b) Note that when fuel flow is measured on an hourly totalized 
basis (e.g., a fuel flowmeter reports totalized fuel flow for each 
hour), before equation D-8 can be used, the total hourly fuel usage must 
be converted from units of lb to units of lb/hr, using equation D-9:

[[Page 438]]

[GRAPHIC] [TIFF OMITTED] TR26MY99.028

Where:

OILrate = Average fuel flow rate for the portion of the hour 
          which the unit operated in lb/hr.
OILunit = Total fuel combusted during the hour, lb.
t = Unit operating time, hour or fraction of an hour (in equal 
          increments that can range from one hundredth to one quarter of 
          an hour, at the option of the owner or operator).
    (c) For affected units that are not subject to an Acid Rain 
emissions limitation, but are regulated under a State or federal 
NOX mass emissions reduction program that adopts the 
requirements of subpart H of this part, the following alternative method 
may be used to determine the heat input rate from oil combustion, when 
the oil flowmeter measures the flow rate of oil volumetrically. In lieu 
of measuring the oil density and converting the volumetric oil flow rate 
to a mass flow rate, Equation D-8 may be applied on a volumetric basis. 
If this option is selected, express the terms OILrate and 
GCVoil in Equation D-8 in units of volume rather than mass. 
For example, the units of OILrate may be gal/hr and the units 
of GCVoil may be Btu/gal.

          3.4.3 Apportioning Heat Input Rate to Multiple Units

    (a) Use the procedure in this section to apportion hourly heat input 
rate to two or more units using a single fuel flowmeter which supplies 
fuel to the units. The designated representative may also petition the 
Administrator under Sec. 75.66 to use this apportionment procedure to 
calculate SO2 and CO2 mass emissions.
    (b) Determine total hourly fuel flow or flow rate through the fuel 
flowmeter supplying gas or oil fuel to the units. Convert fuel flow 
rates to units of 100 scf for gaseous fuels or to lb for oil, using the 
procedures of this appendix. Apportion the fuel to each unit separately 
based on hourly output of the unit in MWe or 1000 lb of 
steam/hr (klb/hr) using Equation F-21a or F-21b in appendix F to this 
part, as applicable:
    Equation D-10 [Reserved]
    Equation D-11 [Reserved]
    (c) Use the total apportioned fuel flow calculated from Equation F-
21a or F-21b to calculate the hourly unit heat input rate, using 
Equations D-6 and D-7 (for gas) or Equations D-8 and D-9 (for oil).

 3.5 Conversion of Hourly Rates to Hourly, Quarterly, and Year-to-Date 
                                 Totals

 3.5.1 Hourly SO2 Mass Emissions from the Combustion of all 
    Fuels. Determine the total mass emissions for each hour from the 
  combustion of all fuels using Equation D-12 (On and after January 1, 
 2009, determine the total mass emission rate (in lbs/hr) for each hour 
from the combustion of all fuels by dividing Equation D-12 by the actual 
                   unit operating time for the hour):
[GRAPHIC] [TIFF OMITTED] TR24JA08.019

Where:

MSO2-hr = Total mass of SO2 emissions from all 
          fuels combusted during the hour, lb.
SO2 rate-I = SO2 mass emission rate for each type 
          of gas or oil fuel combusted during the hour, lb/hr.
ti = Time each gas or oil fuel was combusted for the hour (fuel usage 
          time), fraction of an hour (in equal increments that can range 
          from one hundredth to one quarter of an hour, at the option of 
          the owner or operator).

           3.5.2 Quarterly Total SO2 Mass Emissions

    Sum the hourly SO2 mass emissions in lb as determined 
from Equation D-12 for all hours in a quarter using Equation D-13:
[GRAPHIC] [TIFF OMITTED] TR26MY99.032


[[Page 439]]


Where:

MSO2-qtr = Total mass of SO2 emissions from all 
          fuels combusted during the quarter, tons.
MSO2-hr = Hourly SO2 mass emissions determined 
          using Equation D-12, lb.
2000= Conversion factor from lb to tons.

            3.5.3 Year to Date SO2 Mass Emissions

    Calculate and record SO2 mass emissions in the year to 
date using Equation D-14:
[GRAPHIC] [TIFF OMITTED] TR26MY99.033

Where:

MSO2-YTD = Total SO2 mass emissions for the year 
          to date, tons.
MSO2-qtr = Total SO2 mass emissions for the 
          quarter, tons.

3.5.4 Hourly Total Heat Input Rate and Heat Input from the Combustion of 
                                all Fuels

    3.5.4.1 Determine the total heat input in mmBtu for each hour from 
the combustion of all fuels using Equation D-15:
[GRAPHIC] [TIFF OMITTED] TR26MY99.034

Where:

HIhr = Total heat input from all fuels combusted during the 
          hour, mmBtu.
HIrate-i = Heat input rate for each type of gas or oil 
          combusted during the hour, mmBtu/hr.
ti = Time each gas or oil fuel was combusted for the hour 
          (fuel usage time), fraction of an hour (in equal increments 
          that can range from one hundredth to one quarter of an hour, 
          at the option of the owner or operator).
    3.5.4.2 For reporting purposes, determine the heat input rate to 
each unit, in mmBtu/hr, for each hour from the combustion of all fuels 
using Equation D-15a:
[GRAPHIC] [TIFF OMITTED] TR12JN02.020

Where:

HIrate-hr = Total heat input rate from all fuels combusted 
          during the hour, mmBtu/hr.
HIrate-i = Heat input rate for each type of gas or oil 
          combusted during the hour, mmBtu/hr.
ti = Time each gas or oil fuel was combusted for the hour 
          (fuel usage time), fraction of an hour (in equal increments 
          that can range from one hundredth to one quarter of an hour, 
          at the option of the owner or operator).
tu = Unit operating time

                       3.5.5 Quarterly Heat Input

    Sum the hourly heat input values determined from equation D-15 for 
all hours in a quarter using Equation D-16:
[GRAPHIC] [TIFF OMITTED] TR12JN02.021

Where:

HIqtr = Total heat input from all fuels combusted during the quarter, 
          mmBtu.
HIqtr = Hourly heat input determined using Equation D-15, mmBtu.

                      3.5.6 Year-to-Date Heat Input

    Calculate and record the total heat input in the year to date using 
Equation D-17.
[GRAPHIC] [TIFF OMITTED] TR26MY99.036

HIYTD = Total heat input for the year to date, mmBtu.
HIqtr = Total heat input for the quarter, mmBtu.

                         3.6 Records and Reports

    Calculate and record quarterly and cumulative SO2 mass 
emissions and heat input for each calendar quarter using the procedures 
and equations of section 3.5 of this appendix. Calculate and record 
SO2 emissions and heat input data using a data acquisition 
and handling system. Report these data in a standard electronic format 
specified by the Administrator.

[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26548, 26551, May 17, 
1995; 61 FR 25585, May 22, 1996; 61 FR 59166, Nov. 20, 1996; 63 FR 
57513, Oct. 27, 1998; 64 FR 28652, May 26, 1999; 64 FR 37582, July 12, 
1999; 67 FR 40460, 40472, June 12, 2002; 67 FR 53505, Aug. 16, 2002; 73 
FR 4369, Jan. 24, 2008; 76 FR 17324, Mar. 28, 2011; 76 FR 20536, Apr. 
13, 2011; 77 FR 2460, Jan. 18, 2012]

    Editorial Note: At 67 FR 53505, Aug. 16, 2002, section 2.4.1 Table 
D-6 was amended.

[[Page 440]]

However, this table is a photographed graphic and the amendments could 
not be incorporated.



Sec. Appendix E to Part 75--Optional NOX Emissions Estimation 
    Protocol for Gas-Fired Peaking Units and Oil-Fired Peaking Units

                            1. Applicability

                     1.1 Unit Operation Requirements

    This NOX emissions estimation procedure may be used in 
lieu of a continuous NOX emission monitoring system (lb/
mmBtu) for determining the average NOX emission rate and 
hourly NOX rate from gas-fired peaking units and oil-fired 
peaking units as defined in Sec. 72.2 of this chapter. If a unit's 
operations exceed the levels required to be a peaking unit, the owner or 
operator shall install and certify a NOX-diluent continuous 
emission monitoring system no later than December 31 of the following 
calendar year. If the required CEMS has not been installed and certified 
by that date, the owner or operator shall report the maximum potential 
NOX emission rate (MER) (as defined in Sec. 72.2 of this 
chapter) for each unit operating hour, starting with the first unit 
operating hour after the deadline and continuing until the CEMS has been 
provisionally certified. The provision of Sec. 75.12 apply to excepted 
monitoring systems under this appendix.

                            1.2 Certification

    1.2.1 Pursuant to the procedures in Sec. 75.20, complete all 
testing requirements to certify use of this protocol in lieu of a 
NOX continuous emission monitoring system no later than the 
applicable deadline specified in Sec. 75.4. Apply to the Administrator 
for certification to use this method no later than 45 days after the 
completion of all certification testing. Whenever the monitoring method 
is to be changed, reapply to the Administrator for certification of the 
new monitoring method.
    1.2.2 [Reserved]

                              2. Procedure

                     2.1 Initial Performance Testing

    Use the following procedures for: measuring NOX emission 
rates at heat input rate levels corresponding to different load levels; 
measuring heat input rate; and plotting the correlation between heat 
input rate and NOX emission rate, in order to determine the 
emission rate of the unit(s). The requirements in section 6.1.2 of 
appendix A to this part shall apply to any stack testing performed to 
obtain O2 and NOX concentration measurements under 
this appendix, either for units using the excepted methodology in this 
appendix or for units using the low mass emissions excepted methodology 
in Sec. 75.19.

                          2.1.1 Load Selection

    Establish at least four approximately equally spaced operating load 
points, ranging from the maximum operating load to the minimum operating 
load. Select the maximum and minimum operating load from the operating 
history of the unit during the most recent two years. (If projections 
indicate that the unit's maximum or minimum operating load during the 
next five years will be significantly different from the most recent two 
years, select the maximum and minimum operating load based on the 
projected dispatched load of the unit.) For new gas-fired peaking units 
or new oil-fired peaking units, select the maximum and minimum operating 
load from the expected maximum and minimum load to be dispatched to the 
unit in the first five calendar years of operation.

    2.1.2 NOX and O2 Concentration Measurements

    Use the following procedures to measure NOX and 
O2 concentration in order to determine NOX 
emission rate.
    2.1.2.1 For boilers, select an excess O2 level for each 
fuel (and, optionally, for each combination of fuels) to be combusted 
that is representative for each of the four or more load levels. If a 
boiler operates using a single, consistent combination of fuels only, 
the testing may be performed using the combination rather than each 
fuel. If a fuel is combusted only for the purpose of testing ignition of 
the burners for a period of five minutes or less per ignition test or 
for start-up, then the boiler NOX emission rate does not need 
to be tested separately for that fuel. Operate the boiler at a normal or 
conservatively high excess oxygen level in conjunction with these tests. 
Measure the NOX and O2 at each load point for each 
fuel or consistent fuel combination (and, optionally, for each 
combination of fuels) to be combusted. Measure the NOX and 
O2 concentrations according to method 7E and 3A in appendix A 
of part 60 of this chapter. Use a minimum of 12 sample points, located 
according to Method 1 in appendix A-1 to part 60 of this chapter. The 
designated representative for the unit may also petition the 
Administrator under Sec. 75.66 to use fewer sampling points. Such a 
petition shall include the proposed alternative sampling procedure and 
information demonstrating that there is no concentration stratification 
at the sampling location.
    2.1.2.2 For stationary gas turbines, sample at a minimum of 12 
points per run at each load level. Locate the sample points according to 
Method 1 in appendix A-1 to part 60 of this chapter. For each fuel or 
consistent

[[Page 441]]

combination of fuels (and, optionally, for each combination of fuels), 
measure the NOX and O2 concentrations at each 
sampling point using methods 7E and 3A in appendices A-4 and A-2 to part 
60 of this chapter. For diesel or dual fuel reciprocating engines, 
select the sampling site to be as close as practicable to the exhaust of 
the engine.
    2.1.2.3 Allow the unit to stabilize for a minimum of 15 minutes (or 
longer if needed for the NOX and O2 readings to 
stabilize) prior to commencing NOX, O2, and heat 
input measurements. Determine the measurement system response time 
according to sections 8.2.5 and 8.2.6 of method 7E in appendix A-4 to 
part 60 of this chapter. When inserting the probe into the flue gas for 
the first sampling point in each traverse, sample for at least one 
minute plus twice the measurement system response time (or longer, if 
necessary to obtain a stable reading). For all other sampling points in 
each traverse, sample for at least one minute plus the measurement 
system response time (or longer, if necessary to obtain a stable 
reading). Perform three test runs at each load condition and obtain an 
arithmetic average of the runs for each load condition. During each test 
run on a boiler, record the boiler excess oxygen level at 5 minute 
intervals.

                            2.1.3 Heat Input

    Measure the total heat input (mmBtu) and heat input rate during 
testing (mmBtu/hr) as follows:
    2.1.3.1 When the unit is combusting fuel, measure and record the 
flow of fuel consumed. Measure the flow of fuel with an in-line 
flowmeter(s) and automatically record the data. If a portion of the flow 
is diverted from the unit without being burned, and that diversion 
occurs downstream of the fuel flowmeter, an in-line flowmeter is 
required to account for the unburned fuel. Install and calibrate in-line 
flow meters using the procedures and specifications contained in 
sections 2.1.2, 2.1.3, 2.1.4, and 2.1.5 of appendix D of this part. 
Correct any gaseous fuel flow rate measured at actual temperature and 
pressure to standard conditions of 68 F and 29.92 inches of mercury.
    2.1.3.2 For liquid fuels, analyze fuel samples taken according to 
the requirements of section 2.2 of appendix D of this part to determine 
the heat content of the fuel. Determine heat content of liquid or 
gaseous fuel in accordance with the procedures in appendix F of this 
part. Calculate the heat input rate during testing (mmBtu/hr) associated 
with each load condition in accordance with equations F-19 or F-20 in 
appendix F of this part and total heat input using equation E-1 of this 
appendix. Record the heat input rate at each heat input/load point.

                          2.1.4 Emergency Fuel

    The designated representative of a unit that is restricted by its 
federal, State or local permit to combusting a particular fuel only 
during emergencies where the primary fuel is not available may claim an 
exemption from the requirements of this appendix for testing the 
NOX emission rate during combustion of the emergency fuel. To 
claim this exemption, the designated representative shall include in the 
monitoring plan for the unit documentation that the permit restricts use 
of the fuel to emergencies only. When emergency fuel is combusted, 
report the maximum potential NOX emission rate for the 
emergency fuel, in accordance with section 2.5.2.3 of this appendix. The 
designated representative shall also provide notice under Sec. 
75.61(a)(6) for each period when the emergency fuel is combusted.

                       2.1.5 Tabulation of Results

    Tabulate the results of each baseline correlation test for each fuel 
or, as applicable, combination of fuels, listing: time of test, 
duration, operating loads, heat input rate (mmBtu/hr), F-factors, excess 
oxygen levels, and NOX concentrations (ppm) on a dry basis 
(at actual excess oxygen level). Convert the NOX 
concentrations (ppm) to NOX emission rates (to the nearest 
0.001 lb/mm/Btu) according to equation F-5 of appendix F of this part or 
19-3 in method 19 of appendix A of part 60 of this chapter, as 
appropriate. Calculate the NOX emission rate in lb/mmBtu for 
each sampling point and determine the arithmetic average NOX 
emission rate of each test run. Calculate the arithmetic average of the 
boiler excess oxygen readings for each test run. Record the arithmetic 
average of the three test runs as the NOX emission rate and 
the boiler excess oxygen level for the heat input/load condition.

                        2.1.6 Plotting of Results

    Plot the tabulated results as an x-y graph for each fuel and (as 
applicable) combination of fuels combusted according to the following 
procedures.
    2.1.6.1 Plot the heat input rate (mmBtu/hr) as the independent (or 
x) variable and the NOX emission rates (lb/mmBtu) as the 
dependent (or y) variable for each load point. Construct the graph by 
drawing straight line segments between each load point. Draw a 
horizontal line to the y-axis from the minimum heat input (load) point.
    2.1.6.2 Units that co-fire gas and oil may be tested while firing 
gas only and oil only instead of testing with each combination of fuels. 
In this case, construct a graph for each fuel.

            2.2 Periodic NOX Emission Rate Testing

    Retest the NOX emission rate of the gas-fired peaking 
unit or the oil-fired peaking

[[Page 442]]

unit while combusting each type of fuel (or fuel mixture) for which a 
NOX emission rate versus heat input rate correlation curve 
was derived, at least once every 20 calendar quarters. If a required 
retest is not completed by the end of the 20th calendar quarter 
following the quarter of the last test, use the missing data 
substitution procedures in section 2.5 of this appendix, beginning with 
the first unit operating hour after the end of the 20th calendar 
quarter. Continue using the missing data procedures until the required 
retest has been passed. Note that missing data substitution is fuel-
specific (i.e., the use of substitute data is required only when 
combusting a fuel (or fuel mixture) for which the retesting deadline has 
not been met). Each time that a new fuel-specific correlation curve is 
derived from retesting, the new curve shall be used to report 
NOX emission rate, beginning with the first operating hour in 
which the fuel is combusted, following the completion of the retest. 
Notwithstanding this requirement, for non-Acid Rain Program units that 
report NOX mass emissions and heat input data only during the 
ozone season under Sec. 75.74(c), if the NOX emission rate 
testing is performed outside the ozone season, the new correlation curve 
may be used beginning with the first unit operating hour in the ozone 
season immediately following the testing.

 2.3 Other Quality Assurance/Quality Control-Related NOx Emission Rate 
                                 Testing

    When the operating levels of certain parameters exceed the limits 
specified below, or where the Administrator issues a notice requesting 
retesting because the NOX emission rate data availability for 
when the unit operates within all quality assurance/quality control 
parameters in this section since the last test is less than 90.0 
percent, as calculated by the Administrator, complete retesting of the 
NOX emission rate by the earlier of: (1) 30 unit operating 
days (as defined in Sec. 72.2 of this chapter) or (2) 180 calendar days 
after exceeding the limits or after the date of issuance of a notice 
from the Administrator to re-verify the unit's NOX emission 
rate. Submit test results in accordance with Sec. 75.60 within 45 days 
of completing the retesting.
    2.3.1 For a stationary gas turbine, select at least four operating 
parameters indicative of the turbine's NOX formation 
characteristics, and define in the QA plan for the unit the acceptable 
ranges for these parameters at each tested load-heat input point. The 
acceptable parametric ranges should be based upon the turbine 
manufacturer's recommendations. Alternatively, the owner or operator may 
use sound engineering judgment and operating experience with the unit to 
establish the acceptable parametric ranges, provided that the rationale 
for selecting these ranges is included as part of the quality-assurance 
plan for the unit. If the gas turbine uses water or steam injection for 
NOX control, the water/fuel or steam/fuel ratio shall be one 
of these parameters. During the NOx-heat input correlation tests, record 
the average value of each parameter for each load-heat input to ensure 
that the parameters are within the acceptable range. Redetermine the 
NOX emission rate-heat input correlation for each fuel and 
(optional) combination of fuels after continuously exceeding the 
acceptable range of any of these parameters for one or more successive 
operating periods totaling more than 16 unit operating hours.
    2.3.2 For a diesel or dual-fuel reciprocating engine, select at 
least four operating parameters indicative of the engine's 
NOX formation characteristics, and define in the QA plan for 
the unit the acceptable ranges for these parameters at each tested load-
heat input point. The acceptable parametric ranges should be based upon 
the engine manufacturer's recommendations. Alternatively, the owner or 
operator may use sound engineering judgment and operating experience 
with the unit to establish the acceptable parametric ranges, provided 
that the rationale for selecting these ranges is included as part of the 
quality-assurance plan for the unit. Any operating parameter critical 
for NOX control shall be included. During the NOX 
heat-input correlation tests, record the average value of each parameter 
for each load-heat input to ensure that the parameters are within the 
acceptable range. Redetermine the NOX emission rate-heat 
input correlation for each fuel and (optional) combination or fuels 
after continuously exceeding the acceptable range of any of these 
parameters for one or more successive operating periods totaling more 
than 16 unit operating hours.
    2.3.3 For boilers using the procedures in this appendix, the 
NOX emission rate heat input correlation for each fuel and 
(optional) combination of fuels shall be redetermined if the excess 
oxygen level at any heat input rate (or unit operating load) 
continuously exceeds by more than 2 percentage points O2 from 
the boiler excess oxygen level recorded at the same operating heat input 
rate during the previous NOX emission rate test for one or 
more successive operating periods totaling more than 16 unit operating 
hours.

   2.4 Procedures for Determining Hourly NOX Emission Rate

    2.4.1 Record the time (hr. and min.), load (MWge or steam load in 
1000 lb/hr, or mmBtu/hr thermal output), fuel flow rate and heat input 
rate (using the procedures in section 2.1.3 of this appendix) for each 
hour during which the unit combusts fuel. Calculate the total hourly 
heat input using equation E-1 of

[[Page 443]]

this appendix. Record the heat input rate for each fuel to the nearest 
0.1 mmBtu/hr. During partial unit operating hours or during hours where 
more than one fuel is combusted, heat input must be represented as an 
hourly rate in mmBtu/hr, as if the fuel were combusted for the entire 
hour at that rate (and not as the actual, total heat input during that 
partial hour or hour) in order to ensure proper correlation with the 
NOX emission rate graph.
    2.4.2 Use the graph of the baseline correlation results (appropriate 
for the fuel or fuel combination) to determine the NOX 
emissions rate (lb/mmBtu) corresponding to the heat input rate (mmBtu/
hr). Input this correlation into the data acquisition and handling 
system for the unit. Linearly interpolate to 0.1 mmBtu/hr heat input 
rate and 0.001 lb/mmBtu NOX. For each type of fuel, calculate 
NOX emission rate using the baseline correlation results from 
the most recent test with that fuel, beginning with the date and hour of 
the completion of the most recent test.
    2.4.3 To determine the NOX emission rate for a unit co-
firing fuels that has not been tested for that combination of fuels, 
interpolate between the NOX emission rate for each fuel as 
follows. Determine the heat input rate for the hour (in mmBtu/hr) for 
each fuel and select the corresponding NOX emission rate for 
each fuel on the appropriate graph. (When a fuel is combusted for a 
partial hour, determine the fuel usage time for each fuel and determine 
the heat input rate from each fuel as if that fuel were combusted at 
that rate for the entire hour in order to select the corresponding 
NOX emission rate.) Calculate the total heat input to the 
unit in mmBtu for the hour from all fuel combusted using Equation E-1. 
Calculate a Btu-weighted average of the emission rates for all fuels 
using Equation E-2 of this appendix. For each type of fuel, calculate 
NOX emission rate using the baseline correlation results from 
the most recent test with that fuel, beginning with the date and hour of 
the completion of the most recent test.
    2.4.4 For each hour, record the critical quality assurance 
parameters, as identified in the monitoring plan, and as required by 
section 2.3 of this appendix from the date and hour of the completion of 
the most recent test for each type of fuel.

                       2.5 Missing Data Procedures

    Provide substitute data for each unit electing to use this 
alternative procedure whenever a valid quality-assured hour of 
NOX emission rate data has not been obtained according to the 
procedures and specifications of this appendix. For the purpose of 
providing substitute data, calculate the maximum potential 
NOX emission rate (as defined in Sec. 72.2 of this chapter) 
for each type of fuel combusted in the unit.
    2.5.1 Use the procedures of this section whenever any of the quality 
assurance/quality control parameters exceeds the limits in section 2.3 
of this appendix or whenever any of the quality assurance/quality 
control parameters are not available.
    2.5.2 Substitute missing NOX emission rate data using the 
highest NOX emission rate tabulated during the most recent 
set of baseline correlation tests for the same fuel or, if applicable, 
combination of fuels, except as provided in sections 2.5.2.1, 2.5.2.2, 
2.5.2.3, and 2.5.2.4 of this appendix.
    2.5.2.1 If the measured heat input rate during any unit operating 
hour is higher than the highest heat input rate from the baseline 
correlation tests, the NOX emission rate for the hour is 
considered to be missing. Provide substitute data for each such hour, 
according to section 2.5.2.1.1 or 2.5.2.1.2 of this appendix, as 
applicable. Either:
    2.5.2.1.1 Substitute the higher of: the NOX emission rate 
obtained by linear extrapolation of the correlation curve, or the 
maximum potential NOX emission rate (MER) (as defined in 
Sec. 72.2 of this chapter), specific to the type of fuel being 
combusted. (For fuel mixtures, substitute the highest NOX MER 
value for any fuel in the mixture.) For units with NOX 
emission controls, the extrapolated NOX emission rate may 
only be used if the controls are documented (e.g., by parametric data) 
to be operating properly during the missing data period (see section 
2.5.2.2 of this appendix); or
    2.5.2.1.2 Substitute 1.25 times the highest NOX emission 
rate from the baseline correlation tests for the fuel (or fuel mixture) 
being combusted in the unit, not to exceed the MER for that fuel (or 
mixture). For units with NOX emission controls, the option to 
report 1.25 times the highest emission rate from the correlation curve 
may only be used if the controls are documented (e.g., by parametric 
data) to be operating properly during the missing data period (see 
section 2.5.2.2 of this appendix).
    2.5.2.2 For a unit with add-on NOX emission controls 
(e.g., steam or water injection, selective catalytic reduction), if, for 
any unit operating hour, the emission controls are either not in 
operation or if appropriate parametric data are unavailable to ensure 
proper operation of the controls, the NOX emission rate for 
the hour is considered to be missing. Substitute the fuel-specific MER 
(as defined in Sec. 72.2 of this chapter) for each such hour.
    2.5.2.3 When emergency fuel (as defined in Sec. 72.2) is combusted 
in the unit, report the fuel-specific NOX MER for each hour 
that the fuel is combusted, unless a NOX correlation curve 
has been derived for the fuel.
    2.5.2.4 Whenever 20 full calendar quarters have elapsed following 
the quarter of the last baseline correlation test for a particular

[[Page 444]]

type of fuel (or fuel mixture), without a subsequent baseline 
correlation test being done for that type of fuel (or fuel mixture), 
substitute the fuel-specific NOX MER (as defined in Sec. 
72.2 of this chapter) for each hour in which that fuel (or mixture) is 
combusted until a new baseline correlation test for that fuel (or 
mixture) has been successfully completed. For fuel mixtures, report the 
highest of the individual MER values for the components of the mixture.
    2.5.3 Maintain a record indicating which data are substitute data 
and the reasons for the failure to provide a valid quality-assured hour 
of NOX emission rate data according to the procedures and 
specifications of this appendix.
    2.5.4 Substitute missing data from a fuel flowmeter using the 
procedures in section 2.4.2 of appendix D to this part.
    2.5.5 Substitute missing data for gross calorific value of fuel 
using the procedures in sections 2.4.1 of appendix D to this part.

                             3. Calculations

                             3.1 Heat Input

    Calculate the total heat input by summing the product of heat input 
rate and fuel usage time of each fuel, as in the following equation:
[GRAPHIC] [TIFF OMITTED] TR26MY99.037

Where:

HT = Total heat input of fuel flow or a combination of fuel 
          flows to a unit, mmBtu.
HIfuel 1,2,3,...last = Heat input rate from each fuel, in 
          mmBtu/hr as determined using Equation F-19 or F-20 in section 
          5.5 of appendix F to this part, mmBtu/hr.
t1,2,3....last = Fuel usage time for each fuel (rounded up to 
          the nearest fraction of an hour (in equal increments that can 
          range from one hundredth to one quarter of an hour, at the 
          option of the owner or operator)).

                              3.2 F-factors

    Determine the F-factors for each fuel or combination of fuels to be 
combusted according to section 3.3 of appendix F of this part.

                    3.3 NOX Emission Rate

          3.3.1 Conversion from Concentration to Emission Rate

    Convert the NOX concentrations (ppm) and O2 
concentrations to NOX emission rates (to the nearest 0.01 lb/
mmBtu for tests performed prior to April 1, 2000, or to the nearest 
0.001 lb/mmBtu for tests performed on and after April 1, 2000), 
according to the appropriate one of the following equations: F-5 in 
appendix F to this part for dry basis concentration measurements or 19-3 
in Method 19 of appendix A to part 60 of this chapter for wet basis 
concentration measurements.

          3.3.2 Quarterly Average NOX Emission Rate

    Report the quarterly average emission rate (lb/mmBtu) as required in 
subpart G of this part. Calculate the quarterly average NOX 
emission rate according to equation F-9 in appendix F of this part.

            3.3.3 Annual Average NOX Emission Rate

    Report the average emission rate (lb/mmBtu) for the calendar year as 
required in subpart G of this part. Calculate the average NOX 
emission rate according to equation F-10 in appendix F of this part.

  3.3.4 Average NOX Emission Rate During Co-firing of Fuels
[GRAPHIC] [TIFF OMITTED] TR26MY99.038

Where:

Eh = NOX emission rate for the unit for the hour, 
          lb/mmBtu.
Ef = NOX emission rate for the unit for a given 
          fuel at heat input rate HIf, lb/mmBtu.
HIf = Heat input rate for the hour for a given fuel, during 
          the fuel usage time, as determined using Equation F-19 or F-20 
          in section 5.5 of appendix F to this part, mmBtu/hr.
HT = Total heat input for all fuels for the hour from 
          Equation E-1.
tf = Fuel usage time for each fuel (rounded up to the nearest 
          fraction of an hour (in equal increments that can range from 
          one hundredth to one quarter of an hour, at the option of the 
          owner or operator)).

    Note: For hours where a fuel is combusted for only part of the hour, 
use the fuel flow rate or mass flow rate during the fuel usage time, 
instead of the total fuel flow or mass flow during the hour, when 
calculating heat input rate using Equation F-19 or F-20.

[[Page 445]]

                4. Quality Assurance/Quality Control Plan

    Include a section on the NOX emission rate determination 
as part of the monitoring quality assurance/quality control plan 
required under Sec. 75.21 and appendix B of this part for each gas-
fired peaking unit and each oil-fired peaking unit. In this section 
present information including, but not limited to, the following: (1) a 
copy of all data and results from the initial NOX emission 
rate testing, including the values of quality assurance parameters 
specified in section 2.3 of this appendix; (2) a copy of all data and 
results from the most recent NOX emission rate load 
correlation testing; (3) a copy of the recommended range of quality 
assurance- and quality control-related operating parameters.
    4.1 Submit a copy of the recommended range of operating parameter 
values, and the range of operating parameter values recorded during the 
previous NOX emission rate test that determined the unit's 
NOX emission rate, along with the unit's revised monitoring 
plan submitted with the certification application.
    4.2 Keep records of these operating parameters for each hour of 
operation in order to demonstrate that a unit is remaining within the 
recommended operating range.

[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26551, May 17, 1995; 64 
FR 28665, May 26, 1999; 67 FR 40473, 40474, June 12, 2002; 67 FR 53505, 
Aug. 16, 2002; 73 FR 4372, Jan. 24, 2008; 76 FR 17325, Mar. 28, 2011]



            Sec. Appendix F to Part 75--Conversion Procedures

                            1. Applicability

    Use the procedures in this appendix to convert measured data from a 
monitor or continuous emission monitoring system into the appropriate 
units of the standard.

               2. Procedures for SO2 Emissions

    Use the following procedures to compute hourly SO2 mass 
emission rate (in lb/hr) and quarterly and annual SO2 total 
mass emissions (in tons).
    2.1 When measurements of SO2 concentration and flow rate 
are on a wet basis, use the following equation to compute hourly 
SO2 mass emission rate (in lb/hr):
[GRAPHIC] [TIFF OMITTED] TR26MY99.039

Where:

Eh = Hourly SO2 mass emission rate during unit 
          operation, lb/hr.
K = 1.660 x 10-7 for SO2, (lb/scf)/ppm.
Ch = Hourly average SO2 concentration during unit 
          operation, stack moisture basis, ppm.
Qh = Hourly average volumetric flow rate during unit 
          operation, stack moisture basis, scfh.
2.2 When measurements by the SO2 pollutant concentration 
monitor are on a dry basis and the flow rate monitor measurements are on 
a wet basis, use the following equation to compute hourly SO2 
mass emission rate (in lb/hr):
[GRAPHIC] [TIFF OMITTED] TR26MY99.040

where:

Eh = Hourly SO2 mass emission rate during unit 
          operation, lb/hr.
K = 1.660 x 10-7 for SO2, (lb/scf)/ppm.
Chp = Hourly average SO2 concentration during unit 
          operation, ppm (dry).
Qhs = Hourly average volumetric flow rate during unit 
          operation, scfh as measured (wet).
%H2O = Hourly average stack moisture content during unit 
          operation, percent by volume.

    2.3 Use the following equations to calculate total SO2 
mass emissions for each calendar quarter (Equation F-3) and for each 
calendar year (Equation F-4), in tons:
[GRAPHIC] [TIFF OMITTED] TR12JN02.022

(Eq. F-3)
Where:

Eq = Quarterly total SO2 mass emissions, tons.
Eh = Hourly SO2 mass emission rate, lb/hr.
th = Unit operating time, hour or fraction of an hour (in 
          equal increments that can range from one hundredth to one 
          quarter of an hour, at the option of the owner or operator).
n = Number of hourly SO2 emissions values during calendar 
          quarter.
2000 = Conversion of 2000 lb per ton.

[[Page 446]]

[GRAPHIC] [TIFF OMITTED] TR26MY99.042

Where:

Ea = Annual total SO2 mass emissions, tons.
Eq = Quarterly SO2 mass emissions, tons.
q = Quarters for which Eq are available during calendar year.

    2.4 Round all SO2 mass emission rates and totals to the 
nearest tenth.

             3. Procedures for NOX Emission Rate

    Use the following procedures to convert continuous emission 
monitoring system measurements of NOX concentration (ppm) and 
diluent concentration (percentage) into NOX emission rates 
(in lb/mmBtu). Perform measurements of NOX and diluent 
(O2 or CO2) concentrations on the same moisture 
(wet or dry) basis.
    3.1 When the NOX continuous emission monitoring system 
uses O2 as the diluent, and measurements are performed on a 
dry basis, use the following conversion procedure:
[GRAPHIC] [TIFF OMITTED] TC01SE92.123

(Eq. F-5)

where,

K, E, Ch, F, and %O2 are defined in section 3.3 of 
          this appendix. When measurements are performed on a wet basis, 
          use the equations in Method 19 in appendix A-7 to part 60 of 
          this chapter.

    3.2 When the NOX continuous emission monitoring system 
uses CO2 as the diluent, use the following conversion 
procedure:
[GRAPHIC] [TIFF OMITTED] TR17MY95.014

(Eq. F-6)

where:

K, E, Ch, Fc, and %CO2 are defined in section 3.3 of this 
          appendix.
When CO2 and NOX measurements are performed on a 
          different moisture basis, use the equations in Method 19 in 
          appendix A-7 to part 60 of this chapter.

    3.3 Use the definitions listed below to derive values for the 
parameters in equations F-5 and F-6 of this appendix, or (if applicable) 
in the equations in Method 19 in appendix A-7 to part 60 of this 
chapter.
    3.3.1 K = 1.194 x 10-7 (lb/dscf)/ppm NOX.
    3.3.2 E = Pollutant emissions during unit operation, lb/mmBtu.
    3.3.3 Ch = Hourly average pollutant concentration during 
unit operation, ppm.
    3.3.4 %O2, %CO2 = Oxygen or carbon dioxide 
volume during unit operation (expressed as percent O2 or 
CO2).
    3.3.4.1 For boilers, a minimum concentration of 5.0 percent 
CO2 or a maximum concentration of 14.0 percent O2 
may be substituted for the measured diluent gas concentration value for 
any operating hour in which the hourly average CO2 
concentration is <5.0 percent CO2 or the hourly average 
O2 concentration is 14.0 percent O2. 
For stationary gas turbines, a minimum concentration of 1.0 percent 
CO2 or a maximum concentration of 19.0 percent O2 
may be substituted for measured diluent gas concentration values for any 
operating hour in which the hourly average CO2 concentration 
is <1.0 percent CO2 or the hourly average O2 
concentration is 19.0 percent O2.
    3.3.4.2 If NOX emission rate is calculated using either 
Equation 19-3 or 19-5 in Method 19 in appendix A-7 to part 60 of this 
chapter, a variant of the equation shall be used whenever the diluent 
cap is applied. The modified equations shall be designated as Equations 
19-3D and 19-5D, respectively. Equation 19-3D is structurally the same 
as Equation 19-3, except that the term ``%O2w'' in the 
denominator is replaced with the term ``%O2dc x [(100-% 
H2O)/100]'', where %O2dc is the diluent cap value. 
The numerator of Equation 19-5D is the same as Equation 19-5; however, 
the denominator of Equation 19-5D is simply ``20.9-%O2dc'', 
where %O2dc is the diluent cap value.
    3.3.5 F, Fc = a factor representing a ratio of the volume 
of dry flue gases generated to the caloric value of the fuel combusted 
(F), and a factor representing a ratio of the volume of CO2 
generated to the calorific value of the fuel combusted (Fc), 
respectively. Table 1 lists the values of F and Fc for 
different fuels.

                     Table 1--F- and Fc-Factors \1\
------------------------------------------------------------------------
                                          F-factor (dscf/ FC-factor (scf
                  Fuel                        mmBtu)        CO2/mmBtu)
------------------------------------------------------------------------
Coal (as defined by ASTM D388-99 \2\):
    Anthracite..........................          10,100           1,970
    Bituminous..........................           9,780           1,800
    Subbituminous.......................           9,820           1,840
    Lignite.............................           9,860           1,910
Petroleum Coke..........................           9,830           1,850
Tire Derived Fuel.......................          10,260           1,800
Oil.....................................           9,190           1,420
Gas:
    Natural gas.........................           8,710           1,040
    Propane.............................           8,710           1,190
    Butane..............................           8,710           1,250
Wood:
    Bark................................           9,600           1,920
    Wood residue........................           9,240          1,830
------------------------------------------------------------------------
\1\ Determined at standard conditions: 20 C (68 F) and 29.92 inches of
  mercury.

[[Page 447]]

 
\2\ Incorporated by reference under Sec. 75.6 of this part.

    3.3.6 Equations F-7a and F-7b may be used in lieu of the F or 
Fc factors specified in Section 3.3.5 of this appendix to 
calculate a site-specific dry-basis F factor (dscf/mmBtu) or a site-
specific Fc factor (scf CO2/mmBtu), on either a 
dry or wet basis. At a minimum, the site-specific F or Fc 
factor must be based on 9 samples of the fuel. Fuel samples taken during 
each run of a RATA are acceptable for this purpose. The site-specific F 
or Fc factor must be re-determined at least annually, and the 
value from the most recent determination must be used in the emission 
calculations. Alternatively, the previous F or Fc value may 
continue to be used if it is higher than the value obtained in the most 
recent determination. The owner or operator shall keep records of all 
site-specific F or Fc determinations, active for at least 3 
years. (Calculate all F- and Fc factors at standard 
conditions of 20 C (68 F) and 29.92 inches of mercury).
[GRAPHIC] [TIFF OMITTED] TC01SE92.124

(Eq. F-7a)
[GRAPHIC] [TIFF OMITTED] TC01SE92.125

(Eq. F-7b)

    3.3.6.1 H, C, S, N, and O are content by weight of hydrogen, carbon, 
sulfur, nitrogen, and oxygen (expressed as percent), respectively, as 
determined on the same basis as the gross calorific value (GCV) by 
ultimate analysis of the fuel combusted using ASTM D3176-89 (Reapproved 
2002), Standard Practice for Ultimate Analysis of Coal and Coke, (solid 
fuels), ASTM D5291-02, Standard Test Methods for Instrumental 
Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products 
and Lubricants, (liquid fuels) or computed from results using ASTM 
D1945-96 (Reapproved 2001), Standard Test Method for Analysis of Natural 
Gas by Gas Chromatography, or ASTM D1946-90 (Reapproved 2006), Standard 
Practice for Analysis of Reformed Gas by Gas Chromatography, (gaseous 
fuels) as applicable. (All of these methods are incorporated by 
reference under Sec. 75.6 of this part.)
    3.3.6.2 GCV is the gross calorific value (Btu/lb) of the fuel 
combusted determined by ASTM D5865-01a or ASTM D5865-10, ASTM D240-00 or 
ASTM D4809-00, and ASTM D3588-98, ASTM D4891-89 (Reapproved 2006), GPA 
Standard 2172-96, GPA Standard 2261-00, or ASTM D1826-94 (Reapproved 
1998), as applicable. (All of these methods are incorporated by 
reference under Sec. 75.6.)
    3.3.6.3 For affected units that combust a combination of a fuel (or 
fuels) listed in Table 1 in section 3.3.5 of this appendix with any 
fuel(s) not listed in Table 1, the F or Fc value is subject 
to the Administrator's approval under Sec. 75.66.
    3.3.6.4 For affected units that combust combinations of fuels listed 
in Table 1 in section 3.3.5 of this appendix, prorate the F or 
Fc factors determined by section 3.3.5 or 3.3.6 of this 
appendix in accordance with the applicable formula as follows:
[GRAPHIC] [TIFF OMITTED] TR24JA08.020

Where,
Xi = Fraction of total heat input derived from each type of 
          fuel (e.g., natural gas, bituminous coal, wood). Each 
          Xi value shall be determined from the best 
          available information on the quantity of fuel combusted and 
          the GCV value, over a specified time period. The owner or 
          operator shall explain the method used to calculate 
          Xi in the hardcopy portion of the monitoring plan 
          for the unit. The Xi values may be determined and 
          updated either hourly, daily, weekly, or monthly. In all 
          cases, the prorated F-factor used in the emission calculations 
          shall be determined using the Xi values from the 
          most recent update.
Fi or (Fc)i = Applicable F or Fc factor 
          for each fuel type determined in accordance with Section 3.3.5 
          or 3.3.6 of this appendix.
n = Number of fuels being combusted in combination.

    3.3.6.5 As an alternative to prorating the F or Fc factor as 
described in section 3.3.6.4

[[Page 448]]

of this appendix, a ``worst-case'' F or Fc factor may be 
reported for any unit operating hour. The worst-case F or Fc 
factor shall be the highest F or Fc value for any of the 
fuels combusted in the unit.
    3.4 Use the following equations to calculate the average 
NOX emission rate for each calendar quarter (Equation F-9) 
and the average emission rate for the calendar year (Equation F-10), in 
lb/mmBtu:
[GRAPHIC] [TIFF OMITTED] TR26MY99.043

Where:

Eq = Quarterly average NOX emission rate, lb/
          mmBtu.
Ei = Hourly average NOX emission rate during unit 
          operation, lb/mmBtu.
n = Number of hourly rates during calendar quarter.
[GRAPHIC] [TIFF OMITTED] TR26MY99.044

Where:

Ea = Average NOX emission rate for the calendar 
          year, lb/mmBtu.
Ei = Hourly average NOX emission rate during unit 
          operation, lb/mmBtu.
m = Number of hourly rates for which Ei is available in the 
          calendar year.

    3.5 Round all NOX emission rates to the nearest 0.001 lb/
mmBtu.

             4. Procedures for CO2 Mass Emissions

    Use the following procedures to convert continuous emission 
monitoring system measurements of CO2 concentration 
(percentage) and volumetric flow rate (scfh) into CO2 mass 
emissions (in tons/day) when the owner or operator uses a CO2 
continuous emission monitoring system (consisting of a CO2 or 
O2 pollutant monitor) and a flow monitoring system to monitor 
CO2 emissions from an affected unit.
    4.1 When CO2 concentration is measured on a wet basis, 
use the following equation to calculate hourly CO2 mass 
emissions rates (in tons/hr):
[GRAPHIC] [TIFF OMITTED] TR26MY99.045

Where:

Eh = Hourly CO2 mass emission rate during unit 
          operation, tons/hr.
K = 5.7 x 10-7 for CO2, (tons/scf) /
          %CO2.
Ch = Hourly average CO2 concentration during unit 
          operation, wet basis, either measured directly with a 
          CO2 monitor or calculated from wet-basis 
          O2 data using Equation F-14b, percent 
          CO2.
Qh = Hourly average volumetric flow rate during unit 
          operation, wet basis, scfh.

    4.2 When CO2 concentration is measured on a dry basis, 
use Equation F-2 to calculate the hourly CO2 mass emission 
rate (in tons/hr) with a K-value of 5.7 x 10-7 (tons/scf) 
percent CO2, where Eh = hourly CO2 mass 
emission rate, tons/hr and Chp = hourly average 
CO2 concentration in flue, dry basis, percent CO2.
    4.3 Use the following equations to calculate total CO2 
mass emissions for each calendar quarter (Equation F-12) and for each 
calendar year (Equation F-13):
[GRAPHIC] [TIFF OMITTED] TR26MY99.046

Where:

ECO2q = Quarterly total CO2 mass emissions, tons.
Eh = Hourly CO2 mass emission rate, tons/hr.
th = Unit operating time, in hours or fraction of an hour (in 
          equal increments that can range from one hundredth to one 
          quarter of an hour, at the option of the owner or operator).
HR = Number of hourly CO2 mass emission rates 
          available during calendar quarter.
          [GRAPHIC] [TIFF OMITTED] TR26MY99.047
          
Where:

ECO2a = Annual total CO2 mass emissions, tons.
ECO2q = Quarterly total CO2 mass emissions, tons.
q = Quarters for which ECO2q are available during calendar 
          year.

    4.4 For an affected unit, when the owner or operator is continuously 
monitoring O2 concentration (in percent by volume) of flue 
gases using an O2 monitor, use the equations and procedures 
in section 4.4.1 and 4.4.2 of this appendix to determine hourly 
CO2 mass emissions (in tons).
    4.4.1 If the owner or operator elects to use data from an 
O2 monitor to calculate CO2 concentration, the 
appropriate F and FC factors from section 3.3.5 of this 
appendix shall be used in one of the following equations (as applicable) 
to determine hourly average CO2 concentration of flue gases 
(in percent by volume) from the measured hourly average O2 
concentration:

[[Page 449]]

[GRAPHIC] [TIFF OMITTED] TR24JA08.021

Where:

CO2d = Hourly average CO2 concentration during 
          unit operation, percent by volume, dry basis.
F, FC = F-factor or carbon-based Fc-factor from 
          section 3.3.5 of this appendix.
20.9 = Percentage of O2 in ambient air.
O2d = Hourly average O2 concentration during unit 
          operation, percent by volume, dry basis.
          [GRAPHIC] [TIFF OMITTED] TR24JA08.022
          
Where:

CO2w = Hourly average CO2 concentration during 
          unit operation, percent by volume, wet basis.
O2w = Hourly average O2 concentration during unit 
          operation, percent by volume, wet basis.
F, Fc = F-factor or carbon-based FC-factor from section 3.3.5 
          of this appendix.
20.9 = Percentage of O2 in ambient air.
%H2O = Moisture content of gas in the stack, percent.

    For any hour where Equation F-14a or F-14b results in a negative 
hourly average CO2 value, 0.0% CO2w shall be 
recorded as the average CO2 value for that hour.
    4.4.2 Determine CO2 mass emissions (in tons) from hourly 
average CO2 concentration (percent by volume) using equation 
F-11 and the procedure in section 4.1, where O2 measurements 
are on a wet basis, or using the procedures in section 4.2 of this 
appendix, where O2 measurements are on a dry basis.

                      5. Procedures for Heat Input

    Use the following procedures to compute heat input rate to an 
affected unit (in mmBtu/hr or mmBtu/day):
    5.1 Calculate and record heat input rate to an affected unit on an 
hourly basis, except as provided in sections 5.5 through 5.5.7. The 
owner or operator may choose to use the provisions specified in Sec. 
75.16(e) or in section 2.1.2 of appendix D to this part in conjunction 
with the procedures provided in sections 5.6 through 5.6.2 to apportion 
heat input among each unit using the common stack or common pipe header.
    5.2 For an affected unit that has a flow monitor (or approved 
alternate monitoring system under subpart E of this part for measuring 
volumetric flow rate) and a diluent gas (O2 or 
CO2) monitor, use the recorded data from these monitors and 
one of the following equations to calculate hourly heat input rate (in 
mmBtu/hr).
    5.2.1 When measurements of CO2 concentration are on a wet 
basis, use the following equation:
[GRAPHIC] [TIFF OMITTED] TR26MY99.049

Where:

HI = Hourly heat input rate during unit operation, mmBtu/hr.
Qw = Hourly average volumetric flow rate during unit 
          operation, wet basis, scfh.
Fc = Carbon-based F-factor, listed in section 3.3.5 of this 
          appendix for each fuel, scf/mmBtu.
%CO2w = Hourly concentration of CO2 during unit 
          operation, percent CO2 wet basis.

    5.2.2 When measurements of CO2 concentration are on a dry 
basis, use the following equation:
[GRAPHIC] [TIFF OMITTED] TR26MY99.051


[[Page 450]]


Where:

HI = Hourly heat input rate during unit operation, mmBtu/hr.
Qh = Hourly average volumetric flow rate during unit 
          operation, wet basis, scfh.
Fc = Carbon-based F-Factor, listed in section 3.3.5 of this 
          appendix for each fuel, scf/mmBtu.
%CO2d = Hourly concentration of CO2 during unit 
          operation, percent CO2 dry basis.
%H2O = Moisture content of gas in the stack, percent.

    5.2.3 When measurements of O2 concentration are on a wet 
basis, use the following equation:
[GRAPHIC] [TIFF OMITTED] TR26MY99.052

Where:

HI = Hourly heat input rate during unit operation, mmBtu/hr.
Qw = Hourly average volumetric flow rate during unit 
          operation, wet basis, scfh.
F = Dry basis F-factor, listed in section 3.3.5 of this appendix for 
          each fuel, dscf/mmBtu.
%O2w = Hourly concentration of O2 during unit 
          operation, percent O2 wet basis. For any operating 
          hour where Equation F-17 results in an hourly heat input rate 
          that is <=0.0 mmBtu/hr, 1.0 mmBtu/hr shall be recorded and 
          reported as the heat input rate for that hour.
%H2O = Hourly average stack moisture content, percent by 
          volume.

    5.2.4 When measurements of O2 concentration are on a dry 
basis, use the following equation:
[GRAPHIC] [TIFF OMITTED] TR26MY99.053

Where:

HI = Hourly heat input rate during unit operation, mmBtu/hr.
Qw = Hourly average volumetric flow during unit operation, 
          wet basis, scfh.
F = Dry basis F-factor, listed in section 3.3.5 of this appendix for 
          each fuel, dscf/mmBtu.
%H2O = Moisture content of the stack gas, percent.
%O2d = Hourly concentration of O2 during unit 
          operation, percent O2 dry basis.

5.3 Heat Input Summation (for Heat Input Determined Using a Flow Monitor 
                          and Diluent Monitor)

    5.3.1 Calculate total quarterly heat input for a unit or common 
stack using a flow monitor and diluent monitor to calculate heat input, 
using the following equation:
[GRAPHIC] [TIFF OMITTED] TR26MY99.054

Where:

HIq = Total heat input for the quarter, mmBtu.
HIi = Hourly heat input rate during unit operation, using 
          Equation F-15, F-16, F-17, or F-18, mmBtu/hr.
ti = Hourly operating time for the unit or common stack, hour 
          or fraction of an hour (in equal increments that can range 
          from one hundredth to one quarter of an hour, at the option of 
          the owner or operator).

    5.3.2 Calculate total cumulative heat input for a unit or common 
stack using a flow monitor and diluent monitor to calculate heat input, 
using the following equation:
[GRAPHIC] [TIFF OMITTED] TR26MY99.055

Where:

HIc = Total heat input for the year to date, mmBtu.
HIq = Total heat input for the quarter, mmBtu.

                             5.4 [Reserved]

    5.5 For a gas-fired or oil-fired unit that does not have a flow 
monitor and is using the procedures specified in appendix D to

[[Page 451]]

this part to monitor SO2 emissions or for any unit using a 
common stack for which the owner or operator chooses to determine heat 
input by fuel sampling and analysis, use the following procedures to 
calculate hourly heat input rate in mmBtu/hr. The procedures of section 
5.5.3 of this appendix shall not be used to determine heat input from a 
coal unit that is required to comply with the provisions of this part 
for monitoring, recording, and reporting NOX mass emissions 
under a State or federal NOX mass emission reduction program.
    5.5.1 (a) When the unit is combusting oil, use the following 
equation to calculate hourly heat input rate:
[GRAPHIC] [TIFF OMITTED] TR26MY99.056

Where:

HIo = Hourly heat input rate from oil, mmBtu/hr.
Mo = Mass rate of oil consumed per hour, as determined using 
          procedures in appendix D to this part, in lb/hr, tons/hr, or 
          kg/hr.
GCVO = Gross calorific value of oil, as measured by ASTM 
          D240-00, ASTM D5865-01a, ASTM D5865-10, or ASTM D4809-00 for 
          each oil sample under section 2.2 of appendix D to this part, 
          Btu/unit mass (all incorporated by reference under Sec. 
          75.6).
10\6\ = Conversion of Btu to mmBtu.

    (b) When performing oil sampling and analysis solely for the purpose 
of the missing data procedures in Sec. 75.36, oil samples for measuring 
GCV may be taken weekly, and the procedures specified in appendix D to 
this part for determining the mass rate of oil consumed per hour are 
optional.
    5.5.2 When the unit is combusting gaseous fuels, use the following 
equation to calculate heat input rate from gaseous fuels for each hour:
[GRAPHIC] [TIFF OMITTED] TR26MY99.062

Where:

HIg = Hourly heat input rate from gaseous fuel, mmBtu/hour.
Qg = Metered flow rate of gaseous fuel combusted during unit 
          operation, hundred standard cubic feet per hour.
GCVg = Gross calorific value of gaseous fuel, as determined 
          by sampling (for each delivery for gaseous fuel in lots, for 
          each daily gas sample for gaseous fuel delivered by pipeline, 
          for each hourly average for gas measured hourly with a gas 
          chromatograph, or for each monthly sample of pipeline natural 
          gas, or as verified by the contractual supplier at least once 
          every month pipeline natural gas is combusted, as specified in 
          section 2.3 of appendix D to this part) using ASTM D1826-94 
          (Reapproved 1998), ASTM D3588-98, ASTM D4891-89 (Reapproved 
          2006), GPA Standard 2172-96 Calculation of Gross Heating 
          Value, Relative Density and Compressibility Factor for Natural 
          Gas Mixtures from Compositional Analysis, or GPA Standard 
          2261-00 Analysis for Natural Gas and Similar Gaseous Mixtures 
          by Gas Chromatography, Btu/100 scf (all incorporated by 
          reference under Sec. 75.6 of this part).
10\6\ = Conversion of Btu to mmBtu.

    5.5.3 When the unit is combusting coal, use the procedures, methods, 
and equations in sections 5.5.3.1-5.5.3.3 of this appendix to determine 
the heat input from coal for each 24-hour period. (All ASTM methods are 
incorporated by reference under Sec. 75.6 of this part.)
    5.5.3.1 Perform coal sampling daily according to section 5.3.2.2 in 
Method 19 in appendix A to part 60 of this chapter and use ASTM D2234-
00, Standard Practice for Collection of a Gross Sample of Coal, 
(incorporated by reference under Sec. 75.6 of this part) Type I, 
Conditions A, B, or C and systematic spacing for sampling. (When 
performing coal sampling solely for the purposes of the missing data 
procedures in Sec. 75.36, use of ASTM D2234-00 is optional, and coal 
samples may be taken weekly.)
    5.5.3.2 All ASTM methods are incorporated by reference under Sec. 
75.6. Use ASTM D2013-01 for preparation of a daily coal sample and 
analyze each daily coal sample for gross calorific value using ASTM 
D5865-01a or ASTM D5865-10. On-line coal analysis may also be used if 
the on-line analytical instrument has been demonstrated to be equivalent 
to the applicable ASTM methods under Sec. Sec. 75.23 and 75.66.
    5.5.3.3 Calculate the heat input from coal using the following 
equation:
[GRAPHIC] [TIFF OMITTED] TR17MY95.020

(Eq. F-21)
where:

HIc = Daily heat input from coal, mmBtu/day.
Mc = Mass of coal consumed per day, as measured and recorded in company 
          records, tons.
GCVC = Gross calorific value of coal sample, as measured by 
          ASTM D3176-89 (Reapproved 2002), ASTM D5865-01a, or ASTM 
          D5865-10, Btu/lb (incorporated by reference under Sec. 75.6).
500 = Conversion of Btu/lb to mmBtu/ton.

    5.5.4 For units obtaining heat input values daily instead of hourly, 
apportion the daily heat input using the fraction of the daily steam 
load or daily unit operating load used each hour in order to obtain 
HIi for use

[[Page 452]]

in the above equations. Alternatively, use the hourly mass of coal 
consumed in equation F-21.
    5.5.5 If a daily fuel sampling value for gross calorific value is 
not available, substitute the maximum gross calorific value measured 
from the previous 30 daily samples. If a monthly fuel sampling value for 
gross calorific value is not available, substitute the maximum gross 
calorific value measured from the previous 3 monthly samples.
    5.5.6 If a fuel flow value is not available, use the fuel flowmeter 
missing data procedures in section 2.4 of appendix D of this part. If a 
daily coal consumption value is not available, substitute the maximum 
fuel feed rate during the previous thirty days when the unit burned 
coal.
    5.5.7 Results for samples must be available no later than thirty 
calendar days after the sample is composited or taken. However, during 
an audit, the Administrator may require that the results be available in 
five business days, or sooner if practicable.

 5.6 Heat Input Rate Apportionment for Units Sharing a Common Stack or 
                                  Pipe

    5.6.1 Where applicable, the owner or operator of an affected unit 
that determines heat input rate at the unit level by apportioning the 
heat input monitored at a common stack or common pipe using megawatts 
shall apportion the heat input rate using the following equation:
[GRAPHIC] [TIFF OMITTED] TR26MY99.057

Where:

HIi = Heat input rate for a unit, mmBtu/hr.
HIcs = Heat input rate at the common stack or pipe, mmBtu/hr.
MWi = Gross electrical output, MWe.
ti = Unit operating time, hour or fraction of an hour (in 
          equal increments that can range from one hundredth to one 
          quarter of an hour, at the option of the owner or operator).
tCS = Common stack or common pipe operating time, hour or 
          fraction of an hour (in equal increments that can range from 
          one hundredth to one quarter of an hour, at the option of the 
          owner or operator).
n = Total number of units using the common stack or pipe.
i = Designation of a particular unit.
    5.6.2 Where applicable, the owner or operator of an affected unit 
that determines the heat input rate at the unit level by apportioning 
the heat input rate monitored at a common stack or common pipe using 
steam load shall apportion the heat input rate using the following 
equation:
[GRAPHIC] [TIFF OMITTED] TR26MY99.058

Where:

HIi = Heat input rate for a unit, mmBtu/hr.
HICS = Heat input rate at the common stack or pipe, mmBtu/hr.
SF = Gross steam load, lb/hr, or mmBtu/hr.
ti = Unit operating time, hour or fraction of an hour (in 
          equal increments that can range from one hundredth to one 
          quarter of an hour, at the option of the owner or operator).
tCS = Common stack or common pipe operating time, hour or 
          fraction of an hour (in equal increments that can range from 
          one hundredth to one quarter of an hour, at the option of the 
          owner or operator).
n = Total number of units using the common stack or pipe.
i = Designation of a particular unit.

[[Page 453]]

  5.7 Heat Input Rate Summation for Units with Multiple Stacks or Pipes

    The owner or operator of an affected unit that determines the heat 
input rate at the unit level by summing the heat input rates monitored 
at multiple stacks or multiple pipes shall sum the heat input rates 
using the following equation:
[GRAPHIC] [TIFF OMITTED] TR26MY99.059

Where:

HIUnit = Heat input rate for a unit, mmBtu/hr.
HIs = Heat input rate for the individual stack, duct, or 
          pipe, mmBtu/hr.
tUnit = Unit operating time, hour or fraction of the hour (in 
          equal increments that can range from one hundredth to one 
          quarter of an hour, at the option of the owner or operator).
ts = Operating time for the individual stack or pipe, hour or 
          fraction of the hour (in equal increments that can range from 
          one hundredth to one quarter of an hour, at the option of the 
          owner or operator).
s = Designation for a particular stack, duct, or pipe.

         5.8 Alternate Heat Input Apportionment for Common Pipes

    As an alternative to using Equation F-21a or F-21b in section 5.6 of 
this appendix, the owner or operator may apportion the heat input rate 
at a common pipe to the individual units served by the common pipe based 
on the fuel flow rate to the individual units, as measured by 
uncertified fuel flowmeters. This option may only be used if a fuel 
flowmeter system that meets the requirements of appendix D to this part 
is installed on the common pipe. If this option is used, determine the 
unit heat input rates using the following equation:
[GRAPHIC] [TIFF OMITTED] TR12JN02.023

Where:

HIi = Heat input rate for a unit, mmBtu/hr.
HICP = Heat input rate at the common pipe, mmBtu/hr.
FFi = Fuel flow rate to a unit, gal/min, 100 scfh, or other 
          appropriate units.
ti = Unit operating time, hour or fraction of an hour (in 
          equal increments that can range from one hundredth to one 
          quarter of an hour, at the option of the owner or operator).
tCP = Common pipe operating time, hour or fraction of an hour 
          (in equal increments that can range from one hundredth to one 
          quarter of an hour, at the option of the owner or operator).
n = Total number of units using the common pipe.
i = Designation of a particular unit.

           6. Procedure for Converting Volumetric Flow to STP

    Use the following equation to convert volumetric flow at actual 
temperature and pressure to standard temperature and pressure.

FSTP = FActual(TStd/
          TStack)(PStack/PStd)

where:

FSTP = Flue gas volumetric flow rate at standard temperature 
          and pressure, scfh.
FActual = Flue gas volumetric flow rate at actual temperature 
          and pressure, acfh.
TStd = Standard temperature = 528 R.
TStack = Flue gas temperature at flow monitor location, R, 
          where R = 460 + F.
PStack = The absolute flue gas pressure = barometric pressure 
          at the flow monitor location + flue gas static pressure, 
          inches of mercury.
PStd = Standard pressure = 29.92 inches of mercury.

     7. Procedures for SO2 Mass Emissions, Using Default 
      SO2 Emission Rates and Heat Input Measured by CEMS

    The owner or operator shall use Equation F-23 to calculate hourly 
SO2 mass emissions in accordance with Sec. 75.11(e)(1) 
during the combustion of gaseous fuel, for a unit that uses a flow 
monitor and a diluent gas monitor to measure heat input, and that 
qualifies to use a default SO2 emission rate under section 
2.3.1.1, 2.3.2.1.1, or 2.3.6(b) of appendix D to this part. Equation F-
23 may also be applied to the combustion of solid or liquid fuel that 
meets the definition of very low sulfur fuel in Sec. 72.2 of this 
chapter, combinations of

[[Page 454]]

such fuels, or mixtures of such fuels with gaseous fuel, if the owner or 
operator has received approval from the Administrator under Sec. 75.66 
to use a site-specific default SO2 emission rate for the fuel 
or mixture of fuels.

[GRAPHIC] [TIFF OMITTED] TR24JA08.023

Where:

Eh = Hourly SO2 mass emission rate, lb/hr.
ER = Applicable SO2 default emission rate for gaseous fuel 
          combustion, from section 2.3.1.1, 2.3.2.1.1, or 2.3.6(b) of 
          appendix D to this part, or other default SO2 
          emission rate for the combustion of very low sulfur liquid or 
          solid fuel, combinations of such fuels, or mixtures of such 
          fuels with gaseous fuel, as approved by the Administrator 
          under Sec. 75.66, lb/mmBtu.
HI = Hourly heat input rate, determined using the procedures in section 
          5.2 of this appendix, mmBtu/hr.

             8. Procedures for NOX Mass Emissions

    The owner or operator of a unit that is required to monitor, record, 
and report NOX mass emissions under a State or federal 
NOX mass emission reduction program must use the procedures 
in section 8.1, 8.2, or 8.3 of this appendix, as applicable, to account 
for hourly NOX mass emissions, and the procedures in section 
8.4 of this appendix to account for quarterly, seasonal, and annual 
NOX mass emissions to the extent that the provisions of 
subpart H of this part are adopted as requirements under such a program.
    8.1 The owner or operator may use the hourly NOX emission 
rate and the hourly heat input rate to calculate the NOX mass 
emissions in pounds or the NOX mass emission rate in pounds 
per hour, (as required by the applicable reporting format), for each 
unit or stack operating hour, as follows:
    8.1.1 If both NOX emission rate and heat input rate are 
monitored at the same unit or stack level (e.g., the NOX 
emission rate value and the heat input rate value both represent all of 
the units exhausting to the common stack), then (as required by the 
applicable reporting format) either:
    (a) Use Equation F-24 to calculate the hourly NOX mass 
emissions (lb).
[GRAPHIC] [TIFF OMITTED] TR24JA08.024

Where:

M(NOX)h = NOX mass emissions in lbs for 
          the hour.
ER(NOX)h = Hourly average NOX emission 
          rate for hour h, lb/mmBtu, from section 3 of this appendix, 
          from Method 19 in appendix A-7 to part 60 of this chapter, or 
          from section 3.3 of appendix E to this part. (Include bias-
          adjusted NOX emission rate values, where the bias-
          test procedures in appendix A to this part shows a bias-
          adjustment factor is necessary.)
HIh = Hourly average heat input rate for hour h, mmBtu/hr. 
          (Include bias-adjusted flow rate values, where the bias-test 
          procedures in appendix A to this part shows a bias-adjustment 
          factor is necessary.)
th = Monitoring location operating time for hour h, in hours 
          or fraction of an hour (in equal increments that can range 
          from one hundredth to one quarter of an hour, at the option of 
          the owner or operator). If the combined NOX 
          emission rate and heat input are monitored for all of the 
          units in a common stack, the monitoring location operating 
          time is equal to the total time when any of those units was 
          exhausting through the common stack; or

    (b) Use Equation F-24a to calculate the hourly NOX mass 
emission rate (lb/hr).
[GRAPHIC] [TIFF OMITTED] TR24JA08.025

Where:

E(NOX)h = NOX mass emissions rate in 
          lbs/hr for the hour.
ER(NOX)h = Hourly average NOX emission 
          rate for hour h, lb/mmBtu, from section 3 of this appendix, 
          from Method 19 in appendix A-7 to part 60 of this chapter, or 
          from section 3.3 of appendix E to this part. (Include bias-
          adjusted NOX emission rate values, where the bias-
          test procedures in appendix A to this part shows a bias-
          adjustment factor is necessary.)
HIh = Hourly average heat input rate for hour h, mmBtu/hr. 
          (Include bias-adjusted flow rate values, where the bias-test 
          procedures in appendix A to this part shows a bias-adjustment 
          factor is necessary.)

    8.1.2 If NOX emission rate is measured at a common stack 
and heat input is measured at the unit level, sum the hourly heat inputs 
at the unit level according to the following formula:
[GRAPHIC] [TIFF OMITTED] TR27OC98.012

where:

HICS = Hourly average heat input rate for hour h for the 
          units at the common stack, mmBtu/hr.
tCS = Common stack operating time for hour h, in hours or 
          fraction of an hour (in equal increments that can range from 
          one hundredth to one quarter of an hour, at the option of the 
          owner or operator). (For each hour, tcs is the 
          total time during which one or more of the units which exhaust 
          through the common stack operate.).

[[Page 455]]

HIu = Hourly average heat input rate for hour h for the unit, 
          mmBtu/hr.
tu = Unit operating time for hour h, in hours or fraction of 
          an hour (in equal increments that can range from one hundredth 
          to one quarter of an hour, at the option of the owner or 
          operator).
p = Number of units that exhaust through the common stack.
u = Designation of a particular unit.

Use the hourly heat input rate at the common stack level and the hourly 
average NOX emission rate at the common stack level and the 
procedures in section 8.1.1 of this appendix to determine the hourly 
NOX mass emissions at the common stack.
    8.1.3 If a unit has multiple ducts and NOX emission rate 
is only measured at one duct, use the NOX emission rate 
measured at the duct, the heat input measured for the unit, and the 
procedures in section 8.1.1 of this appendix to determine NOX 
mass emissions.
    8.1.4 If a unit has multiple ducts and NOX emission rate 
is measured in each duct, heat input shall also be measured in each duct 
and the procedures in section 8.1.1 of this appendix shall be used to 
determine NOX mass emissions.
    8.2 Alternatively, the owner or operator may use the hourly 
NOX concentration (as measured by a NOX 
concentration monitoring system) and the hourly stack gas volumetric 
flow rate to calculate the NOX mass emission rate (lb/hr) for 
each unit or stack operating hour, in accordance with section 8.2.1 or 
8.2.2 of this appendix (as applicable). If the hourly NOX 
mass emissions are to be reported in lb, Equation F-26c in section 8.3 
of this appendix shall be used to convert the hourly NOX mass 
emission rates to hourly NOX mass emissions (lb).
    8.2.1 When the NOX concentration monitoring system 
measures on a wet basis, first calculate the hourly NOX mass 
emission rate (in lb/hr) during unit (or stack) operation, using 
Equation F-26a. (Include bias-adjusted flow rate or NOX 
concentration values, where the bias-test procedures in appendix A to 
this part shows a bias-adjustment factor is necessary.)
[GRAPHIC] [TIFF OMITTED] TR24JA08.026

Where:

E(NOX)h = NOX mass emissions rate in 
          lb/hr.
K = 1.194 x 10-7 for NOX, (lb/scf)/ppm.
Chw = Hourly average NOX concentration during unit 
          operation, wet basis, ppm.
Qh = Hourly average volumetric flow rate during unit 
          operation, wet basis, scfh.

    8.2.2 When NOX mass emissions are determined using a dry 
basis NOX concentration monitoring system and a wet basis 
flow monitoring system, first calculate hourly NOX mass 
emission rate (in lb/hr) during unit (or stack) operation, using 
Equation F-26b. (Include bias-adjusted flow rate or NOX 
concentration values, where the bias-test procedures in appendix A to 
this part shows a bias-adjustment factor is necessary.)
[GRAPHIC] [TIFF OMITTED] TR24JA08.027

Where:

E(NOX)h = NOX mass emissions rate, lb/
          hr.
K = 1.194 x 10-7 for NOX, (lb/scf)/ppm.
Chd = Hourly average NOX concentration during unit 
          operation, dry basis, ppm.
Qh = Hourly average volumetric flow rate during unit 
          operation, wet basis, scfh.
%H2O = Hourly average stack moisture content during unit 
          operation, percent by volume.

    8.3 When hourly NOX mass emissions are reported in pounds 
and are determined using a NOX concentration monitoring 
system and a flow monitoring system, calculate NOX mass 
emissions (lb) for each unit or stack operating hour by multiplying the 
hourly NOX mass emission rate (lb/hr) by the unit operating 
time for the hour, as follows:
[GRAPHIC] [TIFF OMITTED] TR24JA08.028

Where:

M(NOX)h = NOX mass emissions for the 
          hour, lb.
Eh = Hourly NOX mass emission rate during unit (or 
          stack) operation from Equation F-26a in section 8.2.1 of this 
          appendix or Equation F-26b in section 8.2.2 of this appendix 
          (as applicable), lb/hr.
th = Unit operating time or stack operating time (as defined 
          in Sec. 72.2 of this chapter) for hour ``h'', in hours or 
          fraction of an hour (in equal increments that can range from 
          one hundredth to one quarter of an hour, at the option of the 
          owner or operator).

    8.4 Use the following procedures to calculate quarterly, cumulative 
ozone season, and cumulative yearly NOX mass emissions, in 
tons:

[[Page 456]]

    (a) When hourly NOX mass emissions are reported in lb., 
use Eq. F-27.
[GRAPHIC] [TIFF OMITTED] TR24JA08.029

Where:

M(NOX)time period = NOX mass emissions 
          in tons for the given time period (quarter, cumulative ozone 
          season, cumulative year-to-date).
M(NOX)h = NOX mass emissions in lb for 
          the hour.
p = The number of hours in the given time period (quarter, cumulative 
          ozone season, cumulative year-to-date).

    (b) When hourly NOX mass emission rate is reported in lb/
hr, use Eq. F-27a.
[GRAPHIC] [TIFF OMITTED] TR24JA08.030

Where:

M(NOX)time period = NOX mass emissions 
          in tons for the given time period (quarter, cumulative ozone 
          season, cumulative year-to-date).
E(NOX)h = NOX mass emission rate in lb/
          hr for the hour.
p = The number of hours in the given time period (quarter, cumulative 
          ozone season, cumulative year-to-date).
th = Monitoring location operating time for hour h, in hours 
          or fraction of an hour (in equal increments that can range 
          from one hundredth to one quarter of an hour, at the option of 
          the owner or operator).

    8.5 Specific provisions for monitoring NOX mass emissions 
from common stacks. The owner or operator of a unit utilizing a common 
stack may account for NOX mass emissions using either of the 
following methodologies, if the provisions of subpart H are adopted as 
requirements of a State or federal NOX mass reduction 
program:
    8.5.1 The owner or operator may determine both NOX 
emission rate and heat input at the common stack and use the procedures 
in section 8.1.1 of this appendix to determine hourly NOX 
mass emissions at the common stack.
    8.5.2 The owner or operator may determine the NOX 
emission rate at the common stack and the heat input at each of the 
units and use the procedures in section 8.1.2 of this appendix to 
determine the hourly NOX mass emissions at each unit.

                              9. [Reserved]

   10. Moisture Determination From Wet and Dry O2 Readings

    If a correction for the stack gas moisture content is required in 
any of the emissions or heat input calculations described in this 
appendix, and if the hourly moisture content is determined from wet- and 
dry-basis O2 readings, use Equation F-31 to calculate the 
percent moisture, unless a ``K'' factor or other mathematical algorithm 
is developed as described in section 6.5.7(a) of appendix A to this 
part:
[GRAPHIC] [TIFF OMITTED] TR24JA08.031

Where:

% H2O = Hourly average stack gas moisture content, percent 
          H2O

[[Page 457]]

O2d = Dry-basis hourly average oxygen concentration, percent 
          O2
O2w = Wet-basis hourly average oxygen concentration, percent 
          O2

[58 FR 3701, Jan. 11, 1993; Redesignated and amended at 60 FR 26553, 
26571, May 17, 1995; 61 FR 25585, May 22, 1996; 61 FR 59166, Nov. 20, 
1996; 63 FR 57513, Oct. 27, 1998; 64 FR 28666, May 26, 1999; 64 FR 
37582, July 12, 1999; 67 FR 40474, 40475, June 12, 2002; 67 FR 53505, 
Aug. 16, 2002; 70 FR 28695, May 18, 2005; 73 FR 4372, Jan. 24, 2008; 76 
FR 17325, Mar. 28, 2011; 77 FR 2460, Jan. 18, 2012]



  Sec. Appendix G to Part 75--Determination of CO2 Emissions

                            1. Applicability

    The procedures in this appendix may be used to estimate 
CO2 mass emissions discharged to the atmosphere (in tons/day) 
as the sum of CO2 emissions from combustion and, if 
applicable, CO2 emissions from sorbent used in a wet flue gas 
desulfurization control system, fluidized bed boiler, or other emission 
controls.

  2. Procedures for Estimating CO2 Emissions From Combustion

    Use the following procedures to estimate daily CO2 mass 
emissions from the combustion of fossil fuels. The optional procedure in 
section 2.3 of this appendix may also be used for an affected gas-fired 
unit. For an affected unit that combusts any nonfossil fuels (e.g., 
bark, wood, residue, or refuse), either use a CO2 continuous 
emission monitoring system or apply to the Administrator for approval of 
a unit-specific method for determining CO2 emissions.
    2.1 Use the following equation to calculate daily CO2 
mass emissions (in tons/day) from the combustion of fossil fuels. Where 
fuel flow is measured in a common pipe header (i.e., a pipe carrying 
fuel for multiple units), the owner or operator may use the procedures 
in section 2.1.2 of appendix D of this part for combining or 
apportioning emissions, except that the term ``SO2 mass 
emissions'' is replaced with the term ``CO2 mass emissions.''
[GRAPHIC] [TIFF OMITTED] TR17MY95.021

Where:

Wco2 = CO2 emitted from combustion, tons/day.
MWc = Molecular weight of carbon (12.0).
MWo2 = Molecular weight of oxygen (32.0)
Wc = Carbon burned, lb/day, determined using fuel sampling 
          and analysis and fuel feed rates.

    2.1.1 Collect at least one fuel sample during each week that the 
unit combusts coal, one sample per each shipment or delivery for oil and 
diesel fuel, one fuel sample for each delivery for gaseous fuel in lots, 
one sample per day or per hour (as applicable) for each gaseous fuel 
that is required to be sampled daily or hourly for gross calorific value 
under section 2.3.5.6 of appendix D to this part, and one sample per 
month for each gaseous fuel that is required to be sampled monthly for 
gross calorific value under section 2.3.4.1 or 2.3.4.2 of appendix D to 
this part. Collect coal samples from a location in the fuel handling 
system that provides a sample representative of the fuel bunkered or 
consumed during the week.
    2.1.2 Determine the carbon content of each fuel sample using one of 
the following methods: ASTM D3178-89 (Reapproved 2002) or ASTM D5373-02 
(Reapproved 2007) for coal; ASTM D5291-02, Standard Test Methods for 
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in 
Petroleum Products and Lubricants, ultimate analysis of oil, or 
computations based upon ASTM D3238-95 (Reapproved 2000) and either ASTM 
D2502-92 (Reapproved 1996) or ASTM D2503-92 (Reapproved 1997) for oil; 
and computations based on ASTM D1945-96 (Reapproved 2001) or ASTM D1946-
90 (Reapproved 2006) for gas (all incorporated by reference under Sec. 
75.6 of this part).
    2.1.3 Use daily fuel feed rates from company records for all fuels 
and the carbon content of the most recent fuel sample under this section 
to determine tons of carbon per day from combustion of each fuel. (All 
ASTM methods are incorporated by reference under Sec. 75.6.) Where more 
than one fuel is combusted during a calendar day, calculate total tons 
of carbon for the day from all fuels.
    2.2 For an affected coal-fired unit, the estimate of daily 
CO2 mass emissions given by equation G-1 may be adjusted to 
account for carbon retained in the ash using the procedures in either 
section 2.2.1 through 2.2.3 or section 2.2.4 of this appendix.
    2.2.1 Determine the ash content of the weekly sample of coal using 
ASTM D3174-00, ``Standard Test Method for Ash in the Analysis Sample of 
Coal and Coke from Coal'' (incorporated by reference under Sec. 75.6 of 
this part).
    2.2.2 Sample and analyze the carbon content of the fly-ash according 
to ASTM D5373-02 (Reapproved 2007), Standard Test Methods for 
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in 
Laboratory Samples of Coal and Coke'' (incorporated by reference under 
Sec. 75.6 of this part).
    2.2.3 Discount the estimate of daily CO2 mass emissions 
from the combustion of coal given by equation G-1 by the percent carbon 
retained in the ash using the following equation:

[[Page 458]]

[GRAPHIC] [TIFF OMITTED] TC01SE92.133

(Eq. G-2)
where,

WNCO2 = Net CO2 mass emissions discharged to the 
          atmosphere, tons/day.
WCO2 = Daily CO2 mass emissions calculated by 
          equation G-1, tons/day.
MWC02 = Molecular weight of carbon dioxide (44.0).
MWc = Molecular weight of carbon (12.0).
A% = Ash content of the coal sample, percent by weight.
C% = Carbon content of ash, percent by weight.
WCOAL = Feed rate of coal from company records, tons/day.

    2.2.4 The daily CO2 mass emissions from combusting coal 
may be adjusted to account for carbon retained in the ash using the 
following equation:

WNCO2 = .99 WCO2
(Eq. G-3)

where,

WNCO2 = Net CO2 mass emissions from the combustion 
          of coal discharged to the atmosphere, tons/day.
.99 = Average fraction of coal converted into CO2 upon 
          combustion.
WCO2 = Daily CO2 mass emissions from the 
          combustion of coal calculated by equation G-1, tons/day.

    2.3 In lieu of using the procedures, methods, and equations in 
section 2.1 of this appendix, the owner or operator of an affected gas-
fired or oil-fired unit (as defined under Sec. 72.2 of this chapter) 
may use the following equation and records of hourly heat input to 
estimate hourly CO2 mass emissions (in tons).
[GRAPHIC] [TIFF OMITTED] TR17MY95.022

(Eq. G-4)

Where:

WCO2 = CO2 emitted from combustion, tons/hr.
MW CO2 = Molecular weight of carbon dioxide, 44.0 lb/lb-mole.
Fc = Carbon based F-factor, 1040 scf/mmBtu for natural gas; 
          1,420 scf/mmBtu for crude, residual, or distillate oil; and 
          calculated according to the procedures in section 3.3.5 of 
          appendix F to this part for other gaseous fuels.
H = Hourly heat input in mmBtu, as calculated using the procedures in 
          section 5 of appendix F of this part.
Uf = 1/385 scf CO2/lb-mole at 14.7 psia and 68 F.

   3. Procedures for Estimating CO2 Emissions From Sorbent

    When the affected unit has a wet flue gas desulfurization system, is 
a fluidized bed boiler, or uses other emission controls with sorbent 
injection, use either a CO2 continuous emission monitoring 
system or an O2 monitor and a flow monitor, or use the 
procedures, methods, and equations in sections 3.1 through 3.2 of this 
appendix to determine daily CO2 mass emissions from the 
sorbent (in tons).
    3.1 When limestone is the sorbent material, use the equations and 
procedures in either section 3.1.1 or 3.1.2 of this appendix.
    3.1.1 Use the following equation to estimate daily CO2 
mass emissions from sorbent (in tons).
[GRAPHIC] [TIFF OMITTED] TC01SE92.134

(Eq. G-5)

where,

SECO2 = CO2 emitted from sorbent, tons/day.
WCaCO3 = CaCO3 used, tons/day.
Fu = 1.00, the calcium to sulfur stoichiometric ratio.
MWCO2 = Molecular weight of carbon dioxide (44).
MWCaCO3 = Molecular weight of calcium carbonate (100).

    3.1.2 In lieu of using Equation G-5, any owner or operator who 
operates and maintains a certified SO2-diluent continuous 
emission monitoring system (consisting of an SO2 pollutant 
concentration monitor and an O2 or CO2 diluent gas 
monitor), for measuring and recording SO2 emission rate (in 
lb/mmBtu) at the outlet to the emission controls and who uses the 
applicable procedures, methods, and equations such as those in EPA 
Method 19 in appendix A to part 60 of this chapter to estimate the 
SO2 emissions removal efficiency of the emission controls, 
may use the following equations to estimate

[[Page 459]]

daily CO2 mass emissions from sorbent (in tons).
[GRAPHIC] [TIFF OMITTED] TC01SE92.135

(Eq. G-6)

where,

SECO2 = CO2 emitted from sorbent, tons/day.
MWCO2 = Molecular weight of carbon dioxide (44).
MWSO2 = Molecular weight of sulfur dioxide (64).
WSO2 = Sulfur dioxide removed, lb/day, as calculated below 
          using Eq. G-7.
Fu = 1.0, the calcium to sulfur stoichiometric ratio.

and
[GRAPHIC] [TIFF OMITTED] TR17MY95.023

(Eq. G-7)

where:

WSO2 = Weight of sulfur dioxide removed, lb/day.
SO20 = SO2 mass emissions monitored at the outlet, 
          lb/day, as calculated using the equations and procedures in 
          section 2 of appendix F of this part.
%R = Overall percentage SO2 emissions removal efficiency, 
          calculated using equations such as those in EPA Method 19 in 
          appendix A to part 60 of this chapter, and using daily instead 
          of annual average emission rates.

    3.2 When a sorbent material other than limestone is used, modify the 
equations, methods, and procedures in section 3.1 of this appendix as 
follows to estimate daily CO2 mass emissions from sorbent (in 
tons).
    3.2.1 Determine a site-specific value for Fu, defined as 
the ratio of the number of moles of CO2 released upon capture 
of one mole of SO2, using methods and procedures satisfactory 
to the Administrator. Use this value of Fu (instead of 1.0) 
in either equation G-5 or equation G-6.
    3.2.2 When using equation G-5, replace MWCaCO3, the 
molecular weight of calcium carbonate, with the molecular weight of the 
sorbent material that participates in the reaction to capture 
SO2 and that releases CO2, and replace 
WCaCO3, the amount of calcium carbonate used (in tons/day), 
with the amount of sorbent material used (in tons/day).

       4. Procedures for Estimating Total CO2 Emissions

    When the affected unit has a wet flue gas desulfurization system, is 
a fluidized bed boiler, or uses other emission controls with sorbent 
injection, use the following equation to obtain total daily 
CO2 mass emissions (in tons) as the sum of combustion-related 
emissions and sorbent-related emissions.

Wt = WCO2 + SECO2
(Eq. G-8)

where,
Wt = Estimated total CO2 mass emissions, tons/day.
WCO2 = CO2 emitted from fuel combustion, tons/day.
SECO2 = CO2 emitted from sorbent, tons/day.

    5. Missing Data Substitution Procedures for Fuel Analytical Data

    Use the following procedures to substitute for missing fuel 
analytical data used to calculate CO2 mass emissions under 
this appendix.

                          5.1-5.1.2 [Reserved]

                     5.2 Missing Carbon Content Data

    Use the following procedures to substitute for missing carbon 
content data.
    5.2.1 In all cases (i.e., for weekly coal samples or composite oil 
samples from continuous sampling, for oil samples taken from the storage 
tank after transfer of a new delivery of fuel, for as-delivered samples 
of oil, diesel fuel, or gaseous fuel delivered in lots, and for gaseous 
fuel that is supplied by a pipeline and sampled monthly, daily or hourly 
for gross calorific value) when carbon content data is missing, report 
the appropriate default value from Table G-1.
    5.2.2 The missing data values in Table G-1 shall be reported 
whenever the results of a required sample of fuel carbon content are 
either missing or invalid. The substitute data value shall be used until 
the next valid carbon content sample is obtained.

[[Page 460]]

[GRAPHIC] [TIFF OMITTED] TR12JN02.024

                     5.3 Gross Calorific Value Data

    For a gas-fired unit using the procedures of section 2.3 of this 
appendix to determine CO2 emissions, substitute for missing 
gross calorific value data used to calculate heat input by following the 
missing data procedures for gross calorific value in section 2.4 of 
appendix D to this part.

[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26556, May 17, 1995; 61 
FR 25585, May 22, 1996; 64 FR 28671, May 26, 1999; 67 FR 40475, June 12, 
2002; 67 FR 57274, Sept. 9, 2002; 73 FR 4376, Jan. 24, 2008]



    Sec. Appendix H to Part 75--Revised Traceability Protocol No. 1 
                               [Reserved]



    Sec. Appendix I to Part 75--Optional F--Factor/Fuel Flow Method 
                               [Reserved]



 Sec. Appendix J to Part 75--Compliance Dates for Revised Recordkeeping 
           Requirements and Missing Data Procedures [Reserved]



PART 76_ACID RAIN NITROGEN OXIDES EMISSION REDUCTION PROGRAM--
Table of Contents



Sec.
76.1 Applicability.
76.2 Definitions.
76.3 General Acid Rain Program provisions.
76.4 Incorporation by reference.
76.5 NOX emission limitations for Group 1 boilers.
76.6 NOX emission limitations for Group 2 boilers.
76.7 Revised NOX emission limitations for Group 1, Phase II 
          boilers.
76.8 Early election for Group 1, Phase II boilers.
76.9 Permit application and compliance plans.

[[Page 461]]

76.10 Alternative emission limitations.
76.11 Emissions averaging.
76.12 Phase I NOX compliance extension.
76.13 Compliance and excess emissions.
76.14 Monitoring, recordkeeping, and reporting.
76.15 Test methods and procedures.

Appendix A to Part 76--Phase I Affected Coal-Fired Utility Units With 
          Group 1 or Cell Burner Boilers
Appendix B to Part 76--Procedures and Methods for Estimating Costs of 
          Nitrogen Oxides Controls Applied to Group 1, Phase I Boilers

    Authority: 42 U.S.C. 7601 and 7651 et seq.

    Source: 60 FR 18761, Apr. 13, 1995, unless otherwise noted.



Sec. 76.1  Applicability.

    (a) Except as provided in paragraphs (b) through (d) of this 
section, the provisions apply to each coal-fired utility unit that is 
subject to an Acid Rain emissions limitation or reduction requirement 
for SO2 under Phase I or Phase II pursuant to sections 404, 
405, or 409 of the Act.
    (b) The emission limitations for NOX under this part 
apply to each affected coal-fired utility unit subject to section 404(d) 
or 409(b) of the Act on the date the unit is required to meet the Acid 
Rain emissions reduction requirement for SO2.
    (c) The provisions of this part apply to each coal-fired 
substitution unit or compensating unit, designated and approved as a 
Phase I unit pursuant to Sec. 72.41 or Sec. 72.43 of this chapter as 
follows:
    (1) A coal-fired substitution unit that is designated in a 
substitution plan that is approved and active as of January 1, 1995 
shall be treated as a Phase I coal-fired utility unit for purposes of 
this part. In the event the designation of such unit as a substitution 
unit is terminated after December 31, 1995, pursuant to Sec. 72.41 of 
this chapter and the unit is no longer required to meet Phase I 
SO2 emissions limitations, the provisions of this part 
(including those applicable in Phase I) will continue to apply.
    (2) A coal-fired substitution unit that is designated in a 
substitution plan that is not approved or not active as of January 1, 
1995, or a coal-fired compensating unit, shall be treated as a Phase II 
coal-fired utility unit for purposes of this part.
    (d) The provisions of this part for Phase I units apply to each 
coal-fired transfer unit governed by a Phase I extension plan, approved 
pursuant to Sec. 72.42 of this chapter, on January 1, 1997. 
Notwithstanding the preceding sentence, a coal-fired transfer unit shall 
be subject to the Acid Rain emissions limitations for nitrogen oxides 
beginning on January 1, 1996 if, for that year, a transfer unit is 
allocated fewer Phase I extension reserve allowances than the maximum 
amount that the designated representative could have requested in 
accordance with Sec. 72.42(c)(5) of this chapter (as adjusted under 
Sec. 72.42(d) of this chapter) unless the transfer unit is the last 
unit allocated Phase I extension reserve allowances under the plan.



Sec. 76.2  Definitions.

    All terms used in this part shall have the meaning set forth in the 
Act, in Sec. 72.2 of this chapter, and in this section as follows:
    Alternative contemporaneous annual emission limitation means the 
maximum allowable NOX emission rate (on a lb/mmBtu, annual 
average basis) assigned to an individual unit in a NOX 
emissions averaging plan pursuant to Sec. 76.10.
    Alternative technology means a control technology for reducing 
NOX emissions that is outside the scope of the definition of 
low NOX burner technology. Alternative technology does not 
include overfire air as applied to wall-fired boilers or separated 
overfire air as applied to tangentially fired boilers.
    Approved clean coal technology demonstration project means a project 
using funds appropriated under the Department of Energy's ``Clean Coal 
Technology Demonstration Program,'' up to a total amount of 
$2,500,000,000 for commercial demonstration of clean coal technology, or 
similar projects funded through appropriations for the Environmental 
Protection Agency. The Federal contribution for a qualifying project 
shall be at least 20 percent of the total cost of the demonstration 
project.
    Arch-fired boiler means a dry bottom boiler with circular burners, 
or coal

[[Page 462]]

and air pipes, oriented downward and mounted on waterwalls that are at 
an angle significantly different from the horizontal axis and the 
vertical axis. This definition shall include only the following units: 
Holtwood unit 17, Hunlock unit 6, and Sunbury units 1A, 1B, 2A, and 2B. 
This definition shall exclude dry bottom turbo fired boilers.
    Cell burner boiler means a wall-fired boiler that utilizes two or 
three circular burners combined into a single vertically oriented 
assembly that results in a compact, intense flame. Any low 
NOX retrofit of a cell burner boiler that reuses the existing 
cell burner, close-coupled wall opening configuration would not change 
the designation of the unit as a cell burner boiler.
    Coal-fired utility unit means a utility unit in which the combustion 
of coal (or any coal-derived fuel) on a Btu basis exceeds 50.0 percent 
of its annual heat input during the following calendar year: for Phase I 
units, in calendar year 1990; and, for Phase II units, in calendar year 
1995 or, for a Phase II unit that did not combust any fuel that resulted 
in the generation of electricity in calendar year 1995, in any calendar 
year during the period 1990-1995. For the purposes of this part, this 
definition shall apply notwithstanding the definition in Sec. 72.2 of 
this chapter.
    Combustion controls means technology that minimizes NOX 
formation by staging fuel and combustion air flows in a boiler. This 
definition shall include low NOX burners, overfire air, or 
low NOX burners with overfire air.
    Cyclone boiler means a boiler with one or more water-cooled 
horizontal cylindrical chambers in which coal combustion takes place. 
The horizontal cylindrical chamber(s) is (are) attached to the bottom of 
the furnace. One or more cylindrical chambers are arranged either on one 
furnace wall or on two opposed furnace walls. Gaseous combustion 
products exiting from the chamber(s) turn 90 degrees to go up through 
the boiler while coal ash exits the bottom of the boiler as a molten 
slag.
    Demonstration period means a period of time not less than 15 months, 
approved under Sec. 76.10, for demonstrating that the affected unit 
cannot meet the applicable emission limitation under Sec. 76.5, 76.6, 
or 76.7 and establishing the minimum NOX emission rate that 
the unit can achieve during long-term load dispatch operation.
    Dry bottom means the boiler has a furnace bottom temperature below 
the ash melting point and the bottom ash is removed as a solid.
    Economizer means the lowest temperature heat exchange section of a 
utility boiler where boiler feed water is heated by the flue gas.
    Flue gas means the combustion products arising from the combustion 
of fossil fuel in a utility boiler.
    Group 1 boiler means a tangentially fired boiler or a dry bottom 
wall-fired boiler (other than a unit applying cell burner technology).
    Group 2 boiler means a wet bottom wall-fired boiler, a cyclone 
boiler, a boiler applying cell burner technology, a vertically fired 
boiler, an arch-fired boiler, or any other type of utility boiler (such 
as a fluidized bed or stoker boiler) that is not a Group 1 boiler.
    Low NOX burners and low NOX burner technology means commercially 
available combustion modification NOX controls that minimize 
NOX formation by introducing coal and its associated 
combustion air into a boiler such that initial combustion occurs in a 
manner that promotes rapid coal devolatilization in a fuel-rich (i.e., 
oxygen deficient) environment and introduces additional air to achieve a 
final fuel-lean (i.e., oxygen rich) environment to complete the 
combustion process. This definition shall include the staging of any 
portion of the combustion air using air nozzles or registers located 
inside any waterwall hole that includes a burner. This definition shall 
exclude the staging of any portion of the combustion air using air 
nozzles or ports located outside any waterwall hole that includes a 
burner (commonly referred to as NOX ports or separated 
overfire air ports).
    Maximum Continuous Steam Flow at 100% of Load means the maximum 
capacity of a boiler as reported in item 3 (Maximum Continuous Steam 
Flow at 100% Load in thousand pounds per hour), Section C (design 
parameters), Part III (boiler information) of the Department of Energy's 
Form EIA-767 for 1995.

[[Page 463]]

    Non-plug-in combustion controls means the replacement, in a cell 
burner boiler, of the portions of the waterwalls containing the cell 
burners by new portions of the waterwalls containing low NOX 
burners or low NOX burners with overfire air.
    Operating period means a period of time of not less than three 
consecutive months and that occurs not more than one month prior to 
applying for an alternative emission limitation demonstration period 
under Sec. 76.10, during which the owner or operator of an affected 
unit that cannot meet the applicable emission limitation:
    (1) Operates the installed NOX emission controls in 
accordance with primary vendor specifications and procedures, with the 
unit operating under normal conditions; and
    (2) records and reports quality-assured continuous emission 
monitoring (CEM) and unit operating data according to the methods and 
procedures in part 75 of this chapter.
    Plug-in combustion controls means the replacement, in a cell burner 
boiler, of existing cell burners by low NOX burners or low 
NOX burners with overfire air.
    Primary vendor means the vendor of the NOX emission 
control system who has primary responsibility for providing the 
equipment, service, and technical expertise necessary for detailed 
design, installation, and operation of the controls, including process 
data, mechanical drawings, operating manuals, or any combination 
thereof.
    Reburning means reducing the coal and combustion air to the main 
burners and injecting a reburn fuel (such as gas or oil) to create a 
fuel-rich secondary combustion zone above the main burner zone and final 
combustion air to create a fuel-lean burnout zone. The formation of 
NOX is inhibited in the main burner zone due to the reduced 
combustion intensity, and NOX is destroyed in the fuel-rich 
secondary combustion zone by conversion to molecular nitrogen.
    Selective catalytic reduction means a noncombustion control 
technology that destroys NOX by injecting a reducing agent 
(e.g., ammonia) into the flue gas that, in the presence of a catalyst 
(e.g., vanadium, titanium, or zeolite), converts NOX into 
molecular nitrogen and water.
    Selective noncatalytic reduction means a noncombustion control 
technology that destroys NOX by injecting a reducing agent 
(e.g., ammonia, urea, or cyanuric acid) into the flue gas, downstream of 
the combustion zone that converts NOX to molecular nitrogen, 
water, and when urea or cyanuric acid are used, to carbon dioxide 
(CO2).
    Stoker boiler means a boiler that burns solid fuel in a bed, on a 
stationary or moving grate, that is located at the bottom of the 
furnace.
    Tangentially fired boiler means a boiler that has coal and air 
nozzles mounted in each corner of the furnace where the vertical furnace 
walls meet. Both pulverized coal and air are directed from the furnace 
corners along a line tangential to a circle lying in a horizontal plane 
of the furnace.
    Turbo-fired boiler means a pulverized coal, wall-fired boiler with 
burners arranged on walls so that the individual flames extend down 
toward the furnace bottom and then turn back up through the center of 
the furnace.
    Vertically fired boiler means a dry bottom boiler with circular 
burners, or coal and air pipes, oriented downward and mounted on 
waterwalls that are horizontal or at an angle. This definition shall 
include dry bottom roof-fired boilers and dry bottom top-fired boilers, 
and shall exclude dry bottom arch-fired boilers and dry bottom turbo-
fired boilers.
    Wall-fired boiler means a boiler that has pulverized coal burners 
arranged on the walls of the furnace. The burners have discrete, 
individual flames that extend perpendicularly into the furnace area.
    Wet bottom means that the ash is removed from the furnace in a 
molten state. The term ``wet bottom boiler'' shall include: wet bottom 
wall-fired boilers, including wet bottom turbo-fired boilers; and wet 
bottom boilers otherwise meeting the definition of vertically fired 
boilers, including wet bottom arch-fired boilers, wet bottom roof-fired 
boilers, and wet bottom top-fired boilers. The term ``wet bottom

[[Page 464]]

boiler'' shall exclude cyclone boilers and tangentially fired boilers.

[60 FR 18761, Apr. 13, 1995, as amended at 61 FR 67162, Dec. 19, 1996]



Sec. 76.3  General Acid Rain Program provisions.

    The following provisions of part 72 of this chapter shall apply to 
this part:
    (a) Sec. 72.2 (Definitions);
    (b) Sec. 72.3 (Measurements, abbreviations, and acronyms);
    (c) Sec. 72.4 (Federal authority);
    (d) Sec. 72.5 (State authority);
    (e) Sec. 72.6 (Applicability);
    (f) Sec. 72.7 (New unit exemption);
    (g) Sec. 72.8 (Retired units exemption);
    (h) Sec. 72.9 (Standard requirements);
    (i) Sec. 72.10 (Availability of information); and
    (j) Sec. 72.11 (Computation of time).
    In addition, the procedures for appeals of decisions of the 
Administrator under this part are contained in part 78 of this chapter.



Sec. 76.4  Incorporation by reference.

    (a) The materials listed in this section are incorporated by 
reference in the sections noted. These incorporations by reference 
(IBR's) were approved by the Director of the Federal Register in 
accordance with 5 U.S.C. 552(a) and 1 CFR part 51. These materials are 
incorporated as they existed on the date of approval, and notice of any 
change in these materials will be published in the Federal Register. The 
materials are available for purchase at the corresponding address noted 
below and are available for inspection at the Public Information 
Reference Unit, U.S. EPA, 401 M St., SW., Washington, DC, and at the 
Library (MD-35), U.S. EPA, Research Triangle Park, North Carolina or 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.
    (b) The following materials are available for purchase from at least 
one of the following addresses: American Society for Testing and 
Materials (ASTM), 1916 Race Street, Philadelphia, Pennsylvania 19103; or 
the University Microfilms International, 300 North Zeeb Road, Ann Arbor, 
Michigan 48106.
    (1) ASTM D 3176-89, Standard Practice for Ultimate Analysis of Coal 
and Coke, IBR approved May 23, 1995 for Sec. 76.15.
    (2) ASTM D 3172-89, Standard Practice for Proximate Analysis of Coal 
and Coke, IBR approved May 23, 1995 for Sec. 76.15.
    (c) The following material is available for purchase from the 
American Society of Mechanical Engineers (ASME), 22 Law Drive, Box 2350, 
Fairfield, NJ 07007-2350.
    (1) ASME Performance Test Code 4.2 (1991), Test Code for Coal 
Pulverizers, IBR approved May 23, 1995 for Sec. 76.15.
    (2) [Reserved]
    (d) The following material is available for purchase from the 
American National Standards Institute, 11 West 42nd Street, New York, NY 
10036 or from the International Organization for Standardization (ISO), 
Case Postale 56, CH-1211 Geneve 20, Switzerland.
    (1) ISO 9931 (December, 1991) ``Coal--Sampling of Pulverized Coal 
Conveyed by Gases in Direct Fired Coal Systems,'' IBR approved May 23, 
1995 for Sec. 76.15.
    (2) [Reserved]



Sec. 76.5  NOX emission limitations for Group 1 boilers.

    (a) Beginning January 1, 1996, or for a unit subject to section 
404(d) of the Act, the date on which the unit is required to meet Acid 
Rain emission reduction requirements for SO2, the owner or 
operator of a Phase I coal-fired utility unit with a tangentially fired 
boiler or a dry bottom wall-fired boiler (other than units applying cell 
burner technology) shall not discharge, or allow to be discharged, 
emissions of NOX to the atmosphere in excess of the following 
limits, except as provided in paragraphs (c) or (e) of this section or 
in Sec. 76.10, 76.11, or 76.12:
    (1) 0.45 lb/mmBtu of heat input on an annual average basis for 
tangentially fired boilers.
    (2) 0.50 lb/mmBtu of heat input on an annual average basis for dry 
bottom wall-fired boilers (other than units applying cell burner 
technology).

[[Page 465]]

    (b) The owner or operator shall determine the annual average 
NOX emission rate, in lb/mmBtu, using the methods and 
procedures specified in part 75 of this chapter.
    (c) Unless the unit meets the early election requirement of Sec. 
76.8, the owner or operator of a coal-fired substitution unit with a 
tangentially fired boiler or a dry bottom wall-fired boiler (other than 
units applying cell burner technology) that satisfies the requirements 
of Sec. 76.1(c)(2), shall comply with the NOX emission 
limitations that apply to Group 1, Phase II boilers.
    (d) The owner or operator of a Phase I unit with a cell burner 
boiler that converts to a conventional wall-fired boiler on or before 
January 1, 1995 or, for a unit subject to section 404(d) of the Act, the 
date the unit is required to meet Acid Rain emissions reduction 
requirements for SO2 shall comply, by such respective date or 
January 1, 1996, whichever is later, with the NOX emissions 
limitation applicable to dry bottom wall-fired boilers under paragraph 
(a) of this section, except as provided in paragraphs (c) or (e) of this 
section or in Sec. 76.10, 76.11, or 76.12.
    (e) The owner or operator of a Phase I unit with a Group 1 boiler 
that converts to a fluidized bed or other type of utility boiler not 
included in Group 1 boilers on or before January 1, 1995 or, for a unit 
subject to section 404(d) of the Act, the date the unit is required to 
meet Acid Rain emissions reduction requirements for SO2 is 
exempt from the NOX emissions limitations specified in 
paragraph (a) of this section, but shall comply with the NOX 
emission limitations for Group 2 boilers under Sec. 76.6.
    (f) Except as provided in Sec. 76.8 and in paragraph (c) of this 
section, each unit subject to the requirements of this section is not 
subject to the requirements of Sec. 76.7.

[60 FR 18761, Apr. 13, 1995, as amended at 61 FR 67162, Dec. 19, 1996]



Sec. 76.6  NOX emission limitations for Group 2 boilers.

    (a) Beginning January 1, 2000 or, for a unit subject to section 
409(b) of the Act, the date on which the unit is required to meet Acid 
Rain emission reduction requirements for SO2, the owner or 
operator of a Group 2, coal-fired boiler with a cell burner boiler, 
cyclone boiler, a wet bottom boiler, or a vertically fired boiler shall 
not discharge, or allow to be discharged, emissions of NOX to 
the atmosphere in excess of the following limits, except as provided in 
Sec. Sec. 76.10 or 76.11:
    (1) 0.68 lb/mmBtu of heat input on an annual average basis for cell 
burner boilers. The NOX emission control technology on which 
the emission limitation is based is plug-in combustion controls or non-
plug-in combustion controls. Except as provided in Sec. 76.5(d), the 
owner or operator of a unit with a cell burner boiler that installs non-
plug-in combustion controls shall comply with the emission limitation 
applicable to cell burner boilers.
    (2) 0.86 lb/mmBtu of heat input on an annual average basis for 
cyclone boilers with a Maximum Continuous Steam Flow at 100% of Load of 
greater than 1060, in thousands of lb/hr. The NOX emission 
control technology on which the emission limitation is based is natural 
gas reburning or selective catalytic reduction.
    (3) 0.84 lb/mmBtu of heat input on an annual average basis for wet 
bottom boilers, with a Maximum Continuous Steam Flow at 100% of Load of 
greater than 450, in thousands of lb/hr. The NOX emission 
control technology on which the emission limitation is based is natural 
gas reburning or selective catalytic reduction.
    (4) 0.80 lb/mmBtu of heat input on an annual average basis for 
vertically fired boilers. The NOX emission control technology 
on which the emission limitation is based is combustion controls.
    (b) The owner or operator shall determine the annual average 
NOX emission rate, in lb/mmBtu, using the methods and 
procedures specified in part 75 of this chapter.

[62 FR 67162, Dec. 19, 1996; 62 FR 3464, Jan. 23, 1997; 62 FR 32040, 
June 12, 1997; 64 FR 55838, Oct. 15, 1999]



Sec. 76.7  Revised NOX emission limitations for Group 1, 
Phase II boilers.

    (a) Beginning January 1, 2000, the owner or operator of a Group 1, 
Phase II coal-fired utility unit with a tangentially fired boiler or a 
dry bottom wall-fired boiler shall not discharge, or

[[Page 466]]

allow to be discharged, emissions of NOX to the atmosphere in 
excess of the following limits, except as provided in Sec. Sec. 76.8, 
76.10, or 76.11:
    (1) 0.40 lb/mmBtu of heat input on an annual average basis for 
tangentially fired boilers.
    (2) 0.46 lb/ mmBtu of heat input on an annual average basis for dry 
bottom wall-fired boilers (other than units applying cell burner 
technology).
    (b) The owner or operator shall determine the annual average 
NOX emission rate, in lb/mmBtu, using the methods and 
procedures specified in part 75 of this chapter.

[60 FR 18761, Apr. 13, 1995, as amended at 61 FR 67163, Dec. 19, 1996]



Sec. 76.8  Early election for Group 1, Phase II boilers.

    (a) General provisions. (1) The owner or operator of a Phase II 
coal-fired utility unit with a Group 1 boiler may elect to have the unit 
become subject to the applicable emissions limitation for NOX 
under Sec. 76.5, starting no later than January 1, 1997.
    (2) The owner or operator of a Phase II coal-fired utility unit with 
a Group 1 boiler that elects to become subject to the applicable 
emission limitation under Sec. 76.5 shall not be subject to Sec. 76.7 
until January 1, 2008, provided the designated representative 
demonstrates that the unit is in compliance with the limitation under 
Sec. 76.5, using the methods and procedures specified in part 75 of 
this chapter, for the period beginning January 1 of the year in which 
the early election takes effect (but not later than January 1, 1997) and 
ending December 31, 2007.
    (3) The owner or operator of any Phase II unit with a cell burner 
boiler that converts to conventional burner technology may elect to 
become subject to the applicable emissions limitation under Sec. 76.5 
for dry bottom wall-fired boilers, provided the owner or operator 
complies with the provisions in paragraph (a)(2) of this section.
    (4) The owner or operator of a Phase II unit approved for early 
election shall not submit an application for an alternative emissions 
limitation demonstration period under Sec. 76.10 until the earlier of:
    (i) January 1, 2008; or
    (ii) Early election is terminated pursuant to paragraph (e)(3) of 
this section.
    (5) The owner or operator of a Phase II unit approved for early 
election may not incorporate the unit into an averaging plan prior to 
January 1, 2000. On or after January 1, 2000, for purposes of the 
averaging plan, the early election unit will be treated as subject to 
the applicable emissions limitation for NOX for Phase II 
units with Group 1 boilers under Sec. 76.7.
    (b) Submission requirements. In order to obtain early election 
status, the designated representative of a Phase II unit with a Group 1 
boiler shall submit an early election plan to the Administrator by 
January 1 of the year the early election is to take effect, but not 
later than January 1, 1997. Notwithstanding Sec. 72.40 of this chapter, 
and unless the unit is a substitution unit under Sec. 72.41 of this 
chapter or a compensating unit under Sec. 72.43 of this chapter, a 
complete compliance plan covering the unit shall not include the 
provisions for SO2 emissions under Sec. 72.40(a)(1) of this 
chapter.
    (c) Contents of an early election plan. A complete early election 
plan shall include the following elements in a format prescribed by the 
Administrator:
    (1) A request for early election;
    (2) The first year for which early election is to take effect, but 
not later than 1997; and
    (3) The special provisions under paragraph (e) of this section.
    (d)(1) Permitting authority's action. To the extent the 
Administrator determines that an early election plan complies with the 
requirements of this section, the Administrator will approve the plan 
and:
    (i) If a Phase I Acid Rain permit governing the source at which the 
unit is located has been issued, will revise the permit in accordance 
with the permit modification procedures in Sec. 72.81 of this chapter 
to include the early election plan; or
    (ii) If a Phase I Acid Rain permit governing the source at which the 
unit is located has not been issued, will issue a Phase I Acid Rain 
permit effective from January 1, 1995 through December 31, 1999, that 
will include the early

[[Page 467]]

election plan and a complete compliance plan under Sec. 72.40(a) of 
this chapter and paragraph (b) of this section. If the early election 
plan is not effective until after January 1, 1995, the permit will not 
contain any NOX emissions limitations until the effective 
date of the plan.
    (2) Beginning January 1, 2000, the permitting authority will approve 
any early election plan previously approved by the Administrator during 
Phase I, unless the plan is terminated pursuant to paragraph (e)(3) of 
this section.
    (e) Special provisions--(1) Emissions limitations--(i) Sulfur 
dioxide. Notwithstanding Sec. 72.9 of this chapter, a unit that is 
governed by an approved early election plan and that is not a 
substitution unit under Sec. 72.41 of this chapter or a compensating 
unit under Sec. 72.43 of this chapter shall not be subject to the 
following standard requirements under Sec. 72.9 of this chapter for 
Phase I:
    (A) The permit requirements under Sec. Sec. 72.9(a)(1) (i) and (ii) 
of this chapter;
    (B) The sulfur dioxide requirements under Sec. 72.9(c) of this 
chapter; and
    (C) The excess emissions requirements under Sec. 72.9(e)(1) of this 
chapter.
    (ii) Nitrogen oxides. A unit that is governed by an approved early 
election plan shall be subject to an emissions limitation for 
NOX as provided under paragraph (a)(2) of this section except 
as provided under paragraph (e)(3)(iii) of this section.
    (2) Liability. The owners and operators of any unit governed by an 
approved early election plan shall be liable for any violation of the 
plan or this section at that unit. The owners and operators shall be 
liable, beginning January 1, 2000, for fulfilling the obligations 
specified in part 77 of this chapter.
    (3) Termination. An approved early election plan shall be in effect 
only until the earlier of January 1, 2008 or January 1 of the calendar 
year for which a termination of the plan takes effect.
    (i) If the designated representative of the unit under an approved 
early election plan fails to demonstrate compliance with the applicable 
emissions limitation under Sec. 76.5 for any year during the period 
beginning January 1 of the first year the early election takes effect 
and ending December 31, 2007, the permitting authority will terminate 
the plan. The termination will take effect beginning January 1 of the 
year after the year for which there is a failure to demonstrate 
compliance, and the designated representative may not submit a new early 
election plan.
    (ii) The designated representative of the unit under an approved 
early election plan may terminate the plan any year prior to 2008 but 
may not submit a new early election plan. In order to terminate the 
plan, the designated representative must submit a notice under Sec. 
72.40(d) of this chapter by January 1 of the year for which the 
termination is to take effect.
    (iii)(A) If an early election plan is terminated any year prior to 
2000, the unit shall meet, beginning January 1, 2000, the applicable 
emissions limitation for NOX for Phase II units with Group 1 
boilers under Sec. 76.7.
    (B) If an early election plan is terminated in or after 2000, the 
unit shall meet, beginning on the effective date of the termination, the 
applicable emissions limitation for NOX for Phase II units 
with Group 1 boilers under Sec. 76.7.

[60 FR 18761, Apr. 13, 1995, as amended at 61 FR 67163, Dec. 19, 1996]



Sec. 76.9  Permit application and compliance plans.

    (a) Duty to apply. (1) The designated representative of any source 
with an affected unit subject to this part shall submit, by the 
applicable deadline under paragraph (b) of this section, a complete Acid 
Rain permit application (or, if the unit is covered by an Acid Rain 
permit, a complete permit revision) that includes a complete compliance 
plan for NOX emissions covering the unit.
    (2) The original and three copies of the permit application and 
compliance plan for NOX emissions for Phase I shall be 
submitted to the EPA regional office for the region where the applicable 
source is located. The original and three copies of the permit 
application and compliance plan for NOX emissions for Phase 
II shall be submitted to the permitting authority.
    (b) Deadlines. (1) For a Phase I unit with a Group 1 boiler, the 
designated

[[Page 468]]

representative shall submit a complete permit application and compliance 
plan for NOX covering the unit during Phase I to the 
applicable permitting authority not later than May 6, 1994.
    (2) For a Phase I or Phase II unit with a Group 2 boiler or a Phase 
II unit with a Group 1 boiler, the designated representative shall 
submit a complete permit application and compliance plan for 
NOX emissions covering the unit in Phase II to the 
Administrator not later than January 1, 1998, except that early election 
units shall also submit an application not later than January 1, 1997.
    (c) Information requirements for NOX compliance plans. 
(1) In accordance with Sec. 72.40(a)(2) of this chapter, a complete 
compliance plan for NOX shall, for each affected unit 
included in the permit application and subject to this part, either 
certify that the unit will comply with the applicable emissions 
limitation under Sec. 76.5, 76.6, or 76.7 or specify one or more other 
Acid Rain compliance options for NOX in accordance with the 
requirements of this part. A complete compliance plan for NOX 
for a source shall include the following elements in a format prescribed 
by the Administrator:
    (i) Identification of the source;
    (ii) Identification of each affected unit that is at the source and 
is subject to this part;
    (iii) Identification of the boiler type of each unit;
    (iv) Identification of the compliance option proposed for each unit 
(i.e., meeting the applicable emissions limitation under Sec. 76.5, 
76.6, 76.7, 76.8 (early election), 76.10 (alternative emission 
limitation), 76.11 (NOX emissions averaging), or 76.12 (Phase 
I NOX compliance extension)) and any additional information 
required for the appropriate option in accordance with this part;
    (v) Reference to the standard requirements in Sec. 72.9 of this 
chapter (consistent with Sec. 76.8(e)(1)(i)); and
    (vi) The requirements of Sec. Sec. 72.21 (a) and (b) of this 
chapter.
    (2) [Reserved]
    (d) Duty to reapply. The designated representative of any source 
with an affected unit subject to this part shall submit a complete Acid 
Rain permit application, including a complete compliance plan for 
NOX emissions covering the unit, in accordance with the 
deadlines in Sec. 72.30(c) of this chapter.



Sec. 76.10  Alternative emission limitations.

    (a) General provisions. (1) The designated representative of an 
affected unit that is not an early election unit pursuant to Sec. 76.8 
and cannot meet the applicable emission limitation in Sec. 76.5, 76.6, 
or 76.7 using, for Group 1 boilers, either low NOX burner 
technology or an alternative technology in accordance with paragraph 
(e)(11) of this section, or, for tangentially fired boilers, separated 
overfire air, or, for Group 2 boilers, the technology on which the 
applicable emission limitation is based may petition the permitting 
authority for an alternative emission limitation less stringent than the 
applicable emission limitation.
    (2) In order for the unit to qualify for an alternative emission 
limitation, the designated representative shall demonstrate that the 
affected unit cannot meet the applicable emission limitation in Sec. 
76.5, 76.6, or 76.7 based on a showing, to the satisfaction of the 
Administrator, that:
    (i)(A) For a tangentially fired boiler, the owner or operator has 
either properly installed low NOX burner technology or 
properly installed separated overfire air; or
    (B) For a dry bottom wall-fired boiler (other than a unit applying 
cell burner technology), the owner or operator has properly installed 
low NOX burner technology; or
    (C) For a Group 1 boiler, the owner or operator has properly 
installed an alternative technology (including but not limited to 
reburning, selective noncatalytic reduction, or selective catalytic 
reduction) that achieves NOX emission reductions demonstrated 
in accordance with paragraph (e)(11) of this section; or
    (D) For a Group 2 boiler, the owner or operator has properly 
installed the appropriate NOX emission control technology on 
which the applicable emission limitation in Sec. 76.6 is based; and
    (ii) The installed NOX emission control system has been 
designed to meet the applicable emission limitation in Sec. 76.5, 76.6, 
or 76.7; and

[[Page 469]]

    (iii) For a demonstration period of at least 15 months or other 
period of time, as provided in paragraph (f)(1) of this section:
    (A) The NOX emission control system has been properly 
installed and properly operated according to specifications and 
procedures designed to minimize the emissions of NOX to the 
atmosphere;
    (B) Unit operating data as specified in this section show that the 
unit and NOX emission control system were operated in 
accordance with the bid and design specifications on which the design of 
the NOX emission control system was based; and
    (C) Unit operating data as specified in this section, continuous 
emission monitoring data obtained pursuant to part 75 of this chapter, 
and the test data specific to the NOX emission control system 
show that the unit could not meet the applicable emission limitation in 
Sec. 76.5, 76.6, or 76.7.
    (b) Petitioning process. The petitioning process for an alternative 
emission limitation shall consist of the following steps:
    (1) Operation during a period of at least 3 months, following the 
installation of the NOX emission control system, that shows 
that the specific unit and the NOX emission control system 
was unable to meet the applicable emissions limitation under Sec. 76.5, 
76.6, or 76.7 and was operated in accordance with the operating 
conditions upon which the design of the NOX emission control 
system was based and with vendor specifications and procedures;
    (2) Submission of a petition for an alternative emission limitation 
demonstration period as specified in paragraph (d) of this section;
    (3) Operation during a demonstration period of at least 15 months, 
or other period of time as provided in paragraph (f)(1) of this section, 
that demonstrates the inability of the specific unit to meet the 
applicable emissions limitation under Sec. 76.5, 76.6, or 76.7 and the 
minimum NOX emissions rate that the specific unit can achieve 
during long-term load dispatch operation; and
    (4) Submission of a petition for a final alternative emission 
limitation as specified in paragraph (e) of this section.
    (c) Deadlines--(1) Petition for an alternative emission limitation 
demonstration period. The designated representative of the unit shall 
submit a petition for an alternative emission limitation demonstration 
period to the permitting authority after the unit has been operated for 
at least 3 months after installation of the NOX emission 
control system required under paragraph (a)(2) of this section and by 
the following deadline:
    (i) For units that seek to have an alternative emission limitation 
demonstration period apply during all or part of calendar year 1996, or 
any previous calendar year by the later of:
    (A) 120 days after startup of the NOX emission control 
system, or
    (B) May 1, 1996.
    (ii) For units that seek an alternative emission limitation 
demonstration period beginning in a calendar year after 1996, not later 
than:
    (A) 120 days after January 1 of that calendar year, or
    (B) 120 days after startup of the NOX emission control 
system if the unit is not operating at the beginning of that calendar 
year.
    (2) Petition for a final alternative emission limitation. Not later 
than 90 days after the end of an approved alternative emission 
limitation demonstration period for the unit, the designated 
representative of the unit may submit a petition for an alternative 
emission limitation to the permitting authority.
    (3) Renewal of an alternative emission limitation. In order to 
request continuation of an alternative emission limitation, the 
designated representative must submit a petition to renew the 
alternative emission limitation on the date that the application for 
renewal of the source's Acid Rain permit containing the alternative 
emission limitation is due.
    (d) Contents of petition for an alternative emission limitation 
demonstration period. The designated representative of an affected unit 
that has met the minimum criteria under paragraph (a) of this section 
and that has been operated for a period of at least 3 months following 
the installation of the required NOX emission control system

[[Page 470]]

may submit to the permitting authority a petition for an alternative 
emission limitation demonstration period. In the petition, the 
designated representative shall provide the following information in a 
format prescribed by the Administrator:
    (1) Identification of the unit;
    (2) The type of NOX control technology installed (e.g., 
low NOX burner technology, selective noncatalytic reduction, 
selective catalytic reduction, reburning);
    (3) If an alternative technology is installed, the time period (not 
less than 6 consecutive months) prior to installation of the technology 
to be used for the demonstration required in paragraph (e)(11) of this 
section.
    (4) Documentation as set forth in Sec. 76.14(a)(1) showing that the 
installed NOX emission control system has been designed to 
meet the applicable emission limitation in Sec. 76.5, 76.6, or 76.7 and 
that the system has been properly installed according to procedures and 
specifications designed to minimize the emissions of NOX to 
the atmosphere;
    (5) The date the unit commenced operation following the installation 
of the NOX emission control system or the date the specific 
unit became subject to the emission limitations of Sec. 76.5, 76.6, or 
76.7, whichever is later;
    (6) The dates of the operating period (which must be at least 3 
months long);
    (7) Certification by the designated representative that the owner(s) 
or operator operated the unit and the NOX emission control 
system during the operating period in accordance with: Specifications 
and procedures designed to achieve the maximum NOX reduction 
possible with the installed NOX emission control system or 
the applicable emission limitation in Sec. 76.5, 76.6, or 76.7; the 
operating conditions upon which the design of the NOX 
emission control system was based; and vendor specifications and 
procedures;
    (8) A brief statement describing the reason or reasons why the unit 
cannot achieve the applicable emission limitation in Sec. 76.5, 76.6, 
or 76.7;
    (9) A demonstration period plan, as set forth in Sec. 76.14(a)(2);
    (10) Unit operating data and quality-assured continuous emission 
monitoring data (including the specific data items listed in Sec. 
76.14(a)(3) collected in accordance with part 75 of this chapter during 
the operating period) and demonstrating the inability of the specific 
unit to meet the applicable emission limitation in Sec. 76.5, 76.6, or 
76.7 on an annual average basis while operating as certified under 
paragraph (d)(7) of this section;
    (11) An interim alternative emission limitation, in lb/mmBtu, that 
the unit can achieve during a demonstration period of at least 15 
months. The interim alternative emission limitation shall be derived 
from the data specified in paragraph (d)(10) of this section using 
methods and procedures satisfactory to the Administrator;
    (12) The proposed dates of the demonstration period (which must be 
at least 15 months long);
    (13) A report which outlines the testing and procedures to be taken 
during the demonstration period in order to determine the maximum 
NOX emission reduction obtainable with the installed system. 
The report shall include the reasons for the NOX emission 
control system's failure to meet the applicable emission limitation, and 
the tests and procedures that will be followed to optimize the 
NOX emission control system's performance. Such tests and 
procedures may include those identified in Sec. 76.15 as appropriate.
    (14) The special provisions at paragraph (g)(1) of this section.
    (e) Contents of petition for a final alternative emission 
limitation. After the approved demonstration period, the designated 
representative of the unit may petition the permitting authority for an 
alternative emission limitation. The petition shall include the 
following elements in a format prescribed by the Administrator:
    (1) Identification of the unit;
    (2) Certification that the owner(s) or operator operated the 
affected unit and the NOX emission control system during the 
demonstration period in accordance with: specifications and procedures 
designed to achieve the maximum NOX reduction possible with 
the installed NOX emission control system or the applicable 
emissions limitation in Sec. 76.5, 76.6, or 76.7; the operating 
conditions (including load dispatch conditions) upon which the design of 
the

[[Page 471]]

NOX emission control system was based; and vendor 
specifications and procedures.
    (3) Certification that the owner(s) or operator have installed in 
the affected unit all NOX emission control systems, made any 
operational modifications, and completed any planned upgrades and/or 
maintenance to equipment specified in the approved demonstration period 
plan for optimizing NOX emission reduction performance, 
consistent with the demonstration period plan and the proper operation 
of the installed NOX emission control system. Such 
certification shall explain any differences between the installed 
NOX emission control system and the equipment configuration 
described in the approved demonstration period plan.
    (4) A clear description of each step or modification taken during 
the demonstration period to improve or optimize the performance of the 
installed NOX emission control system.
    (5) Engineering design calculations and drawings that show the 
technical specifications for installation of any additional operational 
or emission control modifications installed during the demonstration 
period.
    (6) Unit operating and quality-assured continuous emission 
monitoring data (including the specific data listed in Sec. 76.14(b)) 
collected in accordance with part 75 of this chapter during the 
demonstration period and demonstrating the inability of the specific 
unit to meet the applicable emission limitation in Sec. 76.5, 76.6, or 
76.7 on an annual average basis while operating in accordance with the 
certification under paragraph (e)(2) of this section.
    (7) A report (based on the parametric test requirements set forth in 
the approved demonstration period plan as identified in paragraph 
(d)(13) of this section), that demonstrates the unit was operated in 
accordance with the operating conditions upon which the design of the 
NOX emission control system was based and describes the 
reason or reasons for the failure of the installed NOX 
emission control system to meet the applicable emission limitation in 
Sec. 76.5, 76.6, or 76.7 on an annual average basis.
    (8) The minimum NOX emission rate, in lb/mmBtu, that the 
affected unit can achieve on an annual average basis with the installed 
NOX emission control system. This value, which shall be the 
requested alternative emission limitation, shall be derived from the 
data specified in this section using methods and procedures satisfactory 
to the Administrator and shall be the lowest annual emission rate the 
unit can achieve with the installed NOX emission control 
system;
    (9) All supporting data and calculations documenting the 
determination of the requested alternative emission limitation and its 
conformance with the methods and procedures satisfactory to the 
Administrator;
    (10) The special provisions in paragraph (g)(2) of this section.
    (11) In addition to the other requirements of this section, the 
owner or operator of an affected unit with a Group 1 boiler that has 
installed an alternative technology in addition to or in lieu of low 
NOX burner technology and cannot meet the applicable emission 
limitation in Sec. 76.5 shall demonstrate, to the satisfaction of the 
Administrator, that the actual percentage reduction in NOX 
emissions (lbs/mmBtu), on an annual average basis is greater than 65 
percent of the average annual NOX emissions prior to the 
installation of the NOX emission control system. The 
percentage reduction in NOX emissions shall be determined 
using continuous emissions monitoring data for NOX taken 
during the time period (under paragraph (d)(3) of this section) prior to 
the installation of the NOX emission control system and 
during long-term load dispatch operation of the specific boiler.
    (f) Permitting authority's action--(1) Alternative emission 
limitation demonstration period. (i) The permitting authority may 
approve an alternative emission limitation demonstration period and 
demonstration period plan, provided that the requirements of this 
section are met to the satisfaction of the permitting authority. The 
permitting authority shall disapprove a demonstration period if the 
requirements of paragraph (a) of this section were not met during the 
operating period.
    (ii) If the demonstration period is approved, the permitting 
authority will include, as part of the demonstration

[[Page 472]]

period, the 4 month period prior to submission of the application in the 
demonstration period.
    (iii) The alternative emission limitation demonstration period will 
authorize the unit to emit at a rate not greater than the interim 
alternative emission limitation during the demonstration period on or 
after January 1, 1996 for Phase I units and the applicable date 
established in Sec. 76.6 or 76.7 for Phase II units, and until the date 
that the Administrator approves or denies a final alternative emission 
limitation.
    (iv) After an alternative emission limitation demonstration period 
is approved, if the designated representative requests an extension of 
the demonstration period in accordance with paragraph (g)(1)(i)(B) of 
this section, the permitting authority may extend the demonstration 
period by administrative amendment (under Sec. 72.83 of this chapter) 
to the Acid Rain permit.
    (v) The permitting authority shall deny the demonstration period if 
the designated representative cannot demonstrate that the unit met the 
requirements of paragraph (a)(2) of this section. In such cases, the 
permitting authority shall require that the owner or operator operate 
the unit in compliance with the applicable emission limitation in Sec. 
76.5, 76.6, or 76.7 for the period preceding the submission of the 
application for an alternative emission limitation demonstration period, 
including the operating period, if such periods are after the date on 
which the unit is subject to the standard limit under Sec. 76.5, 76.6, 
or 76.7.
    (2) Alternative emission limitation. (i) If the permitting authority 
determines that the requirements in this section are met, the permitting 
authority will approve an alternative emission limitation and issue or 
revise an Acid Rain permit to apply the approved limitation, in 
accordance with subparts F and G of part 72 of this chapter. The permit 
will authorize the unit to emit at a rate not greater than the approved 
alternative emission limitation, starting the date the permitting 
authority revises an Acid Rain permit to approve an alternative emission 
limitation.
    (ii) If a permitting authority disapproves an alternative emission 
limitation under paragraph (a)(2) of this section, the owner or operator 
shall operate the affected unit in compliance with the applicable 
emission limitation in Sec. 76.5, 76.6, or 76.7 (unless the unit is 
participating in an approved averaging plan under Sec. 76.11) beginning 
on the date the permitting authority revises an Acid Rain permit to 
disapprove an alternative emission limitation.
    (3) Alternative emission limitation renewal. (i) If, upon review of 
a petition to renew an approved alternative emission limitation, the 
permitting authority determines that no changes have been made to the 
control technology, its operation, the operating conditions on which the 
alternative emission limitation was based, or the actual NOX 
emission rate, the alternative emission limitation will be renewed.
    (ii) If the permitting authority determines that changes have been 
made to the control technology, its operation, the fuel quality, or the 
operating conditions on which the alternative emission limitation was 
based, the designated representative shall submit, in order to renew the 
alternative emission limitation or to obtain a new alternative emission 
limitation, a petition for an alternative emission limitation 
demonstration period that meets the requirements of paragraph (d) of 
this section using a new demonstration period.
    (g) Special provisions--(1) Alternative emission limitation 
demonstration period--(i) Emission limitations. (A) Each unit with an 
approved alternative emission limitation demonstration period shall 
comply with the interim emission limitation specified in the unit's 
permit beginning on the effective date of the demonstration period 
specified in the permit and, if a timely petition for a final 
alternative emission limitation is submitted, extending until the date 
on which the permitting authority issues or revises an Acid Rain permit 
to approve or disapprove an alternative emission limitation. If a timely 
petition is not submitted, then the unit shall comply with the standard 
emission limit under Sec. 76.5, 76.6, or 76.7 beginning on the date the 
petition was required to be submitted under paragraph (c)(2) of this 
section.
    (B) When the owner or operator identifies, during the demonstration 
period,

[[Page 473]]

boiler operating or NOX emission control system modifications 
or upgrades that would produce further NOX emission 
reductions, enabling the affected unit to comply with or bring its 
emission rate closer to the applicable emissions limitation under Sec. 
76.5, 76.6, or 76.7, the designated representative may submit a request 
and the permitting authority may grant, by administrative amendment 
under Sec. 72.83 of this chapter, an extension of the demonstration 
period for such period of time (not to exceed 12 months) as may be 
necessary to implement such modifications or upgrades.
    (C) If the approved interim alternative emission limitation applies 
to a unit for part, but not all, of a calendar year, the unit shall 
determine compliance for the calendar year in accordance with the 
procedures in Sec. 76.13(a).
    (ii) Operating requirements. (A) A unit with an approved alternative 
emission limitation demonstration period shall be operated under load 
dispatch conditions consistent with the operating conditions upon which 
the design of the NOX emission control system and performance 
guarantee were based, and in accordance with the demonstration period 
plan.
    (B) A unit with an approved alternative emission limitation 
demonstration period shall install all NOX emission control 
systems, make any operational modifications, and complete any upgrades 
and maintenance to equipment specified in the approved demonstration 
period plan for optimizing NOX emission reduction 
performance.
    (C) When the owner or operator identifies boiler or NOX 
emission control system operating modifications that would produce 
higher NOX emission reductions, enabling the affected unit to 
comply with, or bring its emission rate closer to, the applicable 
emission limitation under Sec. 76.5, 76.6, or 76.7, the designated 
representative shall submit an administrative amendment under Sec. 
72.83 of this chapter to revise the unit's Acid Rain permit and 
demonstration period plan to include such modifications.
    (iii) Testing requirements. A unit with an approved alternative 
emission limitation demonstration period shall monitor in accordance 
with part 75 of this chapter and shall conduct all tests required under 
the approved demonstration period plan.
    (2) Final alternative emission limitation--(i) Emission limitations. 
(A) Each unit with an approved alternative emission limitation shall 
comply with the alternative emission limitation specified in the unit's 
permit beginning on the date specified in the permit as issued or 
revised by the permitting authority to apply the final alternative 
emission limitation.
    (B) If the approved interim or final alternative emission limitation 
applies to a unit for part, but not all, of a calendar year, the unit 
shall determine compliance for the calendar year in accordance with the 
procedures in Sec. 76.13(a).

[60 FR 18761, Apr. 13, 1995, as amended at 61 FR 67163, Dec. 19, 1996]



Sec. 76.11  Emissions averaging.

    (a) General provisions. In lieu of complying with the applicable 
emission limitation in Sec. 76.5, 76.6, or 76.7, any affected units 
subject to such emission limitation, under control of the same owner or 
operator, and having the same designated representative may average 
their NOX emissions under an averaging plan approved under 
this section.
    (1) Each affected unit included in an averaging plan for Phase I 
shall be a Phase I unit with a Group 1 boiler subject to an emission 
limitation in Sec. 76.5 during all years for which the unit is included 
in the plan.
    (i) If a unit with an approved NOX compliance extension 
is included in an averaging plan for 1996, the unit shall be treated, 
for the purposes of applying Equation 1 in paragraph (a)(6) of this 
section and Equation 2 in paragraph (d)(1)(ii)(A) of this section, as 
subject to the applicable emissions limitation under Sec. 76.5 for the 
entire year 1996.
    (ii) A Phase II unit approved for early election under Sec. 76.8 
shall not be included in an averaging plan for Phase I.
    (2) Each affected unit included in an averaging plan for Phase II 
shall be a boiler subject to an emission limitation in Sec. 76.5, 76.6, 
or 76.7 for all years for which the unit is included in the plan.

[[Page 474]]

    (3) Each unit included in an averaging plan shall have an 
alternative contemporaneous annual emission limitation (lb/mmBtu) and 
can only be included in one averaging plan.
    (4) Each unit included in an averaging plan shall have a minimum 
allowable annual heat input value (mmBtu), if it has an alternative 
contemporaneous annual emission limitation more stringent than that 
unit's applicable emission limitation under Sec. 76.5, 76.6, or 76.7, 
and a maximum allowable annual heat input value, if it has an 
alternative contemporaneous annual emission limitation less stringent 
than that unit's applicable emission limitation under Sec. 76.5, 76.6, 
or 76.7.
    (5) The Btu-weighted annual average emission rate for the units in 
an averaging plan shall be less than or equal to the Btu-weighted annual 
average emission rate for the same units had they each been operated, 
during the same period of time, in compliance with the applicable 
emission limitations in Sec. 76.5, 76.6, or 76.7.
    (6) In order to demonstrate that the proposed plan is consistent 
with paragraph (a)(5) of this section, the alternative contemporaneous 
annual emission limitations and annual heat input values assigned to the 
units in the proposed averaging plan shall meet the following 
requirement:
[GRAPHIC] [TIFF OMITTED] TR13AP95.000

where:

RLi = Alternative contemporaneous annual emission limitation 
          for unit i, lb/mmBtu, as specified in the averaging plan;
Rli = Applicable emission limitation for unit i, lb/mmBtu, as 
          specified in Sec. 76.5, 76.6, or 76.7 except that for early 
          election units, which may be included in an averaging plan 
          only on or after January 1, 2000, Rli shall equal 
          the most stringent applicable emission limitation under Sec. 
          76.5 or 76.7;
HIi = Annual heat input for unit i, mmBtu, as specified in 
          the averaging plan;
n = Number of units in the averaging plan.

    (7) For units with an alternative emission limitation, 
Rli shall equal the applicable emissions limitation under 
Sec. 76.5, 76.6, or 76.7, not the alternative emissions limitation.
    (8) No unit may be included in more than one averaging plan.
    (b)(1) Submission requirements. The designated representative of a 
unit meeting the requirements of paragraphs (a)(1), (a)(2), and (a)(8) 
of this section may submit an averaging plan (or a revision to an 
approved averaging plan) to the permitting authority(ies) at any time up 
to and including January 1 (or July 1, if the plan is restricted to 
units located within a single permitting authority's jurisdiction) of 
the calendar year for which the averaging plan is to become effective.
    (2) The designated representative shall submit a copy of the same 
averaging plan (or the same revision to an approved averaging plan) to 
each permitting authority with jurisdiction over a unit in the plan.
    (3) When an averaging plan (or a revision to an approved averaging 
plan) is not approved, the owner or operator of each unit in the plan 
shall operate the unit in compliance with the emission limitation that 
would apply in the absence of the averaging plan (or revision to a 
plan).
    (c) Contents of NOX averaging plan. A complete 
NOX averaging plan shall include the following elements in a 
format prescribed by the Administrator:
    (1) Identification of each unit in the plan;
    (2) Each unit's applicable emission limitation in Sec. 76.5, 76.6, 
or 76.7;
    (3) The alternative contemporaneous annual emission limitation for 
each unit (in lb/mmBtu). If any of the units identified in the 
NOX averaging plan utilize a common stack pursuant to

[[Page 475]]

Sec. 75.17(a)(2)(i)(B) of this chapter, the same alternative 
contemporaneous emission limitation shall be assigned to each such unit 
and different heat input limits may be assigned;
    (4) The annual heat input limit for each unit (in mmBtu);
    (5) The calculation for Equation 1 in paragraph (a)(6) of this 
section;
    (6) The calendar years for which the plan will be in effect; and
    (7) The special provisions in paragraph (d)(1) of this section.
    (d) Special provisions--(1) Emission limitations. Each affected unit 
in an approved averaging plan is in compliance with the Acid Rain 
emission limitation for NOX under the plan only if the 
following requirements are met:
    (i) For each unit, the unit's actual annual average emission rate 
for the calendar year, in lb/mmBtu, is less than or equal to its 
alternative contemporaneous annual emission limitation in the averaging 
plan; and
    (A) For each unit with an alternative contemporaneous emission 
limitation less stringent than the applicable emission limitation in 
Sec. 76.5, 76.6, or 76.7, the actual annual heat input for the calendar 
year does not exceed the annual heat input limit in the averaging plan;
    (B) For each unit with an alternative contemporaneous annual 
emission limitation more stringent than the applicable emission 
limitation in Sec. 76.5, 76.6, or 76.7, the actual annual heat input 
for thecalendar year is not less than the annual heat input limit in the 
averaging plan; or
    (ii) If one or more of the units does not meet the requirements 
under paragraph (d)(1)(i) of this section, the designated representative 
shall demonstrate, in accordance with paragraph (d)(1)(ii)(A) of this 
section (Equation 2) that the actual Btu-weighted annual average 
emission rate for the units in the plan is less than or equal to the 
Btu-weighted annual average rate for the same units had they each been 
operated, during the same period of time, in compliance with the 
applicable emission limitations in Sec. 76.5, 76.6, or 76.7.
    (A) A group showing of compliance shall be made based on the 
following equation:
[GRAPHIC] [TIFF OMITTED] TR13AP95.001

where:

Rai = Actual annual average emission rate for unit i, lb/
          mmBtu, as determined using the procedures in part 75 of this 
          chapter. For units in an averaging plan utilizing a common 
          stack pursuant to Sec. 75.17(a)(2)(i)(B) of this chapter, use 
          the same NOX emission rate value for each unit 
          utilizing the common stack, and calculate this value in 
          accordance with appendix F to part 75 of this chapter;
Rli = Applicable annual emission limitation for unit i lb/
          mmBtu, as specified in Sec. 76.5, 76.6, or 76.7, except that 
          for early election units, which may be included in an 
          averaging plan only on or after January 1, 2000, 
          Rli shall equal the most stringent applicable 
          emission limitation under Sec. 76.5 or 76.7;
HIai = Actual annual heat input for unit i, mmBtu, as 
          determined using the procedures in part 75 of this chapter;
n = Number of units in the averaging plan.

    (B) For units with an alternative emission limitation, 
Rli shall equal the applicable emission limitation under 
Sec. 76.5, 76.6, or 76.7, not the alternative emission limitation.
    (C) If there is a successful group showing of compliance under 
paragraph (d)(1)(ii)(A) of this section for a calendar year, then all 
units in the averaging plan shall be deemed to be in compliance for that 
year with their alternative contemporaneous emission limitations and 
annual heat input limits under paragraph (d)(1)(i) of this section.

[[Page 476]]

    (2) Liability. The owners and operators of a unit governed by an 
approved averaging plan shall be liable for any violation of the plan or 
this section at that unit or any other unit in the plan, including 
liability for fulfilling the obligations specified in part 77 of this 
chapter and sections 113 and 411 of the Act.
    (3) Withdrawal or termination. The designated representative may 
submit a notification to terminate an approved averaging plan in 
accordance with Sec. 72.40(d) of this chapter, no later than October 1 
of the calendar year for which the plan is to be withdrawn or 
terminated.



Sec. 76.12  Phase I NOX compliance extension.

    (a) General provisions. (1) The designated representative of a Phase 
I unit with a Group 1 boiler may apply for and receive a 15-month 
extension of the deadline for meeting the applicable emissions 
limitation under Sec. 76.5 where it is demonstrated, to the 
satisfaction of the Administrator, that:
    (i) The low NOX burner technology designed to meet the 
applicable emission limitation is not in adequate supply to enable 
installation and operation at the unit, consistent with system 
reliability, by January 1, 1995 and the reliability problems are due 
substantially to NOX emission control system installation and 
availability; or
    (ii) The unit is participating in an approved clean coal technology 
demonstration project.
    (2) In order to obtain a Phase I NOX compliance 
extension, the designated representative shall submit a Phase I 
NOX compliance extension plan by October 1, 1994.
    (b) Contents of Phase I NOX compliance extension plan. A complete 
Phase I NOX compliance extension plan shall include the 
following elements in a format prescribed by the Administrator:
    (1) Identification of the unit.
    (2) For units applying pursuant to paragraph (a)(1)(i) of this 
section:
    (i) A list of the company names, addresses, and telephone numbers of 
vendors who are qualified to provide the services and low NOX 
burner technology designed to meet the applicable emission limitation 
under Sec. 76.5 and have been contacted to obtain the required services 
and technology. The list shall include the dates of contact, and a copy 
of each request for bids shall be submitted, along with any other 
information necessary to show a good-faith effort to obtain the required 
services and technology necessary to meet the requirements of this part 
on or before January 1, 1995.
    (ii) A copy of those portions of a legally binding contract with a 
qualified vendor that demonstrate that services and low NOX 
burner technology designed to meet the applicable emission limitation 
under Sec. 76.5, with a completion date not later than December 31, 
1995 have been contracted for.
    (iii) Scheduling information, including justification and test 
schedules.
    (iv) To demonstrate, if applicable, that the supply of the low 
NOX burner technology designed to meet the applicable 
emission limitation under Sec. 76.5 is inadequate to enable its 
installation and operation at the unit, consistent with system 
reliability, in time for the unit to comply with the applicable emission 
limitation on or before January 1, 1995, either:
    (A) Certification from the selected vendor(s) (by a certifying 
official) listed in paragraph (b)(2)(i) of this section stating that 
they cannot provide the necessary services and install the low 
NOX burner technology on or before January 1, 1995 and 
explaining the reasons why the services cannot be provided and why the 
equipment cannot be installed in a timely manner; or
    (B) The following information:
    (i) Standard load forecasts, based on standard forecasting models 
available throughout the utility industry and applied to the period, 
January 1, 1993, through December 31, 1994.
    (ii) Specific reasons why an outage cannot be scheduled to enable 
the unit to install and operate the low NOX burner technology 
by January 1, 1995, including reasons why no other units can be used to 
replace this unit's generation during such outage.
    (iii) Fuel and energy balance summaries and power and other 
consumption requirements (including those for air, steam, and cooling 
water).
    (3) To demonstrate, if applicable, participation in an approved 
clean coal

[[Page 477]]

technology demonstration project, a description of the project, 
including all sources of Federal, State, and other outside funding, 
amount and date for approval of Federal funding, the duration of the 
project, and the anticipated completion date of the project.
    (4) The special provisions in paragraph (d) of this section.
    (c)(1) Administrator's action. To the extent the Administrator 
determines that a Phase I NOX compliance extension plan 
complies with the requirements of this section, the Administrator will 
approve the plan and revise the Acid Rain permit governing the unit in 
the plan in order to incorporate the plan by administrative amendment 
under Sec. 72.83 of this chapter, except that the Administrator shall 
have 90 days from receipt of the compliance extension plan to take final 
action.
    (2) The Administrator will approve or disapprove a proposed 
NOX compliance extension plan within 3 months of receipt.
    (d) Special provisions. (1) Emission limitations. The unit shall 
comply with the applicable emission limitation under Sec. 76.5 
beginning April 1, 1996. Compliance shall be determined as specified in 
part 75 of this chapter using measured values of NOX 
emissions and heat input only for the portion of the year that the 
emission limit is in effect.
    (2) If a unit with an approved NOX compliance extension 
is included in an averaging plan under Sec. 76.11 for year 1996, the 
unit shall be treated, for purposes of applying Equation 1 in Sec. 
76.11(a)(6) and Equation 2 in Sec. 76.11(d)(1)(ii)(A), as subject to 
the applicable emission limitation under Sec. 76.5 for the entire year 
1996.
    (e) Extension until December 31, 1997. (1) The designated 
representative of a Phase I unit that is subject to section 404(d) of 
the Act, has a tangentially fired boiler, and is unable to install low 
NOX burner technology by January 1, 1997 may submit a 
petition for and receive an extension for meeting the applicable 
emission limitation under Sec. 76.5 where it is demonstrated, to the 
satisfaction of the Administrator, that:
    (i) The unit is located at a source with two or more other units, 
all of which are Phase I units that are subject to section 404(d) of the 
Act and have tangentially fired boilers;
    (ii) The NOX control system at the unit was scheduled to 
be installed by January 1, 1997 and, because of operational problems 
associated with the NOX control system, will be redesigned; 
and
    (iii) Installation of the redesigned low NOX burner 
technology at the unit cannot be completed by January 1, 1997 without 
causing system reliability problems.
    (2) A complete petition shall include the following elements and 
shall be submitted by April 28, 1995.
    (i) Identification of the unit and the other units at the source;
    (ii) A statement describing how the requirements of paragraphs 
(e)(1)(ii) and (e)(1)(iii) of this section are met;
    (iii) The earliest date, not later than December 31, 1997, by which 
installation of the redesigned low NOX burner technology can 
be completed consistent with system reliability; and
    (iv) The provisions in paragraph (e)(4) of this section.
    (3) To the extent the Administrator determines that a Phase I unit 
meets the requirements of paragraphs (e)(1) and (e)(2) of this section, 
the Administrator will approve the petition within 90 days from receipt 
of the complete petition. The Acid Rain permit governing the unit will 
be revised in order to incorporate the approved extension, which shall 
terminate no later than December 31, 1997, by administrative amendment 
under Sec. 72.83 of this chapter except that the Administrator will 
have 90 days to take final action.
    (4) The unit shall comply with the applicable emission limitation 
under Sec. 76.5 beginning on the day immediately following the day on 
which the extension approved under paragraph (e)(3) of this section 
terminates. Compliance shall be determined as specified in part 75 of 
this chapter using measured values of NOX emissions and heat 
input only for the portion of the year that the emission limit is in 
effect. If a unit with an approved extension is included in an averaging 
plan under Sec. 76.11 for year 1997, the unit shall be treated, for the 
purpose of applying Equation 1 in Sec. 76.11(a)(6) and Equation 2 in

[[Page 478]]

Sec. 76.11(d)(1)(ii)(A), as subject to the applicable emission 
limitation under Sec. 76.5 for the entire year 1997.



Sec. 76.13  Compliance and excess emissions.

    Excess emissions of nitrogen oxides under Sec. 77.6 of this chapter 
shall be calculated as follows:
    (a) For a unit that is not in an approved averaging plan:
    (1) Calculate EEi for each portion of the calendar year 
that the unit is subject to a different NOX emission 
limitation:
[GRAPHIC] [TIFF OMITTED] TR13AP95.002

where:

EEi = Excess emissions for NOX for the portion of 
          the calendar year (in tons);
Rai = Actual average emission rate for the unit (in lb/
          mmBtu), determined according to part 75 of this chapter for 
          the portion of the calendar year for which the applicable 
          emission limitation Rl is in effect;
Rli = Applicable emission limitation for the unit, (in lb/
          mmBtu), as specified in Sec. 76.5, 76.6, or 76.7 or as 
          determined under Sec. 76.10;
          [GRAPHIC] [TIFF OMITTED] TR13AP95.003
          
HI\i\ = Actual heat input for the unit, (in mmBtu), determined according 
          to part 75 of this chapter for the portion of the calendar 
          year for which the applicable emission limitation, 
          Rl, is in effect.

    (2) If EEi is a negative number for any portion of the 
calendar year, the EE value for that portion of the calendar year shall 
be equal to zero (e.g., if EEi = -100, then EEi = 
0).
    (3) Sum all EEi values for the calendar year:

where:

EE = Excess emissions for NOX for the year (in tons);
n = The number of time periods during which a unit is subject to 
          different emission limitations; and

    (b) For units participating in an approved averaging plan, when all 
the requirements under Sec. 76.11(d)(1) are not met,
[GRAPHIC] [TIFF OMITTED] TR13AP95.004

where:

EE = Excess emissions for NOX for the year (in tons);
Rai = Actual annual average emission rate for NOX 
          for unit i, (in lb/mmBtu), determined according to part 75 of 
          this chapter;
Rli = Applicable emission limitation for unit i, (in lb/
          mmBtu), as specified in Sec. 76.5, 76.6, or 76.7;
HIi = Actual annual heat input for unit i, mmBtu, determined 
          according to part 75 of this chapter;
n = Number of units in the averaging plan.



Sec. 76.14  Monitoring, recordkeeping, and reporting.

    (a) A petition for an alternative emission limitation demonstration 
period under Sec. 76.10(d) shall include the following information:
    (1) In accordance with Sec. 76.10(d)(4), the following information:
    (i) Documentation that the owner or operator solicited bids for a 
NOX emission control system designed for application to the 
specific boiler and designed to achieve the applicable emission 
limitation in Sec. 76.5, 76.6, or 76.7 on an annual average basis. This 
documentation must include a copy of all bid specifications.
    (ii) A copy of the performance guarantee submitted by the vendor of 
the installed NOX emission control system to the owner or 
operator showing that such system was designed to meet the applicable 
emission limitation in Sec. 76.5, 76.6, or 76.7 on an annual average 
basis.
    (iii) Documentation describing the operational and combustion 
conditions

[[Page 479]]

that are the basis of the performance guarantee.
    (iv) Certification by the primary vendor of the NOX 
emission control system that such equipment and associated auxiliary 
equipment was properly installed according to the modifications and 
procedures specified by the vendor.
    (v) Certification by the designated representative that the owner(s) 
or operator installed technology that meets the requirements of Sec. 
76.10(a)(2).
    (2) In accordance with Sec. 76.10(d)(9), the following information:
    (i) The operating conditions of the NOX emission control 
system including load range, O2 range, coal volatile matter 
range, and, for tangentially fired boilers, distribution of combustion 
air within the NOX emission control system;
    (ii) Certification by the designated representative that the 
owner(s) or operator have achieved and are following the operating 
conditions, boiler modifications, and upgrades that formed the basis for 
the system design and performance guarantee;
    (iii) Any planned equipment modifications and upgrades for the 
purpose of achieving the maximum NOX reduction performance of 
the NOX emission control system that were not included in the 
design specifications and performance guarantee, but that were achieved 
prior to submission of this application and are being followed;
    (iv) A list of any modifications or replacements of equipment that 
are to be done prior to the completion of the demonstration period for 
the purpose of reducing emissions of NOX; and
    (v) The parametric testing that will be conducted to determine the 
reason or reasons for the failure of the unit to achieve the applicable 
emission limitation and to verify the proper operation of the installed 
NOX emission control system during the demonstration period. 
The tests shall include tests in Sec. 76.15, which may be modified as 
follows:
    (A) The owner or operator of the unit may add tests to those listed 
in Sec. 76.15, if such additions provide data relevant to the failure 
of the installed NOX emission control system to meet the 
applicable emissions limitation in Sec. 76.5, 76.6, or 76.7; or
    (B) The owner or operator of the unit may remove tests listed in 
Sec. 76.15 that are shown, to the satisfaction of the permitting 
authority, not to be relevant to NOX emissions from the 
affected unit; and
    (C) In the event the performance guarantee or the NOX 
emission control system specifications require additional tests not 
listed in Sec. 76.15, or specify operating conditions not verified by 
tests listed in Sec. 76.15, the owner or operator of the unit shall 
include such additional tests.
    (3) In accordance with Sec. 76.10(d)(10), the following information 
for the operating period:
    (i) The average NOX emission rate (in lb/mmBtu) of the 
specific unit;
    (ii) The highest hourly NOX emission rate (in lb/mmBtu) 
of the specific unit;
    (iii) Hourly NOX emission rate (in lb/mmBtu), calculated 
in accordance with part 75 of this chapter;
    (iv) Total heat input (in mmBtu) for the unit for each hour of 
operation, calculated in accordance with the requirements of part 75 of 
this chapter; and
    (v) Total integrated hourly gross unit load (in MWge).
    (b) A petition for an alternative emission limitation shall include 
the following information in accordance with Sec. 76.10(e)(6).
    (1) Total heat input (in mmBtu) for the unit for each hour of 
operation, calculated in accordance with the requirements of part 75 of 
this chapter;
    (2) Hourly NOX emission rate (in lb/mmBtu), calculated in 
accordance with the requirements of part 75 of this chapter; and
    (3) Total integrated hourly gross unit load (MWge).
    (c) Reporting of the costs of low NOX burner technology 
applied to Group 1, Phase I boilers. (1) Except as provided in paragraph 
(c)(2) of this section, the designated representative of a Phase I unit 
with a Group 1 boiler that has installed or is installing any form of 
low NOX burner technology shall submit to the Administrator a 
report containing the capital cost, operating cost, and baseline and 
post-retrofit emission data specified in appendix B to this part. If any 
of the required equipment, cost, and schedule information are not

[[Page 480]]

available (e.g., the retrofit project is still underway), the designated 
representative shall include in the report detailed cost estimates and 
other projected or estimated data in lieu of the information that is not 
available.
    (2) The report under paragraph (c)(1) of this section is not 
required with regard to the following types of Group 1, Phase I units:
    (i) Units employing no new NOX emission control system 
after November 15, 1990;
    (ii) Units employing modifications to boiler operating parameters 
(e.g., burners out of service or fuel switching) without low 
NOX burners or other emission reduction equipment for 
reducing NOX emissions;
    (iii) Units with wall-fired boilers employing only overfire air and 
units with tangentially fired boilers employing only separated overfire 
air; or
    (iv) Units beginning installation of a new NOX emission 
control system after August 11, 1995.
    (3) The report under paragraph (c)(1) of this section shall be 
submitted to the Administrator by:
    (i) 120 days after completion of the low NOX burner 
technology retrofit project; or
    (ii) May 23, 1995, if the project was completed on or before January 
23, 1995.



Sec. 76.15  Test methods and procedures.

    (a) The owner or operator may use the following tests as a basis for 
the report required by Sec. 76.10(e)(7):
    (1) Conduct an ultimate analysis of coal using ASTM D 3176-89 
(incorporated by reference as specified in Sec. 76.4);
    (2) Conduct a proximate analysis of coal using ASTM D 3172-89 
(incorporated by reference as specified in Sec. 76.4); and
    (3) Measure the coal mass flow rate to each individual burner using 
ASME Power Test Code 4.2 (1991), ``Test Code for Coal Pulverizers'' or 
ISO 9931 (1991), ``Coal--Sampling of Pulverized Coal Conveyed by Gases 
in Direct Fired Coal Systems'' (incorporated by reference as specified 
in Sec. 76.4).
    (b) The owner or operator may measure and record the actual 
NOX emission rate in accordance with the requirements of this 
part while varying the following parameters where possible to determine 
their effects on the emissions of NOX from the affected 
boiler:
    (1) Excess air levels;
    (2) Settings of burners or coal and air nozzles, including tilt and 
yaw, or swirl;
    (3) For tangentially fired boilers, distribution of combustion air 
within the NOX emission control system;
    (4) Coal mass flow rates to each individual burner;
    (5) Coal-to-primary air ratio (based on pound per hour) for each 
burner, the average coal-to-primary air ratio for all burners, and the 
deviations of individual burners' coal-to-primary air ratios from the 
average value; and
    (6) If the boiler uses varying types of coal, the type of coal. 
Provide the results of proximate and ultimate analyses of each type of 
as-fired coal.
    (c) In performing the tests specified in paragraph (a) of this 
section, the owner or operator shall begin the tests using the equipment 
settings for which the NOX emission control system was 
designed to meet the NOX emission rate guaranteed by the 
primary NOX emission control system vendor. These results 
constitute the ``baseline controlled'' condition.
    (d) After establishing the baseline controlled condition under 
paragraph (c) of this section, the owner or operator may:
    (1) Change excess air levels [5 percent from the baseline controlled 
condition to determine the effects on emissions of NOX, by 
providing a minimum of three readings (e.g., with a baseline reading of 
20 percent excess air, excess air levels will be changed to 19 percent 
and 21 percent);
    (2) For tangentially fired boilers, change the distribution of 
combustion air within the NOX emission control system to 
determine the effects on NOX emissions by providing a minimum 
of three readings, one with the minimum, one with the baseline, and one 
with the maximum amounts of staged combustion air; and
    (3) Show that the combustion process within the boiler is optimized 
(e.g., that the burners are balanced).

[[Page 481]]



 Sec. Appendix A to Part 76--Phase I Affected Coal-Fired Utility Units 
                   With Group 1 or Cell Burner Boilers

                                    Table 1--Phase I Tangentially Fired Units
----------------------------------------------------------------------------------------------------------------
            State                          Plant                  Unit                    Operator
----------------------------------------------------------------------------------------------------------------
ALABAMA......................  EC GASTON....................  5             ALABAMA POWER CO.
GEORGIA......................  BOWEN........................  1BLR          GEORGIA POWER CO.
GEORGIA......................  BOWEN........................  2BLR          GEORGIA POWER CO.
GEORGIA......................  BOWEN........................  3BLR          GEORGIA POWER CO.
GEORGIA......................  BOWEN........................  4BLR          GEORGIA POWER CO.
GEORGIA......................  JACK MCDONOUGH...............  MB1           GEORGIA POWER CO.
GEORGIA......................  JACK MCDONOUGH...............  MB2           GEORGIA POWER CO.
GEORGIA......................  WANSLEY......................  1             GEORGIA POWER CO.
GEORGIA......................  WANSLEY......................  2             GEORGIA POWER CO.
GEORGIA......................  YATES........................  Y1BR          GEORGIA POWER CO.
GEORGIA......................  YATES........................  Y2BR          GEORGIA POWER CO.
GEORGIA......................  YATES........................  Y3BR          GEORGIA POWER CO.
GEORGIA......................  YATES........................  Y4BR          GEORGIA POWER CO.
GEORGIA......................  YATES........................  Y5BR          GEORGIA POWER CO.
GEORGIA......................  YATES........................  Y6BR          GEORGIA POWER CO.
GEORGIA......................  YATES........................  Y7BR          GEORGIA POWER CO.
ILLINOIS.....................  BALDWIN......................  3             ILLINOIS POWER CO.
ILLINOIS.....................  HENNEPIN.....................  2             ILLINOIS POWER CO.
ILLINOIS.....................  JOPPA........................  1             ELECTRIC ENERGY INC.
ILLINOIS.....................  JOPPA........................  2             ELECTRIC ENERGY INC.
ILLINOIS.....................  JOPPA........................  3             ELECTRIC ENERGY INC.
ILLINOIS.....................  JOPPA........................  4             ELECTRIC ENERGY INC.
ILLINOIS.....................  JOPPA........................  5             ELECTRIC ENERGY INC.
ILLINOIS.....................  JOPPA........................  6             ELECTRIC ENERGY INC.
ILLINOIS.....................  MEREDOSIA....................  5             CEN ILLINOIS PUB SER.
ILLINOIS.....................  VERMILION....................  2             ILLINOIS POWER CO.
INDIANA......................  CAYUGA.......................  1             PSI ENERGY INC.
INDIANA......................  CAYUGA.......................  2             PSI ENERGY INC.
INDIANA......................  EW STOUT.....................  50            INDIANAPOLIS PWR & LT.
INDIANA......................  EW STOUT.....................  60            INDIANAPOLIS PWR & LT.
INDIANA......................  EW STOUT.....................  70            INDIANAPOLIS PRW & LT.
INDIANA......................  HT PRITCHARD.................  6             INDIANAPOLIS PWR & LT.
INDIANA......................  PETERSBURG...................  1             INDIANAPOLIS PWR & LT.
INDIANA......................  PETERSBURG...................  2             INDIANAPOLIS PWR & LT.
INDIANA......................  WABASH RIVER.................  6             PSI ENERGY INC.
IOWA.........................  BURLINGTON...................  1             IOWA SOUTHERN UTL.
IOWA.........................  ML KAPP......................  2             INTERSTATE POWER CO.
IOWA.........................  RIVERSIDE....................  9             IOWA-ILL GAS & ELEC.
KENTUCKY.....................  ELMER SMITH..................  2             OWENSBORO MUN UTIL.
KENTUCKY.....................  EW BROWN.....................  2             KENTUCKY UTL CO.
KENTUCKY.....................  EW BROWN.....................  3             KENTUCKY UTL CO.
KENTUCKY.....................  GHENT........................  1             KENTUCKY UTL CO.
MARYLAND.....................  MORGANTOWN...................  1             POTOMAC ELEC PWR CO.
MARYLAND.....................  MORGANTOWN...................  2             POTOMAC ELEC PWR CO.
MICHIGAN.....................  JH CAMPBELL..................  1             CONSUMERS POWER CO.
MISSOURI.....................  LABADIE......................  1             UNION ELECTRIC CO.
MISSOURI.....................  LABADIE......................  2             UNION ELECTRIC CO.
MISSOURI.....................  LABADIE......................  3             UNION ELECTRIC CO.
MISSOURI.....................  LABADIE......................  4             UNION ELECTRIC CO.
MISSOURI.....................  MONTROSE.....................  1             KANSAS CITY PWR & LT.
MISSOURI.....................  MONTROSE.....................  2             KANSAS CITY PWR & LT.
MISSOURI.....................  MONTROSE.....................  3             KANSAS CITY PWR & LT.
NEW YORK.....................  DUNKIRK......................  3             NIAGARA MOHAWK PWR.
NEW YORK.....................  DUNKIRK......................  4             NIAGARA MOHAWK PWR.
NEW YORK.....................  GREENIDGE....................  6             NY STATE ELEC & GAS.
NEW YORK.....................  MILLIKEN.....................  1             NY STATE ELEC & GAS.
NEW YORK.....................  MILLIKEN.....................  2             NY STATE ELEC & GAS.
OHIO.........................  ASHTABULA....................  7             CLEVELAND ELEC ILLUM.
OHIO.........................  AVON LAKE....................  11            CLEVELAND ELEC ILLUM.
OHIO.........................  CONESVILLE...................  4             COLUMBUS STHERN PWR.
OHIO.........................  EASTLAKE.....................  1             CLEVELAND ELEC ILLUM.
OHIO.........................  EASTLAKE.....................  2             CLEVELAND ELEC ILLUM.
OHIO.........................  EASTLAKE.....................  3             CLEVELAND ELEC ILLUM.
OHIO.........................  EASTLAKE.....................  4             CLEVELAND ELEC ILLUM.
OHIO.........................  MIAMI FORT...................  6             CINCINNATI GAS & ELEC.
OHIO.........................  WC BECKJORD..................  5             CINCINNATI GAS & ELEC.
OHIO.........................  WC BECKJORD..................  6             CINCINNATI GAS & ELEC.
PENNSYLVANIA.................  BRUNNER ISLAND...............  1             PENNSYLVANIA PWR & LT.
PENNSYLVANIA.................  BRUNNER ISLAND...............  2             PENNSYLVANIA PWR & LT.

[[Page 482]]

 
PENNSYLVANIA.................  BRUNNER ISLAND...............  3             PENNSYLVANIA PWR & LT.
PENNSYLVANIA.................  CHESWICK.....................  1             DUQUESNE LIGHT CO.
PENNSYLVANIA.................  CONEMAUGH....................  1             PENNSYLVANIA ELEC CO.
PENNSYLVANIA.................  CONEMAUGH....................  2             PENNSYLVANIA ELEC CO.
PENNSYLVANIA.................  PORTLAND.....................  1             METROPOLITAN EDISON.
PENNSYLVANIA.................  PORTLAND.....................  2             METROPOLITAN EDISON.
PENNSYLVANIA.................  SHAWVILLE....................  3             PENNSYLVANIA ELEC CO.
PENNSYLVANIA.................  SHAWVILLE....................  4             PENNSYLVANIA ELEC CO.
TENNESSEE....................  GALLATIN.....................  1             TENNESSEE VAL AUTH.
TENNESSEE....................  GALLATIN.....................  2             TENNESSEE VAL AUTH.
TENNESSEE....................  GALLATIN.....................  3             TENNESSEE VAL AUTH.
TENNESSEE....................  GALLATIN.....................  4             TENNESSEE VAL AUTH.
TENNESSEE....................  JOHNSONVILLE.................  1             TENNESSEE VAL AUTH.
TENNESSEE....................  JOHNSONVILLE.................  2             TENNESSEE VAL AUTH.
TENNESSEE....................  JOHNSONVILLE.................  3             TENNESSEE VAL AUTH.
TENNESSEE....................  JOHNSONVILLE.................  4             TENNESSEE VAL AUTH.
TENNESSEE....................  JOHNSONVILLE.................  5             TENNESSEE VAL AUTH.
TENNESSEE....................  JOHNSONVILLE.................  6             TENNESSEE VAL AUTH.
WEST VIRGINIA................  ALBRIGHT.....................  3             MONONGAHELA POWER CO.
WEST VIRGINIA................  FORT MARTIN..................  1             MONONGAHELA POWER CO.
WEST VIRGINIA................  MOUNT STORM..................  1             VIRGINIA ELEC & PWR.
WEST VIRGINIA................  MOUNT STORM..................  2             VIRGINIA ELEC & PWR.
WEST VIRGINIA................  MOUNT STORM..................  3             VIRGINIA ELEC & PWR.
WISCONSIN....................  GENOA........................  1             DAIRYLAND POWER COOP.
WISCONSIN....................  SOUTH OAK CREEK..............  7             WISCONSIN ELEC POWER.
WISCONSIN....................  SOUTH OAK CREEK..............  8             WISCONSIN ELEC POWER.
----------------------------------------------------------------------------------------------------------------


                                     Table 2--Phase I Dry Bottom-Fired Units
----------------------------------------------------------------------------------------------------------------
             State                           Plant                   Unit                   Operator
----------------------------------------------------------------------------------------------------------------
ALABAMA.......................  COLBERT.......................  1               TENNESSEE VAL AUTH.
ALABAMA.......................  COLBERT.......................  2               TENNESSEE VAL AUTH.
ALABAMA.......................  COLBERT.......................  3               TENNESSEE VAL AUTH.
ALABAMA.......................  COLBERT.......................  4               TENNESSEE VAL AUTH.
ALABAMA.......................  COLBERT.......................  5               TENNESSEE VAL AUTH.
ALABAMA.......................  EC GASTON.....................  1               ALABAMA POWER CO.
ALABAMA.......................  EC GASTON.....................  2               ALABAMA POWER CO.
ALABAMA.......................  EC GASTON.....................  3               ALABAMA POWER CO.
ALABAMA.......................  EC GASTON.....................  4               ALABAMA POWER CO.
FLORIDA.......................  CRIST.........................  6               GULF POWER CO.
FLORIDA.......................  CRIST.........................  7               GULF POWER CO.
GEORGIA.......................  HAMMOND.......................  1               GEORGIA POWER CO.
GEORGIA.......................  HAMMOND.......................  2               GEORGIA POWER CO.
GEORGIA.......................  HAMMOND.......................  3               GEORGIA POWER CO.
GEORGIA.......................  HAMMOND.......................  4               GEORGIA POWER CO.
ILLINOIS......................  GRAND TOWER...................  9               CEN ILLINOIS PUB SER.
INDIANA.......................  CULLEY........................  2               STHERN IND GAS & EL.
INDIANA.......................  CULLEY........................  3               STHERN IND GAS & EL.
INDIANA.......................  GIBSON........................  1               PSI ENERGY INC.
INDIANA.......................  GIBSON........................  2               PSI ENERGY INC.
INDIANA.......................  GIBSON........................  3               PSI ENERGY INC.
INDIANA.......................  GIBSON........................  4               PSI ENERGY INC.
INDIANA.......................  RA GALLAGHER..................  1               PSI ENERGY INC.
INDIANA.......................  RA GALLAGHER..................  2               PSI ENERGY INC.
INDIANA.......................  RA GALLAGHER..................  3               PSI ENERGY INC.
INDIANA.......................  RA GALLAGHER..................  4               PSI ENERGY INC.
INDIANA.......................  FRANK E RATTS.................  1SG1            HOOSIER ENERGY REC.
INDIANA.......................  FRANK E RATTS.................  2SG1            HOOSIER ENERGY REC.
INDIANA.......................  WABASH RIVER..................  1               PSI ENERGY INC.
INDIANA.......................  WABASH RIVER..................  2               PSI ENERGY INC.
INDIANA.......................  WABASH RIVER..................  3               PSI ENERGY INC.
INDIANA.......................  WABASH RIVER..................  5               PSI ENERGY INC.
IOWA..........................  DES MOINES....................  11              IOWA PWR & LT CO.
IOWA..........................  PRAIRIE CREEK.................  4               IOWA ELEC LT & PWR.
KANSAS........................  QUINDARO......................  2               KS CITY BD PUB UTIL.
KENTUCKY......................  COLEMAN.......................  C1              BIG RIVERS ELEC CORP.
KENTUCKY......................  COLEMAN.......................  C2              BIG RIVERS ELEC CORP.
KENTUCKY......................  COLEMAN.......................  C3              BIG RIVERS ELEC CORP.
KENTUCKY......................  EW BROWN......................  1               KENTUCKY UTL CO.
KENTUCKY......................  GREEN RIVER...................  5               KENTUCKY UTL CO.

[[Page 483]]

 
KENTUCKY......................  HMP&L STATION 2...............  H1              BIG RIVERS ELEC CORP.
KENTUCKY......................  HMP&L STATION 2...............  H2              BIG RIVERS ELEC CORP.
KENTUCKY......................  HL SPURLOCK...................  1               EAST KY PWR COOP.
KENTUCKY......................  JS COOPER.....................  1               EAST KY PWR COOP.
KENTUCKY......................  JS COOPER.....................  2               EAST KY PWR COOP.
MARYLAND......................  CHALK POINT...................  1               POTOMAC ELEC PWR CO.
MARYLAND......................  CHALK POINT...................  2               POTOMAC ELEC PWR CO.
MINNESOTA.....................  HIGH BRIDGE...................  6               NORTHERN STATES PWR.
MISSISSIPPI...................  JACK WATSON...................  4               MISSISSIPPI PWR CO.
MISSISSIPPI...................  JACK WATSON...................  5               MISSISSIPPI PWR CO.
MISSOURI......................  JAMES RIVER...................  5               SPRINGFIELD UTL.
OHIO..........................  CONESVILLE....................  3               COLUMBUS STHERN PWR.
OHIO..........................  EDGEWATER.....................  13              OHIO EDISON CO.
OHIO..........................  MIAMI FORT \1\................  5-1             CINCINNATI GAS&ELEC.
OHIO..........................  MIAMI FORT \1\................  5-2             CINCINNATI GAS&ELEC.
OHIO..........................  PICWAY........................  9               COLUMBUS STHERN PWR.
OHIO..........................  RE BURGER.....................  7               OHIO EDISON CO.
OHIO..........................  RE BURGER.....................  8               OHIO EDISON CO.
OHIO..........................  WH SAMMIS.....................  5               OHIO EDISON CO.
OHIO..........................  WH SAMMIS.....................  6               OHIO EDISON CO.
PENNSYLVANIA..................  ARMSTRONG.....................  1               WEST PENN POWER CO.
PENNSYLVANIA..................  ARMSTRONG.....................  2               WEST PENN POWER CO.
PENNSYLVANIA..................  MARTINS CREEK.................  1               PENNSYLVANIA PWR & LT.
PENNSYLVANIA..................  MARTINS CREEK.................  2               PENNSYLVANIA PWR & LT.
PENNSYLVANIA..................  SHAWVILLE.....................  1               PENNSYLVANIA ELEC CO.
PENNSYLVANIA..................  SHAWVILLE.....................  2               PENNSYLVANIA ELEC CO.
PENNSYLVANIA..................  SUNBURY.......................  3               PENNSYLVANIA PWR & LT.
PENNSYLVANIA..................  SUNBURY.......................  4               PENNSYLVANIA PWR & LT.
TENNESSEE.....................  JOHNSONVILLE..................  7               TENNESSEE VAL AUTH.
TENNESSEE.....................  JOHNSONVILLE..................  8               TENNESSEE VAL AUTH.
TENNESSEE.....................  JOHNSONVILLE..................  9               TENNESSEE VAL AUTH.
TENNESSEE.....................  JOHNSONVILLE..................  10              TENNESSEE VAL AUTH.
WEST VIRGINIA.................  HARRISON......................  1               MONONGAHELA POWER CO.
WEST VIRGINIA.................  HARRISON......................  2               MONONGAHELA POWER CO.
WEST VIRGINIA.................  HARRISON......................  3               MONONGAHELA POWER CO.
WEST VIRGINIA.................  MITCHELL......................  1               OHIO POWER CO.
WEST VIRGINIA.................  MITCHELL......................  2               OHIO POWER CO.
WISCONSIN.....................  JP PULLIAM....................  8               WISCONSIN PUB SER CO.
WISCONSIN.....................  NORTH OAK CREEK \2\...........  1               WISCONSIN ELEC PWR.
WISCONSIN.....................  NORTH OAK CREEK \2\...........  2               WISCONSIN ELEC PWR.
WISCONSIN.....................  NORTH OAK CREEK \2\...........  3               WISCONSIN ELEC PWR.
WISCONSIN.....................  NORTH OAK CREEK \2\...........  4               WISCONSIN ELEC PWR.
WISCONSIN.....................  SOUTH OAK CREEK \2\...........  5               WISCONSIN ELEC PWR.
WISCONSIN.....................  SOUTH OAK CREEK \2\...........  6               WISCONSIN ELEC PWR.
----------------------------------------------------------------------------------------------------------------
\1\ Vertically fired boiler.
\2\ Arch-fired boiler.


                                  Table 3--Phase I Cell Burner Technology Units
----------------------------------------------------------------------------------------------------------------
             State                           Plant                 Unit                   Operator
----------------------------------------------------------------------------------------------------------------
INDIANA.......................  WARRICK.......................          4  STHERN IND GAS & EL.
MICHIGAN......................  JH CAMPBELL...................          2  CONSUMERS POWER CO.
OHIO..........................  AVON LAKE.....................         12  CLEVELAND ELEC ILLUM.
OHIO..........................  CARDINAL......................          1  CARDINAL OPERATING.
OHIO..........................  CARDINAL......................          2  CARDINAL OPERATING.
OHIO..........................  EASTLAKE......................          5  CLEVELAND ELEC ILLUM.
OHIO..........................  GENRL JM GAVIN................          1  OHIO POWER CO.
OHIO..........................  GENRL JM GAVIN................          2  OHIO POWER CO.
OHIO..........................  MIAMI FORT....................          7  CINCINNATI GAS & EL.
OHIO..........................  MUSKINGUM RIVER...............          5  OHIO POWER CO.
OHIO..........................  WH SAMMIS.....................          7  OHIO EDISON CO.
PENNSYLVANIA..................  HATFIELDS FERRY...............          1  WEST PENN POWER CO.
PENNSYLVANIA..................  HATFIELDS FERRY...............          2  WEST PENN POWER CO.
PENNSYLVANIA..................  HATFIELDS FERRY...............          3  WEST PENN POWER CO.
TENNESSEE.....................  CUMBERLAND....................          1  TENNESSEE VAL AUTH.
TENNESSEE.....................  CUMBERLAND....................          2  TENNESSEE VAL AUTH.
WEST VIRGINIA.................  FORT MARTIN...................          2  MONONGAHELA POWER CO.
----------------------------------------------------------------------------------------------------------------


[[Page 484]]



Sec. Appendix B to Part 76--Procedures and Methods for Estimating Costs 
         of Nitrogen Oxides Controls Applied to Group 1, Boilers

                      1. Purpose and Applicability

    This technical appendix specifies the procedures, methods, and data 
that the Administrator will use in establishing ``***the degree of 
reduction achievable through this retrofit application of the best 
system of continuous emission reduction, taking into account available 
technology, costs, and energy and environmental impacts; and which is 
comparable to the costs of nitrogen oxides controls set pursuant to 
subsection (b)(1) (of section 407 of the Act).'' In developing the 
allowable NOX emissions limitations for Group 2 boilers 
pursuant to subsection (b)(2) of section 407 of the Act, the 
Administrator will consider only those systems of continuous emission 
reduction that, when applied on a retrofit basis, are comparable in cost 
to the cost in constant dollars of low NOX burner technology 
applied to Group 1, Phase I boilers.
    The Administrator will evaluate the capital cost (in dollars per 
kilowatt electrical ($/kW)), the operating and maintenance costs (in $/
year), and the cost-effectiveness (in annualized $/ton NOX 
removed) of installed low NOX burner technology controls over 
a range of boiler sizes (as measured by the gross electrical capacity of 
the associated generator in megawatt electrical (MW)) and utilization 
rates (in percent gross nameplate capacity on an annual basis) to 
develop estimates of the capital costs and cost effectiveness for Group 
1, Phase I boilers. The following units will be excluded from these 
determinations of the capital costs and cost effectiveness of 
NOX controls set pursuant to subsection (b)(1) of section 407 
of the Act: (1) Units employing an alternative technology, or overfire 
air as applied to wall-fired boilers or separated overfire air as 
applied to tangentially fired boilers, in lieu of low NOX 
burner technology for reducing NOX emissions; (2) units 
employing no controls, only controls installed before November 15, 1990, 
or only modifications to boiler operating parameters (e.g., burners out 
of service or fuel switching) for reducing NOX emissions; and 
(3) units that have not achieved the applicable emission limitation.

2. Average Capital Cost for Low NOX Burner Technology Applied 
                           to Group 1 Boilers

    The Administrator will use the procedures, methods, and data 
specified in this section to estimate the average capital cost (in $/kW) 
of installed low NOX burner technology applied to Group 1 
boilers.
    2.1 Using cost data submitted pursuant to the reporting requirements 
in section 4 below, boiler-specific actual or estimated actual capital 
costs will be determined for each unit in the population specified in 
section 1 above for assessing the costs of installed low NOX 
burner technology. The scope of installed low NOX burner 
technology costs will include the following capital costs for retrofit 
application: (1) For the burner portion--burners or air and coal 
nozzles, burner throat and waterwall modifications, and windbox 
modifications; and, where applicable, (2) for the combustion air staging 
portion--waterwall modifications or panels, windbox modifications, and 
ductwork, and (3) scope adders or supplemental equipment such as 
replacement or additional fans, dampers, or ignitors necessary for the 
proper operation of the low NOX burner technology. Capital 
costs associated with boiler restoration or refurbishment such as 
replacement of air heaters, asbestos abatement, and recasing will not be 
included in the cost basis for installed low NOX burner 
technology. The scope of installed low NOX burner technology 
retrofit capital costs will include materials, construction and 
installation labor, engineering, and overhead costs.
    2.2 Using gross nameplate capacity (in MW) for each unit as reported 
in the National Allowance Data Base (NADB), boiler-specific capital 
costs will be converted to a $/kW basis.
    2.3 Capital cost curves ($/kW versus boiler size in MW) or equations 
for installed low NOX burner technology retrofit costs will 
be developed for: (1) Dry bottom wall fired boilers (excluding units 
applying cell burner technology) and (2) tangentially fired boilers.

                              3. [Reserved]

                        4. Reporting Requirements

    4.1 The following information is to be submitted by each designated 
representative of a Phase I affected unit subject to the reporting 
requirements of Sec. 76.14(c):
    4.1.1 Schedule and dates for baseline testing, installation, and 
performance testing of low NOX burner technology.
    4.1.2 Estimates of the annual average baseline NOX 
emission rate, as specified in section 3.1.1, and the annual average 
controlled NOX emission rate, as specified in section 3.1.2, 
including the supporting continuous emission monitoring or other test 
data.
    4.1.3 Copies of pre-retrofit and post-retrofit performance test 
reports.
    4.1.4 Detailed estimates of the capital costs based on actual 
contract bids for each component of the installed low NOX 
burner technology including the items listed in section 2.1. Indicate 
number of bids solicited.

[[Page 485]]

Provide a copy of the actual agreement for the installed technology.
    4.1.5 Detailed estimates of the capital costs of system replacements 
or upgrades such as coal pipe changes, fan replacements/upgrades, or 
mill replacements/upgrades undertaken as part of the low NOX 
burner technology retrofit project.
    4.1.6 Detailed breakdown of the actual costs of the completed low 
NOX burner technology retrofit project where low 
NOX burner technology costs (section 4.1.4) are 
disaggregated, if feasible, from system replacement or upgrade costs 
(section 4.1.5).
    4.1.7 Description of the probable causes for significant differences 
between actual and estimated low NOX burner technology 
retrofit project costs.
    4.1.8 Detailed breakdown of the burner and, if applicable, 
combustion air staging system annual operating and maintenance costs for 
the items listed in section 3.3 before and after the installation, 
shakedown, and/or optimization of the installed low NOX 
burner technology. Include estimates and a description of the probable 
causes of the incremental annual operating and maintenance costs (or 
savings) attributable to the installed low NOX burner 
technology.
    4.2 All capital cost estimates are to be broken down into materials 
costs, construction and installation labor costs, and engineering and 
overhead costs. All operating and maintenance costs are to be broken 
down into maintenance materials costs, maintenance labor costs, 
operating labor costs, and fan electricity costs. All capital and 
operating costs are to be reported in dollars with the year of 
expenditure or estimate specified for each component.

[60 FR 18761, Apr. 13, 1995, as amended at 61 FR 67164, Dec. 19, 1996; 
62 FR 3464, Jan. 23, 1997]



PART 77_EXCESS EMISSIONS--Table of Contents



Sec.
77.1 Purpose and scope.
77.2 General.
77.3 Offset plans for excess emissions of sulfur dioxide.
77.4 Administrator's action on proposed offset plans.
77.5 Deduction of allowances to offset excess emissions of sulfur 
          dioxide.
77.6 Penalties for excess emissions of sulfur dioxide and nitrogen 
          oxides.

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

    Source: 58 FR 3757, Jan. 11, 1993, unless otherwise noted.



Sec. 77.1  Purpose and scope.

    (a) This part sets forth the excess emissions offset planning and 
offset penalty requirements under section 411 of the Clean Air Act, 42 
U.S.C. 7401, et seq., as amended by Public Law 101-549 (November 15, 
1990). These requirements shall apply to the owners and operators and, 
to the extent applicable, the designated representative of each affected 
unit and affected source under the Acid Rain Program.
    (b) Nothing in this part shall limit or otherwise affect the 
application of sections 112(r)(9), 113, 114, 120, 303, 304, or 306 of 
the Act, as amended. Any allowance deduction, excess emission penalty, 
or interest required under this part shall not affect the liability of 
the affected unit's and affected source's owners and operators for any 
additional fine, penalty, or assessment, or their obligation to comply 
with any other remedy, for the same violation, as ordered under the Act.



Sec. 77.2  General.

    Part 72 of this chapter, including Sec. Sec. 72.2 (definitions), 
72.3 (measurements, abbreviations, and acronyms), 72.4 (Federal 
authority), 72.5 (State authority), 72.6 (applicability), 72.7 (new 
units exemption), 72.8 (retired units exemption), 72.9 (standard 
requirements), 72.10 (availability of information), and 72.11 
(computation of time), shall apply to this part. The procedures for 
appeals of decisions of the Administrator under this part are contained 
in part 78 of this chapter.



Sec. 77.3  Offset plans for excess emissions of sulfur dioxide.

    (a) Applicability. The owners and operators of any affected source 
that has excess emissions of sulfur dioxide in any calendar year shall 
be liable to offset the amount of such excess emissions by an equal 
amount of allowances from the source's compliance account.
    (b) Deadline. Not later than 60 days after the end of any calendar 
year during which an affected source had excess emissions of sulfur 
dioxide (except for any increase in excess emissions under Sec. 
72.91(b) of this chapter), the designated representative for the source 
shall submit to the Administrator a complete proposed offset plan to 
offset those emissions. Each day after the 60-day deadline that the 
designated representative fails to submit a complete

[[Page 486]]

proposed offset plan shall be a separate violation of this part.
    (c) Number of Plans. The designated representative shall submit a 
proposed offset plan for each affected source with excess emissions of 
sulfur dioxide.
    (d) Contents of plan. A complete proposed offset plan shall include 
the following elements in a format prescribed by the Administrator for 
the source and for the calendar year for which the plan is submitted:
    (1) Identification of the source.
    (2) If the source had excess emissions for the calendar year prior 
to the year for which the plan is submitted, an explanation of how and 
why the excess emissions occurred for the year for which the plan is 
submitted and a description of any measures that were or will be taken 
to prevent excess emissions in the future.
    (3) At the designated representative's option, the number of 
allowances to be deducted from the source's compliance account's to 
offset the excess emissions for the year for which the plan is 
submitted.
    (4) At the designated representative's option, the serial numbers of 
the allowances that are to be deducted from the source's compliance 
account's.
    (5) A statement either that allowances to offset the excess 
emissions are to be deducted immediately from the source's compliance 
account or that they are to be deducted on a specified date in a 
subsequent year.
    (6) If the proposed offset plan does not propose an immediate 
deduction of allowances under paragraph (d)(5) of this section, a 
demonstration that such a deduction will interfere with electric 
reliability.

[58 FR 3757, Jan. 11, 1993, as amended at 62 FR 55487, Oct. 24, 1997; 70 
FR 25337, May 12, 2005]



Sec. 77.4  Administrator's action on proposed offset plans.

    (a) Determination of completeness. The Administrator will determine 
whether the proposed offset plan is complete within 30 days of receipt 
by the Administrator. The offset plan shall be deemed complete if the 
Administrator fails to notify the designated representative to the 
contrary within 30 days of receipt or when the Administrator approves 
the offset plan and deducts allowances in accordance with paragraph 
(b)(1) of this section.
    (b) Review of proposed offset plans. (1) If the designated 
representative submits a complete proposed offset plan for immediate 
deduction, from the source's compliance account, of allowances required 
to offset excess emissions of sulfur dioxide, the Administrator will 
approve the proposed offset plan without further review and will serve 
written notice of any approval on the designated representative. The 
Administrator will also give notice of any approval in the Federal 
Register. The plans will be incorporated in the unit's Acid Rain permit 
in accordance with Sec. 72.84 of this chapter (automatic permit 
amendment) and will not be subject to the requirements of paragraphs (d) 
through (k) of this section.
    (2) Notwithstanding paragraph (b)(1) of this section, the 
Administrator may, in his or her discretion, require that the proposed 
offset plan under paragraph (b)(1) of this section be reviewed under 
paragraphs (c) through (k) of this section. The Administrator may 
exercise such discretion where he or she determines that review of the 
plan is necessary to ensure compliance with the emissions limitation and 
reduction goals or other purposes of title IV of the Act.
    (3) If the designated representative submits a complete proposed 
offset plan that does not meet the requirements of paragraph (b)(1) of 
this section, the Administrator will review the plan under paragraphs 
(c) through (k) of this section.
    (c) Supplemental information. (1)(i) Regardless of whether the 
proposed offset plan is complete under paragraph (a) of this section, 
the Administrator may require submission of any additional information 
that the Administrator determines is necessary to approve an offset 
plan.
    (ii) Such supplemental information may include, but is not limited 
to:
    (A) A description of the measures that are proposed to be taken to 
ensure that the source will have sufficient allowances to offset the 
excess emissions and to prevent excess emissions in future years;

[[Page 487]]

    (B) A schedule of compliance with appropriate increments of progress 
for the proposed measures; and
    (C) A schedule for the submission of progress reports, and 
supporting documentation, describing actions taken and actions remaining 
to be taken under the schedule of compliance and any proposed 
adjustments to the schedule of compliance.
    (2)(i) The designated representative shall submit the information 
required under paragraph (c)(1) of this section within a reasonable 
period determined by the Administrator.
    (ii) If the designated representative fails to submit the 
supplemental information within the required time period, the 
Administrator may disapprove the proposed offset plan.
    (d) Draft offset plan. (1) After the Administrator receives a 
complete proposed offset plan and any supplemental information, the 
Administrator will prepare a draft offset plan that incorporates in 
whole, in part, or with changes or conditions as appropriate, the 
proposed offset plan or disapprove a draft offset plan for the affected 
source. Regardless of whether the Administrator required the submission 
of the information set forth in paragraph (c)(1)(ii) of this section, 
the draft offset plan may include, among other requirements and 
conditions as determined to be appropriate by the Administrator, the 
submission of schedules of compliance, progress reports, and monitoring 
and other information.
    (2) The draft offset plan will be based on the information submitted 
by the designated representative for the affected source and other 
relevant information.
    (3) The Administrator will serve a copy of the draft offset plan and 
the statement of basis on the designated representative of the affected 
source.
    (4) The Administrator will provide a 30-day period for public 
comment, and opportunity to request a public hearing, on the draft 
offset plan or disapproval of a draft offset plan in accordance with the 
public notice required under paragraph (g)(1)(i)(A) of this section.
    (e) Offset plan administrative record. (1) The Administrator will 
prepare an administrative record for an offset plan or disapproval of an 
offset plan. The administrative record will contain:
    (i) The proposed offset plan and any supporting or supplemental 
information submitted by the designated representative;
    (ii) The draft offset plan;
    (iii) The statement of basis;
    (iv) Copies of all documents relied on by the Administrator in 
approving or disapproving the draft offset plan (including any records 
of discussions or conferences with owners, operators or the designated 
representative of the source or interested persons regarding the draft 
offset plan) or, for any such documents that are readily available, a 
statement of their location;
    (v) Copies of all written public comments submitted on the draft 
offset plan or disapproval of a draft offset plan;
    (vi) The record of any public hearing on the draft offset plan or 
disapproval of a draft offset plan;
    (vii) The offset plan approved by the Administrator; and
    (viii) Any response to public comments submitted on the draft offset 
plan or disapproval of a draft offset plan, including any documents 
cited in the response and any other documents relied on by the 
Administrator or, for any such documents that are readily available, a 
statement of their location.
    (2) The Administrator will approve or disapprove an offset plan 
within 6 months of receipt of a complete proposed offset plan.
    (f) Statement of basis. (1) The statement of basis will briefly set 
forth significant factual, legal, and policy considerations on which the 
Administrator relied in approving or disapproving the draft offset plan.
    (2) The statement of basis will include:
    (i) The reasons, and supporting authority, for approval or 
disapproval of any proposed offset plan that does not require immediate 
deduction of allowances, including references to applicable statutory or 
regulatory provisions and to the administrative record; and
    (ii) The name, address, and telephone and facsimile number of the 
EPA office processing the approval or disapproval of the offset plan.

[[Page 488]]

    (g) Opportunities for Public Comment on Draft Offset Plans--(1) 
Generally. (i) The Administrator will give public notice of the 
following:
    (A) The draft offset plan or disapproval of a draft offset plan and 
the opportunity for public comment and to request a public hearing; and
    (B) Date, time, location, and procedures for any scheduled hearing 
on the draft offset plan or the disapproval of a draft offset plan.
    (ii) Any public notice given under this section may be for the 
approval or disapproval of one or more draft offset plans.
    (2) Methods. The Administrator will give the public notice required 
by this section by:
    (i) Serving written notice on the following persons (except to the 
extent any such person has waived his or her right to receive such 
notice):
    (A) The designated representative;
    (B) The air pollution control agencies of affected States; and
    (C) Any interested person.
    (ii) Giving notice by publication in the Federal Register and in a 
newspaper of general circulation in the area where the source is located 
or in a State publication designed to give general public notice.
    (3) Contents. All public notices issued under this part will contain 
the following information:
    (i) Identification of the EPA office processing the approval or 
disapproval of the draft offset plan for which the notice is being 
given.
    (ii) Identification of the designated representative for the 
affected source.
    (iii) Identification of each affected source covered by the proposed 
offset plan.
    (iv) The amount of excess emissions that must be offset and the date 
on which the allowances are proposed to be deducted.
    (v) The address and office hours of a public location where the 
administrative record is available for public inspection and a statement 
that all information submitted by the designated representative and not 
protected as confidential pursuant to section 114(c) of the Act is 
available for public inspections as part of the administrative record.
    (vi) For public notice under paragraph (g)(1)(i)(A) of this section, 
a brief description of the public comment procedures, including:
    (A) A 30-day public comment period beginning the date of publication 
of the notice or, in the case of an extension or reopening of the public 
comment period, such period as the Administrator deems appropriate;
    (B) The address where public comments should be sent;
    (C) Required formats and contents for public comment;
    (D) An opportunity to request a public hearing to occur not earlier 
than 15 days after public notice is given and the location, date, time, 
and procedures of any scheduled public hearing; and
    (E) Any other means by which the public may participate.
    (4) Extensions and Reopenings of the Public Comment Period. On the 
Administrator's own motion, or on the request for any person, the 
Administrator may, at his or her discretion, extend or reopen the public 
comment period where he or she finds that doing so will contribute to 
the decision-making process by clarifying one or more significant issues 
affecting the draft offset plan or disapproval of a draft offset plan. 
Notice of any such extension or reopening will be given under paragraph 
(g)(1)(i)(A) of this section.
    (h) Public comments--(1) General. During the public comment period, 
any person may submit written comments on the draft offset plan or 
disapproval of a draft offset plan.
    (2) Form. (i) Comments shall be submitted in duplicate.
    (ii) The submission shall clearly indicate the draft offset plan 
approval or disapproval to which the comments apply.
    (iii) The submission shall clearly indicate the name of the 
commenter, his or her interest, and his or her affiliation, if any, to 
owners and operators of any unit covered by the proposed offset plan.
    (3) Contents. Timely comments on any aspect of a draft offset plan 
or disapproval of a draft offset plan will be considered unless they 
concern issues that are not relevant, such as:

[[Page 489]]

    (i) The environmental effects of acid rain, acid deposition, sulfur 
dioxide, or nitrogen oxides generally; and
    (ii) Offset plan approval procedures or actions on other proposed 
offset plans that are not relevant to approval or disapproval of the 
draft offset plan in question.
    (4) Persons who do not wish to raise issues on the draft offset plan 
or denial of a draft offset plan, but who wish to be notified of any 
subsequent actions concerning such matter, may so indicate during the 
public comment period or at any other time. The Administrator will place 
their names on a list of interested persons.
    (i) Opportunity for Public Hearing. (1) During the public comment 
period, any person may request a public hearing. A request for a public 
hearing shall be made in writing and shall state the issues proposed to 
be raised in the hearing.
    (2) On the Administrator's own motion or on the request of any 
person, the Administrator may, at his or her discretion, hold a public 
hearing whenever the Administrator finds that such a hearing will 
contribute to the decision-making process by clarifying one or more 
significant issues affecting the draft offset plan or disapproval of a 
draft offset plan. Public hearings will not be held on issues under 
paragraphs (h)(3) (i) and (ii) of this section.
    (3) During a public hearing under this section, any person may 
submit oral or written comments concerning the draft offset plan or 
disapproval of a draft offset plan. The Administrator may set reasonable 
limits on the time allowed for oral statements and will require the 
submission of written summaries of each oral statement.
    (4) The Administrator will assure that a record is made of the 
hearing.
    (j) Response to Comments. (1) The Administrator will consider 
comments on the draft offset plan or disapproval of a draft offset plan 
received during the public comment period and any public hearing. The 
Administrator is not required to consider comments otherwise received.
    (2) In approving or disapproving an offset plan, the Administrator 
will:
    (i) Identify any draft offset plan provision or portion of the 
statement of basis that has been changed and the reasons for the change; 
and
    (ii) Briefly describe and respond to relevant comments under 
paragraph (j)(1) of this section.
    (k) Approval and Effective Date of Excess Emissions Offset Plans. 
(1) After the close of the public comment period, the Administrator will 
approve an offset plan requiring allowance deductions in an amount equal 
to the unit's tons of excess emissions or disapprove an offset plan. The 
Administrator will serve a copy of any approved offset plan and the 
response to comments on the designated representative for the affected 
unit involved and serve written notice of the approval or disapproval of 
the offset plan on any persons who are entitled to written notice under 
paragraphs (g)(2)(i) (B) and (C) of this section or who submitted 
written or oral comments on the approval or disapproval of the draft 
offset plan. The Administrator will also give notice in the Federal 
Register.
    (2) The Administrator will approve an offset plan requiring 
immediate deduction from the source's compliance account of all 
allowances necessary to offset the excess emissions except to the extent 
the designated representative of the source demonstrates that such a 
deduction will interfere with electric reliability.
    (3) Upon approval of the offset plan by the Administrator, the 
offset plan will be incorporated into the Acid Rain permit in accordance 
with Sec. 72.84 (automatic permit amendment) and shall supersede any 
inconsistent provision of the permit.

[58 FR 3757, Jan. 11, 1993, as amended at 62 FR 55487, Oct. 24, 1997; 62 
FR 66279, Dec. 18, 1997; 70 FR 25337, May 12, 2005]



Sec. 77.5  Deduction of allowances to offset excess emissions 
of sulfur dioxide.

    (a) The Administrator will deduct allowances to offset excess 
emissions in accordance with the offset plan approved under Sec. 
77.4(b) (1) or (k) or in accordance with Sec. 72.91(b) of this chapter.
    (b) The designated representative shall hold enough allowances in 
the appropriate compliance account to cover

[[Page 490]]

the deductions to be made in accordance with paragraph (a) or paragraph 
(c) of this section.
    (c) If the designated representative does not submit a timely and 
complete proposed offset plan, or if the Administrator disapproves a 
proposed offset plan under Sec. 77.4 (c) or (k), the Administrator will 
immediately deduct allowances allocated for the year after the year in 
which the source has excess emissions, from the source's compliance 
account on a first-in, first-out basis in accordance with Sec. 
73.35(c)(2) of this chapter, equal to the amount of the source's excess 
emissions of sulfur dioxide.

[58 FR 3757, Jan. 11, 1993, as amended at 70 FR 25337, May 12, 2005]



Sec. 77.6  Penalties for excess emissions of sulfur dioxide and 
nitrogen oxides.

    (a)(1) If excess emissions of sulfur dioxide occur at the affected 
source or nitrogen oxide occur at an affected unit during any year, the 
owners and operators respectively of the affected source and the 
affected units at the source or of the affected unit shall pay, without 
demand, an excess emissions penalty, as calculated under paragraph (b) 
of this section.
    (2) If one or more affected units governed by an approved 
NOX averaging plan under Sec. 76.11 of this chapter fail 
(after applying Sec. 76.11(d)(1)(ii)(C) of this chapter) to meet their 
respective alternative contemporaneous emission limitations or annual 
heat input limits, then excess emissions of nitrogen oxides occur during 
the year at each such unit. The sum of the excess emissions of nitrogen 
oxides of such units shall equal the amount determined under Sec. 
76.13(b) of this chapter. The owners and operators of such units shall 
pay an excess emissions penalty, as calculated under paragraph (b) of 
this section using the sum of the excess emissions of nitrogen oxides of 
such units.
    (3) Except as otherwise provided in this paragraph (a)(3), payment 
under paragraphs (a) (1) or (2) of this section shall be submitted to 
the Administrator by 30 days after the date on which the Administrator 
serves the designated representative a notice that the process of 
recordation set forth in Sec. 73.34(a) of this chapter is completed or 
by July 1 of the year after the year in which the excess emissions 
occurred, whichever date is earlier. Payment under paragraph (a)(1) of 
this section for any increase in excess emissions of sulfur dioxide 
determined after adjustments made under Sec. 72.91(b) of this chapter 
shall be submitted to the Administrator by 30 days after the date on 
which the Administrator serves the designated representative a notice 
that process set forth in Sec. 72.91(b) of this chapter is completed.
    (b) Penalty formula. (1) The following formulas shall be used to 
determine the excess emissions penalty:

Penalty for excess emissions of sulfur dioxide = $2000/ton x annual 
adjustment factor x tons of excess emissions of sulfur dioxide.

Penalty for excess emissions of nitrogen oxides = $2000/ton x annual 
adjustment factor x tons of excess emissions of nitrogen oxides.

    (i) The annual adjustment factor will be calculated as follows:

Annual adjustment factor = 1 + {[CPI(year) - CPI(1990)] / 
CPI(1990){time} 


where:

    (A) ``CPI(year)'' is the Consumer Price Index as defined in Sec. 
72.2 of this chapter and ``year'' is the year in which the source or 
unit as appropriate had excess emissions.
    (B) ``CPI(1990)'' is the Consumer Price Index for 1990, as defined 
in Sec. 72.2 of this chapter.

    (ii) The Administrator will publish the annual adjustment factor in 
the Federal Register by October 15 of each year beginning in 1995.
    (2) The penalty may be rounded to the nearest dollar after 
completing the calculation in paragraph (b)(1)(i) of this section.
    (3) The penalty for excess emissions of sulfur dioxide shall be paid 
separately from the payment for excess emissions of nitrogen oxides. 
Each payment shall be accompanied by a document, in a format prescribed 
by the Administrator, indicating the source or unit as appropriate for 
which the payment is made, whether the payment is for excess emissions 
of sulfur dioxide or nitrogen oxides, the number of tons

[[Page 491]]

of excess emissions, the penalty amount, and the check or money order 
number of the payment.
    (c) If an excess emissions penalty due under this part is not paid 
on or before the applicable deadline under paragraph (a) of this 
section, the penalty shall be subject to interest charges in accordance 
with the Debt Collection Act (31 U.S.C. 3717). Interest shall begin to 
accrue on the date on which the Administrator mails, to the designated 
representative of the source or unit as appropriate with excess 
emissions, a demand notice for the payment.
    (d)(1) Except for wire transfers made in accordance with paragraph 
(d)(2) of this section, payments of penalties shall be made by money 
order, cashier's check, certified check, or U.S. Treasury check made 
payable to the ``U.S. EPA.''
    (2) Payments made under paragraph (c)(1) of this section shall be 
mailed to the following address, unless the Administrator has notified 
the designated representative of a different address: U.S. EPA: 
Headquarters Accounting Operations Branch, Acid Rain Excess Emissions 
Penalties, P.O. Box 952491, St. Louis, MO 63195-2491.
    (3) Payments of penalties of $25,000 or more may be made by wire 
transfer to the U.S. Treasury at the Federal Reserve Bank of New York.
    (e) If the Administrator determines that overpayment has been made, 
he or she will refund the overpayment without interest, as promptly as 
administratively possible.
    (f) Excess emissions in any year resulting directly from an order 
issued in that year under section 110(f) of the Act shall not be subject 
to the penalty payment requirements of this section; provided that the 
designated representative of any source or unit as appropriate subject 
to such order shall advise the Administrator within 30 days of issuance 
of the order that the order will result in such excess emissions.

[58 FR 3757, Jan. 11, 1993, as amended at 60 FR 17131, Apr. 4, 1995; 62 
FR 55487, Oct. 24, 1997; 70 FR 25337, May 12, 2005]



PART 78_APPEAL PROCEDURES--Table of Contents



Sec.
78.1 Purpose and scope.
78.2 General.
78.3 Petition for administrative review and request for evidentiary 
          hearing.
78.4 Filings.
78.5 Limitation on filing or presenting new evidence and raising new 
          issues.
78.6 Action on petition for administrative review.
78.7 [Reserved]
78.8 Consolidation and severance of appeals proceedings.
78.9 Notice of the filing of petition for administrative review.
78.10 Ex parte communications during pendency of a hearing.
78.11 Intervenors.
78.12 Standard of review.
78.13 Scheduling orders and pre-hearing conferences.
78.14 Evidentiary hearing procedure.
78.15 Motions in evidentiary hearings.
78.16 Record of appeal proceeding.
78.17 Proposed findings and conclusions and supporting brief.
78.18 Proposed decision.
78.19 Interlocutory appeal.
78.20 Appeal of decision of Administrator or proposed decision to the 
          Environmental Appeals Board.

    Authority: 42 U.S.C. 7401, 7403, 7410, 7411, 7426, 7601, and 7651, 
et seq.

    Source: 58 FR 3760, Jan. 11, 1993, unless otherwise noted.



Sec. 78.1  Purpose and scope.

    (a)(1) This part shall govern appeals of any final decision of the 
Administrator under subpart HHHH of part 60 of this chapter or State 
regulations approved under Sec. 60.24(h)(6)(i) or (ii) of this chapter, 
part 72, 73, 74, 75, 76, or 77 of this chapter, subparts AA through II 
of part 96 of this chapter or State regulations approved under Sec. 
51.123(o)(1) or (2) of this chapter, subparts AAA through III of part 96 
of this chapter or State regulations approved under Sec. 51.124(o)(1) 
or (2) of this chapter, subparts AAAA through IIII of part 96 of this 
chapter or State regulations approved under Sec. 51.123(aa)(1) or (2) 
of this chapter, part 97 of this chapter, or subpart RR of part 98; 
provided that matters listed in Sec. 78.3(d) and preliminary, 
procedural, or intermediate decisions, such as draft Acid Rain permits, 
may not be appealed. All references in paragraph (b) of this section and 
in Sec. 78.3 to subpart HHHH of part 60 of this chapter, subparts AA 
through II of part 96 of this chapter, subparts AAA through

[[Page 492]]

III of part 96 of this chapter, and subparts AAAA through IIII of part 
96 of this chapter shall be read to include the comparable provisions in 
State regulations approved under Sec. 60.24(h)(6)(i) or (ii) of this 
chapter, Sec. 51.123(o)(1) or (2) of this chapter, Sec. 51.124(o)(1) 
or (2) of this chapter, and Sec. 51.123(aa)(1) or (2) of this chapter, 
respectively.
    (2) Filing an appeal, and exhausting administrative remedies, under 
this part shall be a prerequisite to seeking judicial review. For 
purposes of judicial review, final agency action occurs only when a 
decision appealable under this part is issued and the procedures under 
this part for appealing the decision are exhausted.
    (b) The decisions of the Administrator that may be appealed include 
but are not limited to:
    (1) Under part 72 of this chapter;
    (i) The determination of incompleteness of an Acid Rain permit 
application;
    (ii) The issuance or denial of an Acid Rain permit and approval or 
disapproval of a compliance option by the Administrator;
    (iii) The approval or disapproval of an early ranking application 
for Phase I extension under Sec. 72.42 of this chapter;
    (iv) The final determination of whether a technology is a qualified 
repowering technology under Sec. 72.44 of this chapter;
    (v) [Reserved]
    (vi) The approval or disapproval of a permit revision;
    (vii) The decision on the deduction or return of allowances under 
Sec. Sec. 72.41, 72.42, 72.43, 72.44, 72.91(b), and 72.92 (a) and (c) 
of this chapter; and
    (viii) The failure to issue an Acid Rain permit in accordance with 
the deadline under Sec. 72.74(b) of this chapter.
    (2) Under part 73 of this chapter,
    (i) The correction of an error in an Allowance Tracking System 
account;
    (ii) The decision on the allocation of allowances from the 
Conservation and Renewal Energy Reserve;
    (iii) The decision on the allocation of allowances under regulations 
implementing sections 404(e), 405(g)(4), 405(i)(2), and 410(h) of the 
Act;
    (iv) The decision on the allocation of allowances under part 73, 
subpart F of this chapter;
    (v) The decision on the sale or return of allowances and transfer of 
proceeds under part 73, subpart E; and
    (vi) The decision on the deduction of allowances under Sec. 
73.35(b) of this chapter.
    (3) Under part 74 of this chapter,
    (i) The determination of incompleteness of an opt-in permit 
application;
    (ii) The issuance or denial of an opt-in permit and approval or 
disapproval of the transfer of allowances for the replacement of thermal 
energy;
    (iii) The approval or disapproval of a permit revision to an opt-in 
permit;
    (iv) The decision on the deduction or return of allowances under 
subpart E of part 74 of this chapter;
    (4) Under part 75 of this chapter,
    (i) The decision on a petition for approval of an alternative 
monitoring system;
    (ii) The approval or disapproval of a monitoring system 
certification or recertification;
    (iii) The finalization of annual emissions data, including 
retroactive adjustment based on audit;
    (iv) The determination of the percentage of emissions reduction 
achieved by qualifying Phase I technology; and
    (v) The determination on the acceptability of parametric missing 
data procedures for a unit equipped with add-on controls for sulfur 
dioxide and nitrogen oxides in accordance with part 75 of this chapter.
    (5) Under part 77 of this chapter, the determination of 
incompleteness of an offset plan and the approval or disapproval of an 
offset plan under Sec. 77.4 of this chapter and the deduction of 
allowances under Sec. 77.5(c) of this chapter.
    (6) Under part 97 of this chapter:
    (i) The adjustment of the information in a compliance certification 
or other submission and the deduction or transfer of NOX 
allowances based on the information, as adjusted, under Sec. 97.31 of 
this chapter;
    (ii) The decision on the allocation of NOX allowances to 
a NOX Budget unit under Sec. 97.41(b), (c), (d), or (e) of 
this chapter;
    (iii) The decision on the allocation of NOX allowances to 
a NOX Budget unit from the compliance supplement pool under 
Sec. 97.43 of this chapter;

[[Page 493]]

    (iv) The decision on the deduction of NOX allowances 
under Sec. 97.54 of this chapter;
    (v) The decision on the transfer of NOX allowances under 
Sec. 97.61 of this chapter;
    (vi) The decision on a petition for approval of an alternative 
monitoring system;
    (vii) The approval or disapproval of a monitoring system 
certification or recertification under Sec. 97.71 of this chapter;
    (viii) The finalization of control period emissions data, including 
retroactive adjustment based on audit;
    (ix) The approval or disapproval of a petition under Sec. 97.75 of 
this chapter;
    (x) The determination of the sufficiency of the monitoring plan for 
a NOX Budget opt-in unit;
    (xi) The decision on a request for withdrawal of a NOX 
Budget opt-in unit from the NOX Budget Trading Program under 
Sec. 97.86 of this chapter;
    (xii) The decision on the deduction of NOX allowances 
under Sec. 97.87 of this chapter; and
    (xiii) The decision on the allocation of NOX allowances 
to a NOX Budget opt-in unit under Sec. 97.88 of this 
chapter.
    (7) Under subparts AA through II of part 96 of this chapter,
    (i) The decision on the allocation of CAIR NOX allowances 
under Sec. 96.141(b)(2) or (c)(2) of this chapter.
    (ii) The decision on the deduction of CAIR NOX 
allowances, and the adjustment of the information in a submission and 
the decision on the deduction or transfer of CAIR NOX 
allowances based on the information as adjusted, under Sec. 96.154 of 
this chapter;
    (iii) The correction of an error in a CAIR NOX Allowance 
Tracking System account under Sec. 96.156 of this chapter;
    (iv) The decision on the transfer of CAIR NOX allowances 
under Sec. 96.161 of this chapter;
    (v) The finalization of control period emissions data, including 
retroactive adjustment based on audit;
    (vi) The approval or disapproval of a petition under Sec. 96.175 of 
this chapter.
    (8) Under subparts AAA through III of part 96 of this chapter,
    (i) The decision on the deduction of CAIR SO2 allowances, 
and the adjustment of the information in a submission and the decision 
on the deduction or transfer of CAIR SO2 allowances based on 
the information as adjusted, under Sec. 96.254 of this chapter;
    (ii) The correction of an error in a CAIR SO2 Allowance 
Tracking System account under Sec. 96.256 of this chapter;
    (iii) The decision on the transfer of CAIR SO2 allowances 
under Sec. 96.261 of this chapter;
    (iv) The finalization of control period emissions data, including 
retroactive adjustment based on audit;
    (v) The approval or disapproval of a petition under Sec. 96.275 of 
this chapter.
    (9) Under subparts AAAA through IIII of part 96 of this chapter,
    (i) The decision on the allocation of CAIR NOX Ozone 
Season allowances under Sec. 96.341(b)(2) or (c)(2)of this chapter.
    (ii) The decision on the deduction of CAIR NOX Ozone 
Season allowances, and the adjustment of the information in a submission 
and the decision on the deduction or transfer of CAIR NOX 
Ozone Season allowances based on the information as adjusted, under 
Sec. 96.354 of this chapter;
    (iii) The correction of an error in a CAIR NOX Ozone 
Season Allowance Tracking System account under Sec. 96.356 of this 
chapter;
    (iv) The decision on the transfer of CAIR NOX Ozone 
Season allowances under Sec. 96.361;
    (v) The finalization of control period emissions data, including 
retroactive adjustment based on audit;
    (vi) The approval or disapproval of a petition under Sec. 96.375 of 
this chapter.
    (10) Under subparts AA through II of part 97 of this chapter,
    (i) The decision on the allocation of CAIR NOX allowances 
under subpart EE of part 97 of this chapter.
    (ii) The decision on the deduction of CAIR NOX 
allowances, and the adjustment of the information in a submission and 
the decision on the deduction or transfer of CAIR NOX 
allowances based on the information as adjusted, under Sec. 97.154 of 
this chapter;
    (iii) The correction of an error in a CAIR NOX Allowance 
Tracking System account under Sec. 97.156 of this chapter;
    (iv) The decision on the transfer of CAIR NOX allowances 
under Sec. 97.161 of this chapter;

[[Page 494]]

    (v) The finalization of control period emissions data, including 
retroactive adjustment based on audit;
    (vi) The approval or disapproval of a petition under Sec. 97.175 of 
this chapter.
    (11) Under subparts AAA through III of part 97 of this chapter,
    (i) The decision on the deduction of CAIR SO2 allowances, 
and the adjustment of the information in a submission and the decision 
on the deduction or transfer of CAIR SO2 allowances based on 
the information as adjusted, under Sec. 97.254 of this chapter;
    (ii) The correction of an error in a CAIR SO2 Allowance 
Tracking System account under Sec. 97.256 of this chapter;
    (iii) The decision on the transfer of CAIR SO2 allowances 
under Sec. 97.261 of this chapter;
    (iv) The finalization of control period emissions data, including 
retroactive adjustment based on audit;
    (v) The approval or disapproval of a petition under Sec. 97.275 of 
this chapter.
    (12) Under subparts AAAA through IIII of part 97 of this chapter,
    (i) The decision on the allocation of CAIR NOX Ozone 
Season allowances under subpart EEEE of part 97 of this chapter.
    (ii) The decision on the deduction of CAIR NOX Ozone 
Season allowances, and the adjustment of the information in a submission 
and the decision on the deduction or transfer of CAIR NOX 
Ozone Season allowances based on the information as adjusted, under 
Sec. 97.354 of this chapter;
    (iii) The correction of an error in a CAIR NOX Ozone 
Season Allowance Tracking System account under Sec. 97.356 of this 
chapter;
    (iv) The decision on the transfer of CAIR NOX Ozone 
Season allowances under Sec. 97.361;
    (v) The finalization of control period emissions data, including 
retroactive adjustment based on audit;
    (vi) The approval or disapproval of a petition under Sec. 97.375 of 
this chapter.
    (13) Under subpart AAAAA of part 97 of this chapter,
    (i) The decision on allocation of TR NOX Annual 
allowances under Sec. 97.411(a)(2) and (b) of this chapter.
    (ii) The decision on the transfer of TR NOX Annual 
allowances under Sec. 97.423 of this chapter.
    (iii) The decision on the deduction of TR NOX Annual 
allowances under Sec. Sec. 97.424 and 97.425 of this chapter.
    (iv) The correction of an error in an Allowance Management System 
account under Sec. 97.427 of this chapter.
    (v) The adjustment of information in a submission and the decision 
on the deduction and transfer of TR NOX Annual allowances 
based on the information as adjusted under Sec. 97.428 of this chapter.
    (vi) The finalization of control period emissions data, including 
retroactive adjustment based on audit.
    (vii) The approval or disapproval of a petition under Sec. 97.435 
of this chapter.
    (14) Under subpart BBBBB of part 97 of this chapter,
    (i) The decision on allocation of TR NOX Ozone Season 
allowances under Sec. 97.511(a)(2) and (b) of this chapter.
    (ii) The decision on the transfer of TR NOX Ozone Season 
allowances under Sec. 97.523 of this chapter.
    (iii) The decision on the deduction of TR NOX Ozone 
Season allowances under Sec. Sec. 97.524 and 97.525 of this chapter.
    (iv) The correction of an error in an Allowance Management System 
account under Sec. 97.527 of this chapter.
    (v) The adjustment of information in a submission and the decision 
on the deduction and transfer of TR NOX Ozone Season 
allowances based on the information as adjusted under Sec. 97.528 of 
this chapter.
    (vi) The finalization of control period emissions data, including 
retroactive adjustment based on audit.
    (vii) The approval or disapproval of a petition under Sec. 97.535 
of this chapter.
    (15) Under subpart CCCCC of part 97 of this chapter,
    (i) The decision on allocation of TR SO2 Group 1 
allowances under Sec. 97.611(a)(2) and (b) of this chapter.
    (ii) The decision on the transfer of TR SO2 Group 1 
allowances under Sec. 97.623 of this chapter.
    (iii) The decision on the deduction of TR SO2 Group 1 
allowances under Sec. Sec. 97.624 and 97.625 of this chapter.
    (iv) The correction of an error in an Allowance Management System 
account under Sec. 97.627 of this chapter.
    (v) The adjustment of information in a submission and the decision 
on the

[[Page 495]]

deduction and transfer of TR SO2 Group 1 allowances based on 
the information as adjusted under Sec. 97.628 of this chapter.
    (vi) The finalization of control period emissions data, including 
retroactive adjustment based on audit.
    (vii) The approval or disapproval of a petition under Sec. 97.635 
of this chapter.
    (16) Under subpart DDDDD of part 97 of this chapter,
    (i) The decision on allocation of TR SO2 Group 2 
allowances under Sec. 97.711(a)(2) and (b) of this chapter.
    (ii) The decision on the transfer of TR SO2 Group 1 
allowances under Sec. 97.723 of this chapter.
    (iii) The decision on the deduction of TR SO2 Group 1 
allowances under Sec. Sec. 97.724 and 97.725 of this chapter.
    (iv) The correction of an error in an Allowance Management System 
account under Sec. 97.727 of this chapter.
    (v) The adjustment of information in a submission and the decision 
on the deduction and transfer of TR SO2 Group 1 allowances 
based on the information as adjusted under Sec. 97.728 of this chapter.
    (vi) The finalization of control period emissions data, including 
retroactive adjustment based on audit.
    (vii) The approval or disapproval of a petition under Sec. 97.735 
of this chapter.
    (17) Under subpart RR of part 98 of this chapter,
    (i) A determination of eligibility for research and development 
exemption under Sec. 98.440(d) of this chapter.
    (ii) The approval or disapproval of a request for discontinuation of 
reporting under Sec. 98.441(b) of this chapter.
    (iii) The approval or disapproval of a geologic sequestration 
monitoring, reporting, and verification (MRV) plan under Sec. 98.448(c) 
and Sec. 98.448(d) of this chapter.
    (c) In order to appeal a decision under paragraph (a) of this 
section, a person shall file a petition for administrative review with 
the Environmental Appeals Board under Sec. 78.3. The Environmental 
Appeals Board will, consistent with Sec. 78.6, either:
    (1) Issue an order deciding the appeal; or
    (2) Where there is a disputed issue of fact material to the 
contested portions of the decision, refer the proceeding to the Chief 
Administrative Law Judge, who will designate an Administrative Law Judge 
to conduct an evidentiary hearing to decide the disputed issue of fact. 
If the proposed decision is contested or the Environmental Appeals Board 
decides to review the proposed decision, the Environmental Appeals Board 
will issue an order deciding the appeal.
    (d) Questions arising at any stage of a proceeding that are not 
addressed in this part will be resolved at the discretion of the 
Environmental Appeals Board or the Presiding Officer.

[58 FR 3760, Jan. 11, 1993, as amended at 60 FR 17132, Apr. 4, 1995; 62 
FR 55488, Oct. 24, 1997; 66 FR 12978, Mar. 1, 2001; 69 FR 21644, Apr. 
21, 2004; 70 FR 25338, May 12, 2005; 71 FR 25379, Apr. 28, 2006; 72 FR 
59205, Oct. 19, 2007; 75 FR 75078, Dec. 1, 2010; 76 FR 48378, Aug. 8, 
2011]



Sec. 78.2  General.

    (a) Definitions. (1) The terms used in this subpart with regard to a 
decision of the Administrator that is appealed under this section shall 
have the meaning as set forth in the regulations under which the 
Administrator made such decision and as set forth in paragraph (a)(2) of 
this section.
    (2) Interested person means, with regard to a decision of the 
Administrator:
    (i) Any person who submitted comments, or testified at a public 
hearing, pursuant to an opportunity for comment provided by the 
Administrator as part of the process of making such decision;
    (ii) Who submitted objections pursuant to an opportunity for 
objections provided by the Administrator as part of the process of 
making such decision; or
    (iii) Who submitted, to the Administrator and in a format prescribed 
by the Administrator, his or her name, service address, telephone 
number, and facsimile number and identified such decision in order to be 
placed on a list of persons interested in such decision;
    (iv) Provided that the Administrator may update the list of 
interested persons from time to time by requesting additional written 
indication of continued interest from the persons listed and may delete 
from the list the name

[[Page 496]]

of any person failing to respond as requested.
    (b) Availability of information. The availability to the public of 
information provided to, or otherwise obtained by, the Administrator 
under this subpart shall be governed by part 2 of this chapter.
    (c) Computation of time. (1) In computing any period of time 
prescribed or allowed under this part, except as otherwise provided, the 
day of the event from which the period begins to run shall not be 
included, and Saturdays, Sundays, and federal holidays shall be 
included. When the period ends on a Saturday, Sunday, or federal 
holiday, the stated period shall be extended to include the next 
business day.
    (2) Where a document is served by first class mail or commercial 
delivery service, but not by overnight or same-day delivery, 5 days 
shall be added to the time prescribed or allowed under this part for the 
filing of a responsive document or for otherwise responding.

[76 FR 48379, Aug. 8, 2011]



Sec. 78.3  Petition for administrative review and request for
evidentiary hearing.

    (a)(1) The following persons may petition for administrative review 
of a decision of the Administrator that is made under parts 72, 74, 75, 
76, and 77 of this chapter and that is appealable under Sec. 78.1(a) of 
this part:
    (i) The designated representative for the unit covered by the 
decision;
    (ii) The authorized account representative for an account covered by 
the decision; and
    (iii) Any interested person with regard to the decision.
    (2) The following persons may petition for administrative review of 
a decision of the Administrator that is made under part 73 of this 
chapter and that is appealable under Sec. 78.1(a):
    (i) The authorized account representative for any Allowance Tracking 
System account covered by the decision; and
    (ii) With regard to the decision on the allocation of allowances 
from the Conservation and Renewable Energy Reserve, the certifying 
official whose application is covered by the decision.
    (3) The following persons may petition for administrative review of 
a decision of the Administrator that is made under part 97 of this 
chapter and that is appealable under Sec. 78.1(a) of this part:
    (i) The NOX authorized account representative for the 
unit or any NOX Allowance Tracking System account covered by 
the decision; or
    (ii) Any interested person with regard to the decision.
    (4) The following persons may petition for administrative review of 
a decision of the Administrator that is made under subparts AA through 
II of part 96 of this chapter and that is appealable under Sec. 
78.1(a):
    (i) The CAIR designated representative for a unit or source, or the 
CAIR authorized account representative for any CAIR NOX 
Allowance Tracking System account, covered by the decision; or
    (ii) Any interested person with regard to the decision.
    (5) The following persons may petition for administrative review of 
a decision of the Administrator that is made under subparts AAA through 
III of part 96 of this chapter and that is appealable under Sec. 
78.1(a):
    (i) The CAIR designated representative for a unit or source, or the 
CAIR authorized account representative for any CAIR SO2 
Allowance Tracking System account, covered by the decision; or
    (ii) Any interested person with regard to the decision.
    (6) The following persons may petition for administrative review of 
a decision of the Administrator that is made under subparts AAAA through 
IIII of part 96 of this chapter and that is appealable under Sec. 
78.1(a):
    (i) The CAIR designated representative for a unit or source, or the 
CAIR authorized account representative for any CAIR Ozone Season 
NOX Allowance Tracking System account, covered by the 
decision; or
    (ii) Any interested person with regard to the decision.
    (7) The following persons may petition for administrative review of 
a decision of the Administrator that is made under subparts AA through 
II of

[[Page 497]]

part 97 of this chapter and that is appealable under Sec. 78.1(a):
    (i) The CAIR designated representative for a unit or source, or the 
CAIR authorized account representative for any CAIR NOX 
Allowance Tracking System account, covered by the decision; or
    (ii) Any interested person with regard to the decision.
    (8) The following persons may petition for administrative review of 
a decision of the Administrator that is made under subparts AAA through 
III of part 97 and that is appealable under Sec. 78.1(a):
    (i) The CAIR designated representative for a unit or source, or the 
CAIR authorized account representative for any CAIR SO2 
Allowance Tracking System account, covered by the decision; or
    (ii) Any interested person with regard to the decision.
    (9) The following persons may petition for administrative review of 
a decision of the Administrator that is made under subparts AAAA through 
III of part 97 and that is appealable under Sec. 78.1(a):
    (i) The CAIR designated representative for a unit or source, or the 
CAIR authorized account representative for any CAIR Ozone Season 
NOX Allowance Tracking System account, covered by the 
decision; or
    (ii) Any interested person with regard to the decision.
    (10) The following persons may petition for administrative review of 
a decision of the Administrator that is made under subparts AAAAA, 
BBBBB, CCCCC, and DDDDD of part 97 of this chapter:
    (i) The designated representative for a unit or source, or the 
authorized account representative for any Allowance Management System 
account, covered by the decision; or
    (ii) Any interested person with regard to the decision.
    (11) The following persons may petition for administrative review of 
a decision of the Administrator that is made under subpart RR of part 98 
of this chapter:
    (i) The owner or operator of a facility covered by the decision.
    (ii) Any interested person with regard to the decision.
    (b)(1) Within 30 days following issuance of a decision under Sec. 
78.1 of this part by the Administrator, any person under paragraph (a) 
of this section may file a petition with the Environmental Appeals Board 
for administrative review of the decision. If no petition for 
administrative review of a decision under Sec. 78.1 of this part is 
filed within such period, the decision shall become final agency action 
and shall not meet the prerequisite for judicial review under Sec. 
78.1(a)(2).
    (2) The petition may include a request for an evidentiary hearing to 
resolve any disputed issue of material fact concerning the decision.
    (3) At the same time that the petition for administrative review is 
filed, the petitioner shall:
    (i) Serve a copy of the petition on the designated representative or 
authorized account representative under paragraph (a)(1), (2), and (10), 
and (a)(11) of this section (unless the designated representative or 
authorized account representative is the petitioner) or the 
NOX authorized account representative under paragraph (a)(3) 
of this section (unless the NOX authorized account 
representative is the petitioner) or the CAIR designated representative 
or CAIR authorized account representative under paragraph (a)(4), (5), 
(6), (7), (8), or (9) of this section (unless the CAIR designated 
representative or CAIR authorized account representative is the 
petitioner) and the Administrator; and
    (ii) Mail a notice of the petition to the air pollution control 
agencies of affected States and any interested person.
    (c) The petition for administrative review under this part shall 
state with specificity:
    (1) Each material factual and legal issue alleged to be in dispute 
and any such factual issue for which an evidentiary hearing is sought;
    (2) A clear and concise statement of the nature and scope of the 
interest of the petitioner;
    (3) A clear and concise brief in support of the petition, explaining 
why the factual or legal issues are material

[[Page 498]]

and, if an evidentiary hearing is requested, why direct and cross-
examination of witnesses is necessary to resolve such factual issues;
    (4) If an evidentiary hearing is requested, the time estimated to be 
necessary for an evidentiary hearing;
    (5) If an evidentiary hearing is requested, a certified statement 
that, in the event of an evidentiary hearing, and without cost or 
expense to any other party, any of the following persons shall be 
available to appear and testify:
    (i) The petitioner; and
    (ii) Any officer, director, employee, consultant, or agent of the 
petitioner.
    (6) Specific references to the contested portions of the decision; 
and
    (7) Any revised or alternative action of the Administrator sought by 
the petitioner as necessary to implement the requirements, purposes, or 
policies of title IV of the Act, subparts AA through II of part 96 of 
this chapter, subparts AAA through III of part 96 of this chapter, 
subparts AAAA through IIII of part 96 of this chapter, or part 97 of 
this chapter, as appropriate.
    (d) In no event shall a petition for administrative review be filed, 
or review be available under this part, with regard to:
    (1) Any provision or requirement of part 72, 73, 74, 75, 76, or 77 
of this chapter, including any standard requirement under Sec. 72.9 of 
this chapter and any emissions monitoring or reporting requirements 
under part 75 of this chapter;
    (2) Any provision or requirement of part 97 of this chapter, 
including the standard requirements under Sec. 97.6 of this chapter and 
any emission monitoring or reporting requirements under part 97 of this 
chapter.
    (3) The reliance by the Administrator on a certificate of 
representation submitted by a designated representative or a 
certification statement submitted by an authorized account 
representative under the Acid Rain Program or on an account certificate 
of representation submitted by a NOX authorized account 
representative or an application for a general account submitted by a 
NOX authorized account representative under the 
NOX Budget Trading Program or on an certificate of 
representation submitted by a CAIR designated representative or an 
application for a general account submitted by a CAIR authorized account 
representative under subparts AA through II, subparts AAA through III, 
subparts AAAA through IIII of part 96 of this chapter or under part 97 
of this chapter; and
    (4) Actions of the Administrator under sections 112(r), 113, 114, 
120, 301, and 303 of the Act.
    (5) Any provision or requirement of subparts AA through II of part 
96 of this chapter, including the standard requirements under Sec. 
96.106 of this chapter and any emission monitoring or reporting 
requirements.
    (6) Any provision or requirement of subparts AAA through III of part 
96 of this chapter, including the standard requirements under Sec. 
96.206 of this chapter and any emission monitoring or reporting 
requirements.
    (7) Any provision or requirement of subparts AAAA through IIII of 
part 96 of this chapter, including the standard requirements under Sec. 
96.306 of this chapter and any emission monitoring or reporting 
requirements.
    (8) Any provision or requirement of subparts AA through II of part 
97 of this chapter, including the standard requirements under Sec. 
97.106 of this chapter and any emission monitoring or reporting 
requirements.
    (9) Any provision or requirement of subparts AAA through III of part 
97 of this chapter, including the standard requirements under Sec. 
97.206 of this chapter and any emission monitoring or reporting 
requirements.
    (10) Any provision or requirement of subparts AAAA through IIII of 
part 97 of this chapter, including the standard requirements under Sec. 
97.306 of this chapter and any emission monitoring or reporting 
requirements.
    (11) Any provision or requirement of subparts AAAAA, BBBBB, CCCCC, 
or DDDDD of part 97 of this chapter, including the standard requirements 
under Sec. 97.406, Sec. 97.506, Sec. 97.606, or Sec. 97.706 of this 
chapter and any emission monitoring or reporting requirements.

[[Page 499]]

    (12) Any provision or requirement of subpart RR of part 98 of this 
chapter.

[58 FR 3760, Jan. 11, 1993, as amended at 60 FR 17132, Apr. 4, 1995; 62 
FR 55488, Oct. 24, 1997; 69 FR 21645, Apr. 21, 2004; 70 FR 25338, May 
12, 2005; 71 FR 25379, Apr. 28, 2006; 75 FR 75078, Dec. 1, 2010; 76 FR 
48379, Aug. 8, 2011]



Sec. 78.4  Filings.

    (a)(1) All original filings made under this part shall be signed by 
the person making the filing or by an attorney or authorized 
representative, in accordance with the following requirements:
    (i) Any filings on behalf of owners and operators of a affected unit 
or affected source, TR NOX Annual unit or TR NOX 
Annual source, TR NOX Ozone Season unit or TR NOX 
Ozone Season source, TR SO2 Group 1 unit or TR SO2 
Group 1 source, TR SO2 Group 2 unit or TR SO2 
Group 2 source, or a unit for which a TR opt-in application is submitted 
and not withdrawn shall be signed by the designated representative. Any 
filing on behalf of persons with an ownership interest with respect to 
allowances, TR NOX Annual allowances, TR NOX Ozone 
Season allowances, TR SO2 Group 1 allowances, or TR 
SO2 Group 2 allowances in a general account shall be signed 
by the authorized account representative.
    (ii) Any filings on behalf of owners and operators of a 
NOX Budget unit or NOX Budget source shall be 
signed by the NOX authorized account representative. Any 
filing on behalf of persons with an ownership interest with respect to 
NOX allowances in a general account shall be signed by the 
NOX authorized account representative.
    (iii) Any filings on behalf of owners and operators of a CAIR 
NOX, SO2, or NOX Ozone Season unit or 
source shall be signed by the CAIR designated representative. Any 
filings on behalf of persons with an ownership interest with respect to 
CAIR NOX allowances, CAIR SO2 allowances, or CAIR 
NOX Ozone Season allowances in a general account shall be 
signed by the CAIR authorized account representative.
    (iv) Any filings on behalf of owners and operators of a facility 
covered by subpart RR of part 98 of this chapter shall be signed by the 
designated representative.
    (2) The name, address, e-mail address (if any), telephone number, 
and facsimile number (if any) of the person making the filing shall be 
provided with the filing.
    (b)(1) All data and information referred to, or in any way relied 
upon, in any filings made under this part shall be included in full and 
may not be incorporated by reference, unless the data or information is 
contained in the administrative record for the decision being appealed.
    (2) Notwithstanding paragraph (b)(1) of this section, State or 
Federal statutes, regulations, and judicial decisions published in a 
national reporter system, officially issued EPA documents of general 
applicability, and any other publicly and generally available reference 
material may be incorporated by reference. Any person incorporating such 
materials by reference shall provide copies of the materials as 
instructed by the Environmental Appeals Board or the Presiding Officer.
    (3) If any part of any filing is in a foreign language, it shall be 
accompanied by an English translation verified by the person making the 
translation, under oath, to be complete and accurate, together with the 
name, address, and a brief statement of the qualifications of the person 
making the translation. Translations filed of material originally 
produced in a foreign language shall be accompanied by copies of the 
original material.
    (4) Where relevant data or information is contained in a document 
also containing irrelevant matter, either the irrelevant matter shall be 
deleted or an index to the relevant portions of the document shall be 
included in the document.
    (c)(1) Failure to comply with the requirements of this section or 
any other requirement in this part may result in the noncomplying 
portions of the filing being excluded from consideration. If the 
Environmental Appeals Board or the Presiding Officer determines on 
motion by any party or sua sponte that a filing fails to meet any 
requirement of this part, the Environmental Appeals Board or Presiding 
Officer may return the filing, together with a reference to the 
applicable requirements on which the determination is based. A

[[Page 500]]

person whose filing has been rejected has 7 days (or other reasonable 
period established by the Environmental Appeals Board or Presiding 
Officer), from the date the returned filing is mailed, to correct the 
filing in conformance with this part and refile it.
    (2) The making of a filing shall not mean or imply that the filing, 
in fact, meets all applicable requirements, that the filing contains 
reasonable grounds for the action requested, or that the action 
requested is in accordance with law.
    (d) An original and two copies of any written filing under this part 
shall be filed with the Environmental Appeals Board unless a proceeding 
is pending before a Presiding Officer, in which case they shall be filed 
with the Hearing Clerk (except as provided under Sec. 78.19(d)) of this 
part.
    (e)(1) The party making any filing in a proceeding under this part 
shall also serve a copy of the filing on each party to the proceeding, 
or, with regard to a petition for administrative review, on the persons 
specified in Sec. 78.3(b)(3) of this part.
    (2) Every filing made under this part shall be accompanied by a 
certificate of service citing the date, place, time, and manner of 
service and the names of the persons served.
    (f) The Hearing Clerk will maintain and furnish, to any person upon 
request, the official service list containing the name, service address, 
telephone, and facsimile numbers of each party to a proceeding under 
this part and his or her attorney or duly authorized representative.
    (g) Affidavits filed under this part shall be made on personal 
knowledge and belief, set forth only those facts that are admissible 
into evidence under Sec. 78.5 of this part, and show affirmatively that 
the affiant is competent to testify to the matters stated therein.

[58 FR 3760, Jan. 11, 1993, as amended at 62 FR 55488, Oct. 24, 1997; 62 
FR 66279, Dec. 18, 1997; 69 FR 21645, Apr. 21, 2004; 70 FR 25339, May 
12, 2005; 75 FR 75078, Dec. 1, 2010; 76 FR 48379, Aug. 8, 2011]



Sec. 78.5  Limitation on filing or presenting new evidence and raising
new issues.

    (a) Where there was an opportunity for submission of public comments 
or objections prior to the decision that is subject to appeal, no 
evidence shall be filed or presented, and no issues raised, in a 
proceeding under this part that were not filed, presented, or raised 
during the period for submission of public comments or objections, 
absent a showing of good cause explaining the party's failure to do so 
during the period for submission of public comments or objections. Good 
cause shall include any instance where the party seeking to file or 
present new evidence or raise a new issue shows that the evidence could 
not have reasonably been ascertained, filed, or presented, the issue 
could not have reasonably been ascertained or raised, or that the 
materiality of the new evidence or issue could not have reasonably been 
anticipated, prior to the close of the period for submission of public 
comments or objections.
    (b) If an evidentiary hearing is granted, no evidence shall be filed 
or presented on questions of law or policy or on matters not subject to 
challenge in the evidentiary hearing.

[58 FR 3760, Jan. 11, 1993, as amended at 62 FR 55488, Oct. 24, 1997; 70 
FR 25339, May 12, 2005; 76 FR 48379, Aug. 8, 2011]



Sec. 78.6  Action on petition for administrative review.

    (a) If no evidentiary hearing concerning the petition for review is 
requested or is to be held, the Environmental Appeals Board will issue 
an order under Sec. 78.20(c) of this part.
    (b)(1) The Environmental Appeals Board may grant a request for an 
evidentiary hearing, or schedule an evidentiary hearing sua sponte, if 
the Environmental Appeals Board finds that there are disputed issues of 
fact material to contested portions of the decision and determines, in 
its discretion, that an opportunity for direct- and cross-examination of 
witnesses may be necessary in order to resolve these factual issues.
    (2) To the extent the Environmental Appeals Board grants a request 
for an

[[Page 501]]

evidentiary hearing, in whole or in part, it will:
    (i) Identify the portions of the decision that have been contested, 
and the disputed factual issues that have been raised by the petitioner 
with regard to which the evidentiary hearing has been granted; and
    (ii) Refer the disputed factual issues to the Chief Administrative 
Law Judge for decision and, in its discretion, may also refer all or a 
portion of the remaining legal, policy, or factual issues to the Chief 
Administrative Law Judge for decision.
    (3)(i) After issues are referred to the Chief Administrative Law 
Judge, he or she will designate an Administrative Law Judge as Presiding 
Officer to conduct the evidentiary hearing.
    (ii) Notwithstanding paragraph (b)(3)(i) of this section, if all 
parties waive in writing their right to have an Administrative Law Judge 
designated as the Presiding Officer, the Administrator may designate a 
lawyer permanently or temporarily employed by EPA and without any prior 
connection with the proceeding to serve as Presiding Officer.



Sec. 78.7  [Reserved]



Sec. 78.8  Consolidation and severance of appeals proceedings.

    (a) The Environmental Appeals Board or Presiding Officer has the 
discretion to consolidate, in whole or in part, two or more proceedings 
under this part whenever it appears that a joint proceeding on any or 
all of the matters at issue in the proceedings will be in the interest 
of justice, will expedite or simplify consideration of the issues, and 
will not prejudice any party. Consolidation of proceedings under this 
paragraph (a) will not affect the right of any party to raise issues 
that might have been raised had there been no consolidation.
    (b) The Environmental Appeals Board or Presiding Officer has the 
discretion to sever issues or parties from a proceeding under this part 
whenever it appears that separate proceedings will be in the interest of 
justice, will expedite or simplify consideration of the issues, and will 
not prejudice any party.



Sec. 78.9  Notice of the filing of petition for administrative review.

    The Administrator will publish in the Federal Register a notice 
stating that a petition for administrative review of a decision of the 
Administrator has been filed and specifying any request in the petition 
for an evidentiary hearing.



Sec. 78.10  Ex parte communications during pendency of a hearing.

    (a)(1) No party or interested person outside EPA, representative of 
a party or interested person, or member of the EPA trial staff shall 
make, or knowingly cause to be made, to any member of the decisional 
body an ex parte communication on the merits of a proceeding under this 
part.
    (2) No member of the decisional body shall make, or knowingly cause 
to be made, to any party or interested person outside EPA, 
representative of a party or interested person, or member of the EPA 
trial staff, an ex parte communication on the merits of any proceeding 
under this part.
    (3) A member of the decisional body who receives, makes, or 
knowingly causes to be made an ex parte communication prohibited by this 
paragraph shall file with the Environmental Appeals Board (or, if the 
proceeding is pending before an Administrative Law Judge, with the 
Hearing Clerk) for inclusion in the record of the proceeding under this 
part any such written ex parte communications and memoranda stating the 
substance of any such oral ex parte communication.
    (b) Whenever any member of the decisional body receives an ex parte 
communication made, or knowingly caused to be made by a party or 
representative of a party to a proceeding under this part, the person 
presiding over the proceedings then in progress may, to the extent 
consistent with justice, require the party to show good cause why its 
claim or interest in the proceedings should not be dismissed, denied, 
disregarded, or otherwise adversely affected on account of these ex 
parte communications.
    (c) The prohibitions of paragraph (a) of this section shall begin to 
apply upon publication by the Administrator of the notice of the filing 
of a petition

[[Page 502]]

under Sec. 78.9 of this part. This prohibition terminates on the date 
of final agency action.



Sec. 78.11  Intervenors.

    (a) Within 30 days (or other shorter, reasonable period established 
by the Administrator when giving notice) after notice is given under 
Sec. 78.9 of this part that the petition for administrative review has 
been filed, any person listed in Sec. 78.3(a) of this part may file a 
motion for leave to intervene in the proceeding. A motion for leave to 
intervene under this section shall set forth the grounds for the 
proposed intervention and may respond to the petition for administrative 
review. Late motions to intervene may be granted only for good cause 
shown.
    (b) The Environmental Appeals Board of Presiding Officer will grant 
a motion to intervene only upon an express finding that:
    (1) The motion to intervene raises matters relevant to the factual 
or legal issues to be reviewed;
    (2) The intervenor consented to be bound by all stipulations 
previously entered into by the existing parties, and all orders 
previously issued, in the proceeding; and
    (3) The intervention will promote the interests of justice and will 
not cause undue delay or prejudice to the rights of the existing 
parties.

[58 FR 3760, Jan. 11, 1993, as amended at 62 FR 55488, Oct. 24, 1997]



Sec. 78.12  Standard of review.

    (a) On appeal of a decision of the Administrator prior to which 
there was an opportunity for submission of public comments or 
objections:
    (1) Except as provided under paragraph (a)(2) of this section, the 
petitioner shall have the burden of going forward and of persuasion to 
show that a finding of fact or conclusion of law underlying the decision 
is clearly erroneous or that an exercise of discretion or policy 
determination underlying the decision is arbitrary and capricious or 
otherwise warrants review.
    (2) The owners and operators of the source or unit involved shall 
have the burden of persuasion that an Acid Rain permit NOX 
Budget permit, CAIR permit, or other federally enforceable permit was 
properly issued or should be issued.
    (b) On appeal of a decision of the Administrator not covered by 
paragraph (a) of this section, the Administrator shall have the burden 
of going forward to show the rational basis for the decision. The 
petitioner shall have the burden of persuasion to show that a finding of 
fact or conclusion of law underlying the decision is clearly erroneous 
or that an exercise of discretion or policy determination underlying the 
decision is arbitrary and capricious or otherwise warrants review.

[58 FR 3760, Jan. 11, 1993, as amended at 62 FR 55488, Oct. 24, 1997; 66 
FR 12978, Mar. 1, 2001; 69 FR 21645, Apr. 21, 2004; 70 FR 25339, May 12, 
2005; 76 FR 48379, Aug. 8, 2011]



Sec. 78.13  Scheduling orders and pre-hearing conferences.

    (a) If a request for an evidentiary hearing is granted, the 
Presiding Officer will issue an order scheduling the following:
    (1) The filing by each party of a narrative statement of position on 
each factual issue in controversy.
    (2) The identification of any witness that a party expects to call 
and of any written testimony, documents, papers, exhibits, or other 
materials that a party expects to introduce into evidence. At the 
request of the Presiding Officer, the party shall include a brief 
narrative summary of any witness' expected testimony and of any such 
materials.
    (3) The filing of written testimony, in accordance with Sec. 
78.14(b) of this part, and other evidence in support of a narrative 
statement.
    (4) The filing of any motions by any party, including motions for 
the production of documentation, data, or other information material to 
the disputed facts to be addressed at the hearing.
    (b) The Presiding Officer may, on motion or sua sponte, schedule one 
or more pre-hearing conferences on the record to address any of the 
following:
    (1) Simplification, clarification, amplification, or limitation of 
the issues.
    (2) Admissions and stipulations of facts and determinations of the 
genuineness of documents.

[[Page 503]]

    (3) Objections to the introduction into evidence at the hearing of 
any written testimony or other submissions proposed by a party; provided 
that at any time before the end of the hearing, any party may make, and 
the Presiding Officer may consider and rule upon, a motion to strike 
testimony or other evidence (other than evidence included in the 
administrative record (if any) under Sec. 72.63 of this chapter) on the 
grounds of relevance, competency, or materiality.
    (4) Taking official notice of any matters.
    (5) Grouping of parties with substantially similar interests to 
eliminate redundant evidence, motions, objections, and briefs.
    (6) Such other matters that may expedite the hearing or aid in the 
disposition of matters in dispute.
    (c) The Presiding Officer will issue an order (which may be in the 
form of a transcript) reciting the actions taken at any pre-hearing 
conferences, setting the schedule for any hearing, and stating any areas 
of factual and legal agreement and disagreement and the methods and 
procedures to be used in developing any evidence.

[58 FR 3760, Jan. 11, 1993, as amended at 70 FR 25339, May 12, 2005]



Sec. 78.14  Evidentiary hearing procedure.

    (a) If a request for an evidentiary hearing is granted, the 
Presiding Officer will conduct a fair and impartial hearing on the 
record, take action to avoid unnecessary delay in the disposition of the 
proceedings, and maintain order. For these purposes, the Presiding 
Officer may:
    (1) Administer oaths and affirmations.
    (2) Regulate the course of the hearings and prehearing conferences 
and govern the conduct of participants.
    (3) Examine witnesses.
    (4) Identify and refer issues for interlocutory decision under Sec. 
78.19 of this part.
    (5) Rule on, admit, exclude, or limit evidence.
    (6) Establish the time for filing motions, testimony and other 
written evidence, and briefs and making other filings.
    (7) Rule on motions and other pending procedural matters, including 
but not limited to motions for summary disposition in accordance with 
Sec. 78.15 of this part.
    (8) Order that the hearing be conducted in stages whenever the 
number of parties is large or the issues are numerous and complex.
    (9) Allow direct and cross-examination of witnesses only to the 
extent the Presiding Officer determines that such direct and cross-
examination may be necessary to resolve disputed issues of material 
fact; provided that no direct or cross-examination shall be allowed on 
questions of law or policy or regarding matters that are not subject to 
challenge in the evidentiary hearing.
    (10) Limit public access to the hearing where necessary to protect 
confidential business information. The Presiding Officer will provide 
written notice of the hearing to the parties, and where the hearing will 
be open to the public, notice in the Federal Register no later than 15 
days (or other shorter, reasonable period established by the Presiding 
Officer) prior to commencement of the hearings.
    (11) Take any other action not inconsistent with the provisions of 
this part for the maintenance of order at the hearing and for the 
expeditious, fair and impartial conduct of the proceeding.
    (b) All direct and rebuttal testimony at an evidentiary hearing 
shall be filed in written form, unless, upon motion and good cause 
shown, the Presiding Officer, in his or her discretion, determines that 
oral presentation of such evidence on any particular factual issue will 
materially assist in the efficient resolution of the issue.
    (c)(1) The Presiding Officer will admit all evidence that is not 
irrelevant, immaterial, unduly repetitious, or otherwise unreliable or 
of little probative value. Evidence relating to settlement that would be 
excluded in the Federal courts under the Federal Rules of Evidence shall 
not be admissible.
    (2) Whenever any evidence or testimony is excluded by the Presiding 
Officer as inadmissible, all such evidence will remain a part of the 
record as an offer of proof. The party seeking the admission of oral 
testimony may make

[[Page 504]]

an offer of proof by means of a brief statement on the record describing 
the testimony excluded.
    (3) When two or more parties have substantially similar interests 
and positions, the Presiding Officer may limit the number of attorneys 
or authorized representatives who will be permitted to examine witnesses 
and to make and argue motions and objections on behalf of those parties.
    (4) Rulings of the Presiding Officer on the admissibility of 
evidence or testimony, the propriety of direct and cross-examination, 
and other procedural matters will appear in the record of the hearing 
and control further proceedings unless reversed by the Presiding Officer 
or as a result of an interlocutory appeal taken under Sec. 78.19 of 
this part.
    (5) All objections shall be made promptly or be deemed waived; 
provided that parties shall be presumed to have taken exception to an 
adverse ruling. No objection shall be deemed waived by further 
participation in the hearing.

[58 FR 3760, Jan. 11, 1993, as amended at 62 FR 55488, Oct. 24, 1997]



Sec. 78.15  Motions in evidentiary hearings.

    (a) Any party may make a motion to the Presiding Officer on any 
matter relating to the evidentiary hearing in accordance with the 
scheduling orders issued under Sec. 78.13 of this part. All motions 
shall be in writing and served as provided in Sec. 78.4 of this part, 
except those made on the record during an oral hearing before the 
Presiding Officer.
    (b) Any party may make a motion for a summary disposition in its 
favor on any factual issue on the basis that there is no genuine issue 
of material fact. When a motion for summary disposition is made and 
supported, any party opposing the motion may not rest upon mere 
allegations or denials, but must show, by affidavit or by other 
materials subject to consideration by the Presiding Officer, that there 
is a genuine issue of material fact.
    (c) Within 10 days (or other shorter, reasonable period established 
by the Presiding Officer) after a motion made on the record or service 
of any written motion, any party may file a response to the motion.
    (d) The Presiding Officer may schedule an oral argument and call for 
the filing of briefs on any motion. The Presiding Officer will rule on 
the motion within a reasonable time after the date that responses to the 
motion may be filed under paragraph (c) of this section and that any 
oral argument or filing of briefs is completed.
    (e) If all factual issues are decided by summary disposition prior 
to the hearing, no hearing will be held and the Presiding Officer will 
issue a proposed decision under Sec. 78.18 of this part. If a summary 
disposition is denied or if partial summary disposition is granted, the 
hearing shall proceed on the remaining issues.

[58 FR 3760, Jan. 11, 1993, as amended at 62 FR 55488, Oct. 24, 1997]



Sec. 78.16  Record of appeal proceeding.

    (a) The proposed decision issued by the Presiding Officer, 
transcripts of oral hearings or oral arguments, written direct and 
rebuttal testimony, and any other written materials of any kind filed in 
the proceeding will be part of the record and will be available to the 
public in the office of the Hearing Clerk, subject to the requirements 
of part 2 of this chapter.
    (b) Hearings and oral arguments shall be recorded as specified by 
the Presiding Officer, and thereupon transcribed. After the hearing or 
oral argument, the reporter will certify and file with the Hearing 
Clerk.
    (1) The original transcript; and
    (2) Any exhibits received or offered into evidence at the hearing.
    (c) The Hearing Clerk will promptly give written notice to the 
parties when any transcript is available. Any party that desires a copy 
of the transcript may obtain a copy upon payment of costs.
    (d) The Presiding Officer will allow witnesses, parties, and their 
counsel or representatives:
    (1) Up to 7 days (or other shorter, reasonable period established by 
the Presiding Officer) from issuance of the notice under paragraph (c) 
of this section in order to file written proposed corrections of the 
transcript necessary to

[[Page 505]]

correct errors made in the transcribing; and
    (2) Up to 7 days (or other shorter, reasonable period established by 
the Presiding Officer) from the submission of the corrections in order 
to file objections to the proposed corrections.
    (e) The Presiding Officer will determine which, if any, corrections 
should be made to the transcript and incorporate them into the record.

[58 FR 3760, Jan. 11, 1993, as amended at 62 FR 55488, Oct. 24, 1997]



Sec. 78.17  Proposed findings and conclusions and supporting brief.

    Within 45 days (or other shorter, reasonable period established by 
the Presiding Officer) after issuance of a notice under Sec. 78.16(c) 
of this part that the complete transcript of the evidentiary hearing is 
available, any party may file with the Hearing Clerk proposed findings 
and conclusions on the issues referred to the Presiding Officer and a 
brief in support thereof. Briefs shall contain appropriate references to 
the record. The Presiding Officer may allow reply briefs.

[58 FR 3760, Jan. 11, 1993, as amended at 62 FR 55488, Oct. 24, 1997]



Sec. 78.18  Proposed decision.

    (a) The Presiding Officer will review and evaluate the record, 
including the proposed findings and conclusions and any briefs filed by 
the parties, and issue a proposed decision on the factual, policy, and 
legal issues referred by the Environmental Appeals Board for decision 
under Sec. 78.6(b)(2)(ii) of this part, accompanied by findings of fact 
and proposed conclusions of law, as appropriate, within a reasonable 
time after the evidentiary hearing is completed. The Hearing Clerk will 
promptly serve copies of the proposed decision on all parties and on the 
Environmental Appeals Board.
    (b) The proposed decision of the Presiding Officer shall become the 
final agency action under section 307 of the Act unless:
    (1) A party files objections with the Environmental Appeals Board 
pursuant to Sec. 78.20(a) of this part, or
    (2) The Environmental Appeals Board sua sponte files a notice that 
it will review the decision under Sec. 78.20(b) of this part.

[58 FR 3760, Jan. 11, 1993, as amended at 62 FR 55488, Oct. 24, 1997]



Sec. 78.19  Interlocutory appeal.

    (a) Interlocutory appeal from orders or rulings of the Presiding 
Officer made during the course of a proceeding may be taken if the 
Presiding Officer certifies those orders or rulings to the Environmental 
Appeals Board for interlocutory appeal on the record. Any requests to 
the Presiding Officer to certify an interlocutory appeal shall be filed 
within 10 days of notice of the order or ruling and shall state briefly 
the grounds for the request.
    (b)(1) Within 15 days of the filing of any request for interlocutory 
appeal, the Presiding Officer may certify an order or ruling for 
interlocutory appeal to the Environmental Appeals Board if:
    (i) The order or ruling involves an important question on which 
there is substantial ground for difference of opinion, and
    (ii) Either:
    (A) An immediate appeal of the order or ruling will materially 
advance the ultimate completion of the proceeding, or
    (B) A review after the proceeding is completed will be inadequate or 
ineffective.
    (2) If the Presiding Officer takes no action within 15 days of the 
filing of a request for interlocutory appeal, the request shall be 
automatically dismissed without prejudice.
    (c) If the Presiding Officer grants certification, the Environmental 
Appeals Board may accept or decline the interlocutory appeal within 30 
days of certification. If the Environmental Appeals Board decides that 
certification was improperly granted, it will decline to hear the 
interlocutory appeal. If the Environmental Appeals Board takes no action 
within 30 days of certification, the interlocutory appeal shall be 
automatically dismissed without prejudice.
    (d) If the Presiding Officer declines to certify an order or ruling 
for an interlocutory appeal, the order or ruling may be reviewed by the 
Environmental Appeals Board only upon an appeal of the proposed decision 
following completion of the proceedings before the

[[Page 506]]

Presiding Officer, except when the Environmental Appeals Board 
determines, upon motion of a party and in exceptional circumstances, 
that to delay review would not be in the public interest. Such motion 
shall be filed with Environmental Appeals Board within 5 days after the 
earlier of automatic dismissal of the request for interlocutory appeal 
or receipt by the party of notification that the Presiding Officer 
declines to certify an order or ruling for interlocutory appeal.
    (e) The failure of a party to request an interlocutory appeal shall 
not prevent an appeal of an order or ruling as part of an appeal of a 
proposed decision under Sec. 78.20 of this part.



Sec. 78.20  Appeal of decision of Administrator or proposed decision 
to the Environmental Appeals Board.

    (a) Within 30 days after the issuance of a proposed decision by a 
Presiding Officer under this part, any party may appeal any matter set 
forth in the proposed decision, or any other order or ruling made during 
the proceeding to which the party objected during the proceeding before 
the Presiding Officer, by filing an objection with the Environmental 
Appeals Board. On appeal of an order, ruling, or proposed decision of a 
Presiding Officer:
    (1) The party filing the objection shall have the burden of going 
forward to show that the order, ruling, or proposed decision is based on 
a finding of fact or conclusion of law that is clearly erroneous; or a 
policy determination or exercise of discretion that is arbitrary and 
capricious or otherwise warrants review; and
    (2) The petitioner or the owners and operators shall have the burden 
of persuasion, as set forth in Sec. 78.12(a) (1) and (2) of this part.
    (b) Within 45 days (or other shorter, reasonable period established 
by the Environmental Appeals Board) after issuance of a proposed 
decision of a Presiding Officer, the Environmental Appeals Board may 
issue sua sponte in its discretion a notice of intent to review such 
proposed decision. The Environmental Appeals Board will serve such 
notice upon all parties to the proceeding.
    (c) Within a reasonable time following the filing of a petition for 
administrative review of a decision of the Administrator under Sec. 
78.3 of this part, or, if any issues raised by such petition are 
referred to the Presiding Officer, the filing of objections under 
paragraph (a) of this section or the issuance of a notice of intent to 
review under paragraph (b) of this section, the Environmental Appeals 
Board will issue an order affirming, reversing, modifying, or remanding 
the decision or proposed decision, as appropriate. Prior to issuing this 
order, the Environmental Appeals Board may provide an opportunity for 
parties to file additional briefs.
    (d) If the Environmental Appeals Board issues an order affirming, 
reversing, or modifying the decision of the Administrator, then the 
decision as supplemented or changed by the order, shall be final agency 
action.
    (e) If the Environmental Appeals Board issues an order affirming, 
reversing, or modifying the proposed decision, the proposed decision, as 
supplemented or changed by the order, shall be final agency action.
    (f) If the Environmental Appeals Board issues an order remanding the 
proceeding, then final agency action occurs upon completion of the 
remanded proceeding, including any appeals to the Environmental Appeals 
Board in the remanded proceeding.

[58 FR 3760, Jan. 11, 1993, as amended at 62 FR 55488, Oct. 24, 1997]



PART 79_REGISTRATION OF FUELS AND FUEL ADDITIVES--Table of Contents



                      Subpart A_General Provisions

Sec.
79.1 Applicability.
79.2 Definitions.
79.3 Availability of information.
79.4 Requirement of registration.
79.5 Periodic reporting requirements.
79.6 Requirement for testing.
79.7 Samples for test purposes.
79.8 Penalties.

                 Subpart B_Fuel Registration Procedures

79.10 Application for registration by fuel manufacturer.
79.11 Information and assurances to be provided by the fuel 
          manufacturer.

[[Page 507]]

79.12 Determination of noncompliance.
79.13 Registration.
79.14 Termination of registration of fuels.

               Subpart C_Additive Registration Procedures

79.20 Application for registration by additive manufacturer.
79.21 Information and assurances to be provided by the additive 
          manufacturer.
79.22 Determination of noncompliance.
79.23 Registration.
79.24 Termination of registration of additives.

              Subpart D_Designation of Fuels and Additives

79.30 Scope.
79.31 Additives.
79.32 Motor vehicle gasoline.
79.33 Motor vehicle diesel fuel.

Subpart E [Reserved]

             Subpart F_Testing Requirements for Registration

79.50 Definitions.
79.51 General requirements and provisions.
79.52 Tier 1.
79.53 Tier 2.
79.54 Tier 3.
79.55 Base fuel specifications.
79.56 Fuel and fuel additive grouping system.
79.57 Emission generation.
79.58 Special provisions.
79.59 Reporting requirements.
79.60 Good laboratory practices (GLP) standards for inhalation exposure 
          health effects testing.
79.61 Vehicle emissions inhalation exposure guideline.
79.62 Subchronic toxicity study with specific health effect assessments.
79.63 Fertility assessment/teratology.
79.64 In vivo micronucleus assay.
79.65 In vivo sister chromatid exchange assay.
79.66 Neuropathology assessment.
79.67 Glial fibrillary acidic protein assay.
79.68 Salmonella typhimurium reverse mutation assay.

    Authority: 42 U.S.C. 7414, 7524, 7545 and 7601.

    Source: 40 FR 52011, Nov. 7, 1975, unless otherwise noted.



                      Subpart A_General Provisions



Sec. 79.1  Applicability.

    The regulations of this part apply to the registration of fuels and 
fuel additives designated by the Administrator, pursuant to section 211 
of the Clean Air Act (42 U.S.C. 1857f-6c, as amended by section 9, Pub. 
L. 91-604).



Sec. 79.2  Definitions.

    As used in this part, all terms not defined herein shall have the 
meaning given them in the Act:
    (a) Act means the Clean Air Act (42 U.S.C. 1857 et seq., as amended 
by Pub. L. 91-604).
    (b) Administrator means the Administrator of the Environmental 
Protection Agency.
    (c) Fuel means any material which is capable of releasing energy or 
power by combustion or other chemical or physical reaction.
    (d) Fuel manufacturer means any person who, for sale or introduction 
into commerce, produces, manufactures, or imports a fuel or causes or 
directs the alteration of the chemical composition of a bulk fuel, or 
the mixture of chemical compounds in a bulk fuel, by adding to it an 
additive, except:
    (1) A party (other than a fuel refiner or importer) who adds a 
quantity of additive(s) amounting to less than 1.0 percent by volume of 
the resultant additive(s)/fuel mixture is not thereby considered a fuel 
manufacturer.
    (2) A party (other than a fuel refiner or importer) who adds an 
oxygenate compound to fuel in any otherwise allowable amount is not 
thereby considered a fuel manufacturer.
    (e) Additive means any substance, other than one composed solely of 
carbon and/or hydrogen, that is intentionally added to a fuel named in 
the designation (including any added to a motor vehicle's fuel system) 
and that is not intentionally removed prior to sale or use.
    (f) Additive manufacturer means any person who produces, 
manufactures, or imports an additive for use as an additive and/or sells 
or imports for sale such additive under the person's own name.
    (g) Range of concentration means the highest concentration, the 
lowest concentration, and the average concentration of an additive in a 
fuel.
    (h) Chemical composition means the name and percentage by weight of 
each compound in an additive and the name

[[Page 508]]

and percentage by weight of each element in an additive.
    (i) Chemical structure means the molecular structure of a compound 
in an additive.
    (j) Impurity means any chemical element present in an additive that 
is not included in the chemical formula or identified in the breakdown 
by element in the chemical composition of such additive.
    (k) Oxygenate compound means an oxygen-containing, ashless organic 
compound, such as an alcohol or ether, which may be used as a fuel or 
fuel additive.

[40 FR 52011, Nov. 7, 1975, as amended at 59 FR 33092, June 27, 1994; 62 
FR 12571, Mar. 17, 1997]



Sec. 79.3  Availability of information.

    The availability to the public of information provided to, or 
otherwise obtained by, the Administrator under this part shall be 
governed by part 2 of this chapter except as expressly noted in subpart 
F of this part.

[59 FR 33092, June 27, 1994]



Sec. 79.4  Requirement of registration.

    (a) Fuels. (1) No manufacturer of any fuel designated under this 
part shall, after the date prescribed for such fuel in this part, sell, 
offer for sale, or introduce into commerce such fuel unless the 
Administrator has registered such fuel.
    (2) No manufacturer of a registered fuel shall add or direct the 
addition to it of an additive which he has not previously reported 
unless he has notified the Administrator of such intended use, including 
the expected or estimated range of concentration. If necessary to meet 
an unforeseen production problem, however, a fuel manufacturer may use 
an additive that he has not previously reported provided that (i) the 
additive is on the current list of registered additives and (ii) the 
fuel manufacturer notifies the Administrator within 30 days regarding 
such unforeseen use and his plans regarding continued use, including the 
expected or estimated range of concentration.
    (3) Any designated fuel that is (i) in a research, development, or 
test status; (ii) sold to automobile, engine, or component manufacturers 
for research, development, or test purposes; or (iii) sold to automobile 
manufacturers for factory fill, and is not in any case offered for 
commercial sale to the public, shall be exempt from registration.
    (4) A domestic fuel manufacturer may purchase and offer for 
commercial sale foreign-produced fuel containing unidentified additives 
provided that within 30 days of his offer for sale he notifies the 
Administrator of the purchase, the source of purchase, the quantity 
purchased, and summarized results of any tests performed to determine 
the acceptability of the purchased fuel to the fuel manufacturer.
    (b) Additives. (1) No manufacturer of any fuel additive designated 
under this part shall, after the date by which the additive must be 
registered under this part, sell, offer for sale, or introduce into 
commerce such additive for use in any type of fuel designated under this 
part unless the Administrator has registered that additive for use in 
that type of fuel.
    (2) Any designated additive that is either (i) in a research, 
development, or test status or (ii) sold to petroleum, automobile, 
engine, or component manufacturers for research, development, or test 
purposes, and in either case is not offered for commercial sale to the 
public, shall be exempt from registration.
    (3) Process chemicals used by refineries during the refinery process 
are exempted from the requirement for registration.
    (4) If an additive manufacturer prepares for sale only to fuel 
manufacturers (i) a blend or mixture of two or more registered additives 
or (ii) a blend or mixture of one or more registered additives with one 
or more substances containing only carbon and/or hydrogen, he will not 
be required to register such blend or mixture provided he will, upon 
request, furnish the Administrator with the names and percentages by 
weight of all components of such blend or mixture.

[40 FR 52011, Nov. 7, 1975, as amended at 41 FR 21324, May 25, 1976; 59 
FR 33092, June 27, 1994]

[[Page 509]]



Sec. 79.5  Periodic reporting requirements.

    (a) Fuel manufacturers. (1) For each calendar quarter (January 
through March, April through June, July through September, October 
through December) commencing after the date prescribed for a particular 
fuel in subpart D of this part, fuel manufacturers shall submit to the 
Administrator a report for each registered fuel showing the range of 
concentration of each additive reported under Sec. 79.11(a) and the 
volume of such fuel produced in the quarter. Reports shall be submitted 
by the required deadline as shown in the following table:

                              Table 1 to Sec. 79.5--Quarterly Reporting Deadlines
----------------------------------------------------------------------------------------------------------------
          Calendar quarter                   Time period covered                Quartely report deadline
----------------------------------------------------------------------------------------------------------------
Quarter 1...........................  January 1-March 31..............  June 1.
Quarter 2...........................  April 1-June 30.................  September 1.
Quarter 3...........................  July 1-September 30.............  December 1.
Quarter 4...........................  October 1-December 31...........  March 31.
----------------------------------------------------------------------------------------------------------------

    (2) Fuel manufacturers shall submit to the Administrator a report 
annually for each registered fuel providing additional data and 
information as specified in Sec. Sec. 79.32(c) and (d) and 79.33(c) and 
(d) in the designation of the fuel in subpart D of this part. Reports 
shall be submitted by March 31 for the preceding year, or part thereof, 
on forms supplied by the Administrator upon request. If the date 
prescribed for a particular fuel in subpart D of this part, or the later 
registration of a fuel is between October 1 and December 31, no report 
will be required for the period to the end of that year.
    (b) Additive manufacturers. Additive manufacturers shall submit to 
the Administrator a report annually for each registered additive 
providing additional data and information as specified in Sec. 79.31(c) 
and (d) in the designation of the additive in subpart D of this part. 
Additive manufacturers shall also report annually the volume of each 
additive produced. Reports shall be submitted by March 31 for the 
preceding year, or part thereof, on forms supplied by the Administrator 
upon request. If the date prescribed for a particular additive in 
subpart D of this part, or the later registration of an additive is 
between October 1 and December 31, no report will be required for the 
period to the end of that year. These periodic reports shall not, 
however, be required for any additive that is:
    (1) An additive registered under another name,
    (2) A blend or mixture of two or more registered additives, or
    (3) A blend or mixture of one or more registered additives with one 
or more substances containing only carbon and/or hydrogen.

[40 FR 52011, Nov. 7, 1975, as amended at 79 FR 23630, Apr. 28, 2014



Sec. 79.6  Requirement for testing.

    Provisions regarding testing that is required for registration of a 
designated fuel or fuel additive are contained in subpart F of this 
part.

[59 FR 33092, June 27, 1994]



Sec. 79.7  Samples for test purposes.

    When the Administrator requires for test purposes a fuel or additive 
which is not readily available in the open market, he may request the 
manufacturer of such fuel or additive to furnish a sample in a 
reasonable quantity. The fuel or additive manufacturer shall comply with 
such request within 30 days.



Sec. 79.8  Penalties.

    Any person who violates section 211(a) of the Act or who fails to 
furnish any information or conduct any tests required under this part 
shall be liable to the United States for a civil penalty of not more 
than the sum of $25,000 for every day of such violation and the amount 
of economic benefit or savings resulting from the violation. Civil 
penalties shall be assessed in accordance with paragraphs (b) and (c) of 
section 205 of the Act.

[58 FR 65554, Dec. 15, 1993]

[[Page 510]]



                 Subpart B_Fuel Registration Procedures



Sec. 79.10  Application for registration by fuel manufacturer.

    Any manufacturer of a designated fuel who wishes to register that 
fuel shall submit an application for registration including all of the 
information set forth in Sec. 79.11. If the manufacturer produces more 
than one grade or brand of a designated fuel, a manufacturer may include 
more than one grade or brand in a single application, provided that the 
application includes all information required for registration of each 
such grade or brand by this part. Each application shall be signed by 
the fuel manufacturer and shall be submitted on such forms as the 
Administrator will supply on request.

[59 FR 33092, June 27, 1994]



Sec. 79.11  Information and assurances to be provided by the fuel
manufacturer.

    Each application for registration submitted by the manufacturer of a 
designated fuel shall include the following:
    (a) The commercial identifying name of each additive that will or 
may be used in a designated fuel subsequent to the date prescribed for 
such fuel in subpart D;
    (b) The name of the additive manufacturer of each additive named;
    (c) The range of concentration of each additive named, as follows:
    (1) In the case of an additive which has been or is being used in 
the designated fuel, the range during any 3-month or longer period prior 
to the date of submission;
    (2) In the case of an additive which has not been used in the 
designated fuel, the expected or estimated range;
    (d) The purpose-in-use of each additive named;
    (e) The description (or identification, in the case of a generally 
accepted method) of a suitable analytical technique (if one is known) 
that can be used to detect the presence of each named additive in the 
designated fuel and/or to measure its concentration therein;
    (f) Such other data and information as are specified in the 
designation of the fuel in subpart D;
    (g) Assurances that the fuel manufacturer will notify the 
Administrator in writing and within a reasonable time of any change in:
    (1) The name of any additive previously reported;
    (2) The name of the manufacturer of any additive being used;
    (3) The purpose-in-use of any additive;
    (4) Information submitted pursuant to paragraph (e) of this section;
    (h) Assurances that the fuel manufacturer will not represent, 
directly or indirectly, in any notice, circular, letter, or other 
written communication, or any written, oral, or pictorial notice or 
other announcement in any publication or by radio or television, that 
registration of the fuel constitutes endorsement, certification, or 
approval by any agency of the United States;
    (i) The manufacturer of any fuel which will be sold, offered for 
sale, or introduced into commerce for use in motor vehicles manufactured 
after model year 1974 shall demonstrate that the fuel is substantially 
similar to any fuel utilized in the certification of any 1975 or 
subsequent model year vehicle or engine, or that the manufacturer has 
obtained a waiver under 42 U.S.C. 7545(f)(4); and
    (j) The manufacturer shall submit, or shall reference prior 
submissions, including all of the test data and other information 
required prior to registration of the fuel by the provisions of subpart 
F of this part.

[40 FR 52011, Nov. 7, 1975, as amended at 59 FR 33092, June 27, 1994]



Sec. 79.12  Determination of noncompliance.

    If the Administrator determines that an applicant for registration 
of a designated fuel has failed to submit all of the information 
required by Sec. 79.11, or determines within the applicable period 
provided for Agency review that the applicant has not satisfactorily 
completed any testing which is required prior to registration of the 
fuel by any provision of subpart F of this part, he shall return the 
application to

[[Page 511]]

the manufacturer, along with an explanation of all deficiencies in the 
required information.

[59 FR 33093, June 27, 1994]



Sec. 79.13  Registration.

    (a) If the Administrator determines that a manufacturer has 
submitted an application for registration of a designated fuel which 
includes all of the information and assurances required by Sec. 79.11 
and has satisfactorily completed all of the testing required by subpart 
F of this part, the Administrator shall promptly register the fuel and 
notify the fuel manufacturer of such registration.
    (b) The Administrator shall maintain a list of registered fuels, 
which shall be available to the public upon request.

[40 FR 52011, Nov. 7, 1975, as amended at 41 FR 21324, May 25, 1976; 59 
FR 33093, June 27, 1994]



Sec. 79.14  Termination of registration of fuels.

    Registration may be terminated by the Administrator if the fuel 
manufacturer requests such termination in writing.



               Subpart C_Additive Registration Procedures



Sec. 79.20  Application for registration by additive manufacturer.

    Any manufacturer of a designated fuel additive who wishes to 
register that additive shall submit an application for registration 
including all of the information set forth in Sec. 79.21. Each 
application shall be signed by the fuel additive manufacturer and shall 
be submitted on such forms as the Administrator will supply on request.

[59 FR 33093, June 27, 1994]



Sec. 79.21  Information and assurances to be provided by the additive manufacturer.

    Each application for registration submitted by the manufacturer of a 
designated fuel additive shall include the following:
    (a) The chemical composition of the additive with the methods of 
analysis identified, except that
    (1) If the chemical composition is not known, full disclosure of the 
chemical process of manufacture will be accepted in lieu thereof;
    (2) In the case of an additive for engine oil, only the name, 
percentage by weight, and method of analysis of each element in the 
additive are required provided, however, that a percentage figure 
combining the percentages of carbon, hydrogen, and/or oxygen may be 
provided unless the breakdown into percentages for these individual 
elements is already known to the registrant.
    (3) In the case of a purchased component, only the name, 
manufacturer, and percent by weight of such purchased component are 
required if the manufacturer of the component will, upon request, 
furnish the Administrator with the chemical composition thereof.
    (b) The chemical structure of each compound in the additive if such 
structure is known and is not adequately specified by the name given 
under ``chemical composition.'' Nominal identification is adequate if 
mixed isomers are present.
    (c) The description (or identification, in the case of a generally 
accepted method) of a suitable analytical technique (if one is known) 
that can be used to detect the presence of the additive in any fuel 
named in the designation and/or to measure its concentration therein.
    (d) The specific types of fuels designated under Sec. 79.32 for 
which the fuel additive will be sold, offered for sale, or introduced 
into commerce, and the fuel additive manufacturer's recommended range of 
concentration and purpose-in-use for each such type of fuel.
    (e) Such other data and information as are specified in the 
designation of the additive in subpart D.
    (f) Assurances that any change in information submitted pursuant to 
(1) paragraphs (a), (b), (c), and (d) of this section will be provided 
to the Administrator in writing within 30 days of such change; and (2) 
paragraph (e) of this section as provided in Sec. 79.5(b).
    (g) Assurances that the additive manufacturer will not represent, 
directly or indirectly, in any notice, circular, letter, or other 
written communication

[[Page 512]]

or any written, oral, or pictorial notice or other announcement in any 
publication or by radio or television, that registration of the additive 
constitutes endorsement, certification, or approval by any agency of the 
United States.
    (h) The manufacturer of any fuel additive which will be sold, 
offered for sale, or introduced into commerce for use in any type of 
fuel intended for use in motor vehicles manufactured after model year 
1974 shall demonstrate that the fuel additive, when used at the 
recommended range of concentration, is substantially similar to any fuel 
additive included in a fuel utilized in the certification of any 1975 or 
subsequent model year vehicle or engine, or that the manufacturer has 
obtained a waiver under 42 U.S.C. 7545(f)(4).
    (i) The manufacturer shall submit, or shall reference prior 
submissions, including all of the test data and other information 
required prior to registration of the fuel additive by the provisions of 
subpart F of this part.

[40 FR 52011, Nov. 7, 1975, as amended at 41 FR 21324, May 25, 1976; 59 
FR 33093, June 27, 1994]



Sec. 79.22  Determination of noncompliance.

    If the Administrator determines that an applicant for registration 
of a designated fuel additive has failed to submit all of the 
information required by Sec. 79.21, or determines within the applicable 
period provided for Agency review that the applicant has not 
satisfactorily completed any testing which is required prior to 
registration of the fuel additive by any provision of subpart F of this 
part, he shall return the application to the manufacturer, along with an 
explanation of all deficiencies in the required information.

[59 FR 33093, June 27, 1994]



Sec. 79.23  Registration.

    (a) If the Administrator determines that a manufacturer has 
submitted an application for registration of a designated fuel additive 
which includes all of the information and assurances required by Sec. 
79.21 and has satisfactorily completed all of the testing required by 
subpart F of this part, the Administrator shall promptly register the 
fuel additive and notify the fuel manufacturer of such registration.
    (b) The Administrator shall maintain a list of registered additives, 
which shall be available to the public upon request.

[40 FR 52011, Nov. 7, 1975, as amended at 41 FR 21324, May 25, 1976; 59 
FR 33093, June 27, 1994]



Sec. 79.24  Termination of registration of additives.

    Registration may be terminated by the Administrator if the additive 
manufacturer requests such termination in writing.



              Subpart D_Designation of Fuels and Additives



Sec. 79.30  Scope.

    Fuels and additives designated and dates prescribed by the 
Administrator for the registration of such fuels and additives, pursuant 
to section 211 of the Act, are listed in this subpart. In addition, 
specific informational requirements under Sec. Sec. 79.11(f) and 
79.21(e) are set forth for each designated fuel or additive. Additional 
fuels and/or additives may be designated and pertinent dates and 
additional specific informational requirements prescribed as the 
Administrator deems advisable.



Sec. 79.31  Additives.

    (a) All additives produced or sold for use in motor vehicle gasoline 
and/or motor vehicle diesel fuel are hereby designated. The Act defines 
the term ``motor vehicle'' to mean any self-propelled vehicle designed 
for transporting persons or property on a street or highway. For 
purposes of this registration, however, additives specifically 
manufactured and marketed for use in motorcycle fuels are excluded.
    (b) All designated additives must be registered by July 7, 1976.
    (c) In accordance with Sec. Sec. 79.5(b) and 79.21(e), and to the 
extent such information is known to the additive manufacturer as a 
result of testing conducted for reasons other than additive registration 
or reporting purposes, the additive manufacturer shall furnish the 
highest, lowest, and average values of

[[Page 513]]

the impurities in each designated additive, if greater than 0.1 percent 
by weight. The methods of analysis in making the determinations shall 
also be given.
    (d) In accordance with Sec. Sec. 79.5(b) and 79.21(e), and to the 
extent such information is known to the additive manufacturer, he shall 
furnish summaries of any information developed by or specifically for 
him concerning the following items:
    (1) Mechanisms of action of the additive;
    (2) Reactions between the additive and the fuels listed in paragraph 
(a) of this section;
    (3) Identification and measurement of the emission products of the 
additive when used in the fuels listed in paragraph (a) of this section;
    (4) Effects of the additive on all emissions;
    (5) Toxicity and any other public health or welfare effects of the 
emission products of the additive;
    (6) Effects of the emission products of the additive on the 
performance of emission control devices/systems. Such submissions shall 
be accompanied by a description of the test procedures used in obtaining 
the information. Information will be considered to be known to the 
additive manufacturer if a report thereon has been prepared and 
circulated or distributed outside the research department or division.

(Secs. 211, 301(a), Clean Air Act as amended (40 U.S.C. 7545, 7601(a)))

[40 FR 52011, Nov. 7, 1975, as amended at 41 FR 21324, May 25, 1976; 43 
FR 28490, June 30, 1978; 59 FR 33093, June 27, 1994]



Sec. 79.32  Motor vehicle gasoline.

    (a) The following fuels commonly or commercially known or sold as 
motor vehicle gasoline are hereby individually designated:
    (1) Motor vehicle gasoline, unleaded--motor vehicle gasoline that 
contains no more than 0.05 gram of lead per gallon;
    (2) Motor vehicle gasoline, leaded, premium--motor vehicle gasoline 
that contains more than 0.05 gram of lead per gallon and is sold as 
``premium;''
    (3) Motor vehicle gasoline, leaded, non-premium--motor vehicle 
gasoline that contains more than 0.05 gram of lead per gallon but is not 
sold as ``premium.''

The Act defines the term ``motor vehicle'' to mean any self-propelled 
vehicle designed for transporting persons or property on a street or 
highway. For purposes of this registration, however, gasoline 
specifically blended and marketed for motorcycles is excluded.
    (b) All designated motor vehicle gasolines must be registered by 
September 7, 1976.
    (c) In accordance with Sec. Sec. 79.5(a)(2) and 79.11(f), and to 
the extent such information is known to the fuel manufacturer as a 
result of testing conducted for reasons other than fuel registration or 
reporting purposes, the fuel manufacturer shall furnish the data listed 
below. The highest, lowest, and average values of the listed 
characteristics/properties are to be reported. For initial registration, 
data shall be given for any 3-month or longer period prior to the date 
of submission. For annual reports thereafter, data shall be for the 
calendar year, except that if the first required annual report covers a 
period of less than a year, the data may be for such shorter period.
    (1) Hydrocarbon composition (aromatic content, olefin content, 
saturate content), with the methods of analysis identified;
    (2) Polynuclear organic material content, sulfur content, and trace 
element content, with the methods of analysis identified;
    (3) Reid vapor pressure;
    (4) Distillation temperatures (10 percent point, end point);
    (5) Research octane number and motor octane number.
    (d) In accordance with Sec. Sec. 79.5(a)(2) and 79.11(f), and to 
the extent such information is known to the fuel manufacturer, he shall 
furnish summaries of any information developed by or specifically for 
him concerning the following items:
    (1) Mechanisms of action of each additive he reports;
    (2) Reactions between such additives and motor vehicle gasoline;
    (3) Identification and measurement of the emission products of such 
additives when used in motor vehicle gasoline;

[[Page 514]]

    (4) Effects of such additives on all emissions;
    (5) Toxicity and any other public health or welfare effects of the 
emission products of such additives;
    (6) Effects of the emission products of such additives on the 
performance of emission control devices/systems. Such submissions shall 
be accompanied by a description of the test procedures used in obtaining 
the information. Information will be considered to be known to the fuel 
manufacturer if a report thereon has been prepared and circulated or 
distributed outside the research department or division.

[40 FR 52011, Nov. 7, 1975, as amended at 41 FR 21324, May 25, 1976]



Sec. 79.33  Motor vehicle diesel fuel.

    (a) The following fuels commonly or commercially known or sold as 
motor vehicle diesel fuel are hereby individually designated:
    (1) Motor vehicle diesel fuel, grade 1-D;
    (2) Motor vehicle diesel fuel, grade 2-D.

The Act defines the term ``motor vehicle'' to mean any self-propelled 
vehicle designed for transporting persons or property on a street or 
highway.
    (b) All designated motor vehicle diesel fuels must be registered 
within 12 months after promulgation of this part.
    (c) In accordance with Sec. Sec. 79.5(a)(2) and 79.11(f), and to 
the extent such information is known to the fuel manufacturer as a 
result of testing conducted for reasons other than fuel registration or 
reporting purposes, the fuel manufacturer shall furnish the data listed 
below. The highest, lowest, and average values of the listed 
characteristics/properties are to be reported. For initial registration, 
data shall be given for any 3-month or longer period prior to the date 
of submission. For annual reports thereafter, data shall be for the 
calendar year, except that if the first required annual report covers a 
period of less than a year, the data may be for such shorter period.
    (1) Hydrocarbon composition (aromatic content, olefin content, 
saturate content), with the methods of analysis identified;
    (2) Polynuclear organic material content, sulfur content, and trace 
element content, with the methods of analysis identified;
    (3) Distillation temperatures (90 percent point, end point);
    (4) Cetane number or cetane index;
    (d) In accordance with Sec. Sec. 79.5(a)(2) and 79.11(f), and to 
the extent such information is known to the fuel manufacturer, he shall 
furnish summaries of any information developed by or specifically for 
him concerning the following items:
    (1) Mechanisms of action of each additive he reports;
    (2) Reactions between such additives and motor vehicle diesel fuel;
    (3) Identification and measurement of the emission products of such 
additives when used in motor vehicle diesel fuel;
    (4) Effects of such additives on all emissions;
    (5) Toxicity and any other public health or welfare effects of the 
emission products of such additives.

Such submission shall be accompanied by a description of the test 
procedures used in obtaining the information. Information will be 
considered to be known to the fuel manufacturer if a report thereon has 
been prepared and circulated or distributed outside the research 
department or division.

Subpart E [Reserved]



             Subpart F_Testing Requirements for Registration

    Source: 59 FR 33093, June 27, 1994, unless otherwise noted.



Sec. 79.50  Definitions.

    The definitions listed in this section apply only to subpart F of 
this part.
    Additive/base fuel mixture means the mixture resulting when a fuel 
additive is added in specified proportion to the base fuel of the fuel 
family to which the additive belongs.
    Aerosol additive means a chemical mixture in aerosol form generally 
used as a motor vehicle engine starting aid or carburetor cleaner and 
not recommended to be placed in the fuel tank.

[[Page 515]]

    Aftermarket fuel additive means a product which is added by the end-
user directly to fuel in a motor vehicle or engine to modify the 
performance or other characteristics of the fuel, the engine, or its 
emissions.
    Atypical element means any chemical element found in a fuel or 
additive product which is not allowed in the baseline category of the 
associated fuel family, and an ``atypical fuel or fuel additive'' is a 
product which contains such an atypical element.
    Base fuel means a generic fuel formulated from a set of 
specifications to be representative of a particular fuel family.
    Basic emissions means the total hydrocarbons, carbon monoxide, 
oxides of nitrogen, and particulates occurring in motor vehicle or 
engine emissions.
    Bulk fuel additive means a product which is added to fuel at the 
refinery as part of the original blending stream or after the fuel is 
transported from the refinery but before the fuel is purchased for 
introduction into the fuel tank of a motor vehicle.
    Emission characterization means the determination of the chemical 
composition of emissions.
    Emission generation means the operation of a vehicle or engine or 
the vaporization of a fuel or additive/fuel mixture under controlled 
conditions for the purpose of creating emissions to be used for testing 
purposes.
    Emission sampling means the removal of a fraction of collected 
emissions for testing purposes.
    Emission speciation means the analysis of vehicle or engine 
emissions to determine the individual chemical compounds which comprise 
those emissions.
    Engine Dynamometer Schedule (EDS) means the transient engine speed 
versus torque time sequence commonly used in heavy-duty engine 
evaluation. The EDS for heavy-duty diesel engines is specified in 40 CFR 
part 86, appendix I(f)(2).
    Evaporative Emission Generator (EEG) means a fuel tank or vessel to 
which heat is applied to cause a portion of the fuel to evaporate at a 
desired rate.
    Evaporative emissions means chemical compounds emitted into the 
atmosphere by vaporization of contents of a fuel or additive/fuel 
mixture.
    Evaporative fuel means a fuel which has a Reid Vapor Pressure (RVP, 
pursuant to 40 CFR part 80, appendix ``E'') of 2.0 pounds per square 
inch or greater and is not supplied to motor vehicle engines by way of 
sealed containment and delivery systems.
    Evaporative fuel additive means a fuel additive which, when mixed 
with its specified base fuel, causes an increase in the RVP of the base 
fuel by 0.4 psi or more relative to the RVP of the base fuel alone and 
results in an additive/base fuel mixture whose RVP is 2.0 psi, or 
greater. Excluded from this definition are fuel additives used with 
fuels which are supplied to motor vehicle engines by way of sealed 
containment and delivery systems.
    Federal Test Procedure (FTP) means the body of exhaust and 
evaporative emissions test procedures described in 40 CFR 86 for the 
certification of new motor vehicles to Federal motor vehicle emissions 
standards.
    Fuel family means a set of fuels and fuel additives which share 
basic chemical and physical formulation characteristics and can be used 
in the same engine or vehicle.
    Manufacturer means a person who is a fuel manufacturer or additive 
manufacturer as defined in Sec. 79.2 (d) and (f).
    Nitrated polycyclic aromatic hydrocarbons (NPAH) means the class of 
compounds whose molecular structure includes two or more aromatic rings 
and contains one or more nitrogen substitutions.
    Non-catalyzed emissions means exhaust emissions not subject to an 
effective aftertreatment device such as a functional catalyst or 
particulate trap.
    Oxygenate compound means an oxygen-containing, ashless organic 
compound, such as an alcohol or ether, which may be used as a fuel or 
fuel additive.
    Polycyclic aromatic hydrocarbons (PAH) means the class of 
hydrocarbon compounds whose molecular structure includes two or more 
aromatic rings.
    Relabeled additive means a fuel additive which is registered by its 
original manufacturer with EPA and is also

[[Page 516]]

registered and sold, unchanged in composition, under a different label 
and/or by a different entity.
    Semi-volatile organic compounds means that fraction of gaseous 
combustion emissions which consists of compounds with greater than 
twelve carbon atoms and can be trapped in sorbent polymer resins.
    Urban Dynamometer Driving Schedule (UDDS) means the 1372 second 
transient speed driving sequence used by EPA to simulate typical urban 
driving. The UDDS for light-duty vehicles is described in 40 CFR part 
86, appendix I(a).
    Vapor phase means the gaseous fraction of combustion emissions.
    Vehicle classes/subclasses means the divisions of vehicle groups 
within a vehicle type, including light-duty vehicles, light-duty trucks, 
and heavy-duty vehicles as specified in 40 CFR part 86.
    Vehicle type means the divisions of motor vehicles according to 
combustion cycle and intended fuel class, including, but not necessarily 
limited to, Otto cycle gasoline-fueled vehicles, Otto cycle methanol-
fueled vehicles, diesel cycle diesel-fueled vehicles, and diesel cycle 
methanol-fueled vehicles.
    Whole emissions means all components of unfiltered combustion 
emissions or evaporative emissions.



Sec. 79.51  General requirements and provisions.

    (a) Overview of requirements. (1) All manufacturers of fuels and 
fuel additives that are designated for registration under this part are 
required to comply with the requirements of subpart F of this part 
either on an individual basis or as a participant in a group of 
manufacturers of the same or similar fuels and fuel additives, as 
defined in Sec. 79.56. If manufacturers elect to comply by 
participation in a group, each manufacturer continues to be individually 
subject to the requirements of subpart F of this part, and responsible 
for testing under this subpart. Each manufacturer, subject to the 
provisions for group applications in Sec. 79.51(b) and the special 
provisions in Sec. 79.58, shall submit all Tier 1 and Tier 2 
information required by Sec. Sec. 79.52, 79.53 and 79.59 for each fuel 
or additive, except that the Tier 1 emission characterization 
requirements in Sec. 79.52(b) and/or the Tier 2 testing requirements in 
Sec. 79.53 may be satisfied by adequate existing information pursuant 
to the Tier 1 literature search requirements in Sec. 79.52(d). The 
adequacy of existing information to serve in compliance with specific 
Tier 1 and/or Tier 2 requirements shall be determined according to the 
criteria and procedures specified in Sec. Sec. 79.52(b) and 79.53 (c) 
and (d). In all cases, EPA reserves the right to require, based upon the 
information contained in the application or any other information 
available to the Agency, that manufacturers conduct additional testing 
of any fuel or additive (or fuel/additive group) if EPA determines that 
there is inadequate information upon which to base regulatory decisions 
for such product(s). In any case where EPA determines that the 
requirements of Tiers 1 and 2 have been satisfied but that further 
testing is required, the provisions of Tier 3 (Sec. 79.54) shall apply.
    (2) Laboratory facilities shall perform testing in compliance with 
Good Laboratory Practice (GLP) requirements as those requirements apply 
to inhalation toxicology studies. All studies shall be monitored by the 
facilities' Quality Assurance units (as specified in Sec. 79.60).
    (b) Group Applications. Subject to the provisions of Sec. 79.56 (a) 
through (c), EPA will consider any testing requirements of this subpart 
to have been met for any fuel or fuel additive when a fuel or fuel 
additive which meets the criteria for inclusion in the same group as the 
subject fuel or fuel additive has met that testing requirement, provided 
that all fuels and additives must be individually registered as 
described in Sec. 79.59(b). For purposes of this subpart, a 
determination of which group contains a particular fuel or additive will 
be made pursuant to the provisions of Sec. 79.56 (d) and (e). Nothing 
in this subsection (b) shall be deemed to require a manufacturer to rely 
on another manufacturer's testing.
    (c) Application Procedures and Dates. Each application submitted in 
compliance with this subpart shall be signed by the manufacturer of the 
designated fuel or additive, or by the manufacturer's agent, and shall 
be submitted to

[[Page 517]]

the address and in the format prescribed in Sec. 79.59. A manufacturer 
who chooses to comply as part of a group pursuant to Sec. 79.56 shall 
be covered by the group's joint application. Subject to any 
modifications pursuant to the special provisions in Sec. Sec. 79.51(f) 
or 79.58, the schedule for compliance with the requirements of this 
subpart is as follows:
    (1) Fuels and fuel additives with existing registrations. (i) The 
manufacturer of a fuel or fuel additive product which, pursuant to 
subpart B or C of this part, is registered as of May 27, 1994 must 
submit the additional basic registration data specified in Sec. 
79.59(b) before November 28, 1994.
    (ii) Except as provided in paragraphs (c)(1)(vi) and (vii) of this 
section, the manufacturer of such products must also satisfy the 
requirements and time schedules in either of the following paragraphs 
(c)(1)(ii) (A) or (B) of this section:
    (A) No later than May 27, 1997, all applicable Tier 1 and Tier 2 
requirements must be submitted to EPA, pursuant to Sec. Sec. 79.52, 
79.53, and 79.59; or
    (B) No later than May 27, 1997, all applicable Tier 1 requirements 
(pursuant to Sec. Sec. 79.52 and 79.59), plus evidence of a contract 
with a qualified laboratory (or other suitable arrangement) for 
completion of all applicable Tier 2 requirements, must be submitted to 
EPA. For this purpose, a qualified laboratory is one which can 
demonstrate the capabilities and credentials specified in Sec. 
79.53(c)(1). In addition, by May 26, 2000, all applicable Tier 2 
requirements (pursuant to Sec. Sec. 79.53 and 79.59) must be submitted 
to EPA.
    (iii) In the case of such fuels and fuel additives which, pursuant 
to applicable special provisions in Sec. 79.58, are not subject to Tier 
2 requirements, all other requirements (except Tier 3) must be submitted 
to EPA before May 27, 1997.
    (iv) In the event that Tier 3 testing is also required (under Sec. 
79.54), EPA shall determine an appropriate timeline for completion of 
the additional requirements and shall communicate this schedule to the 
manufacturer according to the provisions of Sec. 79.54(b).
    (v) The manufacturer may at any time modify an existing fuel 
registration by submitting a request to EPA to add or delete a bulk 
additive to the existing registration information for such fuel product, 
provided that any additional additive must be registered by EPA for use 
in the specific fuel family to which the fuel product belongs. However, 
the addition or deletion of a bulk additive to a fuel registration may 
effect the grouping of such registered fuel under the criteria of Sec. 
79.56, and thus may effect the testing responsibilities of the fuel 
manufacturer under this subpart.
    (vi) In regard to atypical fuels or additives in the gasoline and 
diesel fuel families (pursuant to the specifications in Sec. 
79.56(e)(4)(iii)(A) (1) and (2)):
    (A) All applicable Tier 1 requirements, pursuant to Sec. Sec. 79.52 
and 79.59, must be submitted to EPA by May 27, 1997.
    (B) Tier 2 requirements, pursuant to Sec. Sec. 79.53 and 79.59, 
must be satisfied according to the deadlines in either of the following 
paragraphs (c)(1)(vi)(B) (1) or (2) of this section:
    (1) All applicable Tier 2 requirements shall be submitted to EPA by 
November 27, 1998; or
    (2) Evidence of a contract with a qualified laboratory (or other 
suitable arrangement) for completion of all applicable Tier 2 
requirements shall be submitted to EPA by November 27, 1998. For this 
purpose, a qualified laboratory is one which can demonstrate the 
capabilities and credentials specified in Sec. 79.53(c)(1). In 
addition, all applicable Tier 2 requirements must be submitted to EPA by 
November 27, 2001.
    (vii) In regard to nonbaseline diesel products formulated with mixed 
alkyl esters of plant and/or animal origin (i.e., ``biodiesel'' fuels, 
pursuant to Sec. 79.56(e)(4)(ii)(B)(2)):
    (A) All applicable Tier 1 requirements, pursuant to Sec. Sec. 79.52 
and 79.59, must be submitted to EPA by March 17, 1998.
    (B) Tier 2 requirements, pursuant to Sec. Sec. 79.53 and 79.59, 
must be satisfied according to the deadlines in either of the following 
paragraphs (c)(1)(vii)(B) (1) or (2) of this section:
    (1) All applicable Tier 2 requirements shall be submitted to EPA by 
March 17, 1998; or

[[Page 518]]

    (2) Evidence of a contract with a qualified laboratory (or other 
suitable arrangement) for completion of all applicable Tier 2 
requirements shall be submitted to EPA by March 17, 1998. For this 
purpose, a qualified laboratory is one which can demonstrate the 
capabilities and credentials specified in Sec. 79.53(c)(1). In 
addition, all applicable Tier 2 requirements must be submitted to EPA by 
May 27, 2000.
    (2) Registrable fuels and fuel additives. (i) A fuel product which 
is not registered pursuant to subpart B of this part as of May 27, 1994 
shall be considered registrable if, under the criteria established by 
Sec. 79.56, the fuel can be enrolled in the same fuel/additive group 
with one or more currently registered fuels. A fuel additive product 
which is not registered for a specific type of fuel pursuant to subpart 
C of this part as of May 27, 1994 shall be considered registrable for 
that type of fuel if, under the criteria established by Sec. 79.56, the 
fuel/additive mixture resulting from use of the additive product in the 
specific type of fuel can be enrolled in the same fuel/additive group 
with one or more currently registered fuels or bulk fuel additives. For 
the purpose of this determination, currently registered fuels and bulk 
additives are those with existing registrations as of the date on which 
EPA receives the basic registration data (pursuant to Sec. 79.59(b)) 
for the product in question.
    (ii) A manufacturer seeking to register under subpart B of this part 
a fuel product which is deemed registrable under this section, or to 
register under subpart C of this part a fuel additive product for a 
specific type of fuel for which it is deemed registrable under this 
section, shall submit the basic registration data (pursuant to Sec. 
79.59(b)) for that product as part of the application for registration. 
If the Administrator determines that the product is registrable under 
this section, then the Administrator shall promptly register the 
product, provided that the applicant has satisfied all of the other 
requirements for registration under subpart B or subpart C of this part, 
and contingent upon satisfactory submission of required information 
under paragraph (c)(2)(iii) of this section.
    (iii) Registration of a registrable fuel or additive shall be 
subject to the same requirements and compliance schedule as specified in 
paragraph (c)(1) of this section for existing fuels and fuel additives. 
Accordingly, manufacturers of registrable fuels or additives may be 
granted and may retain registration for such products only if any 
applicable and due Tier 1, 2, and 3 requirements have also been 
satisfied by either the manufacturer of the product or the fuel/additive 
group to which the product belongs.
    (3) New fuels and fuel additives. A fuel product shall be considered 
new if it is not registered pursuant to subpart B of this part as of May 
27, 1994 and if, under the criteria established by Sec. 79.56, it 
cannot be enrolled in the same fuel/additive group with one or more 
currently registered fuels. A fuel additive product shall be considered 
new with respect to a specific type of fuel if it is not expressly 
registered for that type of fuel pursuant to subpart C of this part as 
of May 27, 1994 and if, under the criteria established by Sec. 79.56, 
the fuel/additive mixture resulting from use of the additive product in 
the specific type of fuel cannot be enrolled in the same fuel/additive 
group with one or more currently registered fuels or bulk fuel 
additives. For the purpose of this determination, currently registered 
fuels and bulk additives are those with existing registrations as of the 
date on which EPA receives the basic registration data (pursuant to 
Sec. 79.59(b)) for the product in question. For such new product, the 
manufacturer must satisfactorily complete all applicable Tier 1 and Tier 
2 requirements, followed by any Tier 3 testing which the Administrator 
may require, before registration will be granted.
    (d) Notifications. Upon receipt of a manufacturer's (or group's) 
submittal in compliance with the requirements of this subpart, EPA will 
notify such manufacturer (or group) that the application has been 
received and what, if any, information, testing, or retesting is 
necessary to bring the application into compliance with the requirements 
of this subpart. EPA intends to provide such notification of receipt in 
a timely manner for each such application.

[[Page 519]]

    (1) Registered fuel and fuel additive notification. (i) The 
manufacturer of a registered fuel or fuel additive product who is 
notified that the submittal for such product contains adequate 
information pursuant to the Tier 1 and Tier 2 testing and reporting 
requirements (Sec. Sec. 79.52, 79.53, and 79.59 (a) through (c)) may 
continue to sell, offer for sale, or introduce into commerce the 
registered product as permitted by the existing registration for the 
product under Sec. 79.4.
    (ii) If the manufacturer of a registered fuel or fuel additive 
product is notified that testing or retesting is necessary to bring the 
Tier 1 and/or Tier 2 submittal into compliance, the continued sale or 
importation of the product shall be conditional upon satisfactorily 
completing the requirements within the time frame specified in paragraph 
(c)(1) of this section.
    (iii) EPA intends to notify the manufacturer of the adequacy of the 
submitted data within two years of EPA's receipt of such data. However, 
EPA retains the right to require that adequate data be submitted to EPA 
if, upon subsequent review, EPA finds that the original Tier 1 and/or 
Tier 2 submittal is not consistent with the requirements of this 
subpart. If EPA does not notify the manufacturer of the adequacy of the 
Tier 1 and/or Tier 2 data within two years, EPA will not hold the 
manufacturer liable for penalties for violating this rule for the period 
beginning when the data was due until the time EPA notifies the 
manufacturer of the violation.
    (iv) If the manufacturer of a registered fuel or fuel additive 
product is notified (pursuant to Sec. 79.54(b)) that Tier 3 testing is 
required for its product, then the manufacturer may continue to sell, 
offer for sale, introduce into commerce the registered product as 
permitted by the existing registration for the product under Sec. 79.4. 
However, if the manufacturer fails to complete the specified Tier 3 
requirements within the specified time, the registration of the product 
will be subject to cancellation under Sec. 79.51(f)(6).
    (v) EPA retains the right to require additional Tier 3 testing 
pursuant to the procedures in Sec. 79.54.
    (2) New fuel and fuel additive notification. (i) Within six months 
following its receipt of the Tier 1 and Tier 2 submittal for a new 
product (as defined in paragraph (c)(3) of this section), EPA shall 
notify the manufacturer of the adequacy of such submittal in compliance 
with the requirements of Sec. Sec. 79.52, 79.53, and 79.59 (a) through 
(c).
    (A) If EPA notifies the manufacturer that testing, retesting, or 
additional information is necessary to bring the Tier 1 and Tier 2 
submittal into compliance, the manufacturer shall remedy all 
inadequacies and provide Tier 3 data, if required, before EPA shall 
consider the requirements for registration to have been met for the 
product in question.
    (B) If EPA does not notify the manufacturer of the adequacy of the 
Tier 1 and Tier 2 submittal within six months following the submittal, 
the manufacturer shall be deemed to have satisfactorily completed Tiers 
1 and 2.
    (ii) Within six months of the date on which EPA notifies the 
manufacturer of satisfactory completion of Tiers 1 and 2 for a new 
product, or within one year of the submittal of the Tier 1 and Tier 2 
data (whichever is earlier), EPA shall determine whether additional 
testing is currently needed under the provisions of Tier 3 and, pursuant 
to Sec. 79.54(b), shall notify the manufacturer of its determination.
    (A) If the manufacturer of a new fuel or fuel additive product is 
notified that Tier 3 testing is required for such product, then EPA 
shall have the authority to withhold registration until the specified 
Tier 3 requirements have been satisfactorily completed. EPA shall 
determine whether the Tier 3 requirements have been met, and shall 
notify the manufacturer of this determination, within one year of 
receiving the manufacturer's Tier 3 submittal.
    (B) If EPA does not notify the manufacturer of potential Tier 3 
requirements within the prescribed timeframe, then additional testing at 
the Tier 3 level is deemed currently unnecessary and the manufacturer 
shall be considered to have complied with all current registration 
requirements for the new fuel or additive product.
    (iii) Upon completion of all current Tier 1, Tier 2, and Tier 3 
requirements,

[[Page 520]]

and submission of an application for registration which includes all of 
the information and assurances required by Sec. 79.11 or Sec. 79.21, 
the registration of the new fuel or additive shall be granted, and the 
registrant may then sell, offer for sale, or introduce into commerce the 
registered product as permitted by Sec. 79.4.
    (iv) Once the new product becomes registered, EPA reserves the right 
to require additional Tier 3 testing pursuant to the procedures 
specified in Sec. 79.54.
    (e) Inspection of a testing facility. (1) A testing facility, 
whether engaged in emissions analysis or health and/or welfare effects 
testing under the regulations in this subpart, shall permit an 
authorized employee or duly designated representative of EPA, at 
reasonable times and in a reasonable manner, to inspect the facility and 
to inspect (and in the case of records also to copy) all records and 
specimens required to be maintained regarding studies to which this 
subpart applies. The records inspection and copying requirements shall 
not apply to quality assurance unit records of findings and problems, or 
to actions recommended and taken, except the EPA may seek production of 
these records in litigation or informal hearings.
    (2) EPA will not consider reliable for purposes of showing that a 
test substance does or does not present a risk of injury to health or 
the environment any data developed by a testing facility or sponsor that 
refuses to permit inspection in accordance with this section. The 
determination that a study will not be considered reliable does not, 
however, relieve the sponsor of a required test of any obligation under 
any applicable statute or regulation to submit the results of the study 
to EPA.
    (3) Effects of non-compliance. Pursuant to sections 114, 208, and 
211(d) of the CAA, it shall be a violation of this section and a 
violation of 40 CFR part 79, subpart F to deny entry to an authorized 
employee or duly designated representative of EPA for the purpose of 
auditing a testing facility or test data.
    (f) Penalties and Injunctive Relief. (1) Any person who violates 
these regulations shall be subject to a civil penalty of up to $25,000 
for each and every day of the continuance of the violation and the 
economic benefit or savings resulting from the violation. Action to 
collect such civil penalties shall be commenced in accordance with 
paragraph (b) of section 205 of the Clean Air Act or assessed in 
accordance with paragraph (c) of section 205 of the Clean Air Act, 42 
U.S.C. 7524 (b) and (c).
    (2) Under section 205(b) of the CAA, the Administrator may commence 
a civil action for violation of this subpart in the district court of 
the United States for the district in which the violation is alleged to 
have occurred or in which the defendant resides or has a principal place 
of business.
    (3) Under section 205(c) of the CAA, the Administrator may assess a 
civil penalty of $25,000 for each and every day of the continuance of 
the violation and the economic benefit or savings resulting from the 
violation, except that the maximum penalty assessment shall not exceed 
$200,000, unless the Administrator and the Attorney General jointly 
determine that a matter involving a larger penalty amount is appropriate 
for administrative penalty assessment. Any such determination by the 
Administrator and the Attorney General shall not be subject to judicial 
review.
    (4) The Administrator may, upon application by the person against 
whom any such penalty has been assessed, remit or mitigate, with or 
without conditions, any such penalty.
    (5) The district courts of the United States shall have jurisdiction 
to compel the furnishing of information and the conduct of tests 
required by the Administrator under these regulations and to award other 
appropriate relief. Actions to compel such actions shall be brought by 
and in the name of the United States. In any such action, subpoenas for 
witnesses who are required to attend a district court in any district 
may run into any other district.
    (6) Cancellation. (i) The Administrator of EPA may issue a notice of 
intent to cancel a fuel or fuel additive registration if the 
Administrator determines that the registrant has failed to submit in a 
timely manner any data required to maintain registration under this part 
or under section 211(b) or 211(e) of the Clean Air Act.

[[Page 521]]

    (ii) Upon issuance of a notice of intent to cancel, EPA will forward 
a copy of the notice to the registrant by certified mail, return receipt 
requested, at the address of record given in the registration, along 
with an explanation of the reasons for the proposed cancellation.
    (iii) The registrant will be afforded 60 days from the date of 
receipt of the notice of intent to cancel to submit written comments 
concerning the notice, and to demonstrate or achieve compliance with the 
specific data requirements which provide the basis for the proposed 
cancellation. If the registrant does not respond in writing within 60 
days from the date of receipt of the notice of intent to cancel, the 
cancellation of the registration shall become final by operation of law 
and the Administrator shall notify the registrant of such cancellation. 
If the registrant responds in writing within 60 days from the date of 
receipt of the notice of intent to cancel, the Administrator shall 
review and consider all comments submitted by the registrant before 
taking final action concerning the proposed cancellation. The 
registrants' communications should be sent to the following address: 
Director, Field Operations and Support Division, 6406J--Fuel/Additives 
Registration, U.S. Environmental Protection Agency, 1200 Pennsylvania 
Ave., NW, Washington, DC 20460.
    (iv) As part of a written response to a notice of intent to cancel, 
a registrant may request an informal hearing concerning the notice. Any 
such request shall state with specificity the information the registrant 
wishes to present at such a hearing. If an informal hearing is 
requested, EPA shall schedule such a hearing within 60 days from the 
date of receipt of the request. If an informal hearing is held, the 
subject matter of the hearing shall be confined solely to whether or not 
the registrant has complied with the specific data requirements which 
provide the basis for the proposed cancellation. If an informal hearing 
is held, the designated presiding officer may be any EPA employee, the 
hearing procedures shall be informal, and the hearing shall not be 
subject to or governed by 40 CFR part 22 or by 5 U.S.C. 554, 556, or 
557. A verbatim transcript of each informal hearing shall be kept and 
the Administrator shall consider all relevant evidence and arguments 
presented at the hearing in making a final decision concerning a 
proposed cancellation.
    (v) If a registrant who has received a notice of intent to cancel 
submits a timely written response, and the Administrator decides after 
reviewing the response and the transcript of any informal hearing to 
cancel the registration, the Administrator shall issue a final 
cancellation order, forward a copy of the cancellation order to the 
registrant by certified mail, and promptly publish the cancellation 
order in the Federal Register. Any cancellation order issued after 
receipt of a timely written response by the registrant shall become 
legally effective five days after it is published in the Federal 
Register.
    (g) Modification of Regulation. (1) In special circumstances, a 
manufacturer subject to the registration requirements of this rule may 
petition the Administrator to modify the mandatory testing requirements 
in the test standard for any test required by this rule by application 
to Director, Field Operations and Support Division, at the address in 
paragraph (f)(6)(iii) of this section.
    (i) Such request shall be made as soon as the test sponsor is aware 
that the modification is necessary, but in no event shall the request be 
made after 30 days following the event which precipitated the request.
    (ii) Upon such request, the Administrator may, in circumstances 
which are outside the control of the manufacturer(s) or his/their agent 
and which could not have been reasonably foreseen or avoided, modify the 
mandatory testing requirements in the rule if such requirements are 
infeasible.
    (iii) If the Administrator determines that such modifications would 
not significantly alter the scope of the test, EPA will not ask for 
public comment before approving the modification. The Administrator will 
notify the test sponsor by certified mail of the response to the 
request. EPA will place copies of each application and EPA response in 
the public docket. EPA will

[[Page 522]]

publish a notice in the Federal Register annually describing such 
changes which have occurred during the previous year. Until such Federal 
Register notice is published, any modification approved by EPA shall 
apply only to the person or group who requested the modification; EPA 
shall state the applicability of each modification in such notice.
    (iv) Where, in EPA's judgment, the requested modification of a test 
standard would significantly change the scope of the test, EPA will 
publish a notice in the Federal Register requesting comment on the 
request and proposed modification. However, EPA may approve a requested 
modification of a test standard without first seeking public comment if 
necessary to preserve the validity of an ongoing test undertaken in good 
faith.
    (2) [Reserved]
    (h) Special Requirements for Additives. When an additive is the test 
subject, the following rules apply:
    (1) All required emission characterization and health effects 
testing procedures shall be performed on the mixture which results when 
the additive is combined with the base fuel for the appropriate fuel 
family (as specified in Sec. 79.55) at the maximum concentration 
recommended by the additive manufacturer pursuant to Sec. 79.21(d). 
This combination shall be known as the additive/base fuel mixture.
    (i) The appropriate fuel family to be utilized for the additive/base 
fuel mixture is the fuel family which contains the specific type(s) of 
fuel for which the additive is presently registered or for which the 
manufacturer of the additive is seeking registration.
    (ii) Additives belonging to more than one fuel family.
    (A) If an additive product is registered in two or more fuel 
families as of May 27, 1994, then the manufacturer of that additive is 
responsible for testing (or participating in group testing of) the 
respective additive/base fuel mixtures in compliance with the 
requirements of this subpart for each fuel family in which the 
manufacturer wishes to maintain a registration for its additive.
    (B) If a manufacturer is seeking to register such additive in two or 
more fuel families then, for testing and registration purposes, the 
additive shall be considered to be a member of each fuel family in which 
the manufacturer is seeking registration. The manufacturer is 
responsible for testing (or participating in group testing of) the 
respective additive/base fuel mixture in compliance with the 
requirements of this subpart for each fuel family in which the 
manufacturer wishes to obtain a product registration for its additive.
    (iii) In the case of the methanol fuel family, which contains two 
base fuels (M100 and M85 base fuels, pursuant to Sec. 79.55(d)), the 
applicable base fuel is the one which represents the fuel/additive group 
(specified in Sec. 79.56(e)(4)(i)(C)) containing fuels of which the 
most gallons are sold annually.
    (iv) Aftermarket additives which are intended by the manufacturer to 
be added to the fuel tank only at infrequent intervals shall be applied 
according to the manufacturer's specifications during mileage 
accumulation, pursuant to Sec. 79.57(c). However, during emission 
generation and testing, each tankful of fuel used must contain the fuel 
additive at its maximum recommended level. If the additive manufacturer 
believes that this maximum treatment rate will cause adverse effects to 
the test engine and/or that the engine's emissions may be subject to 
artifacts due to overuse of the additive, then the manufacturer may 
submit a request to EPA for modification of this requirement and related 
test procedures. Such request must include objective evidence that the 
modification(s) are needed, along with data demonstrating the maximum 
concentration of the additive which may actually reach the fuel tanks of 
vehicles in use.
    (v) Additives produced exclusively for use in 1 diesel fuel 
shall be tested in the diesel base fuel specified in Sec. 79.55(c), 
even though that base fuel is formulated with 2 diesel fuel. If 
a manufacturer is concerned that emissions generated from this 
combination of fuel and additive are subject to artifacts due to this 
blending, then that manufacturer may submit a request for

[[Page 523]]

a modification in test procedure requirements to the EPA. Any such 
request must include supporting test results and suggested test 
modifications.
    (vi) Bulk additives which are used intermittently for the direct 
purpose of conditioning or treating a fuel during storage or transport, 
or for treating or maintaining the storage, pipeline, and/or other 
components of the fuel distribution system itself and not the vehicle/
engine for which the fuel is ultimately intended, shall, for purposes of 
this program, be added to the base fuel at the maximum concentration 
recommended by the additive manufacturer for treatment of the fuel or 
distribution system component. However, if the additive manufacturer 
believes that this treatment rate will cause adverse effects to the test 
engine and/or that the engine's emissions may be subject to artifacts 
due to overuse of the additive, then the manufacturer may submit a 
request to EPA for modification of this requirement and related test 
procedures. Such request must include objective evidence that the 
modification(s) are needed, along with data demonstrating the maximum 
concentration of the additive which may actually reach the fuel tanks of 
vehicles in use.
    (2) EPA shall use emissions speciation and health effects data 
generated in the analysis of the applicable base fuel as control data 
for comparison with data generated for the additive/base fuel mixture.
    (i) The base fuel control data may be:
    (A) Generated internally as an experimental control in conjunction 
with testing done in compliance with registration requirements for a 
specific additive; or
    (B) Generated externally in the course of testing different 
additive(s) belonging to the same fuel family, or in the testing of a 
base fuel serving as representative of the baseline group for the 
respective fuel family pursuant to Sec. 79.56(e)(4)(i).
    (ii) Control data generated using test equipment (including vehicle 
model and/or engine, or Evaporative Emissions Generator specifications, 
as appropriate) and protocols identical or nearly identical to those 
used in emissions and health effects testing of the subject additive/
base fuel mixture would be most relevant for comparison purposes.
    (iii) If an additive manufacturer chooses the same vehicle/engine to 
independently test the base fuel as an experimental control prior to 
testing the additive/base fuel mixture, then the test vehicle/engine 
shall undergo two mileage accumulation periods, pursuant to Sec. 
79.57(c). The initial mileage accumulation period shall be performed 
using the base fuel alone. After base fuel testing, and prior to testing 
of the additive/base fuel mixture, a second mileage accumulation period 
shall be performed using the additive/base fuel mixture. The procedures 
outlined in this paragraph shall not preclude a manufacturer from 
testing a base fuel and the manufacturer's additive/base fuel mixture 
separately in identical, or nearly identical, vehicles/engines.
    (i) Multiple Test Potential for Non-Baseline Products. (1) When the 
composition information reported in the registration application or 
basic registration data for a gasoline or diesel product meets criteria 
for classification as a non-baseline product (pursuant to Sec. 
79.56(e)(3)(i)(B) or Sec. 79.56(e)(3)(ii)(B)), then the manufacturer is 
responsible for testing (or participating in group testing) of a 
separate formulation for each reported oxygenating compound, specified 
class of oxygenating compounds, or other substance which defines a 
separate non-baseline fuel/additive group pursuant to Sec. 
79.56(e)(4)(ii)(A) or (B). For each such substance, testing shall be 
performed on a mixture of the relevant substance in the appropriate base 
fuel, formulated according to the specifications for the corresponding 
group representatives in Sec. 79.56(e)(4)(ii).
    (2) When the composition information reported in the registration 
application or basic registration data for a non- baseline gasoline 
product contains a range of total oxygenate concentration-in-use which 
encompasses gasoline formulations with less than 1.5 weight percent 
oxygen as well as gasoline formulations with 1.5 weight percent oxygen 
or more, then the manufacturer is required to test (or participate in 
applicable group testing of) a baseline gasoline formulation as well as 
one or

[[Page 524]]

more non-baseline gasoline formulations as described in paragraph (h)(1) 
of this section.
    (3) When the composition information reported in the registration 
application or basic registration data for a non- baseline diesel 
product contains a range of total oxygenate concentration-in-use which 
encompasses diesel formulations with less than 1.0 weight percent oxygen 
as well as diesel formulations with 1.0 weight percent oxygen or more, 
then the manufacturer is required to test (or participate in applicable 
group testing) of a baseline diesel formulation as well as one or more 
non-baseline diesel formulations as described in paragraph (h)(1) of 
this section.
    (4) The presence in a particular oxygenating additive of small 
amounts of other unintended oxygenate compounds as byproducts of the 
manufacturing process of the given oxygenating additive does not affect 
the grouping of that additive and does not create multiple testing 
responsibilities for manufacturers who blend that additive into fuel.
    (j) Multiple Test Potential for Atypical Fuel Formulations. When the 
composition information reported in the registration application or 
basic registration data for a fuel product includes more than one 
atypical bulk additive product (pursuant to Sec. 79.56(e)(2)(iii)), and 
when these additives belong to different fuel/additive groups (pursuant 
to Sec. 79.56(e)(4)(iii)), then:
    (1) When such disparate additive products are for the same purpose-
in-use and are not ordinarily used in the fuel simultaneously, the fuel 
manufacturer shall be responsible for testing (or participating in the 
group testing of) a separate formulation for each such additive product. 
Testing related to each additive product shall be performed on a mixture 
of the additive in the applicable base fuel, as described in paragraph 
(g)(1) of this section, or by participation in the costs of testing the 
designated representative of the fuel/additive group to which each 
separate atypical additive product belongs.
    (2) When the disparate additive products are not for the same 
purpose-in-use, the fuel manufacturer shall nevertheless be responsible 
for testing a separate formulation for each such additive product, as 
described in paragraph (g)(1) of this section, if these additives are 
not ordinarily blended together in the same commercial formulation of 
the fuel.
    (3) When the disparate additive products are ordinarily blended 
together in the same commercial formulation of the fuel, then the fuel 
manufacturer shall be responsible for the testing of a single test 
formulation containing all such simultaneously used atypical additive 
products. Alternatively, this responsibility can be satisfied by 
enrolling such fuel product in a group which includes other fuel or 
additive products with the same total combination of atypical elements 
as that occurring in the fuel product in question. If the basic 
registration data for the subject fuel includes any alternative 
additives which contain atypical elements not represented in the test 
formulation, then the fuel manufacturer is also responsible for testing 
a separate formulation for each such additional disparate additive 
product.
    (k) Emission Control System Testing. If any information submitted in 
accordance with this subpart or any other information available to EPA 
shows that a fuel or fuel additive may have a deleterious effect on the 
performance of any emission control system or device currently in use or 
which has been developed to a point where in a reasonable time it would 
be in general use were such effect avoided, EPA may, in its judgment, 
require testing to determine whether such effects in fact exist. Such 
testing will be required in accordance with such protocols and schedules 
as the Administrator shall reasonably require and shall be paid for by 
the fuel or fuel additive manufacturer.

[59 FR 33093, June 27, 1994, as amended at 61 FR 36511, July 11, 1996; 
62 FR 12575, Mar. 17, 1997]



Sec. 79.52  Tier 1.

    (a) General Specifications. Tier 1 requires manufacturers of 
designated fuels or fuel additives (or groups of manufacturers pursuant 
to Sec. 79.56) to supply to the Administrator the identity and 
concentration of certain emission products of such fuels or additives

[[Page 525]]

and any available information regarding the health and welfare effects 
of the whole and speciated emissions of such fuels or additives. In 
addition to any information required under Sec. 79.59 and in 
conformance with the reporting requirements thereof, manufacturers shall 
provide, pursuant to the timing provisions of Sec. 79.51(c), the 
following information.
    (b) Emissions Characterization. Manufacturers must provide a 
characterization of the emission products which are generated by 
evaporation (if required pursuant to Sec. 79.58(b)) and by combustion 
of the fuel or additive/base fuel mixture in a motor vehicle. For this 
purpose, manufacturers may perform the characterization procedures 
described in this section or may rely on existing emission 
characterization data. To be considered adequate in lieu of performing 
new emission characterization procedures, the data must be the result of 
tests using the product in question or using a fuel or additive/base 
fuel mixture meeting the same grouping criteria as the product in 
question. In addition, the emissions must be generated in a manner 
reasonably similar to those described in Sec. 79.57, and the 
characterization procedures must be adequately performed and documented 
and must give results reasonably comparable to those which would be 
obtained by performing the procedures described herein. Reports of 
previous tests must be sufficiently detailed to allow EPA to judge the 
adequacy of protocols, techniques, and conclusions. After the 
manufacturer's submittal of such data, if EPA finds that the 
manufacturer has relied upon inadequate test data, then the manufacturer 
will not be considered to be in compliance until the corresponding tests 
have been conducted and the results submitted to EPA.
    (1) General Provisions. (i) The emissions to be characterized shall 
be generated, collected, and stored according to the processes described 
in Sec. 79.57. Characterization of combustion and evaporative emissions 
shall be performed separately on each emission sample collected during 
the applicable emission generation procedure.
    (ii) As provided in Sec. 79.57(d), if the emission generation 
vehicle/engine is ordinarily equipped with an emission aftertreatment 
device, then all requirements in this section for the characterization 
of combustion emissions must be completed both with and without the 
aftertreatment device in a functional state. The emissions shall be 
generated three times (on three different days) without a functional 
aftertreatment device and, if applicable, three times (on three 
different days) with a functional aftertreatment device, and each such 
time shall be analyzed according to the remaining provisions in this 
paragraph (b) of this section.
    (iii) Measurement of background emissions: It is required that 
ambient/dilution air be analyzed for levels of background chemical 
species present at the time of emissions sampling (for both combustion 
and evaporative emissions) and that sample values be corrected by 
substracting the concentrations contributed by the ambient/dilution air. 
Background chemical species measurement/analysis during the FTP is 
specified in Sec. Sec. 86.109-94(c)(5) and 86.135-94 of this chapter.
    (iv) Concentrations of emission products shall be reported either in 
units of grams per mile (g/mi) or grams per brake-horsepower/hour (g/
bhp-hr) (for chassis dynamometer and engine dynamometer test 
configurations, respectively), as well as in units of weight percent of 
measured total hydrocarbons.
    (v) Laboratory practice must be of high quality and must be 
consistent with state-of-the-art methods as presented in current 
environmental and analytical chemistry literature. Examples of 
analytical procedures which may be used in conducting the emission 
characterization/speciation requirements of this section can be found 
among the references in paragraph (b)(5) of this section.
    (2) Characterization of the combustion emissions shall include, for 
products in all fuel families (except when expressly noted in this 
section):
    (i) Determination of the concentration of the basic emissions as 
follows: total hydrocarbons, carbon monoxide, oxides of nitrogen, and 
particulates. Manufacturers are referred to the vehicle certification 
procedures in 40 CFR

[[Page 526]]

part 86, subparts B and D (Sec. Sec. 86.101 through 86.145 and 
Sec. Sec. 86.301 through 86.348) for guidance on the measurement of the 
basic emissions of interest to this subpart.
    (ii) Characterization of the vapor phase of combustion emissions, as 
follows:
    (A) Determination of the identity and concentration of individual 
species of hydrocarbon compounds containing 12 or fewer carbon atoms. 
Such characterization shall begin within 30 minutes after emission 
collection is completed.
    (B) Determination of the identity and concentration of individual 
species of aldehyde and ketone compounds containing eight or fewer 
carbon atoms. Characterization of these emissions captured in cartridges 
shall be performed within two weeks if the cartridge is stored at room 
temperature, and one month if the cartridge is stored at 0 C or less. 
If the emissions are sampled using the impinger method, the sample must 
be stored in a capped sample vial at 0 C or less and characterized 
within one week.
    (C) Determination of the identity and concentration of individual 
species of alcohol and ether compounds containing six or fewer carbon 
atoms, for those fuels and additive/base fuel mixtures which contain 
alcohol and/or ether compounds containing from one to six carbon atoms 
in the uncombusted state. For fuel and additive formulations containing 
alcohols or ethers with more than six carbon atoms in the uncombusted 
state, alcohol and ether species with that higher number of carbon atoms 
or less must be identified and measured in the emissions. Such 
characterization shall begin within four hours after emission collection 
is completed.
    (iii) Characterization of the semi-volatile and particulate phases 
of combustion emissions to identify and measure polycyclic aromatic 
compounds, as follows:
    (A) Analysis for polycyclic aromatic compounds shall not be 
conducted at or soon after the start of a recommended engine lubricant 
change interval.
    (B) Analysis for polycyclic aromatic hydrocarbons (PAHs) and 
nitrated polycyclic aromatic hydrocarbons (NPAHs), specified in 
paragraph (b)(2)(iii)(D) of this section, need not be done for any fuels 
and additives in the methane or propane fuel families, nor for fuels and 
additives in the atypical categories of any other fuel families, 
pursuant to the definitions of such families and categories in Sec. 
79.56.
    (C) Analysis for poly-chlorinated dibenzodioxins and dibenzofurans 
(PCDD/PCDFs), specified in paragraph (b)(2)(iii)(E) of this section, is 
required only for fuels and additives which contain chlorine as an 
atypical element, pursuant to paragraph (b)(2)(iv) of this section, 
which requires all individual emission products containing atypical 
elements to be determined for atypical fuels and additives. However, 
manufacturers of baseline and nonbaseline fuels and fuel additives in 
all fuel families, except those in the methane and propane fuel 
families, are strongly encouraged to conduct these analyses on a 
voluntary basis.
    (D) The analytical method used to measure species of PAHs and NPAHs 
should be capable of detecting at least 1 ppm (equivalent to 0.001 
microgram ([micro]g) of compound per milligram of organic extract) of 
these compounds in the extractable organic matter. The concentration of 
each individual PAH or NPAH compound identified shall be reported in 
units of microgram per mile or nanograms per brake-horsepower/hour (for 
chassis dynamometer and engine dynamometer test configurations, 
respectively). Each compound which is present at 0.001 [micro]g per mile 
(0.5 nanograms per brake-horsepower/hour) or more must be identified, 
measured, and reported. The following individual species shall be 
measured:
    (1) PAHs:
    (i) Benzo(a)anthracene;
    (ii) Benzo[b]fluoranthene;
    (iii) Benzo[k]fluoranthene;
    (iv) Benzo(a)pyrene;
    (v) Chrysene;
    (vi) Dibenzo[a,h]anthracene; and
    (vii) Indeno[1,2,3-c,d]pyrene.
    (2) NPAHs:
    (i) 7-Nitrobenzo[a]anthracene;
    (ii) 6-Nitrobenzo[a]pyrene;
    (iii) 6-Nitrochrysene;
    (iv) 2-Nitrofluorene; and
    (v) 1-Nitropyrene.

[[Page 527]]

    (E) The analytical method used to measure species and classes of 
PCDD/PCDFs should be capable of detecting at least 1 part per trillion 
(ppt) (equivalent to 0.001 picogram (pg) of compound per milligram of 
organic extract) of these compounds in the extractable organic matter. 
The concentration of each individual PCDD/PCDF compound identified shall 
be reported in units of picograms (pg) per mile or picograms per brake-
horsepower/hour (for chassis dynamometer and engine dynamometer test 
configurations, respectively). Each compound which is present at 0.5 pg/
mile (0.3 pg/bhp-hr) or more must be identified, measured, and reported.
    (1) With respect to measurement of PCDD/PCDFs only, the liquid 
extracts from the particulate and semi-volatile emissions fractions may 
be combined into one sample for analysis.
    (2) The manufacturer is referred to 40 CFR part 60, appendix A, 
Method 23 for a protocol which may be used to identify and measure any 
potential PCDD/PCDFs which might be present in exhaust emissions from a 
fuel or additive/base fuel mixture.
    (3) The following individual compounds and classes of compounds of 
PCDD/PCDFs shall be identified and measured:
    (i) Individual tetra-chloro-substituted dibenzodioxins (tetra-CDDs);
    (ii) Individual tetra-chloro-substituted dibenzofurans (tetra-CDFs);
    (iii) Penta-CDDs and penta-CDFs, as one class;
    (iv) Hexa-CDDs and hexa-CDFs, as one class;
    (v) Hepta-CDDs and hepta-CDFs as one class; and
    (vi) Octo-CDDs and octo-CDFs as one class.
    (iv) With respect to all phases (vapor, semi-volatile, and 
particulate) of combustion emissions generated from those fuels and 
additive/base fuel mixtures classified in the atypical categories 
(pursuant to Sec. 79.56), the identity and concentration of individual 
emission products containing such atypical elements shall also be 
determined.
    (3) For evaporative fuels and evaporative fuel additives, 
characterization of the evaporative emissions shall include:
    (i) Determination of the concentration of total hydrocarbons for the 
applicable vehicle type and class in 40 CFR part 86, subpart B 
(Sec. Sec. 86.101 through 86.145).
    (ii) Determination of the identity and concentration of individual 
species of hydrocarbon compounds containing 12 or fewer carbon atoms. 
Such characterization shall begin within 30 minutes after emission 
collection is completed.
    (iii) In the case of those fuels and additive/base fuel mixtures 
which contain alcohol and/or ether compounds in the uncombusted state, 
determination of the identity and concentration of individual species of 
alcohol and ether compounds containing six or fewer carbon atoms. For 
fuel and additive formulations containing alcohols or ethers with more 
than six carbon atoms in the uncombusted state, alcohol and ether 
species with that higher number of carbon atoms or less must be 
identified and measured in the emissions. Such characterization shall 
begin within four hours after emission collection is completed.
    (iv) In the case of those fuels and additive/base fuel mixtures 
which contain atypical elements, determination of the identity and 
concentration of individual emission products containing such atypical 
elements.
    (4) Laboratory quality control. (i) At a minimum, laboratories 
performing the procedures specified in this section shall conduct 
calibration testing of their emissions characterization equipment before 
each new fuel/additive product test start-up. Known samples 
representative of the compounds potentially to be found in emissions 
from the product to be characterized shall be used to calibrate such 
equipment.
    (ii) Laboratories performing the procedures specified in this 
section shall agree to permit quality control inspections by EPA, and 
for this purpose shall admit any EPA Enforcement Officer, upon proper 
presentation of credentials, to any facility where vehicles are 
conditioned or where emissions are generated, collected, stored, 
sampled, or characterized in meeting the requirements of this section. 
Such laboratory audits may include EPA distribution of ``blind'' samples 
for analysis by participating laboratories.

[[Page 528]]

    (5) References. For additional background information on the 
emission characterization procedures outlined in this paragraph, the 
following references may be consulted:
    (i) ``Advanced Emission Speciation Methodologies for the Auto/Oil 
Air Quality Improvement Program--I. Hydrocarbons and Ethers,'' Auto Oil 
Air Quality Improvement Research Program, SP-920, 920320, SAE, February 
1992.
    (ii) ``Advanced Speciation Methodologies for the Auto/Oil Air 
Quality Improvement Research Program--II. Aldehydes, Ketones, and 
Alcohols,'' Auto Oil Air Quality Improvement Research Program, SP-920, 
920321, SAE, February 1992.
    (iii) ASTM D 5197-91, ``Standard Test Method for Determination of 
Formaldehyde and Other Carbonyl Compounds in Air (Active Sampler 
Methodology).''
    (iv) Johnson J. H., Bagley, S. T., Gratz, L. D., and Leddy, D. G., 
``A Review of Diesel Particulate Control Technology and Emissions 
Effects--1992 Horning Memorial Award Lecture,'' SAE Technical Paper 
Series, SAE 940233, 1994.
    (v) Keith et al., ACS Committee on Environmental Improvement, 
``Principles of Environmental Analysis,'' The Journal of Analytical 
Chemistry, Volume 55, pp. 2210-2218, 1983.
    (vi) Perez, J.M., Jabs, R.E., Leddy, D.G., eds. ``Chemical Methods 
for the Measurement of Unregulated Diesel Emissions (CRC-APRAC Project 
No. CAPI-1-64), Coordinating Research Council, CRC Report No. 551, 
August, 1987.
    (vii) Schuetzle, D., ``Analysis of Nitrated Polycyclic Aromatic 
Hydrocarbons in Diesel Particulates,'' Analytical Chemistry, Volume 54, 
pp. 265-271, 1982.
    (viii) Siegl, W.O., et al., ``Improved Emissions Speciation 
Methodology for Phase II of the Auto/Oil Air Quality Improvement 
Research Program--Hydrocarbons and Oxygenates'', SAE Technical Paper 
Series, SAE 930142, 1993.
    (ix) Tejada, S. B. et al., ``Analysis of Nitroaromatics in Diesel 
and Gasoline Car Emissions,'' SAE Paper No. 820775, 1982.
    (x) Tejada, S. B. et al., ``Fluorescence Detection and 
Identification of Nitro Derivatives of Polynuclear Aromatic Hydrocarbons 
by On-Column Catalytic Reduction to Aromatic Amines,'' Analytical 
Chemistry, Volume 58, pp. 1827-1834, July 1986.
    (xi) ``Test Method for Determination of C1-C4 Alcohols and MTBE in 
Gasoline by Gas Chromatography,'' 40 CFR part 80, appendix F.
    (c) [Reserved]
    (d) Literature Search. (1) Manufacturers of fuels and fuel additives 
shall conduct a literature search and compilation of information on the 
potential toxicologic, environmental, and other public welfare effects 
of the emissions of such fuels and additives. The literature search 
shall include all available relevant information from in-house, 
industry, government, and public sources pertaining to the emissions of 
the subject fuel or fuel additive or the emissions of similar fuels or 
additives, with such similarity determined according to the provisions 
of Sec. 79.56.
    (2) The literature search shall address the potential adverse 
effects of whole combustion emissions, evaporative emissions, relevant 
emission fractions, and individual emission products of the subject fuel 
or fuel additive except as specified in the following paragraph. The 
individual emission products to be included are those identified 
pursuant to the emission characterization procedures specified in 
paragraph (b) of this section, other than carbon monoxide, carbon 
dioxide, nitrogen oxides, benzene, 1,3-butadiene, acetaldehyde, and 
formaldehyde.
    (3) In the case of the individual emission products of non-baseline 
or atypical fuels and additives (pursuant to Sec. 79.56(e)(2)), the 
literature data need not be submitted for those emission products which 
are the same as the combustion emission products of the respective base 
fuel for the product's fuel family (pursuant to Sec. 79.55). For this 
purpose, data on the base fuel emission products for the product's fuel 
family:
    (i) May be found in the literature of previously-conducted, adequate 
emission speciation studies for the base fuel, or for a fuel or 
additive/fuel mixture capable of grouping with the base

[[Page 529]]

fuel (see, for example, the references in paragraph (b)(5) of this 
section).
    (ii) May be compiled while gathering internal control data during 
emissions characterization studies on the manufacturer's non-baseline or 
atypical product; or
    (iii) May be obtained from various manufacturers in the course of 
their testing different additive(s) belonging to the same fuel family, 
or in the testing of a base fuel serving as representative of the 
baseline group for the respective fuel family.
    (e) Data bases. The literature search must include the results of 
searching appropriate commercially available chemical, toxicologic, and 
environmental databases. The databases shall be searched using, at a 
minimum, CAS numbers (when applicable), chemical names, and common 
synonyms.
    (f) Search period. The literature search shall cover a time period 
beginning at least thirty years prior to the date of submission of the 
reports specified in Sec. Sec. 79.59(b) through (c) and ending no 
earlier than six months prior to the date on which testing is commenced 
or reports are submitted in compliance with this subpart.
    (g) References. Information on base fuel emission inventories may be 
found in references in paragraphs (b)(5)(i) through (xi) of this 
section, as well as in the following:
    (1) Auto/Oil Air Quality Improvement Research Program, Technical 
Bulletin 1, December 1990.
    (2) Keith et al., ACS Committee on Environmental Improvement, 
``Principles of Environmental Analysis,'' The Journal of Analytical 
Chemistry, Volume 55, pp. 2210-2218, 1983.
    (3) ``The Composition of Gasoline Engine Hydrocarbon Emissions--An 
Evaluation of Catalyst and Fuel Effects''--SAE 902074 and ``Speciated 
Hydrocarbon Emissions from Aromatic, Olefin, and Paraffinic Model 
Fuels''--SAE 930373.

[59 FR 33093, June 27, 1994, as amended at 61 FR 36511, July 11, 1996; 
62 FR 12571, Mar. 17, 1997]



Sec. 79.53  Tier 2.

    (a) Generally. Subject to the provisions of Sec. 79.53(b) through 
(d), the combustion emissions of each fuel or fuel additive subject to 
testing under this subpart must be tested in accordance with each of the 
testing guidelines in Sec. Sec. 79.60 through 79.68, except that fuels 
and additives in the methane and propane fuel families (pursuant to 
Sec. 79.56(e)(1)(v) and (vi)) need not undergo the Salmonella 
mutagenicity assay in Sec. 79.68). Similarly, subject to the provisions 
of Sec. 79.53(b) through (d), the evaporative emissions of each 
designated evaporative fuel and each designated evaporative fuel 
additive subject to testing under this subpart must be tested according 
to each of the testing guidelines in Sec. Sec. 79.60 through 79.67 
(excluding Sec. 79.68, Salmonella typhimurium Reverse Mutation Assay).
    (b) Manufacturer Determination. Manufacturers shall determine 
whether the information gathered pursuant to the literature search in 
Sec. 79.52(d) contains the results of adequately performed and 
adequately documented previous testing which provides information 
reasonably comparable to that supplied by the health tests described in 
Sec. Sec. 79.62 through 79.68 regarding the carcinogenicity, 
mutagenicity, neurotoxicity, teratogenicity, reproductive/fertility 
measures, and general toxicity effects of the emissions of the fuel or 
additive. When manufacturers make an affirmative determination, they 
need submit only the information gathered pursuant to Sec. 79.52(d) for 
such tests. EPA maintains final authority in judging whether the 
information is an adequate substitution in lieu of conducting the 
associated tests. EPA's determination of the adequacy of existing 
information shall be guided by the considerations described in paragraph 
(d) of this section. If EPA finds that the manufacturer has relied upon 
inadequate test data, then the manufacturer will not be considered to be 
in compliance until the corresponding tests have been conducted and the 
results submitted to EPA.
    (c) Testing. (1) All testing required pursuant to this section must 
be done in accordance with the procedures, equipment, and facility 
requirements described in Sec. Sec. 79.57, 79.60, and 79.61 regarding 
emissions generation, good laboratory practices, and inhalation exposure 
testing, respectively, as well as any other requirements described in

[[Page 530]]

this subpart. The laboratory conducting the animal studies shall be 
registered and in good standing with the United States Department of 
Agriculture and regularly inspected by United States Department of 
Agriculture veterinarians. In addition, the facility must be accredited 
by a generally recognized independent organization which sets laboratory 
animal care standards. Use of inadequate test protocols or substandard 
laboratory techniques in performing any testing required by this subpart 
may result in cancellation of all affected registrations.
    (2) Carcinogenic or mutagenic effects in animals from emissions 
exposures shall be determined pursuant to Sec. 79.64 In vivo 
Micronucleus Assay, Sec. 79.65 In vivo Sister Chromatid Exchange Assay, 
and Sec. 79.68 Salmonella typhimurium Reverse Mutation Assay. 
Teratogenic effects and reproductive toxicity shall be examined pursuant 
to Sec. 79.63 Fertility Assessment/Teratology. General toxicity and 
pulmonary effects shall be determined pursuant to Sec. 79.62 Subchronic 
Toxicity Study with Specific Health Effect Assessments. Neurotoxic 
effects shall be determined pursuant to Sec. 79.66 Neuropathology 
Assessment and Sec. 79.67 Glial Fibrillary Acidic Protein Assay.
    (d) EPA Determination. (1) After submission of all information and 
testing, EPA in its judgment shall determine whether previously 
conducted tests relied upon in the registration submission are 
adequately performed and documented and provide information reasonably 
comparable to that which would be provided by the tests described 
herein. Manufacturers' submissions shall be sufficiently detailed to 
allow EPA to judge the adequacy of protocols, techniques, experimental 
design, statistical analyses, and conclusions. Studies shall be 
performed using generally accepted scientific principles, good 
laboratory techniques, and the testing guidelines specified in these 
regulations.
    (2) EPA shall give appropriate weight when making this determination 
to the following factors:
    (i) The age of the data;
    (ii) The adequacy of documentation of procedures, findings, and 
conclusions;
    (iii) The extent to which the testing conforms to generally accepted 
scientific principles and practices;
    (iv) The type and number of test subjects;
    (v) The number and adequacy of exposure concentrations, i.e., 
emission dilutions;
    (vi) The degree to which the tested emissions were generated by 
procedures and under conditions reasonably comparable to those set forth 
in Sec. 79.57; and
    (vii) The degree to which the test procedures conform to the testing 
guidelines set forth in Sec. Sec. 79.60 through 79.68 and/or furnish 
information comparable to that provided by such testing.
    (3) The test animals shall be rodents, preferably a strain of rat, 
and testing shall include all of the endpoints covered in Sec. Sec. 
79.62 through 79.68. All studies shall be properly executed, with 
appropriate documentation, and in accord with the individual health 
testing guidelines (Sec. Sec. 79.60 through 79.68) of this part, e.g., 
90-day, 6-hour per day exposure, minimum.
    (4) In general, the data in a manufacturer's registration submittal 
shall be adequate if the duration of a test's exposure period is at 
least as long, in days and hours, as the inhalation exposure specified 
in the related health test guideline(s). Data from tests with shorter 
exposure durations than those specified in the guidelines may be 
acceptable if the test results are positive (i.e., exhibit adverse 
effects) and/or include a demonstrable concentration-response 
relationship.
    (5) Data in support of a manufacturer's registration submittal shall 
directly address the effects of inhalation exposure to the whole 
evaporative and exhaust emissions of the respective fuel or additive or 
to the whole evaporative and exhaust emissions of other fuels or 
additives which satisfy the criteria in Sec. 79.56 for classification 
into the same group as the subject fuel or fuel additive. Data obtained 
in the testing of a raw liquid fuel or additive/base fuel mixture or a 
raw, aerosolized fuel or additive/base fuel mixture shall not be 
adequate to support a manufacturer's registration submittal. Data from 
testing of evaporative emissions

[[Page 531]]

cannot substitute for test data on combustion emissions. Data from 
testing of combustion emissions cannot substitute for test data on 
evaporative emissions.



Sec. 79.54  Tier 3.

    (a) General Criteria for Requiring Tier 3 Testing. (1) Tier 3 
testing shall be required of a manufacturer or group of manufacturers at 
EPA's discretion when remaining uncertainties as to the significance of 
observed health effects, welfare effects, and/or emissions exposures 
from a fuel or fuel/additive mixture interfere with EPA's ability to 
make reasonable estimates of the potential risks posed by emissions from 
the fuel or additive products. Tier 3 testing may be conducted either on 
an individual basis or a group basis. If performed on a group basis, EPA 
may require either the same representative to be used in Tier 3 testing 
as was used in Tier 2 testing or may select a different member or 
members of the group to represent the group in the Tier 3 tests.
    (2) In addition to the criteria specific to particular tests as 
summarized and detailed in the testing guidelines (Sec. Sec. 79.62 
through 79.68), EPA may consider a number of factors (including, but not 
limited to):
    (i) The number of positive and negative outcomes related to each 
endpoint;
    (ii) The identification of concentration-effect relationships;
    (iii) The statistical sensitivity and significance of such studies;
    (iv) The severity of the observed effects (e.g., whether the effects 
would be likely to lead to incapacitating or irreversible conditions);
    (v) The type and number of species included in the reported tests;
    (vi) The consistency and clarity of apparent mechanisms, target 
organs, and outcomes;
    (vii) The presence or absence of effective health test control data 
for base-fuel-only versus additive/base fuel mixture comparisons;
    (viii) The nature and amount of known toxic agents in the emissions 
stream; and
    (ix) The observation of lesions which specifically implicate 
inhalation as an important exposure route.
    (3) Consideration of exposure. EPA retains discretion to consider, 
in addition to available toxicity data, any Tier 1 data on potential 
exposures to emissions from a particular fuel or fuel additive (or group 
of fuels and/or fuel additives) in determining whether to require Tier 3 
testing. EPA may consider, but is not limited to, the following factors:
    (i) Types and emission rates of speciated emission components;
    (ii) Types and emission rates of combinations of compounds or 
elements of concern;
    (iii) Historical and/or projected production volumes and market 
distributions; and
    (iv) Estimated population and/or environmental exposures obtained 
through extrapolation, modeling, or literature search findings on 
ambient, occupational, or epidemiological exposures.
    (b) Notice. (1) EPA will determine whether Tier 3 testing is 
necessary upon receipt of a manufacturer's (or group's) submittal as 
prescribed under Sec. 79.51(d). If EPA determines on the basis of the 
Tier 1 and 2 data submission and any other available information that 
further testing is necessary, EPA will require the responsible 
manufacturer(s) to conduct testing as described elsewhere in this 
section. EPA will notify the manufacturer (or group) by certified letter 
of the purpose and nature of any proposed testing and of the proposed 
deadline for completing the testing. A copy of the letter will be placed 
in the public record. EPA will provide the manufacturer a 60-day comment 
period after the manufacturer's receipt of such notice. EPA may extend 
the comment period if it appears from the nature of the issues raised 
that further discussion is warranted. In the event that no comment is 
received by EPA from the manufacturer (or group) within the comment 
period, the manufacturer (or group) shall be deemed to have consented to 
the adoption by EPA of the proposed Tier 3 requirements.
    (2) EPA will issue a notice in the Federal Register of its intent to 
require testing under Tier 3 for a particular fuel or additive 
manufacturer and that a copy of the letter to the

[[Page 532]]

manufacturer outlining the Tier 3 testing for that manufacturer is 
available in the public record for review and comment. The public shall 
have a minimum of thirty (30) days after the publication of this notice 
to comment on the proposed Tier 3 testing.
    (3) EPA will include in the public record a copy of any timely 
comments concerning the proposed Tier 3 testing requirements received 
from the affected manufacturer or group or from the public, and the 
responses of EPA to such comments. After reviewing all such comments 
received, EPA will adopt final Tier 3 requirements by sending a 
certified letter describing such final requirements to the manufacturer 
or group. EPA will also issue a notice in the Federal Register 
announcing that it has adopted such final Tier 3 requirements and that a 
copy of the letter adopting the requirements has been included in the 
public record.
    (4) Prior to beginning any required Tier 3 testing, the manufacturer 
shall submit detailed test protocols to EPA for approval. Once EPA has 
determined the Tier 3 testing requirements and approves the test 
protocols, any modification to the requirements shall be governed by 
Sec. 79.51(f).
    (c) Carcinogenicity and Mutagenicity Testing. (1) A potential need 
for Tier 3 carcinogenicity and/or mutagenicity testing may be indicated 
if the results of the In vivo Micronucleus Assay, required under Sec. 
79.64, the In vivo Sister Chromatid Exchange Assay, required under Sec. 
79.65, the Salmonella mutagenicity assay required under Sec. 79.68, or 
relevant pathologic findings under Sec. 79.62 demonstrate a 
statistically significant dose-related positive response as compared 
with appropriate controls. Alternatively, Tier 3 carcinogenicity testing 
and/or mutagenicity testing may be required if there are positive 
outcomes for at least one concentration in two or more of the tests 
required under Sec. Sec. 79.64, 79.65, and 79.68.
    (2) The testing for carcinogenicity required under this paragraph 
may, at EPA's discretion, be conducted in accordance with 40 CFR 
798.3300 or 798.3320, or their equivalents (see suggested references 
following each health effects testing guideline). The testing for 
mutagenicity required under this paragraph may likewise be conducted in 
accordance with 40 CFR 798.5195, 798.5500, 798.5955, 798.7100, and/or 
other suitable equivalent testing (see suggested references following 
each health effects testing guideline). EPA may supplement or modify 
guidelines as required to ensure that the prescribed testing addresses 
the identified areas of concern.
    (d) Reproductive and Teratological Effects Testing. (1) A potential 
need for Tier 3 testing may be indicated if the results of the Fertility 
Assessment/Teratology study required under Sec. 79.63 or relevant 
findings under Sec. 79.62 demonstrate, in comparison with appropriate 
controls, a statistically significant dose-related positive response in 
one or more of the possible test outcomes. Similarly, Tier 3 testing may 
be indicated if statistically significant positive results are confined 
to either sex, or to the fetus as opposed to the pregnant adult.
    (2) The testing for reproductive and teratological effects required 
under this paragraph may, at EPA's discretion, be conducted in 
accordance with 40 CFR 798.4700 and/or by performance of a reproductive 
assay by continuous breeding. These guidelines may be modified or 
supplemented by EPA as required to ensure that the prescribed testing 
addresses the identified areas of concern.
    (e) Neurotoxicity Testing. (1) A potential need for Tier 3 
neurotoxicity testing may be indicated if either the results of the 
Neuropathology Assessment required under Sec. 79.67 shows 
concentration-related effects in exposed animals or the Glial Fibrillary 
Acidic Protein Assay required under Sec. 79.66 demonstrates a 
statistically significant concentration-related positive response as 
compared with appropriate controls. Similarly, Tier 3 neurotoxicity 
testing may be indicated if relevant results under Sec. 79.62 
demonstrate a statistically significant positive response in comparison 
to appropriate controls.
    (2) The testing for neurotoxicity required under this paragraph may, 
at EPA's discretion, be conducted in accordance with 40 CFR 798.3260 and 
40 CFR part 798 subpart G. These guidelines may be modified or 
supplemented

[[Page 533]]

by EPA as required to ensure that the prescribed testing addresses the 
identified areas of concern.
    (f) General and Pulmonary Toxicity Testing. (1) A potential need for 
Tier 3 general and/or pulmonary toxicity testing may be indicated if, in 
comparison with appropriate controls, the results of the Subchronic 
Toxicity Study, pursuant to Sec. 79.62, demonstrate abnormal gross 
analysis or histopathological findings (especially as relates to lung 
pathology from whole-body preserved test animals) or persistence or 
delayed occurrence of toxic effects beyond the exposure period.
    (2) A potential need for Tier 3 testing with respect to other organ 
systems or endpoints not addressed by specific Tier 2 tests, e.g., 
hepatic, renal, or endocrine toxicity, may be demonstrated by findings 
in the Tier 2 Subchronic Toxicity Study (pursuant to Sec. 79.62) or by 
findings in the Tier 1 literature search of adverse functional, 
physiologic, metabolic, or histopathologic effects of fuel or additive 
emissions to such other organ systems or any other information available 
to EPA. In addition, findings in the Tier 1 emission characterization of 
significant levels of a known toxicant to such other organ systems and 
endpoints may also indicate a need for relevant health effects testing. 
The testing required under this paragraph may include tests conducted in 
accordance with 40 CFR 798.3260 or 798.3320. These guidelines may be 
modified or supplemented by EPA as necessary to ensure that the 
prescribed testing addresses the identified areas of concern.
    (3) The testing for general/pulmonary toxicity required under this 
paragraph may, at EPA's discretion, be conducted in accordance with 40 
CFR 798.2450 or 798.3260. These guidelines may be modified or 
supplemented by EPA as necessary to ensure that the prescribed testing 
addresses the identified areas of concern. Pulmonary function 
measurements, host defense assays, immunotoxicity tests, cell 
morphology/morphometry, and/or enzyme assays of lung lavage cells and 
fluids may be specifically required.
    (g) Other Tier 3 Testing. (1) A manufacturer or group may be 
required to use up-to-date modeling, sampling, monitoring, and/or 
analytic approaches at the Tier 3 level to provide:
    (i) Estimates of exposures to the emission products of a fuel or 
fuel additive or group of products;
    (ii) The expected atmospheric transformation products of such 
emissions; and
    (iii) The environmental partitioning of such emissions to the air, 
soil, water, and biota.
    (2) Additional emission characterization may be required if 
uncertainty over the identity of chemical species or rate of their 
emission interferes with reasonable judgments as to the presence and/or 
concentration of potentially toxic substances in the emissions of a fuel 
or fuel additive. The required tests may include characterization of 
additional classes of emissions, the characterization of emissions 
generated by additional vehicles/engines of various technology mixes 
(e.g., catalyzed versus non-catalyzed emissions), and/or other more 
precise analytic procedures for identification or quantification of 
emissions compounds. Additional emissions testing may also be required 
to evaluate concerns which may arise regarding the potential effects of 
a fuel or fuel additive on the performance of emission control 
equipment.
    (3) A manufacturer or group may be required to conduct biological 
and/or exposure studies at the Tier 3 level to evaluate directly the 
potential public welfare or environmental effects of the emissions of a 
fuel or additive, if significant concerns about such effects arise as a 
result of EPA's review of the literature search or emission 
characterization findings in Tier 1 or the results of the toxicological 
tests in Tier 2.
    (4) With regard to group submittals, Tier 3 studies on a fuel or 
additive product(s) other than the originally specified group 
representative may be required if specific differences in the product's 
composition indicate that its emissions may have different toxicologic 
properties from those of the original group representative.

[[Page 534]]

    (5) Additional emission characterization and/or toxicologic tests 
may be required to evaluate the impact of different vehicle, engine, or 
emission control technologies on the observed composition or health or 
welfare effects of the emissions of a fuel or additive.
    (6) Toxicological tests on individual emission products may be 
required.
    (7) Upon review of information submitted for an aerosol product 
under Sec. 79.58(e), emissions characterization, exposure, and/or 
toxicologic testing at a Tier 3 level may be required.
    (8) A manufacturer which qualifies for and has elected to use the 
special provisions for the products of small businesses (pursuant to 
Sec. 79.58(d)) may be required to conduct emission characterization, 
exposure, and/or toxicologic studies at the Tier 3 level for such 
products, as specified in Sec. 79.58(d)(4).
    (9) The examples of potential Tier 3 tests described in this section 
do not in any way limit EPA's broad discretion and authority under Tier 
3.



Sec. 79.55  Base fuel specifications.

    (a) General Characteristics. (1) The base fuel(s) in each fuel 
family shall serve as the group representative(s) for the baseline 
group(s) in each fuel family pursuant to Sec. 79.56. Also, as specified 
in Sec. 79.51(h)(1), for fuel additives undergoing testing, the 
designated base fuel for the respective fuel family shall serve as the 
substrate in which the additive shall be mixed prior to the generation 
of emissions.
    (2) Base fuels shall contain a limited complement of the additives 
which are essential for the fuel's production or distribution and/or for 
the successful operation of the test vehicle/engine throughout the 
mileage accumulation and emission generation periods. Such additives 
shall be used at the minimum effective concentration-in-use for the base 
fuel in question.
    (3) Unless otherwise restricted, the presence of trace contaminants 
does not preclude the use of a fuel or fuel additive as a component of a 
base fuel formulation.
    (4) When an additive is the test subject, any additive normally 
contained in the base fuel which serves the same function as the subject 
additive shall be removed from the base fuel formulation. For example, 
if a corrosion inhibitor were the subject of testing and if this 
additive were to be tested in a base fuel which normally contained a 
corrosion inhibitor, this test additive would replace the corrosion 
inhibitor normally included as a component of the base fuel.
    (5) Additive components of the methanol, ethanol, methane, and 
propane base fuels in addition to any such additives included below 
shall be limited to those recommended by the manufacturers of the 
vehicles and/or engines used in testing such fuels. For this purpose, 
EPA will review requests from manufacturers (or their agents) to modify 
the additive specifications for the alternative fuels and, if necessary, 
EPA shall change these specifications based on consistency of those 
changes with the associated vehicle manufacturer's recommendations for 
the operation of the vehicle. EPA shall publish notice of any such 
changes to a base fuel and/or its base additive package specifications 
in the Federal Register.
    (b) Gasoline Base Fuel. (1) The gasoline base fuel is patterned 
after the reformulated gasoline summer baseline fuel as specified in CAA 
section 211(k)(10)(B)(i). The specifications and blending tolerances for 
the gasoline base fuel are listed in table F94-1. The additive types 
which shall be required and/or permissible in the gasoline base fuel are 
listed in table 1 as well.

               Table F94-1--Gasoline Base Fuel Properties
------------------------------------------------------------------------
 
------------------------------------------------------------------------
API Gravity..................................  57.4[0.3
Sulfur, ppm..................................  339[25
Benzene, vol%................................  1.53[0.3
RVP, psi.....................................  8.7[0.3
Octane, (R + M)/2............................  87.3[0.5
Distillation Parameters:
  10%, F.....................................  128[5
  50%, F.....................................  218[5
  90%, F.....................................  330[5
Aromatics, vol%..............................  32.0[2.7
Olefins, vol%................................  9.2[2.5
Saturates, vol%..............................  58.8[2.0
Additive Types:
  Required...................................  Deposit Control
                                               Corrosion Inhibitor
                                               Demulsifier
                                               Anti-oxidant
                                               Metal Deactivator
  Permissible................................  Anti-static
------------------------------------------------------------------------


[[Page 535]]

    (2) The additive components of the gasoline base fuel shall contain 
compounds comprised of no elements other than carbon, hydrogen, oxygen, 
nitrogen, and sulfur. Additives shall be used at the minimum 
concentration needed to perform effectively in the gasoline base fuel. 
In no case shall their concentration in the base fuel exceed the maximum 
concentration recommended by the additive manufacturer. The increment of 
sulfur contributed to the formulation by any additive shall not exceed 
15 parts per million sulfur by weight and shall not cause the gasoline 
base fuel to exceed the sulfur specifications in table F94-1 of this 
section.
    (c) Diesel Base Fuel. (1) The diesel base fuel shall be a 2 
diesel fuel having the properties and blending tolerances shown in table 
F94-2 of this section. The additive types which shall be permissible in 
diesel base fuel are presented in table F94-2 as well.

                Table F94-2--Diesel Base Fuel Properties
------------------------------------------------------------------------
 
------------------------------------------------------------------------
API Gravity..................................  33[1
Sulfur, wt%..................................  0.05[0.0025
Cetane Number................................  45.2[2
Cetane Index.................................  45.7[2
Distillation Parameters:
  10%, F.....................................  433[5
  50%, F.....................................  516[5
  90%, F.....................................  606[5
Aromatics, vol%..............................  38.4[2.7
Olefins, vol%................................  1.5[0.4
Saturates, vol%..............................  60.1[2.0
Additive Types:
  Required...................................  Corrosion Inhibitor
                                               Demulsifier
                                               Anti-oxidant
                                               Metal Deactivator
  Permitted..................................  Anti-static
                                               Flow Improver
  Not Permitted..............................  Deposit Control
------------------------------------------------------------------------

    (2) The additive components of the diesel base fuel shall contain 
compounds comprised of no elements other than carbon, hydrogen, oxygen, 
nitrogen, and sulfur. Additives shall be used at the minimum 
concentration needed to perform effectively in the diesel base fuel. In 
no case shall their concentration in the base fuel exceed the maximum 
concentration recommended by the additive manufacturer. The increment of 
sulfur contributed to the base fuel by additives shall not cause the 
diesel base fuel to exceed the sulfur specifications in table F94-2 of 
this section.
    (d) Methanol Base Fuels. (1) The methanol base fuels shall contain 
no elements other than carbon, hydrogen, oxygen, nitrogen, sulfur, and 
chlorine.
    (2) The M100 base fuel shall consist of 100 percent by volume 
chemical grade methanol.
    (3) The M85 base fuel is to contain 85 percent by volume chemical 
grade methanol, blended with 15 percent by volume gasoline base fuel 
meeting the gasoline base fuel specifications outlined in paragraph 
(b)(1) of this section. Manufacturers shall ensure the methanol 
compatibility of lubricating oils as well as fuel additives used in the 
gasoline portion of the M85 base fuel.
    (4) The methanol base fuels shall meet the specifications listed in 
table F94-3.

               Table F94-3--Methanol Base Fuel Properties
------------------------------------------------------------------------
 
------------------------------------------------------------------------
M100:
    Chemical Grade MeOH, vol%..................................      100
    Chlorine (as chlorides), wt%, max..........................   0.0001
    Water, wt%, max............................................      0.5
    Sulfur, wt%, max...........................................    0.002
M85
    Chemical Grade MeOH, vol%,.................................       85
    Gasoline Base Fuel, vol%...................................       15
    Chlorine (as chlorides), wt%, max..........................   0.0001
    Water, wt%, max............................................      0.5
    Sulfur, wt%, max...........................................    0.004
------------------------------------------------------------------------

    (e) Ethanol Base Fuel. (1) The ethanol base fuel, E85, shall contain 
no elements other than carbon, hydrogen, oxygen, nitrogen, sulfur, 
chlorine, and copper.
    (2) The ethanol base fuel shall contain 85 percent by volume 
chemical grade ethanol, blended with 15 percent by volume gasoline base 
fuel that meets the specifications listed in paragraph (b)(1) of this 
section. Additives used in the gasoline component of E85 shall be 
ethanol-compatible.
    (3) The ethanol base fuel shall meet the specifications listed in 
table F94-4.

                Table F94-4--Ethanol Base Fuel Properties
------------------------------------------------------------------------
 
------------------------------------------------------------------------
E85:
    Chemical Grade EtOH, vol%, min.............................       85
    Gasoline Base Fuel, vol%...................................       15
    Chlorine (as chloride), wt%, max...........................   0.0004
    Copper, mg/L, max..........................................     0.07
    Water, wt%, max............................................      0.5
    Sulfur, wt%, max...........................................    0.004
------------------------------------------------------------------------


[[Page 536]]

    (f) Methane Base Fuel. (1) The methane base fuel is a gaseous motor 
vehicle fuel marketed commercially as compressed natural gas (CNG), 
whose primary constituent is methane.
    (2) The methane base fuel shall contain no elements other than 
carbon, hydrogen, oxygen, nitrogen, and sulfur. The fuel shall contain 
an odorant additive for leak detection purposes. The added odorant shall 
be used at a level such that, at ambient conditions, the fuel must have 
a distinctive odor potent enough for its presence to be detected down to 
a concentration in air of not over \1/5\ (one-fifth) of the lower limit 
of flammability. After addition of the odorant, the methane base fuel 
shall contain no more than 16 ppm sulfur by volume.
    (3) The methane base fuel shall meet the specifications listed in 
table F94-5.

              Table F94-5--Methane Base Fuel Specifications
------------------------------------------------------------------------
 
------------------------------------------------------------------------
Methane, mole%, min.............................................    89.0
Ethane, mole%, max..............................................     4.5
Propane and higher HC, mole%, max...............................     2.3
C6 and higher HC, mole%, max....................................     0.2
Oxygen, mole%, max..............................................     0.6
Sulfur (including odorant additive) ppmv, max...................      16
Inert gases:
  Sum of CO2 and N2, mole%, max.................................     4.0
------------------------------------------------------------------------

    (g) Propane Base Fuel. (1) The propane base fuel is a gaseous motor 
vehicle fuel, marketed commercially as liquified petroleum gas (LPG), 
whose primary constituent is propane.
    (2) The propane base fuel may contain no elements other than carbon, 
hydrogen, oxygen, nitrogen, and sulfur. The fuel shall contain an 
odorant additive for leak detection purposes. The added odorant shall be 
used at a level such that at ambient conditions the fuel must have a 
distinctive odor potent enough for its presence to be detected down to a 
concentration in air of not over \1/5\ (one-fifth) of the lower limit of 
flammability. After addition of the odorant, the propane base fuel shall 
contain no more than 120 ppm sulfur by weight.
    (3) The propane base fuel shall meet the specifications listed in 
table F94-6.

              Table F94-6--Propane Base Fuel Specifications
------------------------------------------------------------------------
 
------------------------------------------------------------------------
Vapor pressure at 100-F, psig, max..............................     208
Evaporative temperature, 95%, F, max............................     -37
Propane, vol%, min..............................................    92.5
Propylene, vol%, max............................................     5.0
Butane and heavier, vol%, max...................................     2.5
Residue-evaporation of 100mL, max, mL...........................    0.05
Sulfur (including odorant additive) ppmw, max...................     123
------------------------------------------------------------------------



Sec. 79.56  Fuel and fuel additive grouping system.

    (a) Manufacturers of fuels and fuel additives are allowed to satisfy 
the testing requirements in Sec. Sec. 79.52, 79.53, and 79.54 and the 
associated reporting requirements in Sec. 79.59 on an individual or 
group basis, provided that such products meet the criteria in this 
section for enrollment in the same fuel/additive group. However, each 
manufacturer of a fuel or fuel additive must individually comply with 
the notification requirements of Sec. 79.59(b). Further, if a 
manufacturer elects to comply by participation in a group, each 
manufacturer continues to be individually subject to the information 
requirements of this subpart.
    (1) The use of the grouping provision to comply with Tier 1 and Tier 
2 testing requirements is voluntary. No manufacturer is prohibited from 
testing and submitting its own data for its own product registration, 
despite its qualification for membership in a particular group.
    (2) The only groups permitted are those established in this section.
    (b) Each manufacturer who chooses to enroll a fuel or fuel additive 
in a group of similar fuels and fuel additives as designated in this 
section may satisfy the registration requirements through a group 
submission of jointly-sponsored testing and analysis conducted on a 
product which is representative of all products in that group, provided 
that the group representative is chosen according to the specifications 
in this section.
    (1) The health effects information submitted by a group shall be 
considered applicable to all fuels and fuel additives in the group. A 
fuel or fuel additive manufacturer who has chosen to participate in a 
group may subsequently choose to perform testing of such fuel or fuel 
additive on an individual basis; however, until such independent 
registration information has

[[Page 537]]

been received and reviewed by EPA, the information initially submitted 
by the group on behalf of the manufacturer's fuel or fuel additive shall 
be considered applicable and valid for that fuel or fuel additive. It 
could therefore be used to support requirements for further testing 
under the provisions of Tier 3 or to support regulatory decisions 
affecting that fuel or fuel additive.
    (2) Manufacturers are responsible for determining the appropriate 
groups for their products according to the criteria in this section and 
for enrolling their products into those groups under industry-sponsored 
or other independent brokering arrangements.
    (3) Manufacturers who enroll a fuel or fuel additive into a group 
shall share the applicable costs according to appropriate arrangements 
established by the group. The organization and administration of group 
functions and the development of cost-sharing arrangements are the 
responsibility of the participating manufacturers. If manufacturers are 
unable to agree on fair and equitable cost sharing arrangements and if 
such dispute is referred by one or more manufacturers to EPA for 
resolution, then the provisions in Sec. 79.56(c) (1) and (2) shall 
apply.
    (c) In complying with the registration requirements for a given fuel 
or fuel additive, notwithstanding the enrollment of such fuel or 
additive in a group, a manufacturer may make use of available 
information for any product which conforms to the same grouping criteria 
as the given product. If, for this purpose, a manufacturer wishes to 
rely upon the information previously submitted by another manufacturer 
(or group of manufacturers) for registration of a similar product (or 
group of products), then the previous submitter is entitled to 
reimbursement by the manufacturer for an appropriate portion of the 
applicable costs incurred to obtain and report such information. Such 
entitlement shall remain in effect for a period of fifteen years 
following the date on which the original information was submitted. 
Pursuant to Sec. 79.59(b)(4)(ii), the manufacturer who relies on 
previously-submitted registration data shall certify to EPA that the 
original submitter has been notified and that appropriate reimbursement 
arrangements have been made.
    (1) When private efforts have failed to resolve a dispute about a 
fair amount or method of cost-sharing or reimbursement for testing costs 
incurred under this subpart, then any party involved in that dispute may 
initiate a hearing by filing two signed copies of a request for a 
hearing with a regional office of the American Arbitration Association 
and mailing a copy of the request to EPA. A copy must also be sent to 
each person from whom the filing party seeks reimbursement or who seeks 
reimbursement from that party. The information and fees to be included 
in the request for hearing are specified in 40 CFR 791.20(b) and (c).
    (2) Additional procedures and requirements governing the hearing 
process are those specified in 40 CFR 791.22 through 791.50, 791.60, 
791.85, and 791.105, excluding 40 CFR 791.39(a)(3) and 791.48(d).
    (d) Basis for classification. (1) Rather than segregating fuels and 
fuel additives into separate groups, the grouping system applies the 
same grouping criteria and creates a single set of groups applicable 
both to fuels and fuel additives.
    (2) Fuels shall be classified pursuant to Sec. 79.56(e) into 
categories and groups of similar fuels and fuel additives according to 
the components and characteristics of such fuels in their uncombusted 
state. The classification of a fuel product must take into account the 
components of all bulk fuel additives which are listed in the 
registration application or basic registration data submitted for the 
fuel product.
    (3) Fuel additives shall be classified pursuant to Sec. 79.56(e) 
into categories and groups of similar fuels and fuel additives according 
to the components and characteristics of the respective uncombusted 
additive/base fuel mixture pursuant to Sec. 79.51(h)(1).
    (4) In determining the category and group to which a fuel or fuel 
additive belongs, impurities present in trace amounts shall be ignored 
unless otherwise noted. Impurities are those substances which are 
present through contamination or which remain in the fuel

[[Page 538]]

or additive naturally after processing is completed.
    (5) Reference standards. (i) American Society for Testing and 
Materials (ASTM) standard D 4814-93a, ``Standard Specification for 
Automotive Spark-Ignition Engine Fuel'', used to define the general 
characteristics of gasoline fuels (paragraph (e)(3)(i)(A)(3) of this 
section) and ASTM standard D 975-93, ``Standard Specification for Diesel 
Fuel Oils'', used to define the general characteristics of diesel fuels 
(paragraph (e)(3)(ii)(A)(3) of this section) have been incorporated by 
reference.
    (ii) This incorporation by reference was approved by the Director of 
the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 
51. Copies may be obtained from the American Society for Testing and 
Materials (ASTM), 1916 Race Street, Philadelphia, PA 19103. Copies may 
be inspected at U.S. EPA, OAR, 401 M Street SW., Washington, DC 20460 or 
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.
    (e) Grouping criteria. The grouping system is represented by a 
matrix of three fuel/additive categories within six specified fuel 
families (see table F94-7, Grouping System for Fuels and Fuel 
Additives). Each category may include one or more groups. Within each 
group, a representative may be designated based on the criteria in this 
section and joint registration information may be developed and 
submitted for member fuels and fuel additives.

                                                Table F94-7--Grouping System for Fuels and Fuel Additives
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                        Conventional Fuel Families                                   Alternative Fuel Families
                                 -----------------------------------------------------------------------------------------------------------------------
            Category                                                                                              Methane (CNG, LNG)
                                     Gasoline (A)         Diesel (B)         Methanol (C)         Ethanol (D)             (E)          Propane (LPG) (F)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Baseline........................  One group           One group           Two groups: (1)     One group           One group           One group
                                   represented by      represented by      M100 group          (includes ethanol-  (includes both      represented by
                                   gasoline base       diesel base fuel.   (includes           gasoline            CNG and LNG),       LPG base fuel.
                                   fuel.                                   methanol-gasoline   formulations with   represented by
                                                                           formulations with   at least 50%        CNG base fuel.
                                                                           at least 96%        ethanol)
                                                                           methanol)           represented by
                                                                           represented by      E85 base fuel.
                                                                           M100 base fuel
                                                                           (2) M85 (includes
                                                                           methanol-gasoline
                                                                           formulations with
                                                                           50-95% methanol)
                                                                           represented by
                                                                           M85 base fuel.
Non-baseline....................  One group for each  One group for each  One group for each  One group for each  One group to        One group to
                                   gasoline-           oxygen-             individual non-     individual non-     include methane     include propane
                                   oxygenate blend     contributing        methanol, non-      ethanol, non-       formulations        formulations
                                   or each gasoline-   compound or class   gasoline            gasoline            exceeding the       exceeding the
                                   methanol/co-        of compounds; one   component and one   component and one   specified limit     specified limit
                                   solvent blend;      group for each      group for each      group for each      for non-methane     for butane and
                                   one group for       synthetic crude-    unique              unique              hydrocarbons.       higher
                                   each synthetic      derived fuel.       combination of      combination of                          hydrocarbons.
                                   crude-derived                           such components.    such components.
                                   fuel.
Atypical........................  One group for each  One group for each  One group for each  One group for each  One group for each  One group for each
                                   atypical element/   atypical element/   atypical element/   atypical element/   atypical element/   atypical element/
                                   characteristic,     characteristic,     characteristic,     characteristic,     characteristic,     characteristic,
                                   or unique           or unique           or unique           or unique           or unique           or unique
                                   combination of      combination of      combination of      combination of      combination of      combination of
                                   atypical elements/  atypical elements/  atypical elements/  atypical elements/  atypical elements/  atypical elements/
                                   characteristics.    characteristics.    characteristics.    characteristics.    characteristics.    characteristics.
--------------------------------------------------------------------------------------------------------------------------------------------------------


[[Page 539]]

    (1) Fuel families. Each of the following six fuel families (Table 
F94-7, columns A-F) includes fuels of the type referenced in the name of 
the family as well as bulk and aftermarket additives which are intended 
for use in those fuels. When applied to fuel additives, the criteria in 
these descriptions refer to the associated additive/base fuel mixture, 
pursuant to Sec. 79.51(h)(1). One or more base fuel formulations are 
specified for each fuel family pursuant to Sec. 79.55.
    (i) The Gasoline Family includes fuels composed of more than 50 
percent gasoline by volume and their associated fuel additives. The base 
fuel for this family is specified in Sec. 79.55(b).
    (ii) The Diesel Family includes fuels composed of more than 50 
percent diesel fuel by volume and their associated fuel additives. The 
Diesel fuel family includes both Diesel 1 and Diesel 2 
formulations. The base fuel for this family is specified in Sec. 
79.55(c).
    (iii) The Methanol Family includes fuels composed of at least 50 
percent methanol by volume and their associated fuel additives. The M100 
and M85 base fuels are specified in Sec. 79.55(d).
    (iv) The Ethanol Family includes fuels composed of at least 50 
percent ethanol by volume and their associated fuel additives. The base 
fuel for this family is E85 as specified in Sec. 79.55(e).
    (v) The Methane Family includes compressed natural gas (CNG) and 
liquefied natural gas (LNG) fuels containing at least 50 mole percent 
methane and their associated fuel additives. The base fuel for the 
family is a CNG formulation specified in Sec. 79.55(f).
    (vi) The Propane Family includes propane fuels containing at least 
50 percent propane by volume and their associated fuel additives. The 
base fuel for this family is a liquefied petroleum gas (LPG) as 
specified in Sec. 79.55(g).
    (vii) A manufacturer seeking registration for formulation(s) which 
do not fit the criteria for inclusion in any of the fuel families 
described in this section shall contact EPA at the address in Sec. 
79.59(a)(1) for further guidance in classifying and testing such 
formulation(s).
    (2) Fuel/additive categories. Fuel/additive categories (Table F94-7, 
rows 1-3) are subdivisions of fuel families which represent the degree 
to which fuels and fuel additives in the family resemble the base 
fuel(s) designated for the family. Three general category types are 
defined in this section. When applied to fuel additives, the criteria in 
these descriptions refer to the associated additive/base fuel mixture, 
pursuant to Sec. 79.51(h)(1).
    (i) Baseline categories consist of fuels and fuel additives which 
contain no elements other than those permitted in the base fuel for the 
respective fuel family and conform to specified limitations on the 
amounts of certain components or characteristics applicable to that fuel 
family.
    (ii) Non-Baseline Categories consist of fuels and fuel additives 
which contain no elements other than those permitted in the base fuel 
for the respective fuel family, but which exceed one or more of the 
limitations for certain specified components or characteristics 
applicable to baseline formulations in that fuel family.
    (iii) Atypical Categories consist of fuels and fuel additives which 
contain elements or classes of compounds other than those permitted in 
the base fuel for the respective fuel family or which otherwise do not 
meet the criteria for either baseline or non-baseline formulations in 
that fuel family. A fuel or fuel additive product having both non-
baseline and atypical characteristics pursuant to Sec. 79.56(e)(3), 
shall be considered to be an atypical product.
    (3) This section defines the specific categories applicable to each 
fuel family. When applied to fuel additives, the criteria in these 
descriptions refer to the associated additive/base fuel mixture, 
pursuant to Sec. 79.51(h)(1).
    (i) Gasoline Categories. (A) The Baseline Gasoline category contains 
gasoline fuels and associated additives which satisfy all of the 
following criteria:
    (1) Contain no elements other than carbon, hydrogen, oxygen, 
nitrogen, and/or sulfur.
    (2) Contain less than 1.5 percent oxygen by weight.
    (3) Sulfur concentration is limited to 1000 ppm per the 
specifications cited in the following paragraph.
    (4) Possess the physical and chemical characteristics of unleaded 
gasoline as

[[Page 540]]

specified by ASTM standard D 4814-93a (incorporated by reference, 
pursuant to paragraph (d)(5) of this section), in at least one Seasonal 
and Geographical Volatility Class.
    (5) Derived only from conventional petroleum, heavy oil deposits, 
coal, tar sands, and/or oil sands.
    (B) The Non-Baseline Gasoline category is comprised of gasoline 
fuels and associated additives which conform to the specifications in 
paragraph (e)(3)(i)(A) of this section for the Baseline Gasoline 
category except that they contain 1.5 percent or more oxygen by weight 
and/or may be derived from sources other than those listed in paragraph 
(e)(3)(i)(A)(5) of this section.
    (C) The Atypical Gasoline category is comprised of gasoline fuels 
and associated additives which contain one or more elements other than 
carbon, hydrogen, oxygen, nitrogen, and sulfur.
    (ii) Diesel Categories. (A) The Baseline Diesel category is 
comprised of diesel fuels and associated additives which satisfy all of 
the following criteria:
    (1) Contain no elements other than carbon, hydrogen, oxygen, 
nitrogen, and/or sulfur. Pursuant to 40 CFR 80.29, highway diesel sold 
after October 1, 1993 shall contain 0.05 percent or less sulfur by 
weight;
    (2) Contain less than 1.0 percent oxygen by weight;
    (3) Diesel formulations containing more than 0.05 percent sulfur by 
weight are precluded by 40 CFR 80.29;
    (4) Possess the characteristics of diesel fuel as specified by ASTM 
standard D 975-93 (incorporated by reference, pursuant to paragraph 
(d)(5) of this section); and
    (5) Derived only from conventional petroleum, heavy oil deposits, 
coal, tar sands, and/or oil sands.
    (B) The Non-Baseline Diesel category is comprised of diesel fuels 
and associated additives which conform to the specifications in 
paragraph (e)(3)(ii)(A) of this section for the Baseline Diesel category 
except that they contain 1.0 percent or more oxygen by weight and/or may 
be derived from sources other than those listed in paragraph 
(e)(3)(ii)(A)(5) of this section.
    (C) The Atypical Diesel category is comprised of diesel fuels and 
associated additives which contain one or more elements other than 
carbon, hydrogen, oxygen, nitrogen, and sulfur.
    (iii) Methanol categories. (A) The Baseline Methanol category is 
comprised of methanol fuels and associated additives which contain at 
least 50 percent methanol by volume, no more than 4.0 percent by volume 
of substances other than methanol and gasoline, and no elements other 
than carbon, hydrogen, oxygen, nitrogen, sulfur, and/or chlorine. 
Baseline methanol shall contain no more than 0.004 percent by weight of 
sulfur or 0.0001 percent by weight of chlorine.
    (B) The Non-Baseline Methanol category is comprised of fuel blends 
which contain at least 50 percent methanol by volume, more than 4.0 
percent by volume of a substance(s) other than methanol and gasoline, 
and meet the baseline limitations on elemental composition in paragraph 
(e)(3)(iii)(A) of this section.
    (C) The Atypical Methanol category consists of methanol fuels and 
associated additives which do not meet the criteria for either the 
Baseline or the Non-Baseline Methanol category.
    (iv) Ethanol categories. (A) The Baseline Ethanol category is 
comprised of ethanol fuels and associated additives which contain at 
least 50 percent ethanol by volume, no more than five (5) percent by 
volume of substances other than ethanol and gasoline, and no elements 
other than carbon, hydrogen, oxygen, nitrogen, sulfur, chlorine, and 
copper. Baseline ethanol formulations shall contain no more than 0.004 
percent by weight of sulfur, 0.0004 percent by weight of chlorine, and/
or 0.07 mg/L of copper.
    (B) The Non-Baseline Ethanol category is comprised of fuel blends 
which contain at least 50 percent ethanol by volume, more than five (5) 
percent by volume of a substance(s) other than ethanol and gasoline, and 
meet the baseline limitations on elemental composition in paragraph 
(e)(3)(iv)(A) of this section.
    (C) The Atypical Ethanol category consists of ethanol fuels and 
associated additives which do not meet the criteria for either the 
Baseline or the Non-Baseline Ethanol categories.
    (v) Methane categories. (A) The Baseline Methane category is 
comprised of

[[Page 541]]

methane fuels and associated additives (including at least an odorant 
additive) which contain no elements other than carbon, hydrogen, oxygen, 
nitrogen, and/or sulfur, and contain no more than 20 mole percent non-
methane hydrocarbons. Baseline methane formulations shall not contain 
more than 16 ppm by volume of sulfur, including any sulfur which may be 
contributed by the odorant additive.
    (B) The Non-Baseline Methane category consists of methane fuels and 
associated additives which conform to the specifications in paragraph 
(e)(3)(v)(A) of this section for the Baseline Methane category except 
that they exceed 20 mole percent non-methane hydrocarbons.
    (C) The Atypical Methane category consists of methane fuels and 
associated additives which contain one or more elements other than 
carbon, hydrogen, oxygen, nitrogen, and/or sulfur, or exceed 16 ppm by 
volume of sulfur.
    (vi) Propane categories. (A) The Baseline Propane category is 
comprised of propane fuels and associated additives (including at least 
an odorant additive) which contain no elements other than carbon, 
hydrogen, oxygen, nitrogen, and/or sulfur, and contain no more than 20 
percent by volume non-propane hydrocarbons. Baseline Propane 
formulations shall not contain more than 123 ppm by weight of sulfur, 
including any sulfur which may be contributed by the odorant additive.
    (B) The Non-Baseline Propane category consists of propane fuels and 
associated additives which conform to the specifications in paragraph 
(e)(3)(vi)(A) of this section for the Baseline Propane category, except 
that they exceed the 20 percent by volume limit for butane and higher 
hydrocarbons.
    (C) The Atypical Propane category consists of propane fuels and 
associated additives which contain elements other than carbon, hydrogen, 
oxygen, nitrogen, and/or sulfur, or exceed 123 ppm by weight of sulfur.
    (4) Fuel/additive groups. Fuel/additive groups are subdivisions of 
the fuel/additive categories. One or more group(s) are defined within 
each category in each fuel family according to the presence of differing 
characteristics in the fuel or additive/base fuel mixture. For each 
group, one formulation (either a base fuel or a member fuel or additive 
product) is chosen to represent all the member products in the group in 
any tests required under this subpart. The section which follows 
describes the fuel/additive groups.
    (i) Baseline groups. (A) The Baseline Gasoline category comprises a 
single group. The gasoline base fuel specified in Sec. 79.55(b) shall 
serve as the representative of this group.
    (B) The Baseline Diesel category comprises a single group. The 
diesel base fuel specified in Sec. 79.55(c) shall serve as the 
representative of this group.
    (C) The Baseline Methanol category includes two groups: M100 and 
M85. The M100 group consists of methanol-gasoline formulations 
containing at least 96 percent methanol by volume. These formulations 
must contain odorants and bitterants (limited in elemental composition 
to carbon, hydrogen, oxygen, nitrogen, sulfur, and chlorine) for 
prevention of purposeful or inadvertent consumption. The M100 base fuel 
specified in Sec. 79.55(d) shall serve as the representative for this 
group. The M85 group consists of methanol-gasoline formulations 
containing at least 50 percent by volume but less than 96 percent by 
volume methanol. The M85 base fuel specified in Sec. 79.55(d) shall 
serve as the representative of this group.
    (D) The Baseline Ethanol category comprises a single group. The E85 
base fuel specified in Sec. 79.55(e) shall serve as the representative 
of this group.
    (E) The Baseline Methane category comprises a single group. The CNG 
base fuel specified in Sec. 79.55(f) shall serve as the representative 
of this group.
    (F) The Baseline Propane category comprises a single group. The LPG 
base fuel specified in Sec. 79.55(g) shall serve as the representative 
of this group.
    (ii) Non-baseline groups--(A) Non-Baseline Gasoline. The Non-
Baseline gasoline fuels and associated additives shall sort into groups 
according to the following criteria:
    (1) For gasoline fuel and additive products which contain 1.5 
percent oxygen by weight or more, a separate non-

[[Page 542]]

baseline gasoline group shall be defined by each oxygenate compound or 
methanol/co-solvent blend listed as a component in the registration 
application or basic registration data of any such fuel or additive.
    (i) Examples of oxygenates occurring in non-baseline gasoline 
formulations include ethanol, methyl tertiary butyl ether (MTBE), ethyl 
tertiary butyl ether (ETBE), tertiary amyl methyl ether (TAME), 
diisopropyl ether (DIPE), dimethyl ether (DME), tertiary amyl ethyl 
ether (TAEE), and any other compound(s) which increase the oxygen 
content of the gasoline formulation. A separate non-baseline gasoline 
group is defined for each such oxygenating compound.
    (ii) Each unique methanol and co-solvent combination (whether one, 
two, or more additional oxygenate compounds) used in a non-baseline fuel 
shall also define a separate group. An oxygenate compound used as a co-
solvent for methanol in a non-baseline gasoline formulation must be 
identified as such in its registration. If the oxygenate is not 
identified as a methanol co-solvent, then the compound shall be regarded 
by EPA as defining a separate non-baseline gasoline group. Examples of 
methanol/co-solvent combinations occurring in non-baseline gasoline 
formulations include methanol/isopropyl alcohol, methanol/butanol, and 
methanol with alcohols up to C8/octanol (Octamix).
    (iii) For each such group, the representative to be used in testing 
shall be a formulation consisting of the gasoline base fuel blended with 
the relevant oxygenate compound (or methanol/co-solvent combination) in 
an amount equivalent to the highest actual or recommended concentration-
in-use of the oxygenate (or methanol/co-solvent combination) recorded in 
the basic registration data of any member fuel or additive product. In 
the event that two or more products in the same group contain the same 
and highest amount of the oxygenate or methanol/co-solvent blend, then 
the representative shall be chosen at random for such candidate 
products.
    (2) An oxygenate compound or methanol/co-solvent combination to be 
blended with the gasoline base fuel for testing purposes shall be 
chemical-grade quality, at a minimum, and shall not contain a 
significant amount of other contaminating oxygenate compounds.
    (3) Separate non-baseline gasoline groups shall also be defined for 
gasoline formulations derived from each particular petroleum source not 
listed in paragraph (e)(3)(i)(A)(5) of this section.
    (i) Such groups may include, but are not limited to, those derived 
from shale, used oil, waste plastics, and other recycled chemical/
petrochemical products.
    (4) Pursuant to Sec. 79.51(i), non-baseline gasoline products may 
belong to more than one fuel/additive group.
    (B) Non-Baseline Diesel. The Non-Baseline diesel fuels and 
associated additives shall sort into groups according to the following 
criteria:
    (1) For diesel fuel and additive products which contain 1.0 percent 
or more oxygen by weight in the form of alcohol(s) and/or ether(s):
    (i) A separate non-baseline diesel group shall be defined by each 
individual alcohol or ether listed as a component in the registration 
application or basic registration data of any such fuel or additive.
    (ii) For each such group, the representative to be used in testing 
shall be a formulation consisting of the diesel base fuel blended with 
the relevant alcohol or ether in an amount equivalent to the highest 
actual or recommended concentration-in-use of the alcohol or ether 
recorded in the basic registration data of any member fuel or additive 
product.
    (2) A separate non-baseline diesel group is also defined for each of 
the following classes of oxygenating compounds: mixed nitroso-compounds; 
mixed nitro-compounds; mixed alkyl nitrates; mixed alkyl nitrites; 
peroxides; furans; mixed alkyl esters of plant and/or animal origin 
(biodiesel). For each such group, the representative to be used in 
testing shall be formulated as follows:
    (i) From the class of compounds which defines the group, a 
particular oxygenate compound shall be chosen from among all such 
compounds recorded in the registration application

[[Page 543]]

or basic registration data of any fuel or additive in the group.
    (ii) The selected compound shall be the one recorded in any member 
product's registration application with the highest actual or 
recommended maximum concentration-in-use.
    (iii) In the event that two or more oxygenate compounds in the 
relevant class have the highest recorded concentration-in-use, then the 
oxygenate compound to be used in the group representative shall be 
chosen at random from the qualifying candidate compounds.
    (iv) The compound thus selected shall be the group representative, 
and shall be used in testing at the following concentration:
    (A) For biodiesel groups, the representative shall be 100 percent 
biodiesel fuel.
    (B) Otherwise, the group representative shall be the selected 
compound mixed into diesel base fuel at the maximum recommended 
concentration-in-use.
    (3) Separate non-baseline diesel groups shall also be defined for 
diesel formulations derived from each particular petroleum source not 
listed in paragraph (e)(3)(i)(A)(5) of this section.
    (i) Such groups may include, but are not limited to, those derived 
from shale, used oil, waste plastics, and other recycled chemical/
petrochemical products.
    (ii) In any such group, the first product to be registered or to 
apply for EPA registration shall be the representative of that group. If 
two or more products are registered or apply for first registration 
simultaneously, then the representative shall be chosen by a random 
method from among such candidate products.
    (4) Pursuant to Sec. 79.51(i), non-baseline diesel products may 
belong to more than one fuel/additive group.
    (C) Non-baseline methanol. The Non-Baseline methanol formulations 
are sorted into groups based on the non-methanol, non-gasoline 
component(s) of the blended fuel. Each such component occurring 
separately and each unique combination of such components shall define a 
separate group.
    (1) The representative of each such non-baseline methanol group 
shall be the group member with the highest percent by volume of non-
methanol, non-gasoline component(s).
    (2) In case two or more such members have the same and highest 
concentration of non-methanol, non-gasoline component(s), the 
representative of the group shall be chosen at random from among such 
equivalent member products.
    (D) Non-Baseline Ethanol. The Non-Baseline ethanol formulations are 
sorted into groups based on the non-ethanol, non-gasoline component(s) 
of the blended fuel. Each such component occurring separately and each 
unique combination of such components shall define a separate group.
    (1) The representative of each such non-baseline ethanol group shall 
be the group member with the highest percent by volume of non-ethanol, 
non-gasoline component(s).
    (2) In case two or more such members have the same and highest 
concentration of non-ethanol, non-gasoline component(s), the 
representative of the group shall be chosen at random from among such 
equivalent member products.
    (E) Non-Baseline Methane. The Non-Baseline methane category consists 
of one group. The group representative shall be the member fuel or fuel/
additive formulation containing the highest concentration-in-use of non-
methane hydrocarbons. If two or more member products have the same and 
the highest concentration-in-use, then the representative shall be 
chosen at random from such products.
    (F) Non-baseline propane. The Non-Baseline propane category consists 
of one group. The group representative shall be the member fuel or fuel/
additive formulation containing the highest concentration-in-use of 
butane and higher hydrocarbons. If two or more products have the same 
and the highest concentration-in-use, then the representative shall be 
chosen at random from such products.
    (iii) Atypical groups. (A) As defined for each individual fuel 
family in Sec. 79.56(e)(3), fuels and additives meeting any one of the 
following criteria are considered atypical.
    (1) Gasoline Atypical fuels and additives contain one or more 
elements in

[[Page 544]]

addition to carbon, hydrogen, oxygen, nitrogen, and sulfur.
    (2) Diesel Atypical fuels and additives contain one or more element 
in addition to carbon, hydrogen, oxygen, nitrogen, and sulfur.
    (3) Methanol Atypical fuels and additives contain:
    (i) one or more element in addition to carbon, hydrogen, oxygen, 
nitrogen, sulfur, and chlorine, and/or
    (ii) sulfur in excess of 0.004 percent by weight, and/or
    (iii) chlorine in excess of 0.0001 percent by weight.
    (4) Ethanol Atypical fuels and additives contain:
    (i) one or more element in addition to carbon, hydrogen, oxygen, 
nitrogen, sulfur, chlorine, and copper, and/or
    (ii) sulfur in excess of 0.004 percent by weight, and/or
    (iii) contain chlorine (as chloride) in excess of 0.0004 percent by 
weight, and/or
    (iv) contain copper in excess of 0.07 mg/L.
    (5) Methane Atypical fuels and additives contain:
    (i) one or more element in addition to carbon, hydrogen, oxygen, 
nitrogen, and sulfur, and/or
    (ii) sulfur in excess of 16 ppm by volume.
    (6) Propane Atypical fuels and additives contain:
    (i) one or more element in addition to carbon, hydrogen, oxygen, 
nitrogen, and sulfur, and/or
    (ii) sulfur in excess of 123 ppm by weight.
    (B) General rules for sorting these atypical fuels and additives 
into separate groups are as follows:
    (1) Pursuant to Sec. 79.51(j), a given atypical product may belong 
to more than one atypical group.
    (2) Fuels and additives in different fuel families may not be 
grouped together, even if they contain the same atypical element(s) or 
other atypical characteristic(s).
    (3) A fuel or additive containing one or more atypical elements 
attached to a polymer compound must be sorted into a separate group from 
atypical fuels or fuel additives containing the same atypical element(s) 
in non-polymer form. However, the occurrence of a polymer compound which 
does not contain an atypical element does not affect the grouping of a 
fuel or additive.
    (C) Specific rules for sorting each family's atypical fuels and 
additives into separate groups, and for choosing each such group's 
representative for testing, are as follows:
    (1) A separate group is created for each atypical element (or other 
atypical characteristic) occurring separately, i.e., in the absence of 
any other atypical element or characteristic, in one or more fuels and/
or additives within a given fuel family.
    (i) Consistent with the basic grouping guidelines provided in Sec. 
79.56(d), a fuel product which is classified as atypical because its 
basic registration data or application lists a bulk additive containing 
an atypical characteristic, may be grouped with that additive and/or 
with other fuels and additives containing the same atypical 
characteristic.
    (ii) Within a group of products containing only one atypical element 
or characteristic, the fuel or additive/base fuel mixture with the 
highest concentration-in-use or recommended concentration-in-use of the 
atypical element or characteristic shall be the designated 
representative of that group. In the event that two or more fuels or 
additive/base fuel mixtures within the group contain the same and 
highest concentration of the single atypical element or characteristic, 
then the group representative shall be selected by a random method from 
among such candidate products.
    (2) A separate group is also created for each unique combination of 
atypical elements (and/or other specified atypical characteristics) 
occurring together in one or more fuels and/or additives within a given 
fuel family.
    (i) Consistent with the basic grouping guidelines provided in Sec. 
79.56(d), a fuel which is classified as atypical because its basic 
registration data lists one bulk additive containing two or more 
atypical characteristics, may be grouped with that additive and/or with 
other fuels and/or additives containing

[[Page 545]]

the same combination of atypical characteristics. Grouping of fuels 
containing more than one atypical additive shall be guided by provisions 
of Sec. 79.51(j).
    (ii) Within a group of such products containing a unique combination 
of two or more atypical elements or characteristics, the designated 
representative shall be the product within the group which contains the 
highest total concentration of the atypical elements or characteristics.
    (iii) In the event that two or more products within a given atypical 
group contain the same and highest concentration of the same atypical 
elements or characteristics then, among such candidate products, the 
designated representative shall be the product which, first, has the 
highest total concentration of metals, followed in order by highest 
total concentration of halogens, highest total concentration of other 
atypical elements (including sulfur concentration, as applicable), 
highest total concentration of polymers containing atypical elements, 
and, lastly, highest total concentration of oxygen.
    (iv) If two or more products have the same and highest concentration 
of the variable identified in the preceding paragraph, then, among such 
products, the one with the greatest concentration of the next highest 
variable on the list shall be the group representative.
    (v) This decision-making process shall continue until a single 
product is determined to be the representative. If two or more products 
remain tied at the end of this process, then the representative shall be 
chosen by a random method from among such remaining products.

[59 FR 33093, June 27, 1994, as amended at 62 FR 12571, Mar. 17, 1997]



Sec. 79.57  Emission generation.

    This section specifies the equipment and procedures that must be 
used in generating the emissions which are to be subjected to the 
characterization procedures and/or the biological tests specified in 
Sec. Sec. 79.52(b) and 79.53 of these regulations. When applicable, 
they may also be required in conjunction with testing under Sec. Sec. 
79.54 and 79.58(c). Additional requirements concerning emission 
generation, delivery, dilution, quality control, and safety practices 
are outlined in Sec. 79.61.
    (a) Vehicle and engine selection criteria. (1) All vehicles and 
engines used to generate emissions for testing a fuel or additive/fuel 
mixture must be new (i.e., never before titled) and placed into the 
program with less than 500 miles on the odometer or 12 hours on the 
engine chronometer. The vehicles and engines shall be unaltered from the 
specifications of the original equipment manufacturer.
    (2) The vehicle/engine type, vehicle/engine class, and vehicle/
engine subclass designated to generate emissions for a given fuel or 
additive shall be the same type, class, and subclass which, over the 
previous three years, has consumed the most gallons of fuel in the fuel 
family applicable to the given fuel or additive. No distinction shall be 
made between light-duty vehicles and light-duty trucks for purposes of 
this classification.
    (3) Within this vehicle/engine type, class, and subclass, the 
specific vehicles and engines acceptable for emission generation are 
those that represent the most common fuel metering system and the most 
common of the most important emission control system devices or 
characteristics with respect to emission reduction performance for the 
model year in which testing begins. These vehicles will be determined 
through a survey of the previous model year's vehicle/engine sales 
within the given subclass. These characteristics shall include, but need 
not be limited to, aftertreatment device(s), fuel aspiration, air 
injection, exhaust gas recirculation, and feedback type.
    (4) Within the applicable subclass, the five highest selling 
vehicle/engine models that contain the most common such equipment and 
characteristics shall be determined. Any of these five models of the 
current model year (at the time testing begins) may be selected for 
emission generation.
    (i) If one or more of the five models is not available for the 
current model year, the choice of model for emission generation shall be 
limited to those remaining among the five.
    (ii) If fewer than five models of the given vehicle/engine type are 
available

[[Page 546]]

for the current model year, all such models shall be eligible.
    (5) When the fuel or fuel additive undergoing testing is not 
commonly used or intended to be used in the vehicle/engine types 
prescribed by this selection procedure, or when rebuilding or alteration 
is required to obtain a suitable vehicle/engine for emission generation, 
the manufacturer may submit a request to EPA for a modification in test 
procedure requirements. Any such request must include objective test 
results which support the claim that a more appropriate vehicle/engine 
type is needed as well as a suggested substitute vehicle/engine type. 
The vehicle/engine selection in this case shall be approved by EPA prior 
to the start of testing.
    (6) Once a particular model has been chosen on which to test a fuel 
or additive product, all mileage accumulation and generation of 
emissions for characterization and biological testing of such product 
shall be conducted on that same model.
    (i) If the initial test vehicle/engine fails or must be replaced for 
any reason, emission generation shall continue with a second vehicle/
engine which is identical to, or resembles to the greatest extent 
possible, the initial test vehicle/engine. If more than one replacement 
vehicle/engine is necessary, all such vehicles/engines shall be 
identical, or resemble to the greatest extent possible, the initial test 
vehicle/engine.
    (ii) Manufacturers are encouraged to obtain, at the start of a test 
program, more than one emission generation vehicle/engine of the 
identical model, to ensure the availability of back-up emission 
generator(s). All backup vehicles/engines must be conditioned and must 
have their emissions fully characterized, as done for the initial test 
vehicle/engine, prior to their use as emission generators for biological 
testing. Alternating between such vehicles/engines regularly during the 
course of testing is permissible and advisable, particularly to allow 
regular maintenance on such vehicles/engines during prolonged health 
effects testing.
    (b) Vehicle/engine operation and maintenance. (1) For the purpose of 
generating combustion emissions from a fuel or additive/base fuel 
mixture for which the relevant class is light duty, either a light-duty 
vehicle shall be operated on a chassis dynamometer or a light-duty 
engine shall be operated on an engine dynamometer. When the relevant 
class is heavy duty, the emissions shall be generated on a heavy-duty 
engine operated on an engine dynamometer. In both cases, the vehicle or 
engine model shall be selected as described in paragraph (a) of this 
section and shall have all applicable fuel and emission control systems 
intact.
    (2) Except as provided in Sec. 79.51(h)(2)(iii), the fuel or 
additive/base fuel mixture being tested shall be used at all times 
during operation of the test vehicle or engine. No other fuels or 
additives shall be used in the test vehicle or engine once mileage 
accumulation has begun until emission generation for emission 
characterization and biological testing purposes is completed.
    (i) A vehicle or engine may be used to generate emissions for the 
testing of more than one fuel or additive, provided that all such fuels 
and additives belong to the same fuel family pursuant to Sec. 
79.56(e)(i), and that, once a vehicle or engine has been used to 
generate emissions for an atypical fuel or additive (pursuant to Sec. 
79.56(e)(2)(iii)), it shall not be used in the testing of any other fuel 
or additive. Paragraphs (a) (2) and (3) of this section shall apply only 
to the first fuel or additive tested.
    (ii) Prior to being used to generate emissions for testing an 
additional fuel or additive, a vehicle or engine which has previously 
been used for testing a different fuel or additive shall undergo an 
effective intermediate preconditioning cycle to remove the previously 
used fuel and its emissions from the vehicle's fuel and exhaust systems 
and from the combustion emission and evaporative emission control 
systems, if any.
    (iii) Such preconditioning shall include, at a minimum, the 
following steps:
    (A) The canister (if any) shall be removed from the vehicle and 
purged with 300 F nitrogen at 20 liters per minute until the 
incremental weight loss of the canister is less than 1 gram in 30 
minutes. This typically takes 3-4

[[Page 547]]

hours and removes 100 to 120 grams of adsorbed gasoline vapors.
    (B) The fuel tank shall be drained and filled to capacity with the 
new test fuel or additive/fuel mixture.
    (C) The vehicle or engine shall be operated until at least 95% of 
the fuel tank capacity is consumed.
    (D) The purged canister shall be returned to the vehicle.
    (E) The fuel tank shall be drained and filled to 40% capacity with 
test fuel.
    (F) Two-hour fuel tank heat builds from 72-120 F shall be performed 
repeatedly as necessary to achieve canister breakthrough. The fuel tank 
must be drained and filled prior to each heat build.
    (3) Scheduled and unscheduled vehicle/engine maintenance. (i) During 
emission generation, vehicles and engines must be maintained in good 
condition by following the recommendations of the original equipment 
manufacturer (OEM) for scheduled service and parts replacement, with 
repairs performed only as necessary. Modifications, adjustments, and 
maintenance procedures contrary to procedures found in 40 CFR part 86 
for the maintenance of test vehicles/engines or performed solely for the 
purpose of emissions improvement are not allowed.
    (ii) If unscheduled maintenance becomes necessary, the vehicle or 
engine must be repaired to OEM specifications, using OEM or OEM-approved 
parts. In addition, the tester is required to measure the basic 
emissions pursuant to Sec. 79.52(b)(2)(i) after the unscheduled 
maintenance and before resuming testing to ensure that the post-
maintenance emissions shall be within 20 percent of pre-maintenance 
emissions levels. If the basic emissions cannot be brought within 20 
percent of their previous levels, then the manufacturer shall restart 
the emissions characterization and health testing of its products 
combustion emissions using a new vehicle/engine.
    (c) Mileage accumulation. (1) A vehicle/engine break-in period is 
required prior to generating emissions for characterization and/or 
biological testing under this subpart. The required mileage accumulation 
may be accomplished on a test track, on the street, on a dynamometer, or 
using any other conventionally accepted method.
    (2) Vehicles to be used in the evaluation of baseline and non-
baseline fuels and fuel additives shall accumulate 4,000 miles prior to 
emission testing. Engines to be used in the evaluation of baseline and 
non-baseline fuels and fuel additives shall accumulate 125 hours of 
operation on an engine dynamometer prior to emission testing.
    (3) When the test formulation is classified as an atypical fuel or 
fuel additive formulation (pursuant to definitions in Sec. 
79.56(e)(4)(iii)), the following additional mileage accumulation 
requirements apply:
    (i) The test vehicle/engine must be operated for a minimum of 4,000 
vehicle miles or 125 hours of engine operation.
    (ii) Thereafter, at intervals determined by the tester, all emission 
fractions (i.e., vapor, semi-volatile, and particulate) shall be sampled 
and analyzed for the presence and amount of the atypical element(s) and/
or other atypical constituents. Pursuant to paragraph (d) of this 
section, the sampled emissions must be generated in the absence of an 
intact aftertreatment device. Immediately before the samples are taken, 
a brief warmup period (at least ten miles or the engine equivalent) is 
required.
    (iii) Mileage accumulation shall continue until either 50 percent or 
more of the mass of each atypical element (or other atypical 
constituent) entering the engine can be measured in the exhaust 
emissions (all fractions combined), or the vehicle/engine has 
accumulated mileage (or hours) equivalent to 40 percent of the average 
useful life of the applicable vehicle/engine class (pursuant to 
regulations in 40 CFR part 86). For example, the maximum mileage 
required for light-duty vehicles is 40 percent of 100,000 miles (i.e., 
40,000 miles), while the maximum time of operation for heavy-duty 
engines is the equivalent of 40 percent of 290,000 miles (i.e., the 
equivalent in engine hours of 116,000 miles).
    (iv) When either condition in paragraph (c)(3)(iii) of this section 
has been reached, additional emission characterization and biological 
testing of the emissions may begin.

[[Page 548]]

    (d) Use of exhaust aftertreatment devices. (1) If the selected test 
vehicle/engine, as certified by EPA, does not come equipped with an 
emissions aftertreatment device (such as a catalyst or particulate 
trap), such device shall not be used in the context of this program.
    (2) Except as provided in paragraph (d)(3) of this section for 
certain specialized additives, the following provisions apply when the 
test vehicle/engine, as certified by EPA, comes equipped with an 
emissions aftertreatment device.
    (i) For mileage accumulation:
    (A) When the test formulation does not contain any atypical elements 
(pursuant to definitions in Sec. 79.56(e)(4)(iii)), an intact 
aftertreatment device must be used during mileage accumulation.
    (B) When the test formulation does contain atypical elements, then 
the manufacturer may choose to accumulate the required mileage using a 
vehicle/engine equipped with either an intact aftertreatment device or 
with a non-functional aftertreatment device (e.g., a blank catalyst 
without its catalytic wash coat). In either case, sampling and analysis 
of emissions for measurement of the mass of the atypical element(s) (as 
described in Sec. 79.57(c)(3)) must be done on emissions generated with 
a non-functional (blank) aftertreatment device.
    (1) If the manufacturer chooses to accumulate mileage without a 
functional aftertreatment device, and if the manufacturer wishes to do 
this outside of a laboratory/test track setting, then a memorandum of 
exemption for product testing must be obtained by applying to the 
Director of the Field Operations and Support Division (see Sec. 
79.59(a)(1)).
    (2) [Reserved]
    (ii) For Tier 1 (Sec. 79.52), the total set of requirements for the 
characterization of combustion emissions (Sec. 79.52(b)) must be 
completed two times, once using emissions generated with the 
aftertreatment device intact and a second time with the aftertreatment 
device rendered nonfunctional or replaced with a non-functional 
aftertreatment device as described in paragraph (d)(2)(i)(B) of this 
section.
    (iii) For Tier 2 (Sec. 79.53), the standard requirements for 
biological testing of combustion emissions shall be conducted using 
emissions generated with a non-functioning aftertreatment device as 
described in paragraph (d)(2)(i)(B) of this section.
    (iv) For alternative Tier 2 requirements (Sec. 79.58(c)) or Tier 3 
requirements (Sec. 79.54) which may be prescribed by EPA, the use of 
functional or nonfunctional aftertreatment devices shall be specified by 
EPA as part of the test guidelines.
    (v) In the case where an intact aftertreatment device is not in 
place, all other manufacturer-specified combustion characteristics 
(e.g., back pressure, residence time, and mixing characteristics) of the 
altered vehicle/engine shall be retained to the greatest extent 
possible.
    (3) Notwithstanding paragraphs (d)(1) and (d)(2) of this section, 
when the subject of testing is a fuel additive specifically intended to 
enhance the effectiveness of exhaust aftertreatment devices, the related 
aftertreatment device may be used on the emission generation vehicle/
engine during all mileage accumulation and testing.
    (e) Generation of combustion emissions--(1) Generating combustion 
emissions for emission characterization. (i) Combustion emissions shall 
be generated according to the exhaust emission portion of the Federal 
Test Procedure (FTP) for the certification of new motor vehicles, found 
in 40 CFR part 86, subpart B for light-duty vehicles/engines, and 
subparts D, M and N for heavy-duty vehicles/engines. The Urban 
Dynamometer Driving Schedule (UDDS), pursuant to 40 CFR part 86, 
appendix I(a), shall apply to light-duty vehicles/engines and the Engine 
Dynamometer Driving Schedule (EDS), pursuant to 40 CFR part 86, appendix 
I(f)(2), shall apply to heavy-duty vehicles/engines. The motoring 
portion of the heavy-duty test cycle may be eliminated, at the 
manufacturer's option, for the generation of emissions.
    (A) For light-duty engines operated on an engine dynamometer, the 
tester shall determine the speed-torque equivalencies (``trace'') for 
its test engine from valid FTP testing performed on a chassis 
dynamometer, using a test vehicle with an engine identical to that being 
tested. The test engine must

[[Page 549]]

then be operated under these speed and torque specifications to simulate 
the FTP cycle.
    (B) Special procedures not included in the FTP may be necessary in 
order to characterize emissions from fuels and fuel additives containing 
atypical elements or to collect some types of emissions (e.g., 
particulate emissions from light-duty vehicles/engines, semi-volatile 
emissions from both light-duty and heavy-duty vehicles/engines). Such 
alterations to the FTP are acceptable.
    (C) For Tier 2 testing, the engines shall operate on repeated bags 2 
and 3 of the UDDS or back to back repeats of the heavy-duty transient 
cycle of the EDS.
    (ii) Pursuant to Sec. 79.52(b)(1)(i) and Sec. 79.57(d)(2)(ii), 
emission generation and characterization must be repeated three times 
when the selected vehicle/engine is normally operated without an 
emissions aftertreatment device and six times when the selected vehicle/
engine is normally operated with an emissions aftertreatment device. In 
the latter case, the emission generation and characterization process 
shall be repeated three times with the intact aftertreatment device in 
place and three times with a non-functioning (blank) aftertreatment 
device in place.
    (iii) From both light-duty and heavy-duty vehicles/engines, samples 
of vapor phase, semi-volatile phase, and particulate phase emissions 
shall be collected, except that semi-volatile phase, and particulate 
emissions need not be sampled for fuels and additives in the methane and 
propane families (pursuant to Sec. 79.56(e)(1)(v) and (vi)). The number 
and type of samples to be collected and separately analyzed during one 
emission generation/characterization process are as follows:
    (A) In the case of combustion emissions generated from light-duty 
vehicles/engines, the samples consist of three bags of vapor emissions 
(one from each segment of the light-duty exhaust emission cycle) plus 
one sample of particulate-phase emissions and one sample of semi-
volatile-phase emissions (collected over all segments of the exhaust 
emission cycle). If the mass of particulate emissions or semi-volatile 
emissions obtained during one driving cycle is not sufficient for 
characterization, up to three driving cycles may be performed and the 
extracted fractions combined prior to chemical analysis. Particulate-
phase emissions shall not be combined with semi-volatile-phase 
emissions. The test laboratory should focus on the characterization of 
the limit of detection for particulates and semi-volatile emissions.
    (B) In the case of combustion emissions generated from heavy-duty 
engines, the samples consist of one sample of each emission phase 
(vapor, particulate, and semi-volatile) collected over the entire cold-
start cycle and a second sample of each such phase collected over the 
entire hot-start cycle (see 40 CFR 86.334 through 86.342).
    (iv) Emission collection and storage. (A) Vapor phase emissions 
shall be collected and stored in Tedlar bags for subsequent chemical 
analysis. Storage conditions are specified in Sec. 79.52(b)(2).
    (B) Particulate phase emissions shall be collected on a particulate 
filter (or more than one, if required) using methods described in 40 CFR 
86.1301 through 86.1344. These methods, ordinarily applied only to 
heavy-duty emissions, are to be adapted and used for collection of 
particulates from light-duty vehicles/engines, as well. The particulate 
matter may be stored on the filter in a sealed container, or the soluble 
organic fraction may be extracted and stored in a separate sealed 
container. Both the particulate and the extract shall be shielded from 
ultraviolet light and stored at -20 C or less. Particulate emissions 
shall be tested no later than six months from the date they were 
generated.
    (C) Semi-volatile emissions shall be collected immediately 
downstream from the particulate collection filters using porous polymer 
resin beds, or their equivalent, designed for their capture. The soluble 
organic fraction of semi-volatile emissions shall be extracted 
immediately and tested within six months of being generated. The extract 
shall be stored in a sealed container which is shielded from ultraviolet 
light and stored at -20 C or less.
    (D) Particulate and semi-volatile phase emission collection, 
handling and extraction methods shall not alter

[[Page 550]]

the composition of the collected material, to the extent possible.
    (v) Additional requirements for combustion emission sampling, 
storage, and characterization are specified in Sec. 79.52(b).
    (2) Generating whole combustion emissions for biological testing. 
(i) Biological tests requiring whole combustion emissions shall be 
conducted using emissions generated from the test vehicle or engine 
operated in accordance with general FTP requirements.
    (ii) Light-duty test vehicles/engines shall be repeatedly operated 
over the Urban Dynamometer Driving Schedule (UDDS) (or equivalent engine 
dynamometer trace, per paragraph (e)(1)(i)(A) of this section) and 
heavy-duty test engines shall be repeatedly operated over the Engine 
Dynamometer Schedule (EDS) (see 40 CFR part 86, appendix I).
    (A) The tolerances of the driving cycle shall be two times those of 
the Federal Test Procedure and must be met 95 percent of the time.
    (B) The UDDS or EDS shall be repeated as many times as required for 
the biological test session.
    (C) Light-duty dynamometers shall be calibrated prior to the start 
of a biological test (40 CFR 86.118-78), verified weekly (40 CFR 86.118-
78), and recalibrated as required. Heavy-duty dynamometers shall be 
calibrated and checked prior to the start of a biological test (40 CFR 
86.1318-84), recalibrated every two weeks (40 CFR 86.1318-84(a)) and 
checked as stated in 40 CFR 86.1318-84(b) and (c).
    (D) The fuel reservoir for the test vehicle/engine shall be large 
enough to operate the test vehicle/engine throughout the daily 
biological exposure period, avoiding the need for refueling during 
testing.
    (iii) An apparatus to integrate the large concentration swings 
typical of transient-cycle exhaust is to be used between the source of 
emissions and the exposure chamber containing the animal test cages(s). 
The purpose of such apparatus is to decrease the variability of the 
biological exposure atmosphere and achieve the necessary concentration 
of CO or NOX, whichever is limiting.
    (A) A large mixing chamber is suggested for this purpose. The mixing 
chamber would be charged from the CVS at a constant rate determined by 
the exposure chamber purge rate. Flow to the exposure chamber would 
begin at the conclusion of the initial transient cycle with the 
associated mixing chamber charge.
    (B) A potential alternative apparatus is a mini-diluter (see, for 
example, AIGER/CRADA, February, 1994 in Sec. 79.57(g)).
    (C) [Reserved]
    (iv) Emission dilution. (A) Dilution air can be pre-dried to lower 
the relative humidity, thus permitting a lower dilution rate and a 
higher concentration of hydrocarbons to be achieved without condensation 
of water vapor.
    (B) These procedures include requirements that the mean exposure 
concentration in the inhalation test chamber on 90 percent or more of 
the exposure days shall be controlled as follows:
    (1) If the species being controlled is hydrocarbon or particulate, 
the mean exposure concentration must be within 15 percent of the target 
concentration for the single species being controlled.
    (2) For other species, the mean exposure concentration must be 
within 10 percent of the target concentration for the single species 
being controlled.
    (3) For all species, daily monitoring of CO, CO2, 
NOX, SOX, and total hydrocarbons in the exposure 
chamber shall be required. Analysis of the particle size distribution 
shall also be performed to establish the stability and consistency of 
particle size distribution in the test exposure.
    (C) After the initial exhaust dilution to preserve the character of 
the exhaust, the exhaust stream can be further diluted in the mixing 
chamber (and/or after leaving the chamber) to achieve the desired 
biological exposure concentrations.
    (v) Verification procedures. (A) The entire system used to dilute 
and transport whole combustion emissions (i.e., from exhaust pipe to 
outlet in the biological testing chamber) shall be verified before any 
animal exposures begin, and verified at least weekly during testing. 
(See procedures at 40 CFR 86.119-90 for light-duty vehicles and Sec. 
86.1319-90 for heavy-duty engines.)

[[Page 551]]

Verification testing shall be accomplished by introducing a known sample 
at the end of the vehicle/engine exhaust pipe into the dilution system 
and measuring the amount exiting the system. For example, an injected 
hydrocarbon sample could be detected with a gas chromatograph (GC) and 
flame ionization detector (FID) to determine the recovery factor.
    (B) [Reserved]
    (vi) Emission exposure quality control. (A) The tester shall 
incorporate the additional quality assurance and safety procedures 
outlined in Sec. 79.61(d) to control variability of emissions during 
the generation of exposure emissions during health effect testing.
    (B) These procedures include requirements that the mean exposure 
concentration in the inhalation test chamber on 90 percent or more of 
the exposure days shall be controlled as follows:
    (1) If the species being controlled is hydrocarbon or particulate, 
the mean exposure concentration must be within 15 percent of the target 
concentration for the single species being controlled.
    (2) For other species, the mean exposure concentration must be 
within 10 percent of the target concentration for the single species 
being controlled.
    (3) For all species, daily monitoring of CO, CO2, 
NOX, SOX, and total hydrocarbons in the exposure 
chamber shall be required. Analysis of the particle size distribution 
shall also be performed to establish the stability and consistency of 
particle size distribution in the test exposure.
    (C) The testing facility shall allow an audit of its premises, the 
qualifications, e.g., curriculum vitae, of its staff assigned to 
testing, and the specimens and records of the testing for registration 
purposes (as specified in Sec. 79.60).
    (vii) To allow for customary laboratory scheduling and unforeseen 
problems affecting the combustion emission generation or dilution 
equipment, biological exposures may be interrupted on limited occasions, 
as specified in Sec. 79.61(d)(5). Interruptions exceeding these 
limitations shall cause the affected test(s) to be void. Testers shall 
be aware of concerns for backup vehicles/engines cited in paragraph 
(a)(7)(ii) of this section.
    (3) Generating particulate and semi-volatile emissions for 
biological testing. (i) Salmonella mutagenicity testing, pursuant to 
Sec. 79.68, shall be conducted on extracts of the particulate and semi-
volatile emission phases separately. These emissions shall be generated 
by operating the test vehicle/engine over the appropriate FTP driving 
schedule (see paragraph (e)(2)(ii) of this section) and collected and 
analyzed according to methods described in 40 CFR 86.1301 through 1344 
(further information on this subject may be found in Perez, et al. CRC 
Report No. 551, 1987 listed in Sec. 79.57(g)).
    (A) Particulate emissions shall be collected on particulate filters 
and extracted from the collection equipment for use in biological tests. 
The number of repetitions of the applicable driving schedule required to 
collect sufficient quantities of the particulate emissions will vary, 
depending on the characteristics of the engine, the test fuel, and the 
requirements of the biological test protocol. The particulate sample may 
be collected on one or more filters, as necessary.
    (B) Semi-volatile emissions shall be collected immediately 
downstream from the particulate collection filters using porous polymer 
resin beds, or their equivalent, designed for their capture. Semi-
volatile phase emissions shall be collected on one apparatus. The time 
spent collecting sufficient quantities of the test substances in 
emissions samples will vary, depending on the emission characteristics 
of the engine and fuel or additive/base fuel mixture and on the 
requirements of the biological test protocol.
    (ii) The extraction method shall be determined by the specifications 
of the biological test for which the emissions are used.
    (iii) Particulate and semi-volatile emission storage requirements 
are as specified in Sec. 79.57(e)(1)(iv).
    (iv) Particulate and semi-volatile phase emission collection, 
handling and extraction methods shall not alter the composition of the 
collected material, to the extent possible.
    (v) Particulate emissions shall not be combined with semi-volatile 
phase emissions.

[[Page 552]]

    (f) Generation of evaporative emissions for characterization and 
biological testing. (1) Except as provided in paragraph (f)(5) of this 
section, an evaporative emissions generator shall be used to volatilize 
samples of a fuel or additive/base fuel mixture for evaporative 
emissions characterization and biological testing. Emissions shall be 
collected and sampled using equipment and methods appropriate for use 
with the compounds being characterized and the requirements of the 
emission characterization analysis. In the case of potentially explosive 
test substance concentrations, care must be taken to avoid generating 
explosive atmospheres. The tester is referred to Sec. 79.61(d)(8) for 
considerations involving explosivity.
    (2) Evaporative Emissions Generator (EEG) Description. An EEG is a 
fuel tank or vessel to which heat is applied causing a portion of the 
fuel to evaporate at a desired rate. The manufacturer has flexibility in 
designing an EEG for testing a particular fuel or fuel additive. The 
sample used to generate emissions in the EEG shall be renewed at least 
daily.
    (i) The evaporation chamber shall be made from materials compatible 
with the fuels and additives being tested and shall be equipped with a 
drain.
    (ii) The chamber shall be filled to 40 [5 percent of its interior 
volume with the fuel or additive/base fuel mixture being tested, with 
the remainder of the volume containing air.
    (iii) The concentration of the evaporated fuel or additive/base fuel 
mixture in the vapor space of the evaporation chamber during the time 
emissions are being withdrawn for testing shall not vary by more than 10 
percent from the equilibrium concentration in the vapor space of 
emissions generated from the fresh fuel or additive/base fuel mixture in 
the chamber.
    (A) During the course of a day's emission generation period, the 
level of fuel in the EEG shall be maintained to within 7 percent of its 
height at the start of the daily exposure period.
    (B) The fuel used in the EEG shall be drained at the end of each 
daily exposure. The EEG shall be refilled with a fresh supply of the 
test formulation before the start of each daily exposure.
    (C) The vapor space of the evaporation chamber shall be well mixed 
throughout the time emissions are being withdrawn for testing.
    (iv) The size of the evaporation chamber shall be determined by the 
rate at which evaporative emissions shall be needed in the test animal 
exposure chambers and the rate at which the fuel or the additive/base 
fuel mixture evaporates. The rate of evaporative emissions may be 
adjusted by altering the size of the EEG or by using one or more 
additional EEG(s). Emission rate modifications shall not be adjusted by 
temperature control or pressure control.
    (v) The temperature of the fuel or additive/base fuel mixture in the 
evaporation chamber shall be 130 F [5 F. The vapors shall maintain 
this temperature up to the point in the system where the vapors are 
diluted.
    (vi) The pressure in the vapor space of the evaporation chamber and 
the dilution and sampling apparatus shall stay within 10 percent of 
ambient atmospheric pressure.
    (vii) There shall be no controls or equipment on the evaporation 
chamber system that change the concentration or composition of the 
vapors generated for testing.
    (viii) Manufacturers shall perform verification testing of 
evaporative emissions in a manner analogous to the verification testing 
performed for combustion emissions.
    (3) For biological testing, vapor shall be withdrawn from the EEG at 
a constant rate, diluted with air as required for the particular study, 
and conducted immediately to the biological testing chamber(s) in a 
manner similar to the method used in Sec. 79.57(e), excluding the 
mixing chamber therein. The rate of emission generation shall be high 
enough to supply the biological exposure chamber with sufficient 
emissions to allow for a minimum of fifteen air changes per exposure 
chamber per hour. To allow for customary laboratory scheduling and for 
unforeseen problems with the evaporative emission generation or dilution 
equipment,

[[Page 553]]

biological exposures may be interrupted on limited occasions, as 
specified in Sec. 79.61(d)(5). Interruptions exceeding these 
limitations shall cause the affected test(s) to be void.
    (4) For characterization of evaporative emissions, samples of 
equilibrated emissions to the vapor space of the EEG shall be withdrawn 
into Tedlar bags, then stored and analyzed as specified in Sec. 
79.52(b).
    (5) A manufacturer (or group of manufacturers) may submit to EPA a 
request for approval of an alternative method of generating evaporative 
emissions for use in emission characterization and biological tests 
required under this subpart.
    (i) To be approved by EPA, the request must fully explain the 
rationale for the proposed method as well as the technical procedures, 
quality control, and safety precautions to be used, and must demonstrate 
that the proposed method will meet the following criteria:
    (A) The emission mixture generated by the proposed procedures must 
be reasonably similar to the equilibrium composition of the vapor which 
occurs in the vehicle fuel tank head space when the subject fuel or 
additive/base fuel mixture is in use and near-maximum in-use 
temperatures are encountered.
    (B) The emissions mixture generated by the proposed method must be 
sufficiently concentrated to provide adequate exposure levels in the 
context of the required toxicologic tests.
    (C) The proposed method must include procedures to ensure that the 
emissions delivered to the biologic exposure chambers will provide a 
reasonably constant exposure atmosphere over time.
    (ii) If EPA approves the request, EPA will place in the public 
record a copy of the request, together with all supporting procedural 
descriptions and justifications, and will notify the public of its 
availability by publishing a notice in the Federal Register.
    (g) References. For additional background information on the 
emission generation procedures outlined in this paragraph (g), the 
following references may be consulted. Additional references can be 
found in Sec. 79.61(f).
    (1) AIGER/CRADA (American Industry/Government Emissions Research 
Cooperative Research and Development Agreement, ``Specifications for 
Advanced Emissions Test Instrumentation'' AIGER PD-94-1, Revision 5.0, 
February, 1994
    (2) Black, F. and R. Snow, ``Constant Volume Sampling System Water 
Condensation'' SAE 940970 in ``Testing and Instrumentation'' 
SP-1039, Society of Automotive Engineers, Feb. 28-Mar. 3, 1994.
    (3) Perez, J.M., Jass, R.E., Leddy, D.G., eds. ``Chemical Methods 
for the Measurement of Unregulated Diesel Emissions (CRC-APRAC Project 
No. CAPI-1-64), Coordinating Research Council, CRC Report No. 551, 
August, 1987.
    (4) Phalen, R.F., ``Inhalation Studies: Foundations and 
Techniques'', CRC Press, Inc., Boca Raton, Florida, 1984.

[59 FR 33093, June 27, 1994, as amended at 61 FR 36511, July 11, 1996; 
63 FR 63792, Nov. 17, 1998]



Sec. 79.58  Special provisions.

    (a) Relabeled Additives. Sellers of relabeled additives (pursuant to 
Sec. 79.50) are not required to comply with the provisions of Sec. 
79.52, 79.53 or 79.59, except that such sellers are required to comply 
with Sec. 79.59(b).
    (b) Low Vapor Pressure Fuels and Additives. Fuels which are not 
designated as ``evaporative fuels'' and fuel additives which are not 
designated as ``evaporative fuel additives'' pursuant to the definitions 
in Sec. 79.50 need not undergo the emission characterization or health 
effects testing specified in Sec. Sec. 79.52 and 79.53 for evaporative 
emissions. At EPA's discretion, the evaporative emissions of such fuels 
and additives may be required to undergo Tier 3 testing, pursuant to 
Sec. 79.54.
    (c) Alternative Tier 2 Provisions. At EPA's discretion, EPA may 
modify the standard Tier 2 health effects testing requirements for a 
fuel or fuel additive (or group). Such modification may encompass 
substitution, addition, or deletion of Tier 2 studies or study 
specifications, and/or changes in underlying engine or equipment 
requirements, except that a Tier 2 endpoint will not be

[[Page 554]]

deleted in the absence of existing information deemed adequate by EPA or 
alternative testing requirements for such endpoint. If warranted by the 
particular requirements, EPA will allow additional time for completion 
of the alternative Tier 2 testing program.
    (1) When EPA intends to require testing in lieu of or in addition to 
standard Tier 2 health testing, EPA will notify the responsible 
manufacturer (or group) by certified letter of the specific tests which 
EPA is proposing to require in lieu of or in addition to Tier 2, and the 
proposed schedule for completion and submission of such tests. A copy of 
the letter will be placed in the public record. EPA intends to send the 
notification prior to November 27, 1995, or in the case of new fuels and 
additives (as defined in Sec. 79.51(c)(3)), within 18 months of EPA's 
receipt of an intent to register such product. However, EPA's 
notification to the manufacturer (or group) may occur at any time up to 
EPA's receipt of Tier 2 data for the product(s) in question. EPA will 
provide the manufacturer with 60 days from the date of receipt of the 
notice to comment on the tests which EPA is proposing to require and on 
the proposed schedule. If the manufacturer believes that undue costs or 
hardships will occur as a result of EPA's delay in providing 
notification of alternative Tier 2 requirements, then the manufacturer's 
comments should describe and include evidence of such hardship. In 
particular, if the standard Tier 2 toxicology testing for the fuel or 
additive in question has already begun at the time the manufacturer 
receives EPA's notification of proposed alternative Tier 2 requirements, 
then EPA shall refrain from requiring alternative Tier 2 tests provided 
that EPA receives the standard Tier 2 data and report (pursuant to Sec. 
79.59(c)) within one year of the date on which the toxicology testing 
began.
    (2) EPA will issue a notice in the Federal Register announcing its 
intent to require special testing in lieu of or in addition to the 
standard Tier 2 testing for a particular fuel or additive manufacturer 
or group, and that a copy of the letter to the manufacturer or group 
describing the proposed alternative Tier 2 testing for that manufacturer 
or group is available in the public record for review and comment. The 
public shall have a minimum of 30 days after the publication of this 
notice to comment on the proposed alternative Tier 2 testing.
    (3) EPA will include in the public record a copy of any timely 
comments concerning the proposed alternative Tier 2 testing requirements 
received from the affected manufacturer or group or from the public, and 
the responses of EPA to such comments. After reviewing all such comments 
received, EPA may adopt final alternative Tier 2 requirements by sending 
a certified letter describing such final requirements to the 
manufacturer or group. In that event, EPA will also issue a notice in 
the Federal Register announcing that it has adopted final alternative 
Tier 2 requirements and that a copy of the letter adopting the 
requirements has been included in the public record.
    (4) After EPA's receipt of a manufacturer's (or group's) submittals, 
EPA will notify the responsible manufacturer (or group) regarding the 
adequacy of the submittal and potential Tier 3 testing requirements 
according to the same relative time intervals and by the same procedures 
as specified in Sec. 79.51 (c) and (d) for routine Tier 1 and Tier 2 
submittals.
    (d) Small Business Provisions. (1) For purposes of these provisions, 
when subsidiary, divisional, or other complex business arrangements 
exist, manufacturer is defined as the business entity with ultimate 
ownership of all related parents, subsidiaries, divisions, branches, or 
other operating units. Total annual sales means the average of the 
manufacturer's total sales revenue, excluding any revenue which 
represents the collection of Federal, State, or local excise taxes or 
sales taxes, in each of the three years prior to such manufacturer's 
submittal to EPA of the basic registration information pursuant to Sec. 
79.59(b)(2) through (b)(5).
    (2) Provisions Applicable to Baseline and Non-baseline Products. A 
manufacturer with total annual sales less than $50 million is not 
required to meet the requirements of Tier 1 and Tier 2 (specified in 
Sec. Sec. 79.52 and 79.53) with regard to

[[Page 555]]

such manufacturer's fuel and/or additive products which meet the 
criteria for inclusion in a Baseline or Non-baseline group pursuant to 
Sec. 79.56. Upon such manufacturer's satisfactory completion and 
submittal to EPA of basic registration data specified in Sec. 79.59(b), 
the manufacturer may request and EPA shall issue a registration for such 
product, subject to Sec. 79.51(c) and paragraphs (d)(4) and (d)(5) of 
this section.
    (3) Provisions Applicable to Atypical Products. A manufacturer with 
total annual sales less than $10 million is not required to meet the 
requirements of Tier 2 (specified in Sec. 79.53) in regard to such 
manufacturer's fuel and/or additive products which meet the criteria for 
inclusion in an Atypical group pursuant to Sec. 79.56. Upon such 
manufacturer's satisfactory completion and submittal to EPA of basic 
registration data specified in Sec. 79.59(b) and Tier 1 information 
specified in Sec. 79.52 for an Atypical fuel or additive, the 
manufacturer may request and EPA shall issue a registration for such 
product, subject to Sec. 79.51(c) and paragraphs (d)(4) and (d)(5) of 
this section. Compliance with Tier 1 requirements under this paragraph 
may be accomplished by the individual manufacturer or as a part of a 
group pursuant to Sec. 79.56.
    (4) Any registration granted by EPA under the provisions of this 
section are conditional upon satisfactory completion of any Tier 3 
requirements which EPA may subsequently impose pursuant to Sec. 79.54. 
In such circumstances, the Tier 3 requirements might include (but would 
not necessarily be limited to) information which would otherwise have 
been required under the provisions of Tier 1 and/or Tier 2.
    (5) The provisions in paragraphs (d)(2) and (d)(3) of this section 
are voluntary on the part of qualifying small manufacturers. Such 
manufacturers may choose to fulfill the standard requirements for their 
fuels and additives, individually or as a part of a group, rather than 
satisfying only the requirements specified in paragraphs (d)(2) and/or 
(d)(3) of this section. If a qualifying small manufacturer elects these 
special provisions rather than the standard requirements for a product, 
then EPA will generally assume that any additional information submitted 
by other manufacturers, for fuels and additives meeting the same 
grouping criteria (under Sec. 79.56) as that of the small 
manufacturer's product, is pertinent to further testing and/or 
regulatory decisions that may affect the small manufacturer's product.
    (6) In the case of an additive for which the manufacturer is not 
required to meet the requirements of Tier 2 pursuant to paragraph (d)(3) 
of this section:
    (i) A fuel manufacturer which blends such an additive into fuel 
shall not be required to meet the requirements of Tier 2 with respect to 
such additive/fuel mixture.
    (ii) An additive manufacturer which blends such an additive with one 
or more other registered additive products and/or with substances 
containing only carbon and/or hydrogen shall not be required to meet the 
requirements of Tier 2 with respect to such additive or additive blend.
    (e) Aftermarket Aerosol Additives. (1) To obtain registration for an 
aftermarket aerosol fuel additive, the manufacturer shall provide 
existing information in the form of a literature search, a discussion of 
the potential exposure(s) to such product, and the basic registration 
data specified in Sec. 79.59(b).
    (2) The literature search shall include existing data on potential 
health and welfare effects due to exposure to the aerosol product itself 
and its raw (uncombusted) components. The analysis for potential 
exposures shall be based on the actual or anticipated production volume 
and market distribution of the particular aerosol product, and its 
estimated frequency of use. Other Tier 1 and Tier 2 requirements are not 
routinely required for aerosol products. EPA will review the submitted 
information and, at EPA's discretion, may require from the manufacturer 
further information and/or testing under Tier 3 on a case-by-case basis.

[59 FR 33093, June 27, 1994, as amended at 62 FR 12571, Mar. 17, 1997]



Sec. 79.59  Reporting requirements.

    (a) Timing. (1) The manufacturer of each designated fuel or fuel 
additive shall submit to EPA the basic registration data detailed in 
paragraph (b) of

[[Page 556]]

this section. Forms for submitting this data may be obtained from EPA at 
the following address: Director, Field Operations and Support Division, 
6406J--Fuel/Additives Registration, U.S. Environmental Protection 
Agency, 1200 Pennsylvania Ave., NW., Washington, DC 20460.
    (i) For existing products (pursuant to Sec. 79.51(c)(1)), 
manufacturers shall submit the basic registration data as specified in 
Sec. 79.59(b) to EPA by November 28, 1994.
    (ii) For registrable products (pursuant to Sec. 79.51(c)(2)), 
manufacturers shall submit the basic registration data as specified in 
Sec. 79.59(b) to apply for registration for such product.
    (iii) For new products (pursuant to Sec. 79.51(c)(3)), 
manufacturers are strongly encouraged to notify EPA of an intent to 
obtain product registration by submitting the basic registration data as 
specified in Sec. 79.59(b) prior to starting Tiers 1 and 2.
    (2) The information specified in paragraph (c) of this section shall 
be submitted to the address in paragraph (a)(1) of this section at the 
conclusion of activities performed in compliance with Tiers 1 and 2 
under the provisions of Sec. Sec. 79.52 and 79.53, according to the 
time constraints specified in Sec. 79.51 (c) through (d).
    (3) The information specified in paragraph (d) of this section shall 
be submitted to EPA at the address in paragraph (a)(1) of this section 
at the conclusion of activities performed in compliance with Tier 3 
under the provisions of Sec. 79.54.
    (b) Basic Registration Data. Each manufacturer of a designated fuel 
or fuel additive shall submit the following data in regard to such fuel 
or fuel additive:
    (1) The information specified in Sec. 79.11 or Sec. 79.21. If such 
information has already been submitted to EPA in compliance with subpart 
B or C of this part, and if such previous information is accurate and 
up-to-date, the manufacturer need not resubmit this information.
    (2) Annual production volume of the fuel or fuel additive product, 
in units of gallons per year if most commonly sold in liquid form or 
kilograms per year if most commonly sold in solid form. For fuels and 
fuel additives already in production, the most recent annual production 
volume and the volume projected to be produced in the third subsequent 
year shall be provided. For products not yet in production, the best 
estimate of expected annual volume during the third year of production 
shall be provided.
    (3) Market distribution of the product. For fuels and bulk 
additives, this information shall be presented as the percent of total 
annual sales volume marketed in each Petroleum Administration for 
Defense District (PADD). The States comprising each PADD are listed in 
the following section. For aftermarket additives, the distribution data 
shall be presented as the percent of total annual sales volume marketed 
in each State. For a product not yet in production, the manufacturer 
shall present the distribution (by PADD or State, as applicable) 
projected to occur during the third year of production.
    (i) The following States and jurisdictions are included in PADD I:

Connecticut
Delaware
District of Columbia
Florida
Georgia
Maine
Maryland
Massachusetts
New Hampshire
New Jersey
New York
North Carolina
Pennsylvania
Rhode Island
South Carolina
Vermont
Virginia
West Virginia

    (ii) The following States are included in PADD II:

Illinois
Indiana
Iowa
Kansas
Kentucky
Michigan
Minnesota
Missouri
Nebraska
North Dakota
Ohio
Oklahoma
South Dakota
Tennessee
Wisconsin

    (iii) The following States are included in PADD III:

Alabama
Arkansas
Louisiana
Mississippi
New Mexico
Texas

    (iv) The following States are included in PADD IV:

Colorado
Idaho
Montana
Utah
Wyoming

    (v) The following States are included in PADD V:


[[Page 557]]


Alaska
Arizona
California
Hawaii
Nevada
Oregon
Washington

    (4) Any applicable information pursuant to the grouping provisions 
in Sec. 79.56, as follows:
    (i) If the manufacturer has enrolled or intends to enroll the 
product in a fuel/additive group, the relevant group and the person(s) 
or entity expected to submit information on behalf of the group must be 
identified.
    (ii) If the manufacturer intends to rely on registration information 
previously submitted by another manufacturer (or group) for registration 
of other product(s) in the same fuel/additive group, then the original 
submitter and its product (or product group) shall be identified. In 
such cases, the manufacturer shall provide evidence that the original 
submitter has been notified of the use of its registration data and that 
the manufacturer has complied or intends to comply with the proportional 
reimbursement required under Sec. 79.56(c) of this rule.
    (5) Any applicable information pursuant to the special provisions in 
Sec. 79.58, as follows:
    (i) If the manufacturer claims applicability of the special 
provisions for relabeled additives, pursuant to Sec. 79.58(a), then the 
manufacturer and brand name of the original product shall be given.
    (ii) If the manufacturer claims applicability of any small business 
provisions pursuant to Sec. 79.58(d), the average of the manufacturer's 
total annual sales revenue for the previous three years shall be given.
    (iii) If the manufacturer claims applicability of the special 
provisions for aerosol products, pursuant to Sec. 79.58(e), then the 
purpose and recommended frequency of use shall be given.
    (c) Tier 1 and Tier 2 Reports. If the results of Tiers 1 and 2 are 
reported to EPA at the same time, then the report shall include the 
following documents in paragraphs (c)(1) through (7) of this section. If 
Tier 1 and Tier 2 results are submitted to EPA separately, then the 
separate Tier 1 report shall include only documents in paragraphs (c) 
(1) through (4), (c)(6), and associated appendices in paragraphs (c)(7) 
of this section, and the separate Tier 2 report shall include only 
documents in paragraphs (c)(1) through (3), (c)(5), (c)(6), and 
associated appendices in paragrpah (c)(7) of this section. In addition, 
manufacturers complying with Tier 2 requirements according to one of the 
time schedules specified in Sec. 79.51(c)(1)(ii)(B), Sec. 
79.51(c)(1)(vi)(B)(2), or Sec. 79.51(c)(1)(vii)(B)(2) must submit 
evidence of a suitable arrangement for completion of Tier 2 (e.g., a 
copy of a signed contract with a qualified laboratory for applicable 
Tier 2 services) by the date specified in the applicable time schedule.
    (1) Cover page. (i) Identification of test substance,
    (ii) Name and address of the manufacturer of the test substance,
    (iii) Name and phone number of a designated contact person,
    (iv) Group information, if applicable, including:
    (A) Group name or grouping criteria,
    (B) Name and address of responsible organization or entity reporting 
for the group,
    (C) Product trade name and manufacturer of each member fuel and 
additive to which the report pertains.
    (2) Executive Summary. Text overview of the significant results and 
conclusions obtained as a result of completing the requirements of Tier 
1 and/or Tier 2, including references if used to support such results 
and conclusions.
    (3) Test Substance Information. Test substance description, 
including, as applicable,
    (i) Base fuel parameter values (including types and concentrations 
of base fuel additives) or test fuel composition (if a fuel other than 
the base fuel is used in testing). These values must be provided for 
each of the fuel parameters specified in Sec. 79.55 for the applicable 
fuel family.
    (ii) Test additive composition and concentration
    (4) Summary of Tier 1. (i) Literature Search. Pursuant to Sec. 
79.52(d), the literature search shall include a text summary of the 
methods and results of the literature search, including the following:
    (A) Identification of person(s) performing the literature search,

[[Page 558]]

    (B) Description of data sources accessed, search strategy used, 
search period, and terms included in literature search,
    (C) Documentation of all unpublished in-house and other privately-
conducted studies,
    (D) Tables summarizing the protocols and results of all cited 
studies,
    (E) Summary of significant results and conclusions with respect to 
the effects of the emissions of the subject fuel or fuel additive on the 
public health and welfare, including references if used to support such 
results and conclusions.
    (F) Statement of the extent to which the literature search has 
produced adequate information comparable to that which would otherwise 
be obtained through the performance of applicable emission 
characterization requirements under Sec. 79.52(b) and/or health effects 
testing requirements under Sec. 79.53, including justifications and 
specific references.
    (ii) Emission Characterization. Pursuant to Sec. 79.52(b), the 
emission characterization shall include:
    (A) Name, address, and telephone number of the laboratory performing 
the characterization,
    (B) Name and description of analytic methods used for 
characterization.
    (5) Summary of Tier 2. For each health effects test performed 
pursuant to the provisions of Sec. 79.53, the Tier 2 summary shall 
contain the following information:
    (i) Name, address, and telephone number of the testing facility,
    (ii) Summary of procedures (including quality assurance, quality 
control and compliance with Good Laboratory Practice Standards as 
specified in Sec. 79.60), findings, and conclusions, including 
references if used to support such results and conclusions,
    (iii) Description of any problems and their resolution.
    (6) Conclusions. The conclusions shall identify the need for further 
testing, if that need exists, or justify that current testing and/or 
available information is adequate for the tier(s) included in the 
report.
    (7) Appendices. The appendices shall contain detailed documentation 
related to the summary information described in this section, including, 
at a minimum, the following five appendices:
    (i) Literature search appendices shall contain:
    (A) Copies of literature source outputs, including reference lists 
and associated abstracts from database searches, printed or on 3\1/2\ 
inch IBM-compatible computer diskettes;
    (B) Summary tables organized by health or welfare endpoint and type 
of emission (e.g., combustion, evaporation, individual emission 
product), presenting in tabular form the following information at a 
minimum: number and species of test subjects, exposure concentrations/
duration, positive (i.e., abnormal) findings including numbers of test 
subjects involved, and bibliographic references;
    (C) Complete documentation and/or reprints of articles for any 
previous study relied upon for satisfying emission characterization and/
or Tier 2 test requirements; and
    (D) Full reports for unpublished/in-house studies.
    (ii) Emissions characterization appendices shall contain:
    (A) Complete laboratory reports, including documentation of 
calibration and verification procedures;
    (B) Documentation of the emissions generation procedures used; and
    (C) Lists of speciated emission products and their emission rates 
reported in units of grams/mile.
    (iii) [Reserved]
    (iv) Tier 2 appendices shall contain, for each test performed:
    (A) Complete protocol used;
    (B) Documentation of emission generation procedures; and
    (C) Complete laboratory report in compliance with the reporting 
standards in Sec. 79.60, including detailed test results and 
conclusions, and descriptions of any problems encountered and their 
resolution.
    (v) Laboratory certification/accreditation information, personnel 
credentials, and statements of compliance with the Good Laboratory 
Practices Standards specified in Sec. 79.60 and the requirements in 
Sec. 79.53(c)(1).

[[Page 559]]

    (d) Tier 3 Report. Subject to applicability as specified in Sec. 
79.54, each manufacturer of a designated fuel or fuel additive, or each 
group of such manufacturers pursuant to the provisions of Sec. 79.56, 
shall submit the following information with respect to each Tier 3 test 
conducted for such fuels or fuel additives:
    (1) The test objectives, including a summary of the reason(s) why 
such additional testing, beyond Tiers 1 and 2, was required;
    (2) Name, address, and telephone number of each testing facility;
    (3) Summary of test procedures, results and conclusions;
    (4) Complete documentation of test protocols and emission generation 
procedures, complete laboratory reports in compliance with the reporting 
standards of Sec. 79.60, detailed test results and conclusions, 
including references if used to support such results and conclusions, 
and descriptions of any problems encountered and their resolution; and
    (5) Laboratory certification information, personnel credentials, and 
statements of compliance with the Good Laboratory Practices Standards 
specified in Sec. 79.60.
    (e) Availability of Information. (1) All health and safety test data 
and other information concerning health and welfare effects which is 
submitted by any manufacturer or group pursuant to Sec. Sec. 79.52(c), 
79.53, or 79.54, shall be considered to be public information and shall 
be made available to the public by EPA upon request. A reasonable fee 
may be charged by EPA for copying such materials. Any manufacturer or 
group who claims that any information concerning the composition of a 
fuel or fuel additive product, or any other information, submitted under 
this subpart is confidential business information must state this claim 
in writing at the time of the submittal.
    (2) To assert a business confidentiality claim concerning any 
information submitted under this subpart, the submitter must:
    (i) Clearly mark the information as confidential at each location it 
appears in the submission; and
    (ii) Submit with the information claimed as confidential a separate 
document setting forth the claim and listing each location at which the 
information appears in the submission.
    (3) If any person subsequently requests access to information 
submitted under this subpart (other than health and safety test data and 
other information concerning health and welfare effects), and such 
information is subject to a claim of business confidentiality, the 
request and any subsequent disclosure shall be governed by the 
provisions of 40 CFR part 2.

[59 FR 33093, June 27, 1994, as amended at 62 FR 12572, 12576, Mar. 17, 
1997]



Sec. 79.60  Good laboratory practices (GLP) standards for inhalation
exposure health effects testing.

    (a) General Provisions--(1) Scope. (i) This section prescribes good 
laboratory practices (GLPs) for conducting inhalation exposure studies 
relating to motor vehicle emissions health effects testing under this 
part. These directions are intended to ensure the quality and integrity 
of health effects data submitted pursuant to registration regulations 
issued under sections 211(b) or 211(e) of the Clean Air Act (CAA) (42 
U.S.C. 7545).
    (ii) This section applies to any study described by paragraph 
(a)(1)(i) of this section which any person conducts, initiates, or 
supports on or after May 27, 1994.
    (iii) It is EPA's policy that all health effects data developed 
under sections 211(b) and (e) of CAA be in accordance with provisions of 
this section. If data are not developed in accordance with the 
provisions of this section, EPA may consider such data insufficient to 
evaluate the health effects of a motor vehicle's fuel or fuel additive 
emissions, unless the submitter provides additional information 
demonstrating that the data are reliable and adequate and EPA determines 
that the data are sufficient.
    (2) Definitions. As used in this section, the following terms shall 
have the meanings specified:
    Batch means a specific quantity or lot of a test fuel, additive/base 
fuel mixture, or reference substance that has been characterized 
according to Sec. 79.60(f)(1)(i).
    CAA means the Clean Air Act.

[[Page 560]]

    Carrier means any material which is combined with engine/motor 
vehicle emissions or a reference substance for administration to a test 
system. ``Carrier'' includes, but is not limited to, clean, filtered 
air, water, feed, and nutrient media.
    Control atmosphere means clean, filtered air which is administered 
to the test system in the course of a study for the purpose of 
establishing a basis for comparison with the test atmosphere for 
chemical or biological measurements.
    Experimental start date means the first date the test atmosphere is 
applied to the test system.
    Experimental termination date means the last date on which data are 
collected directly from the study.
    Person includes an individual, partnership, corporation, 
association, scientific or academic establishment, government agency, or 
organizational unit thereof, and any other legal entity.
    Quality assurance unit means any person or organizational element, 
except the study director, designated by testing facility management to 
perform the duties relating to quality assurance of the studies.
    Raw data means any laboratory worksheets, records, memoranda, notes, 
or exact copies thereof, that are the result of original observations 
and activities of a study and are necessary for the reconstruction and 
evaluation of the report of that study. In the event that exact 
transcripts of raw data have been prepared (e.g., tapes which have been 
transcribed verbatim, dated, and verified accurate by signature), the 
exact copy or exact transcript may be substituted for the original 
source as raw data. ``Raw data'' may include photographs, videotape, 
microfilm or microfiche copies, computer printouts, magnetic media, 
including dictated observations, and recorded data from automated 
instruments.
    Reference substance means any chemical substance or mixture, 
analytical standard, or material other than engine/motor vehicle 
emissions and/or its carrier, that is administered to or used in 
analyzing the test system in the course of a study. A ``reference 
substance'' is used to establish a basis for comparison with the test 
atmosphere for known chemical or biological measurements, i.e., positive 
or negative control substance.
    Specimen means any material derived from a test system for 
examination or analysis.
    Sponsor means person who initiates and supports, by provision of 
financial or other resources, a study or a person who submits a study to 
EPA in response to the CAA Section 211(b) or 211(e) Fuels and Fuel 
Additives Registration Rule or a testing facility, if it both initiates 
and actually conducts the study.
    Study means any experiment, at one or more test sites, in which a 
test system is exposed to a test atmosphere under laboratory conditions 
to determine or help predict the health effects of that exposure in 
humans, other living organisms, or media.
    Study completion date means the date the final report is signed by 
the study director.
    Study director means the individual responsible for the overall 
conduct of a study.
    Study initiation date means the date the protocol is signed by the 
study director.
    Test substance means a vapor and/or aerosol mixture composed of 
engine/motor vehicle emissions and clean, filtered air which is 
administered directly, or indirectly, by the inhalation route to a test 
system in a study which develops data to meet the registration 
requirements of CAA section 211(b) or (e).
    Test system means any animal, microorganism, chemical or physical 
matrix, to which the test, control, or reference substance is 
administered or added for study. This definition also includes 
appropriate groups or components of the system not treated with the 
test, control, or reference substance.
    Testing facility means a person who actually conducts a study, i.e., 
actually uses the test substance in a test system. ``Testing facility'' 
encompasses only those operational units that are being or have been 
used to conduct studies.
    TSCA means the Toxic Substances Control Act (15 U.S.C. 2601 et 
seq.).
    (3) Applicability to studies performed under grants and contracts. 
When a

[[Page 561]]

sponsor or other person utilizes the services of a consulting 
laboratory, contractor, or grantee to perform all or a part of a study 
to which this section applies, it shall notify the consulting 
laboratory, contractor, or grantee that the service is, or is part of, a 
study that must be conducted in compliance with the provisions of this 
section.
    (4) Statement of compliance or non-compliance. Any person who 
submits to EPA a test in compliance with registration regulations issued 
under CAA section 211(b) or section 211(e) shall include in the 
submission a true and correct statement, signed by the sponsor and the 
study director, of one of the following types:
    (i) A statement that the study was conducted in accordance with this 
section; or
    (ii) A statement describing in detail all differences between the 
practices used in the study and those required by this section; or
    (iii) A statement that the person was not a sponsor of the study, 
did not conduct the study, and does not know whether the study was 
conducted in accordance with this section.
    (5) Inspection of a testing facility. (i) A testing facility shall 
permit an authorized employee or duly designated representative of EPA, 
at reasonable times and in a reasonable manner, to inspect the facility 
and to inspect (and in the case of records also to copy) all records and 
specimens required to be maintained regarding studies to which this 
section applies. The records inspection and copying requirements shall 
not apply to quality assurance unit records of findings and problems, or 
to actions recommended and taken, except the EPA may seek production of 
these records in litigation or formal adjudicatory hearings.
    (ii) EPA will not consider reliable for purposes of showing that a 
test substance does or does not present a risk of injury to health or 
the environment any data developed by a testing facility or sponsor that 
refuses to permit inspection in accordance with this section. The 
determination that a study will not be considered reliable does not, 
however, relieve the sponsor of a required test of any obligation under 
any applicable statute or regulation to submit the results of the study 
to EPA.
    (6) Effects of non-compliance. (i) Pursuant to sections 114, 208, 
and 211(d) of the CAA, it shall be a violation of this section and a 
violation of this rule (40 CFR part 79, subpart F) if:
    (A) The test is not being or was not conducted in accordance with 
any requirement of this part; or
    (B) Data or information submitted to EPA under part 79, including 
the statement required by Sec. 79.60(a)(4), include information or data 
that are false or misleading, contain significant omissions, or 
otherwise do not fulfill the requirements of this part; or
    (C) Entry in accordance with Sec. 79.60(a)(5) for the purpose of 
auditing test data is denied.
    (ii) EPA, at its discretion, may not consider reliable for purposes 
of showing that a chemical substance or mixture does not present a risk 
of injury to health any study which was not conducted in accordance with 
this part. EPA, at its discretion, may rely upon such studies for 
purposes of showing adverse effects. The determination that a study will 
not be considered reliable does not, however, relieve the sponsor of a 
required test of the obligation under any applicable statute or 
regulation to submit the results of the study to EPA.
    (iii) If data submitted in compliance with registration regulations 
issued under CAA section 211(b) or section 211(e) are not developed in 
accordance with this section, EPA may determine that the sponsor has not 
fulfilled its obligations under 40 CFR part 79 and may require the 
sponsor to develop data in accordance with the requirements of this 
section in order to satisfy such obligations.
    (b) Organization and Personnel--(1) Personnel. (i) Each individual 
engaged in the conduct of or responsible for the supervision of a study 
shall have education, training, and experience, or combination thereof, 
to enable that individual to perform the assigned functions.
    (ii) Each testing facility shall maintain a current summary of 
training and experience and job description for each individual engaged 
in or supervising the conduct of a study.

[[Page 562]]

    (iii) There shall be a sufficient number of personnel for the timely 
and proper conduct of the study according to the protocol.
    (iv) Personnel shall take necessary personal sanitation and health 
precautions designed to avoid contamination of test fuel and additive/
base fuel mixtures, test and reference substances, and test systems.
    (v) Personnel engaged in a study shall wear clothing appropriate for 
the duties they perform. Such clothing shall be changed as often as 
necessary to prevent microbiological, radiological, or chemical 
contamination of test systems and test, control, and reference 
substances.
    (vi) Any individual found at any time to have an illness that may 
adversely affect the quality and integrity of the study shall be 
excluded from direct contact with test systems, fuel and fuel/additive 
mixtures, test and reference substances and any other operation or 
function that may adversely affect the study until the condition is 
corrected. All personnel shall be instructed to report to their 
immediate supervisors any health or medical conditions that may 
reasonably be considered to have an adverse effect on a study.
    (2) Testing facility management. For each study, testing facility 
management shall:
    (i) Designate a study director as described in Sec. 79.60(b)(3) 
before the study is initiated.
    (ii) Replace the study director promptly if it becomes necessary to 
do so during the conduct of a study.
    (iii) Assure that there is a quality assurance unit as described in 
Sec. 79.60(b)(4).
    (iv) Assure that test fuels and fuel/additive mixtures and test and 
reference substances have been identified as to content, strength, 
purity, stability, and uniformity, as applicable.
    (v) Assure that personnel, resources, facilities, equipment, 
materials and methodologies are available as scheduled.
    (vi) Assure that personnel clearly understand the functions they are 
to perform.
    (vii) Assure that any deviations from these regulations reported by 
the quality assurance unit are communicated to the study director and 
corrective actions are taken and documented.
    (3) Study director. For each study, a scientist or other 
professional person with a doctorate degree or equivalent in toxicology 
or other appropriate discipline shall be identified as the study 
director. The study director has overall responsibility for the 
technical conduct of the study, as well as for the interpretation, 
analysis, documentation, and reporting of results, and represents the 
single point of study control. The study director shall assure that:
    (i) The protocol, including any changes, is approved as provided by 
Sec. 79.60(g)(1)(i) and is followed;
    (ii) All experimental data, including observations of unanticipated 
responses of the test system are accurately recorded and verified;
    (iii) Unforeseen circumstances that may affect the quality and 
integrity of the study are noted when they occur, and corrective action 
is taken and documented;
    (iv) Test systems are as specified in the protocol;
    (v) All applicable good laboratory practice regulations are 
followed; and
    (vi) All raw data, documentation, protocols, specimens, and final 
reports are archived properly during or at the close of the study.
    (4) Quality assurance unit. A testing facility shall have a quality 
assurance unit which shall be responsible for monitoring each study to 
assure management that the facilities, equipment, personnel, methods, 
practices, records, and controls are in conformance with the regulations 
in this section. For any given study, the quality assurance unit shall 
be entirely separate from and independent of the personnel engaged in 
the direction and conduct of that study. The quality assurance unit 
shall conduct inspections and maintain records appropriate to the study.
    (i) Quality assurance unit duties. (A) Maintain a copy of a master 
schedule sheet of all studies conducted at the testing facility indexed 
by test substance and containing the test system, nature of study, date 
study was initiated, current status of each study, identity of the 
sponsor, and name of the study director.

[[Page 563]]

    (B) Maintain copies of all protocols pertaining to all studies for 
which the unit is responsible.
    (C) Inspect each study at intervals adequate to ensure the integrity 
of the study and maintain written and properly signed records of each 
periodic inspection showing the date of the inspection, the study 
inspected, the phase or segment of the study inspected, the person 
performing the inspection, findings and problems, action recommended and 
taken to resolve existing problems, and any scheduled date for re-
inspection. Any problems which are likely to affect study integrity 
found during the course of an inspection shall be brought to the 
attention of the study director and management immediately.
    (D) Periodically submit to management and the study director written 
status reports on each study, noting any problems and the corrective 
actions taken.
    (E) Determine that no deviations from approved protocols or standard 
operating procedures were made without proper authorization and 
documentation.
    (F) Review the final study report to assure that such report 
accurately describes the methods and standard operating procedures, and 
that the reported results accurately reflect the raw data of the study.
    (G) Prepare and sign a statement to be included with the final study 
report which shall specify the dates inspections were made and findings 
reported to management and to the study director.
    (ii) The responsibilities and procedures applicable to the quality 
assurance unit, the records maintained by the quality assurance unit, 
and the method of indexing such records shall be in writing and shall be 
maintained. These items including inspection dates, the study inspected, 
the phase or segment of the study inspected, and the name of the 
individual performing the inspection shall be made available for 
inspection to authorized employees or duly designated representatives of 
EPA.
    (iii) An authorized employee or a duly designated representative of 
EPA shall have access to the written procedures established for the 
inspection and may request test facility management to certify that 
inspections are being implemented, performed, documented, and followed 
up in accordance with this paragraph.
    (c) Facilities--(1) General. Each testing facility shall be of 
suitable size and construction to facilitate the proper conduct of 
studies. Testing facilities which are not completely located within an 
indoor controlled environment shall be of suitable location/proximity to 
facilitate the proper conduct of studies. Testing facilities shall be 
designed so that there is a degree of separation that will prevent any 
function or activity from having an adverse effect on the study.
    (2) Test system care facilities. (i) A testing facility shall have a 
sufficient number of animal rooms or other test system areas, as needed, 
to ensure proper separation of species or test systems, quarantine or 
isolation of animals or other test systems, and routine or specialized 
housing of animals or other test systems.
    (ii) A testing facility shall have a number of animal rooms or other 
test system areas separate from those described in paragraph (a) of this 
section to ensure isolation of studies being done with test systems or 
test, control, and reference substances known to be biohazardous, 
including volatile atmospheres and aerosols, radioactive materials, and 
infectious agents. The animal handling facility must operate under the 
supervision of a veterinarian.
    (iii) Separate areas shall be provided, as appropriate, for the 
diagnosis, treatment, and control of laboratory test system diseases. 
These areas shall provide effective isolation for the housing of test 
systems either known or suspected of being diseased, or of being 
carriers of disease, from other test systems.
    (iv) Facilities shall have proper provisions for collection and 
disposal of contaminated air, water, or other spent materials. When 
animals are housed, facilities shall exist for the collection and 
disposal of all animal waste and refuse or for safe sanitary storage of 
waste before removal from the testing facility. Disposal facilities 
shall be so provided and operated as to minimize

[[Page 564]]

vermin infestation, odors, disease hazards, and environmental 
contamination.
    (v) Facilities shall have provisions to regulate environmental 
conditions (e.g., temperature, humidity, day length, etc.) as specified 
in the protocol.
    (3) Test system supply/operation areas. (i) There shall be storage 
areas, as needed, for feed, bedding, supplies, and equipment. Storage 
areas for feed and bedding shall be separated from areas where the test 
systems are located and shall be protected against infestation or 
contamination. Perishable supplies shall be preserved by appropriate 
means.
    (ii) Separate laboratory space and other space shall be provided, as 
needed, for the performance of the routine and specialized procedures 
required by studies.
    (4) Facilities for handling test fuels and fuel/additive mixtures 
and reference substances. (i) As necessary to prevent contamination or 
mixups, there shall be separate areas for:
    (A) Receipt and storage of the test fuels and fuel/additive mixtures 
and reference substances;
    (B) Mixing of the test fuels, fuel/additive mixtures, and reference 
substances with a carrier, i.e., liquid hydrocarbon; and
    (C) Storage of the test fuels, fuel/additive mixtures, and reference 
substance/carrier mixtures.
    (ii) Storage areas for test fuels and fuel/additive mixtures and 
reference substances and for reference mixtures shall be separate from 
areas housing the test systems and shall be adequate to preserve the 
identity, strength, purity, and stability of the substances and 
mixtures.
    (5) Specimen and data storage facilities. Space shall be secured for 
archives for the storage and retrieval of all raw data and specimens 
from completed studies.
    (d) Equipment--(1) Equipment design. Equipment used in the 
generation, measurement, or assessment of data and equipment used for 
facility environmental control shall be of appropriate design and 
adequate capacity to function according to the protocol and shall be 
suitably located for operation, inspection, cleaning, and maintenance.
    (2) Maintenance and calibration of equipment. (i) Equipment shall be 
adequately inspected, cleaned, and maintained. Equipment used for the 
generation, measurement, or assessment of data shall be adequately 
tested, calibrated, and/or standardized.
    (ii) The written standard operating procedures required under Sec. 
79.60(e)(1)(ii)(K) shall set forth in sufficient detail the methods, 
materials, and schedules to be used in the routine inspection, cleaning, 
maintenance, testing, calibration, and/or standardization of equipment, 
and shall specify, when appropriate, remedial action to be taken in the 
event of failure or malfunction of equipment. The written standard 
operating procedures shall designate the person responsible for the 
performance of each operation.
    (iii) Written records shall be maintained of all inspection, 
maintenance, testing, calibrating, and/or standardizing operations. 
These records, containing the date of the operation, shall describe 
whether the maintenance operations were routine and followed the written 
standard operating procedures. Written records shall be kept of non-
routine repairs performed on equipment as a result of failure and 
malfunction. Such records shall document the nature of the defect, how 
and when the defect was discovered, and any remedial action taken in 
response to the defect.
    (e) Testing Facilities Operation--(1) Standard operating procedures. 
(i) A testing facility shall have standard operating procedures in 
writing, setting forth study methods that management is satisfied are 
adequate to insure the quality and integrity of the data generated in 
the course of a study. All deviations in a study from standard operating 
procedures shall be authorized by the study director and shall be 
documented in the raw data. Significant changes in established standard 
operating procedures shall be properly authorized in writing by 
management.
    (ii) Standard operating procedures shall be established for, but not 
limited to, the following:
    (A) Test system room preparation;
    (B) Test system care;

[[Page 565]]

    (C) Receipt, identification, storage, handling, mixing, and method 
of sampling of test fuels and fuel/additive mixtures and reference 
substances;
    (D) Test system observations;
    (E) Laboratory or other tests;
    (F) Handling of test animals found moribund or dead during study;
    (G) Necropsy or postmortem examination of test animals;
    (H) Collection and identification of specimens;
    (I) Histopathology
    (J) Data handling, storage and retrieval.
    (K) Maintenance and calibration of equipment.
    (L) Transfer, proper placement, and identification of test systems.
    (iii) Each laboratory or other study area shall have immediately 
available manuals and standard operating procedures relative to the 
laboratory procedures being performed. Published literature may be used 
as a supplement to standard operating procedures.
    (iv) A historical file of standard operating procedures, and all 
revisions thereof, including the dates of such revisions, shall be 
maintained.
    (2) Reagents and solutions. All reagents and solutions in the 
laboratory areas shall be labeled to indicate identity, titer or 
concentration, storage requirements, and expiration date. Deteriorated 
or outdated reagents and solutions shall not be used.
    (3) Animal and other test system care. (i) There shall be standard 
operating procedures for the housing, feeding, handling, and care of 
animals and other test systems.
    (ii) All newly received test systems from outside sources shall be 
isolated and their health status or appropriateness for the study shall 
be evaluated. This evaluation shall be in accordance with acceptable 
veterinary medical practice or scientific methods.
    (iii) At the initiation of a study, test systems shall be free of 
any disease or condition that might interfere with the purpose or 
conduct of the study. If during the course of the study, the test 
systems contract such a disease or condition, the diseased test systems 
shall be isolated, if necessary. These test systems may be treated for 
disease or signs of disease provided that such treatment does not 
interfere with the study. The diagnosis, authorization of treatment, 
description of treatment, and each date of treatment shall be documented 
and shall be retained.
    (iv) When laboratory procedures require test animals to be 
manipulated and observed over an extended period of time or when studies 
require test animals to be removed from and returned to their housing 
units for any reason (e.g., cage cleaning, treatment, etc.), these test 
systems shall receive appropriate identification (e.g., tattoo, color 
code, etc.). Test system identification shall conform with current 
laboratory animal handling practice. All information needed to 
specifically identify each test system within the test system-housing 
unit shall appear on the outside of that unit. Suckling animals are 
excluded from the requirement of individual identification unless 
otherwise specified in the protocol.
    (v) Except as specified in paragraph (e)(3)(v)(A) of this section, 
test animals of different species shall be housed in separate rooms when 
necessary. Test animals of the same species, but used in different 
studies, shall not ordinarily be housed in the same room when 
inadvertent exposure to the test or reference substances or test system 
mixup could affect the outcome of either study. If such mixed housing is 
necessary, adequate differentiation by space and identification shall be 
made.
    (A) Test systems that may be used in multispecies tests need not be 
housed in separate rooms, provided that they are adequately segregated 
to avoid mixup and cross-contamination.
    (B) [Reserved]
    (vi) Cages, racks, pens, enclosures, and other holding, rearing, and 
breeding areas, and accessory equipment, shall be cleaned and sanitized 
at appropriate intervals.
    (vii) Feed and water used for the test animals shall be analyzed 
periodically to ensure that contaminants known to be capable of 
interfering with the study and reasonably expected to be present in such 
feed or water are not present at greater than trace levels. 
Documentation of such analyses shall be maintained as raw data.

[[Page 566]]

    (viii) Bedding used in animal cages or pens shall not interfere with 
the purpose or conduct of the study and shall be changed as often as 
necessary to keep the animals dry and clean.
    (ix) If any pest control materials are used, the use shall be 
documented. Cleaning and pest control materials that interfere with the 
study shall not be used.
    (x) All test systems shall be acclimatized to the environmental 
conditions of the test, prior to their use in a study.
    (f) Test fuels, additive/base fuel mixtures, and reference 
substances--(1) Test fuel, fuel/additive mixture, and reference 
substance identity. (i) The product brand name/service mark, strength, 
purity, content, or other characteristics which appropriately define the 
test fuel, fuel/additive mixture, or reference substance shall be 
reported for each batch and shall be documented before its use in a 
study. Methods of synthesis, fabrication, or derivation, as appropriate, 
of the test fuel, fuel/additive mixture, or reference substance shall be 
documented by the sponsor or the testing facility, and such location of 
documentation shall be specified.
    (ii) The stability of test fuel, fuel/additive mixture, and 
reference substances under storage conditions at the test site shall be 
known for all studies.
    (2) Test fuel, additive/base fuel mixture, and reference substance 
handling. Procedures shall be established for a system for the handling 
of the test fuel, fuel/additive mixture, and reference substance(s) to 
ensure that:
    (i) There is proper storage.
    (ii) Distribution is made in a manner designed to preclude the 
possibility of contamination, deterioration, or damage.
    (iii) Proper identification is maintained throughout the 
distribution process.
    (iv) The receipt and distribution of each batch is documented. Such 
documentation shall include the date and quantity of each batch 
distributed or returned.
    (3) Mixtures of test emissions or reference solutions with carriers.
    (i) For test emissions or each reference substance mixed with a 
carrier, tests by appropriate analytical methods shall be conducted:
    (A) To determine the uniformity of the test substance and to 
determine, periodically, the concentration of the test emissions or 
reference substance in the mixture;
    (B) When relevant to the conduct of the experiment, to determine the 
solubility of each reference substance in the carrier mixture before the 
experimental start date; and
    (C) To determine the stability of test emissions or a reference 
solution in the test substance before the experimental start date or 
concomitantly according to written standard operating procedures, which 
provide for periodic analysis of each batch.
    (ii) Where any of the components of the reference substance/carrier 
mixture has an expiration date, that date shall be clearly shown on the 
container. If more than one component has an expiration date, the 
earliest date shall be shown.
    (iii) If a chemical or physical agent is used to facilitate the 
mixing of a test substance with a carrier, assurance shall be provided 
that the agent does not interfere with the integrity of the test.
    (g) Protocol for and conduct of a study--(1) Protocol. (i) Each 
study shall have a written protocol that clearly indicates the 
objectives and all methods for the conduct of the study. The protocol 
shall contain but shall not be limited to the following information:
    (A) A descriptive title and statement of the purpose of the study.
    (B) Identification of the test fuel, fuel/additive mixture, and 
reference substance by name, chemical abstracts service (CAS) number or 
code number, as applicable.
    (C) The name and address of the sponsor and the name and address of 
the testing facility at which the study is being conducted.
    (D) The proposed experimental start and termination dates.
    (E) Justification for selection of the test system, as necessary.
    (F) Where applicable, the number, body weight, sex, source of 
supply, species, strain, substrain, and age of the test system.

[[Page 567]]

    (G) The procedure for identification of the test system.
    (H) A description of the experimental design, including methods for 
the control of bias.
    (I) Where applicable, a description and/or identification of the 
diet used in the study. The description shall include specifications for 
acceptable levels of contaminants that are reasonably expected to be 
present in the dietary materials and are known to be capable of 
interfering with the purpose or conduct of the study if present at 
levels greater than established by the specifications.
    (J) Each concentration level, expressed in milligrams per cubic 
meter of air or other appropriate units, of the test or reference 
substance to be administered and the frequency of administration.
    (K) The type and frequency of tests, analyses, and measurements to 
be made.
    (L) The records to be maintained.
    (M) The date of approval of the protocol by the sponsor and the 
dated signature of the study director.
    (N) A statement of the proposed statistical method.
    (ii) All changes in or revisions of an approved protocol and the 
reasons therefor shall be documented, signed by the study director, 
dated, and maintained with the protocol.
    (2) Conduct of a study. (i) The study shall be conducted in 
accordance with the protocol.
    (ii) The test systems shall be monitored in conformity with the 
protocol.
    (iii) Specimens shall be identified by test system, study, nature, 
and date of collection. This information shall be located on the 
specimen container or shall accompany the specimen in a manner that 
precludes error in the recording and storage of data.
    (iv) In animal studies where histopathology is required, records of 
gross findings for a specimen from postmortem observations shall be 
available to a pathologist when examining that specimen 
histopathologically.
    (v) All data generated during the conduct of a study, except those 
that are generated by automated data collection systems, shall be 
recorded directly, promptly, and legibly in ink. All data entries shall 
be dated on the day of entry and signed or initialed by the person 
entering the data. Any change in entries shall be made so as not to 
obscure the original entry, shall indicate the reason for such change, 
and shall be dated and signed or identified at the time of the change. 
In automated data collection systems, the individual responsible for 
direct data input shall be identified at the time of data input. Any 
change in automated data entries shall be made so as not to obscure the 
original entry, shall indicate the reason for change, shall be dated, 
and the responsible individual shall be identified.
    (h) Records and Reports--(1) Reporting of study results. (i) A final 
report shall be prepared for each study and shall include, but not 
necessarily be limited to, the following:
    (A) Name and address of the facility performing the study and the 
dates on which the study was initiated and was completed, terminated, or 
discontinued.
    (B) Objectives and procedures stated in the approved protocol, 
including any changes in the original protocol.
    (C) Statistical methods employed for analyzing the data.
    (D) The test fuel, additive/base fuel mixture, and test and 
reference substances identified by name, chemical abstracts service 
(CAS) number or code number, strength, purity, content, or other 
appropriate characteristics.
    (E) Stability, and when relevant to the conduct of the study, the 
solubility of the test emissions and reference substances under the 
conditions of administration.
    (F) A description of the methods used.
    (G) A description of the test system used. Where applicable, the 
final report shall include the number of animals or other test organisms 
used, sex, body weight range, source of supply, species, strain and 
substrain, age, and procedure used for identification.
    (H) A description of the concentration regimen as daily exposure 
period, i.e., number of hours, and exposure duration, i.e., number of 
days.

[[Page 568]]

    (I) A description of all circumstances that may have affected the 
quality or integrity of the data.
    (J) The name of the study director, the names of other scientists or 
professionals and the names of all supervisory personnel, involved in 
the study.
    (K) A description of the transformations, calculations, or 
operations performed on the data, a summary and analysis of the data, 
and a statement of the conclusions drawn from the analysis.
    (L) The signed and dated reports of each of the individual 
scientists or other professionals involved in the study, including each 
person who, at the request or direction of the testing facility or 
sponsor, conducted an analysis or evaluation of data or specimens from 
the study after data generation was completed.
    (M) The locations where all specimens, raw data, and the final 
report are to be kept or stored.
    (N) The statement, prepared and signed by the quality assurance 
unit, as described in Sec. 79.60(b)(4)(i)(G).
    (ii) The final report shall be signed and dated by the study 
director.
    (iii) Corrections or additions to a final report shall be in the 
form of an amendment by the study director. The amendment shall clearly 
identify that part of the final report that is being added to or 
corrected and the reasons for the correction or addition, and shall be 
signed and dated by the person responsible. Modification of a final 
report to comply with the submission requirements of EPA does not 
constitute a correction, addition, or amendment to a final report.
    (iv) A copy of the final report and of any amendment to it shall be 
maintained by the sponsor and the test facility.
    (2) Storage and retrieval of records and data. (i) All raw data, 
documentation, records, protocols, specimens, and final reports 
generated as a result of a study shall be retained. Specimens obtained 
from mutagenicity tests, wet specimens of blood, urine, feces, and 
biological fluids, do not need to be retained after quality assurance 
verification. Correspondence and other documents relating to 
interpretation and evaluation of data, other than those documents 
contained in the final report, also shall be retained.
    (ii) All raw data, documentation, protocols, specimens, and interim 
and final reports shall be archived for orderly storage and expedient 
retrieval. Conditions of storage shall minimize deterioration of the 
documents or specimens in accordance with the requirements for the time 
period of their retention and the nature of the documents of specimens. 
A testing facility may contract with commercial archives to provide a 
repository for all material to be retained. Raw data and specimens may 
be retained elsewhere provided that the archives have specific reference 
to those other locations.
    (iii) An individual shall be identified as responsible for the 
archiving of records.
    (iv) Access to archived material shall require authorization and 
documentation.
    (v) Archived material shall be indexed to permit expedient 
retrieval.
    (3) Retention of records. (i) Record retention requirements set 
forth in this section do not supersede the record retention requirements 
of any other regulations in this subchapter.
    (ii) Except as provided in paragraph (h)(3)(iii) of this section, 
documentation records, raw data, and specimens pertaining to a study and 
required to be retained by this part shall be archived for a period of 
at least ten years following the completion of the study.
    (iii) Wet specimens, samples of test fuel, additive/base fuel 
mixtures, or reference substances, and specially prepared material which 
are relatively fragile and differ markedly in stability and quality 
during storage, shall be retained only as long as the quality of the 
preparation affords evaluation. Specimens obtained from mutagenicity 
tests, wet specimens of blood, urine, feces, biological fluids, do not 
need to be retained after quality assurance verification. In no case 
shall retention be required for a longer period than that set forth in 
paragraph (h)(3)(ii) of this section.
    (iv) The master schedule sheet, copies of protocols, and records of 
quality assurance inspections, as required by Sec. 79.60(b)(4)(iii) 
shall be maintained by

[[Page 569]]

the quality assurance unit as an easily accessible system of records for 
the period of time specified in paragraph (h)(3)(ii) of this section.
    (v) Summaries of training and experience and job descriptions 
required to be maintained by Sec. 79.60(b)(1)(ii) may be retained along 
with all other testing facility employment records for the length of 
time specified in paragraph (h)(3)(ii) of this section.
    (vi) Records and reports of the maintenance and calibration and 
inspection of equipment, as required by Sec. 79.60(d)(2) (ii) and 
(iii), shall be retained for the length of time specified in paragraph 
(h)(3)(ii) of this section.
    (vii) If a facility conducting testing or an archive contracting 
facility goes out of business, all raw data, documentation, and other 
material specified in this section shall be transferred to the sponsor 
of the study for archival.
    (viii) Records required by this section may be retained either as 
original records or as true copies such as photocopies, microfilm, 
microfiche, or other accurate reproductions of the original records.



Sec. 79.61  Vehicle emissions inhalation exposure guideline.

    (a) Purpose. This guideline provides additional information on 
methodologies required to conduct health effects tests involving 
inhalation exposures to vehicle combustion emissions from fuels or fuel/
additive mixtures. Where this guideline and the other health effects 
testing guidelines in 40 CFR 79.62 through 79.68 specify differing 
values for the same test parameter, the specifications in the individual 
health test guideline shall prevail for that health effect endpoint.
    (b) Definitions. For the purposes of this section the following 
definitions apply.
    Acute inhalation study means a short-term toxicity test 
characterized by a single exposure by inhalation over a short period of 
time (at least 4 hours and less than 24 hours), followed by at least 14 
days of observation.
    Aerodynamic diameter means the diameter of a sphere of unit density 
that has the same settling velocity as the particle of the test 
substance. It is used to compare particles of different sizes, densities 
and shapes, and to predict where in the respiratory tract such particles 
may be deposited. It applies to the size of aerosol particles.
    Chronic inhalation study means a prolonged and repeated exposure by 
inhalation for the life span of the test animal; technically, two years 
in the rat.
    Concentration means an exposure level. Exposure is expressed as 
weight or volume of test aerosol/substance per volume of air, usually 
mg/m\3\ or as parts per million (ppm) over a given time period. 
Micrograms per cubic meter ([micro]g/m\3\) or parts per billion may be 
appropriate, as well.
    Cumulative toxicity means the adverse effects of repeated exposures 
occurring as a result of prolonged action or increased concentration of 
the administered test substance or its metabolites in the susceptible 
tissues.
    Inhalable diameter means that aerodynamic diameter of a particle 
which is considered to be inhalable for the organism. It is used to 
refer to particles which are capable of being inhaled and may be 
deposited anywhere within the respiratory tract from the trachea to the 
alveoli.
    Mass median aerodynamic diameter (MMAD) means the calculated 
aerodynamic diameter, which divides the particles of an aerosol in half 
based on the mass of the particles. Fifty percent of the particles in 
mass will be larger than the median diameter, and fifty percent will be 
smaller than the median diameter. MMAD describes the particle 
distribution of any aerosol based on the weight and size of the 
particles. MMAD and the geometric standard deviation describe the 
particle-size distribution.
    Material safety data sheet (MSDS) means documentation or information 
on the physical, chemical, and hazardous characteristics of a given 
chemical, usually provided by the product's manufacturer.
    Reynolds number means a dimensionless number that is proportional to 
the ratio of inertial forces to frictional forces acting on a fluid. It 
quantitatively provides a measure of whether flow is laminar or 
turbulent. A fluid traveling through a pipe is fully developed into a 
laminar flow for a

[[Page 570]]

Reynolds number less than 2000, and fully developed into a turbulent 
flow for a Reynolds number greater than 4000.
    Subacute inhalation toxicity means the adverse effects occurring as 
a result of the repeated daily exposure of experimental animals to a 
chemical by inhalation for part (less than 10 percent) of a lifespan; 
generally, less than 90 days.
    Subchronic inhalation study means a repeated exposure by inhalation 
for part (approximately 10 percent) of a life span of the exposed test 
animal.
    Toxic effect means an adverse change in the structure or function of 
an experimental animal as a result of exposure to a chemical substance.
    (c) Principles and design criteria of inhalation exposure systems. 
Proper conduct of inhalation toxicity studies of the emissions of fuels 
and additive/fuel mixtures requires that the exposure system be designed 
to ensure the controlled generation of the exposure atmosphere, the 
adequate dilution of the test emissions, delivery of the diluted 
exposure atmosphere to the test animals, and use of appropriate exposure 
chamber systems selected to meet criteria for a given exposure study.
    (1) Emissions generation. Emissions shall be generated according to 
the specifications in 40 CFR 79.57.
    (2) Dilution and delivery systems. (i) The delivery system is the 
means used to transport the emissions from the generation system to the 
exposure system. The dilution system is generally a component of the 
delivery system.
    (ii) Dilution provides control of the emissions concentration 
delivered to the exposure system, serving the function of diluting the 
associated combustion gases, such as carbon monoxide, carbon dioxide, 
nitrogen oxides, sulfur dioxide and other noxious gases and vapors, to 
levels that will ensure that there are no significant or measurable 
responses in the test animals as a result of exposure to the combustion 
gases. The formation of particle species is strongly dependent on the 
dilution rate, as well.
    (iii) The engine exhaust system shall connect to the first-stage-
dilution section at 90 to the axis of the dilution section. This is 
then connected to a right angle elbow on the center line of the dilution 
section. Engine emissions are injected through the elbow so that exhaust 
flow is concurrent to dilution flow.
    (iv) Materials. In designing the dilution and delivery systems, the 
use of plastic, e.g., PVC and similar materials, copper, brass, and 
aluminum pipe and tubing shall be avoided if there exists a possibility 
of chemical reaction occurring between emissions and tubing. Stainless 
steel pipe and tubing is recommended as the best choice for most 
emission dilution and delivery applications, although glass and teflon 
may be appropriate, as well.
    (v) Flow requirements. (A) Conduit for dilute raw emissions shall be 
of such dimensions as to provide residence times for the emissions on 
the order of less than one second to several seconds before the 
emissions are further diluted and introduced to the test chambers. With 
the high flow rates in the dilute raw emissions conduit, it will be 
necessary to sample various portions of the dilute emissions for 
delivering differing concentrations to the test chambers. The unused 
portions of the emissions stream are normally exhausted to the 
atmosphere outside of the exposure facility.
    (B) Dimensions of the dilute raw exhaust conduit shall be such that, 
at a minimum, the flow Reynolds number is 70,000 or greater (see Mokler, 
et al., 1984 in paragraph (f)(13) of this section). This will maintain 
highly turbulent flow conditions so that there is more complete mixing 
of the exhaust emissions.
    (C) Wall losses. The delivery system shall be designed to minimize 
wall losses. This can be done by sizing the tubing or pipe to maintain 
laminar flow of the diluted emissions to the exposure chamber. A flow 
Reynolds number of 1000-3000 will ensure minimal wall losses. Also, the 
length of and number and degree of bends in the delivery lines to the 
exposure chamber system shall be minimized.
    (D) Whole-body exposure vs. nose-only exposure delivery systems. 
Flow rates through whole-body chamber systems are of the order of 100 
liters per minute to 500 liters per minute. Nose-only systems are on the 
order of less than 50 liters per minute. To maintain

[[Page 571]]

laminar flow conditions, the principles described in paragraph 
(c)(2)(v)(C) of this section apply to both systems.
    (vi) Dilution requirements. (A) To maintain the water vapor, and 
dissolved organic compounds, in the raw exhaust emissions stream, a 
manufacturer/tester will initially dilute one part emissions with a 
minimum of five parts clean, filtered air (see Hinners, et al., 1979 in 
paragraph (f)(11) of this section). Depending on the water vapor content 
of a particular fuel/additive mixture's combustion emissions and the 
humidity of the dilution air, initial exhaust dilutions as high as 1:15 
or 1:20 may be necessary to maintain the general character of the 
exhaust as it cools, e.g., M100. At this point, it is expected that the 
exhaust stream would be further diluted to more appropriate levels for 
rodent health effects testing.
    (B) A maximum concentration (minimum dilution) of the raw exhaust 
going into the test animal cages is anticipated to lie in the range 
between 1:5 and 1:50 exhaust emissions to clean, filtered air. The 
minimum concentration (maximum dilution) of raw exhaust for health 
effects testing is anticipated to be in range between 1:100 and 1:150. 
Individual manufacturers will treat these ranges as approximations only 
and will determine the optimum range of emission concentrations to 
elicit effects in Tier 2 health testing for their particular fuel/fuel 
additive mixture.
    (3) Exposure chamber systems--(i) Referenced Guidelines. (A) The 
U.S. Department of Health and Human Services ``Guide for the Care and 
Use of Laboratory Animals'' (Guide), 1985 cited in paragraph 
(c)(3)(ii)(A)(4), and in paragraphs (d)(2)(i), (d)(2)(ii), (d)(2)(iii), 
(d)(4)(ii), and (d)(4)(iii) of this section, has been incorporated by 
reference.
    (B) This incorporation by reference was approved by the Director of 
the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 
51. Copies may be purchased from the Superintendent of Documents, U.S. 
Government Printing Office, Washington, DC 20402. Copies may be 
inspected at U.S. EPA, OAR, 401 M Street SW, Washington, DC 20460 or 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.
    (ii) Exposure chambers. There are two basic types of dynamic 
inhalation exposure chambers, whole-body chambers and nose-/head-only 
exposure chambers (see Cheng and Moss, 1989 in paragraph (f)(8) of this 
section).
    (A) Whole-body chambers. (1) The flow rate through a chamber shall 
be maintained at 15 air changes per hour.
    (2) The chambers are usually maintained at a slightly negative 
pressure (0.5 to 1.5 inch of water) to prevent leakage of test substance 
into the exposure room.
    (3) The exposure chamber shall be designed in such a way as to 
provide uniform distribution of exposure concentrations in all 
compartments (see Cheng et al., 1989 in paragraph (f)(7) of this 
section).
    (4) Animals are housed in separate compartments inside the chamber, 
where the whole surface area of an animal is exposed to the test 
material. The spaces required for different animal species shall follow 
the Guide. In general, the volume of animal bodies occupy less than 5 
percent of the chamber volume.
    (B) Head/nose-only exposure chambers. (1) In head/nose-only exposure 
chambers, only the head (oronasal) portion of the animal is exposed to 
the test material.
    (2) The chamber volume and flow rates are much less than in the 
whole-body exposure chambers because the subjects are usually restrained 
in a tube holder where the animal's breathing can be easily monitored. 
The head/nose-only exposure chamber is suitable for short-term exposures 
or when use of a small amount of test material is required.
    (iii) Since whole-body exposure appears to be the least stressful 
mode of exposure, it is the preferred method. In general, head/nose only 
exposure, which is sometimes used to avoid concurrent exposure by the 
dermal or oral routes, i.e., grooming, is not recommended because of the 
stress accompanying the restraining of the animals.

[[Page 572]]

However, there may be specific instances where it may be more 
appropriate than whole-body exposure. The tester shall provide 
justification for its selection.
    (d) Inhalation exposure procedures--(1) Animal selection. (i) The 
rat is the preferred species for vehicle emission inhalation health 
effects testing. Commonly used laboratory strains shall be used. Any 
rodent species may be used, but the tester shall provide justification 
for the choice of that species.
    (ii) Young adult animals, approximately ten weeks of age for the 
rat, shall be used. At the commencement of the study, the weight 
variation of animals used shall not exceed [20 percent of the mean 
weight for each sex. Animals shall be randomly assigned to treatment and 
control groups according to their weight.
    (iii) An equal number of male and female rodents shall be used at 
each concentration level. Situations may arise where use of a single sex 
may be appropriate. Females, in general, shall be nulliparous and 
nonpregnant.
    (iv) The number of animals used at each concentration level and in 
the control group(s) depends on the type of study, number of biological 
end points used in the toxicity evaluation, the pre-determined 
sensitivity of detection and power of significance of the study, and the 
animal species. For an acute study, at least five animals of each sex 
shall be used in each test group. For both the subacute and subchronic 
studies, at least 10 rodents of each sex shall be used in each test 
group. For a chronic study, at least 20 male and 20 female rodents shall 
be used in each test group.
    (A) If interim sacrifices are planned, the number of animals shall 
be increased by the number of animals scheduled to be sacrificed during 
the course of the study.
    (B) For a chronic study, the number of animals at the termination of 
the study must be adequate for a meaningful and valid statistical 
evaluation of chronic effects.
    (v) A concurrent control group is required. This group shall be 
exposed to clean, filtered air under conditions identical to those used 
for the group exposed to the test atmosphere.
    (vi) The same species/strain shall be used to make comparisons 
between fuel-only and fuel/additive mixture studies. If another species/
strain is used, the tester shall provide justification for its 
selection.
    (2) Animal handling and care. (i) A key element in the conduct of 
inhalation exposure studies is the proper handling and care of the test 
animal population. Therefore, the exposure conditions must conform 
strictly with the conditions for housing and animal care and use set 
forth in the Guide.
    (ii) In whole-body exposure chambers, animals shall be housed in 
individual caging. The minimum cage size per animal will be in 
accordance with instructions set forth in the Guide.
    (iii) Chambers shall be cleaned and maintained in accordance with 
recommendations and schedules set forth in the Guide.
    (A) Observations shall be made daily with appropriate actions taken 
to minimize loss of animals to the study (e.g., necropsy or 
refrigeration of animals found dead and isolation or sacrifice of weak 
or moribund animals). Exposure systems using head/nose-only exposure 
chambers require no special daily chamber maintenance. Chambers shall be 
inspected to ensure that they are clean, and that there are no 
obstructions in the chamber which would restrict air flow to the 
animals. Whole-body exposure chambers will be inspected on a minimum of 
twice daily, once before exposures and once after exposures.
    (B) Signs of toxicity shall be recorded as they are observed, 
including the time of onset, degree, and duration.
    (C) Cage-side observations shall include, but are not limited to: 
changes in skin, fur, eye and mucous membranes, respiratory, autonomic, 
and central nervous systems, somatomotor activity, and behavioral 
patterns. Particular attention shall be directed to observation of 
tremors, convulsions, salivation, diarrhea, lethargy, sleep, and coma.
    (iv) Food and water will be withheld from animals for head/nose-only 
exposure systems. For whole-body-exposure systems, water only may be 
provided. When the exposure generation system is not operating, food 
will be available

[[Page 573]]

ad libitum. During operation of the generation system, food will be 
withheld to avoid possible contamination by emissions.
    (v) At the end of the study period, all survivors in the main study 
population shall be sacrificed. Moribund animals shall be removed and 
sacrificed when observed.
    (3) Concentration levels and selection. (i) In acute and subacute 
toxicity tests, at least three exposure concentrations and a control 
group shall be used and spaced appropriately to produce test groups with 
a range of toxic effects and mortality rates. The data shall be 
sufficient to produce a concentration-response curve and permit an 
acceptable estimation of the median lethal concentration.
    (ii) In subchronic and chronic toxicity tests, testers shall use at 
least three different concentration levels, with a control exposure 
group, to determine a concentration-response relationship. 
Concentrations shall be spaced appropriately to produce test groups with 
a range of toxic effects. The concentration-response data may also be 
sufficient to determine a NOAEL, unless the result of a limit test 
precludes such findings. The criteria for selecting concentration levels 
has been published (40 CFR 798.2450 and 798.3260).
    (A) The highest concentration shall result in toxic effects but not 
produce an incidence of fatalities which would prevent a meaningful 
evaluation of the study.
    (B) The lowest concentration shall not produce toxic effects which 
are directly attributable to the test exposure. Where there is a useful 
estimation of human exposure, the lowest concentration shall exceed 
this.
    (C) The intermediate concentration level(s) shall produce minimal 
observable toxic effects. If more than one intermediate concentration 
level is used, the concentrations shall be spaced to produce a gradation 
of toxic effects.
    (D) In the low, intermediate, and control exposure groups, the 
incidence of fatalities shall be low to absent, so as not to preclude a 
meaningful evaluation of the results.
    (4) Exposure chamber environmental conditions. The following 
environmental conditions in the exposure chamber are critical to the 
maintenance of the test animals: flow; temperature; relative humidity; 
lighting; and noise.
    (i) Filtered and conditioned air shall be used during exposure, to 
dilute the exhaust emissions, and during non- exposure periods to 
maintain environmental conditions that are free of trace gases, dusts, 
and microorganisms on the test animals. Twelve to fifteen air changes 
per hour will be provided at all times to whole-body-exposure chambers. 
The minimum air flow rate for head/nose-only exposure chambers will be a 
function of the number of animals and the average minute volume of the 
animals:

Qminimum(L/min) = 2 x number of animals x average minute 
volume

(see Cheng and Moss, 1989 in paragraph (f)(8) of this section).
    (ii) Recommended ranges of temperature for various species are given 
in the Guide. The recommended temperature ranges will be used for 
establishing temperature conditions of whole-body- exposure chambers. 
For rodents in whole-body-exposure chambers, the recommended temperature 
is 22 C [2 C and for rabbits, it is 20 C [3 C. Temperature ranges 
have not been established for head/nose-only tubes; however, recommended 
maximum temperature limits have been established at the Inhalation 
Toxicology Research Institute (see Barr, 1988 in paragraph (f)(1) of 
this section). Maximum temperature for rats and mice in head/nose-only 
tubes is 23 C.
    (iii) Relative humidity. The relative humidity in the chamber air is 
important for heat balance and shall be maintained between 40 percent 
and 60 percent, but in certain instances, this may not be practicable. 
Testers shall follow Guide recommends for a 30 percent to 70 percent 
relative humidity range for rodents in exposure chambers.
    (iv) Lighting. Light intensity of 30 foot candles at 3 ft. from the 
floor of the exposure facility is recommended (see Rao, 1986 in 
paragraph (f)(16) of this section).
    (5) Exposure conditions. Unless precluded by the requirements of a 
particular test protocol, animal subjects

[[Page 574]]

shall be exposed to the test atmosphere based on a nominal 5-day-per-
week regimen, subject to the following rules:
    (i) Each daily exposure must be at least 6 hours plus the time 
necessary to build the chamber atmosphere to 90 percent of the target 
exposure atmosphere. Interruptions of daily exposures caused by 
technical difficulties, if infrequent in occurrence and limited in 
duration, may be made up the same day by adding equivalent exposure time 
after the technical problem has been corrected and the exposure 
atmosphere restored to the required level.
    (ii) Normally, no more than two non-exposure days may occur 
consecutively during the test period. However, if a third consecutive 
non-exposure day should occur due to circumstances beyond the tester's 
control, it may be remedied by adding a supplementary exposure day. 
Federal and other holidays do not constitute such circumstances. 
Whenever possible, a make-up day should be taken at the first 
opportunity, i.e., on the next day which would otherwise have been an 
intentional non-exposure day. If a compensatory day must be scheduled at 
the end of the standard test period, then it may occur either:
    (A) Immediately following the last standard exposure day, with no 
intervening non-exposure days; or
    (B) With up to two intervening non-exposure days, provided that no 
fewer than two consecutive compensatory exposure days are completed 
before the test is terminated and the animals sacrificed.
    (iii) Except as allowed in paragraph (d)(5)(ii)(B) of this section, 
in no case shall there be fewer than four exposure days per week at any 
time during the test period.
    (iv) A nominal 90-day (13-week) subchronic test period shall include 
no fewer than 63 total exposure days.
    (6) Exposure atmosphere. (i) The exposure atmosphere shall be held 
as constant as is practicable and must be monitored continuously or 
intermittently, depending on the method of analysis, to ensure that 
exposure levels are at the target values or within stated limits during 
the exposure period. Sampling methodology will be determined based on 
the type of generation system and the type of exposure chamber system 
specified for the exposure study.
    (A) Integrated samples of test atmosphere aerosol shall be taken 
daily during the exposure period from a single representative sample 
port in the chamber near the breathing zone of the animals. Gas samples 
shall be taken daily to determine concentrations (ppm) of the major 
vapor components of the test atmosphere including CO, CO2, 
NOX, SO2, and total hydrocarbons.
    (B) To ensure that animals in different locations of the chamber 
receive a similar exposure atmosphere, distribution of an aerosol or 
vapor concentration in exposure chambers can be determined without 
animals during the developmental phase of the study, or it can be 
determined with animals early in the study. For head/nose-only exposure 
chambers, it may not be possible to monitor the chamber distribution 
during the exposure, because the exposure port contains the animal.
    (C) During the development of the emissions generation system, 
particle size analysis shall be performed to establish the stability of 
an aerosol concentration with respect to particle size. Over the course 
of the exposure, analysis shall be conducted as often as is necessary to 
determine the consistency of particle size distribution.
    (D) Chamber rise and fall times. The rise time required for the 
exposure concentration to reach 90 percent of the stable concentration 
after the generator is turned on, and the fall time when the chamber 
concentration decreases to 10 percent of the stable concentration after 
the generation system is stopped shall be determined in the 
developmental phase of the study. Time-integrated samples collected for 
calculating exposure concentrations shall be taken after the rise time. 
The daily exposure time is exclusive of the rise or the fall time.
    (ii) Instrumentation used for a given study will be determined based 
on the type of generation system and the type of exposure chamber system 
specified for the exposure study.
    (A) For exhaust studies, combustion gases shall be sampled by 
collecting exposure air in bags and then analyzing the collected air 
sample to determine

[[Page 575]]

major components of the combustion gas using gas analyzers. Exposure 
chambers can also be connected to gas analyzers directly by using 
sampling lines and switching valves. Samples can be taken more 
frequently using the latter method. Aerosol instruments, such as 
photometers, or time-integrated gravimetric determination may be used to 
determine the stability of any aerosol concentration in the chamber.
    (B) For evaporative emission studies, concentration of fuel vapors 
can usually be determined by using a gas chromatograph (GC) and/or 
infrared (IR) spectrometry. Grab samples for intermittent sampling can 
be taken from the chamber by using bubble samplers with the appropriate 
solvent to collect the vapors, or by collecting a small volume of air in 
a syringe. Intermediate or continuous monitoring of the chamber 
concentration is also possible by connecting the chamber with a GC or IR 
detector.
    (7) Monitoring chamber environmental conditions may be performed by 
a computer system or by exposure system operating personnel.
    (i) The flow-metering device used for the exposure chambers must be 
a continuous monitoring device, and actual flow measurements must be 
recorded at least every 30 minutes. Accuracy must be [5 percent of full 
scale range. Measurement of air flow through the exposure chamber may be 
accomplished using any device that has sufficient range to accurately 
measure the air flow for the given chamber. Types of flow metering 
devices include rotameters, orifice meters, venturi meters, critical 
orifices, and turbinemeters (see Benedict, 1984 in paragraph (f)(4) and 
Spitzer, 1984 in paragraph (f)(17) of this section).
    (ii) Pressure. Pressure measurement may be accomplished using 
manometers, electronic pressure transducers, magnehelics, or similar 
devices (see Gillum, 1982 in paragraph (f)(10) of this section). 
Accuracy of the pressure device must be [5 percent of full scale range. 
Pressure measurements must be continuous and recorded at least every 30 
minutes.
    (iii) Temperature. The temperature of exposure chambers must be 
monitored continuously and recorded at least every 30 minutes. 
Temperature may be measured using thermometers, RTD's, thermocouples, 
thermistors, or other devices (see Benedict, 1984 in paragraph (f)(4) of 
this section). It is necessary to incorporate an alarm system into the 
temperature monitoring system. The exposure operators must be notified 
by the alarm system when the chamber temperature exceeds 26.7 C (80 
F). The exposure must be discontinued and emergency procedures enacted 
to immediately reduce temperatures or remove test animals from high 
temperature environment when chamber temperatures exceed 29 C. Accuracy 
of the temperature monitoring device will be [1 C for the temperature 
range of 20-30 C.
    (iv) Relative humidity. The relative humidity of exposure chambers 
must be monitored continuously and recorded at least every 30 minutes. 
Relative humidity may be measured using various devices (see Chaddock, 
1985 in paragraph (f)(6) of this section).
    (v) Lighting shall be measured quarterly, or once at the beginning, 
middle, and end of the study for shorter studies.
    (vi) Noise level in the exposure chamber(s) shall be measured 
quarterly, or once at the beginning, middle, and end of the study for 
shorter studies.
    (vii) Oxygen content is critical, especially in nose-only chamber 
systems, and shall be greater than or equal to 19 percent in the test 
cages. An oxygen sensor shall be located at a single position in the 
test chamber and a lower alarm limit of 18 percent shall be used to 
activate an alarm system.
    (8) Safety procedures and requirements. In the case of potentially 
explosive test substance concentrations, care shall be taken to avoid 
generating explosive atmospheres.
    (i) It is mandatory that the upper explosive limit (UEL) and lower 
explosive limit (LEL) for the fuel and/or fuel additive(s) that are 
being tested be determined. These limits can be found in the material 
safety data sheets (MSDS) for each substance and in various reference 
texts. The air concentration of the fuel or additive-base fuel mixture 
in the generation system, dilution/delivery

[[Page 576]]

system, and the exposure chamber system shall be calculated to ensure 
that explosive limits are not present.
    (ii) Storage, handling, and use of fuels or fuel/additive mixtures 
shall follow guidelines given in 29 CFR 1910.106.
    (iii) Monitoring for carbon monoxide (CO) levels is mandatory for 
combustion systems. CO shall be continuously monitored in the immediate 
area of the engine/vehicle system and in the exposure chamber(s).
    (iv) Air samples shall be taken quarterly in the immediate area of 
the vapor generation system and the exposure chamber system, or once at 
the beginning, middle, and end of the study for shorter studies. These 
samples shall be analyzed by methods described in paragraph 
(d)(6)(ii)(B) of this section.
    (v) With the presence of fuels and/or fuel additives, all electrical 
and electronic equipment must be grounded. Also, the dilution/delivery 
system and chamber exposure system must be grounded. Guidelines for 
grounding are given in 29 CFR 1910.304.
    (9) Quality control and quality assurance procedures--(i) Standard 
operating procedures (SOPs). SOPs for exposure operations, sampling 
instruments, animal handling, and analytical methods shall be written 
during the developmental phase of the study.
    (ii) Technicians/operators shall be trained in exposure operation, 
maintenance, and documentation, as appropriate, and their training shall 
be documented.
    (iii) Flow meters, sampling instruments, and balances used in the 
inhalation experiments shall be calibrated with standards during the 
developmental phase to determine their sensitivity, detection limits, 
and linearity. During the exposure period, instruments shall be checked 
for calibration and documented to ensure that each instrument still 
functions properly.
    (iv) The mean exposure concentration shall be within 10 percent of 
the target concentration on 90 percent or more of exposure days. The 
coefficient of variation shall be within 25 percent of target on 90 
percent or more of exposure days. For example, a manufacturer might 
determine a mean exposure concentration of its product's exposure 
emissions by identifying ``marker'' compound(s) typical of the emissions 
of the fuel or fuel/additive mixture under study as a surrogate for the 
total of individual compounds in those exposure emissions. The 
manufacturer would note any concentration changes in the level of the 
``marker'' compound(s) in the sample's daily emissions for biological 
testing.
    (v) The spatial variation of the chamber concentration shall be 10 
percent, or less. If a higher spatial variation is observed during the 
developmental phase, then air mixing in the chamber shall be increased. 
In any case, animals shall be rotated among the various cages in the 
exposure chamber(s) to insure each animal's uniform exposure during the 
study.
    (e) Data and reporting. Data shall be summarized in tabular form, 
showing for each group the number of animals at the start of the test, 
the number of animals showing lesions, the types of lesions, and the 
percentage of animals displaying each type of lesion.
    (1) Treatment of results. All observed results, quantitative and 
incidental, shall be evaluated by an appropriate statistical method. Any 
generally accepted statistical method may be used; the statistical 
methods shall be selected during the design of the study.
    (2) Evaluation of results. The findings of an inhalation toxicity 
study should be evaluated in conjunction with the findings of preceding 
studies and considered in terms of the observed toxic effects and the 
necropsy and histopathological findings. The evaluation will include the 
relationship between the concentration of the test atmosphere and the 
duration of exposure, and the severity of abnormalities, gross lesions, 
identified target organs, body weight changes, effects on mortality and 
any other general or specific toxic effects.
    (3) Test conditions. (i) The exposure apparatus shall be described, 
including:
    (A) The vehicle/engine design and type, the dynamometer, the cooling 
system, if any, the computer control system, and the dilution system for 
exhaust emission generation;
    (B) The evaporative emissions generator model, type, or design and 
its dilution system; and

[[Page 577]]

    (C) Other test conditions, such as the source and quality of mixing 
air, fuel or fuel/additive mixture used, treatment of exhaust air, 
design of exposure chamber and the method of housing animals in a test 
chamber shall be described.
    (ii) The equipment for measuring temperature, humidity, particulate 
aerosol concentrations and size distribution, gas analyzers, fuel vapor 
concentrations, chamber distribution, and rise and fall time shall be 
described.
    (iii) Daily exposure results. The daily record shall document the 
date, the start and stop times of the exposure, number of samples taken 
during the day, daily concentrations determined, calibration of 
instruments, and problems encountered during the exposure. The daily 
exposure data shall be signed by the exposure operator and reviewed and 
signed by the exposure supervisor responsible for the study.
    (4) Exposure data shall be tabulated and presented with mean values 
and a measure of variability (e.g., standard deviation), and shall 
include:
    (i) Airflow rates through the inhalation equipment;
    (ii) Temperature and humidity of air;
    (iii) Chamber concentrations in the chamber breathing zone;
    (iv) Concentration of combustion exhaust gases in the chamber 
breathing zone;
    (v) Particle size distribution (e.g., mass median aerodynamic 
diameter and geometric standard deviation from the mean);
    (vi) Rise and fall time;
    (vii) Chamber concentrations during the non-exposure period; and
    (viii) Distribution of test substance in the chamber.
    (5) Animal data. Tabulation of toxic response data by species, 
strain, sex and exposure level for:
    (i) Number of animals exposed;
    (ii) Number of animals showing signs of toxicity; and
    (iii) Number of animals dying.
    (f) References. For additional background information on this 
exposure guideline, the following references should be consulted.
    (1) Barr, E.B. (1988) Operational Limits for Temperature and Percent 
Oxygen During HM Nose-Only Exposures--Emergency Procedures [interoffice 
memorandum]. Albuquerque, NM: Lovelace Inhalation Toxicology Research 
Institute; May 13.
    (2) Barr, E.B.; Cheng, Y.S.; Mauderly, J.L. (1990) Determination of 
Oxygen Depletion in a Nose-Only Exposure Chamber. Presented at: 1990 
American Association for Aerosol Research; June; Philadelphia, PA: 
American Association for Aerosol Research; abstract no. P2e1.
    (3) Barrow, C.S. (1989) Generation and Characterization of Gases and 
Vapors. In: McClellan, R.O., Henderson, R.F. ed. Concepts in Inhalation 
Toxicology. New York, NY: Hemisphere Publishing Corp., 63-84.
    (4) Benedict, R.P. (1984) Fundamentals of Temperature, Pressure, and 
Flow Measurements. 3rd ed. New York, NY: John Wiley and Sons.
    (5) Cannon, W.C.; Blanton, E.F.; McDonald, K.E. The Flow-Past 
Chamber. (1983) An Improved Nose-Only Exposure System for Rodents. Am. 
Ind. Hyg. Assoc. J. 44: 923-928.
    (6) Chaddock, J.B. ed. (1985) Moisture and humidity. Measurement and 
Control in Science and Industry: Proceedings of the 1985 International 
Symposium on Moisture and Humidity; April 1985; Washington, D.C. 
Research Triangle Park, NC: Instrument Society of America.
    (7) Cheng, Y.S.; Barr, E.B.; Carpenter, R.L.; Benson, J.M.; Hobbs, 
C.H. (1989) Improvement of Aerosol Distribution in Whole-Body Inhalation 
Exposure Chambers. Inhal. Toxicol. 1: 153-166.
    (8) Cheng,Y.S.; Moss, O.R. (1989) Inhalation Exposure Systems. In: 
McClellan, R.O.; Henderson, R.F. ed. Concepts in Inhalation Toxicology. 
New York, NY: Hemisphere Publishing Corp., 19-62.
    (9) Cheng, Y.S.; Yeh, H.C.; Mauderly, J.L.; Mokler, B.V. (1984) 
Characterization of Diesel Exhaust in a Chronic Inhalation Study. Am. 
Ind. Hyg. Assoc. J. 45: 547-555.
    (10) Gillum, D.R. (1982) Industrial Pressure Measurement. Research 
Triangle Park, NC: Instrument Society of America.
    (11) Hinners, R.G.; Burkart, J.K.; Malanchuk, M. (1979) Animal 
Exposure Facility for Diesel Exhaust Studies.

[[Page 578]]

    (12) Kittelson, D.B.; Dolan, D.F. (1979) Diesel exhaust aerosols. In 
Willeke, K. ed. Generation of Aerosols and Facilities for Exposure 
Experiments. Ann Arbor, MI: Ann Arbor Science Publishers Inc., 337-360.
    (13) Mokler, B.V.; Archibeque, F.A.; Beethe, R.L.; Kelly, C.P.J.; 
Lopez, J.A.; Mauderly, J.L.; Stafford, D.L. (1984) Diesel Exhaust 
Exposure System for Animal Studies. Fundamental and Applied Toxicology 
4: 270-277.
    (14) Moore, W.; et al. (1978) Preliminary finding on the Deposition 
and Retention of Automotive Diesel Particulate in Rat Lungs. Proc. of 
Annual Meeting of the Air Pollution Control Assn, 3, paper 78-33.7.
    (15) Raabe, O.G., Bennick, J.E., Light, M.E., Hobbs, C.H., Thomas, 
R.L., Tillery, M.I. (1973) An Improved Apparatus for Acute Inhalation 
Exposure of Rodents to Radioactive Aerosols. Toxicol & Applied 
Pharmaco.; 1973; 26: 264-273.
    (16) Rao, G.N. (1986) Significance of Environmental Factors on the 
Test System. In: Hoover, B.K.; Baldwin, J.K.; Uelner, A.F.; Whitmire, 
C.E.; Davies, C.L.; Bristol, D.W. ed. Managing conduct and data quality 
of toxicology studies. Raleigh, NC: Princeton Scientific Publishing Co., 
Inc.: 173-185.
    (17) Spitzer, D.W. (1984) Industrial Flow Measurement. Research 
Triangle Park, NC: Instrument Society of America.
    (18) 40 CFR part 798, Health effects testing guidelines.
    (19) 29 CFR part 1910, Occupational safety and health standards for 
general industry.
    (20) Federal Register, 42 FR 26748, May 25, 1977.

[59 FR 33093, June 27, 1994, as amended at 61 FR 58746, Nov. 18, 1996; 
61 FR 36512, July 11, 1996]



Sec. 79.62  Subchronic toxicity study with specific health effect
assessments.

    (a) Purpose--(1) General toxicity. This subchronic inhalation study 
is designed to determine a concentration-response relationship for 
potential toxic effects in rats resulting from continuous or repeated 
inhalation exposure to vehicle/engine emissions over a period of 90 
days. A subgroup of perfusion-fixed animals is required, in addition to 
the main study population, for more exacting organ and tissue histology. 
This test will provide screening information on target organ toxicities 
and on concentration levels useful for running chronic studies and 
establishing exposure criteria. Initial information on effective 
concentrations/exposures of the test atmosphere may be determined from 
the literature of previous studies or through concentration range-
finding trials prior to starting this study. This health effects 
screening test is not capable of directly determining those effects 
which have a long latency period for development (e.g., carcinogenicity 
and life-shortening), though it may permit the detremination of a no-
observed-adverse-effect level, or NOAEL.
    (2) Specific health effects assessments (HEAs). These supplemental 
studies are designed to determine the potential for reproductive/
teratologic, carcinogenic, mutagenic, and neurotoxic health effect 
outcomes from vehicle/engine emission exposures. They are done in 
combination with the subchronic toxicity study and paragraph (c) of this 
section or may be done separately as outlined by the appropriate test 
guideline.
    (i) Fertility assessment/teratology. The fertility assessment is an 
in vivo study designed to provide information on potential health 
hazards to the fetus arising from the mother's repeated exposure to 
vehicle/engine emissions before and during her pregnancy. By including a 
mating of test animals, the study provides preliminary data on the 
effects of repeated vehicle/engine emissions exposure on gonadal 
function, conception, and fertility. The fertility assessment/teratology 
guideline is found in Sec. 79.63.
    (ii) Micronucleus (MN) Assay. The MN assay is an in vivo cytogenetic 
test which gives information on potential carcinogenic and/or mutagenic 
effects of exposure to vehicle/engine emissions. The MN assay detects 
damage to the chromosomes or mitotic apparatus of cells in the tissues 
of a test subject exposed repeatedly to vehicle/engine emissions. The 
assay is based on an increase in the frequency of micronucleated 
erythrocytes found in bone marrow from treated animals compared to that 
of control animals.

[[Page 579]]

The guideline for the MN assay is found in Sec. 79.64.
    (iii) Sister Chromatid Exchange (SCE) Assay. The SCE assay is an in 
vivo analysis which gives information on potential mutagenic and/or 
carcinogenic effects of exposure to vehicle/engine emissions. The assay 
detects the ability of a chemical to enhance the exchange of DNA between 
two sister chromatids of a duplicating chromosome. This assay uses 
peripheral blood lymphocytes isolated from an exposed rodent test 
species and grown to confluence in cell culture. The guideline for the 
SCE assay is found in Sec. 79.65.
    (iv) Neurotoxicity (NTX) measures. NTX measures include (A) 
histopathology of specified central and peripheral nervous system 
tissues taken from emission-exposed rodents, and (B) an assay of brain 
tissue levels of glial fibrillary acidic protein (GFAP), a major 
filament protein of astrocytes, from emission-exposed rodents. The 
guidelines for the neurohistopathology and GFAP studies are found in 
Sec. 79.66 and Sec. 79.67, respectively.
    (b) Definitions. For the purposes of this section, the following 
definitions apply:
    No-observed-adverse-effect-level (NOAEL) means the maximum 
concentration used in a test which produces no observed adverse effects. 
A NOAEL is expressed in terms of weight or volume of test substance 
given daily per unit volume of air ([micro]g/L or ppm).
    Subchronic inhalation toxicity means the adverse effects occurring 
as a result of the continuous or repeated daily exposure of experimental 
animals to a chemical by inhalation for part (approximately 10 percent) 
of a life span.
    (c) Principle of the test method. As long as none of the 
requirements of any study are violated by the combination, one or more 
HEAs may be combined with the general toxicity study through concurrent 
exposures of their study populations and/or by sharing the analysis of 
the same animal subjects. Requirements duplicated in combined studies 
need not be repeated. Guidelines for combining HEAs with the general 
toxicity study are as follows.
    (1) Fertility assessment. (i) The number of study animals in the 
test population is increased when the fertility assessment is run 
concurrently with the 90-day toxicity study. A minimum of 40 females per 
test group shall undergo vaginal lavage daily for two weeks before the 
start of the exposure period. The resulting wet smears are examined to 
cull those animals which are acyclic. Twenty-five females shall be 
randomly assigned to a for-breeding group with the balance of females 
assigned to a group for histopathologic examination.
    (ii) All test groups are exposed over a period of 90 days to various 
concentrations of the test atmosphere for a minimum of six hours per 
day. After seven weeks of exposures, analysis of vaginal cell smears 
shall resume on a daily basis for the 25 for-breeding females and shall 
continue for a period of four weeks or until each female in the group is 
confirmed pregnant. Following the ninth week of exposures, each for-
breeding female is housed overnight with a single study male. Matings 
shall continue for as long as two weeks, or until pregnancy is confirmed 
(pregnancy day 0). Pregnant females are only exposed through day 15 of 
their pregnancy while daily exposures continue throughout the course of 
the study for non-pregnant females and study males.
    (iii) On pregnancy day 20, pregnant females are sacrificed and their 
uteri are examined. Pregnancy status and fetal effects are recorded as 
described in Sec. 79.63. At the end of the exposure period, all males 
and non-pregnant females are sacrificed and necropsied. Testes and 
epididymal tissue samples are taken from five perfusion-fixed test 
subjects and histopathological examinations are carried out on the 
remainder of the non-pregnant females and study males.
    (2) Carcinogenicity/mutagenicity(C/M) assessment. When combined with 
the subchronic toxicity study, the main study population is used to 
perform both the in vivo MN and SCE assays. Because of the constant 
turnover of the cells to be analyzed in these assays, a separate study 
population may be used for this assessment. A study population needs 
only to be exposed a minimum of

[[Page 580]]

four weeks. At exposure's end, ten animals per exposure and control 
groups are anaesthetized and heart punctures are performed on all 
members. After separating blood components, individual lymphocyte cell 
cultures are set up for SCE analysis. One femur from each study subject 
is also removed and the marrow extracted. The marrow is smeared onto a 
glass slide, and stained for analysis of micronuclei in erythrocytes.
    (3) Neurotoxicity (NTX) measures. (i) When combined with this 
subchronic toxicity study, test animals designated for whole-body 
perfusion fixation/lung histology and exposed as part of the main animal 
population are used to perform the neurohistology portion of these 
measures. After the last exposure period, a minimum of ten animals from 
each exposure group shall be preserved in situ with fixative. Sections 
of brain, spinal cord, and proximal sciatic or tibial nerve are then 
cut, processed further in formalin, and mounted for viewing under a 
light microscope. Fibers from the sciatic or tibial nerve sample are 
teased apart for further analysis under the microscope.
    (ii) GFAP assay. After the last exposure period, a minimum of ten 
rodents from each exposure group shall be sacrificed, and their brains 
excised and divided into regions. The tissue samples are then applied to 
filter paper, washed with anti-GFAP antibody, and visualized with a 
radio-labelled Protein A. The filters are quantified for degree of 
immunoreactivity between the antibody and GFAP in the tissue samples. A 
non-radioactive ELISA format is also referenced in the GFAP guideline 
cited in paragraph (a)(2)(iv) of this section. Note: Because the GFAP 
assay requires fresh, i.e., non-preserved, brain tissue, the number of 
test animals may need to be increased to provide an adequate number of 
test subjects to complete the histopathology requirements of both the 
GFAP and the general toxicity portion of the 90-day inhalation study.
    (iii) The start of the exposure period for the NTX measures study 
population may be staggered from that of the main study group to more 
evenly distribute the analytical work required in both study 
populations. The exposures would remain the same in all other respects.
    (d) Test procedures--(1) Animal selection--(i) Species and sex. The 
rat is the recommended species. If another rodent species is used, the 
tester shall provide justification for its selection. Both sexes shall 
be used in any assessment unless it is demonstrated that one sex is 
refractory to the effects of exposure.
    (ii) Age and number. Rats shall be at least ten weeks of age at the 
beginning of the study exposure. The number of animals necessary for 
individual health effect outcomes is as follows:
    (A) Thirty rodents per concentration level/group, fifteen of each 
sex, shall be used to satisfy the reporting requirements of the 90-day 
toxicity study. Ten animals per concentration level/group shall be 
designated for whole body perfusion with fixative (by gravity) for lung 
studies, and neurohistology and testes studies, as appropriate.
    (B) Thirty-five rodents, 25 females and ten males, shall be added 
for each test concentration or control group when combining a 90-day 
toxicity study with a fertility assessment.
    (C) The tester shall provide a group of 10 animals (five animals per 
sex per experimental/control groups) in addition to the main test 
population when performing the GFAP neurotoxicity HEA.
    (2) Recovery group. The manufacturer shall include a group of 20 
animals (10 animals per sex) in the test population, exposing them to 
the highest concentration level for the entire length of the study's 
exposure period. This group shall then be observed for reversibility, 
persistence, or delayed occurrence of toxic effects during a post-
exposure period of not less than 28 days.
    (3) Inhalation exposure. (i) All data developed within this study 
shall be in accordance with good laboratory practice provisions under 
Sec. 79.60.
    (ii) The general conduct of this study shall be in accordance with 
the vehicle emissions inhalation exposure guideline in Sec. 79.61.
    (4) Observation of animals. (i) All toxicological (e.g., weight 
loss) and neurological signs (e.g., motor disturbance) shall be recorded 
frequently enough to observe any abnormality, and not less

[[Page 581]]

than weekly for all study animals. Animals shall be weighed weekly.
    (ii) The following is a minimal list of measures that shall be 
noted:
    (A) Body weight;
    (B) Subject's reactivity to general stimuli such as removal from the 
cage or handling;
    (C) Description, incidence, and severity of any convulsions, 
tremors, or abnormal motor movements in the home cage;
    (D) Descriptions and incidence of posture and gait abnormalities 
observed in the home cage;
    (E) Description and incidence of any unusual or abnormal behaviors, 
excessive or repetitive actions (stereotypies), emaciation, dehydration, 
hypotonia or hypertonia, altered fur appearance, red or crusty deposits 
around the eyes, nose, or mouth, and any other observations that may 
facilitate interpretation of the data.
    (iii) Any animal which dies during the test is necropsied as soon as 
possible after discovery.
    (5) Clinical examinations. (i) The following examinations shall be 
performed on the twenty animals designated as the 90-day study 
population, exclusive of pregnant dams and those study animals targeted 
for perfusion by gravity:
    (A) The following hematology determinations shall be carried out at 
least two times during the test period (after 30 days of exposure and 
just prior to terminal sacrifice at the end of the exposure period): 
hematocrit, hemoglobin concentration, erythrocyte count, total and 
differential leukocyte count, and a measure of clotting potential such 
as prothrombin time, thromboplastin time, or platelet count.
    (B) Clinical biochemistry determinations on blood shall be carried 
out at least two times during the test period, after 30 days of exposure 
and just prior to terminal sacrifice at the end of the exposure period, 
on all groups of animals including concurrent controls. Clinical 
biochemical testing shall include assessment of electrolyte balance, 
carbohydrate metabolism, and liver and kidney function. The selection of 
specific tests will be influenced by observations on the mode of action 
of the substance. In the absence of more specific tests, the following 
determinations may be made: calcium, phosphorus, chloride, sodium, 
potassium, fasting glucose (with period of fasting appropriate to the 
species), serum alanine aminotransferase, serum aspartate 
aminotransferase, sorbitol dehydrogenase, gamma glutamyl transpeptidase, 
urea nitrogen, albumen, blood creatinine, methemoglobin, bile acids, 
total bilirubin, and total serum protein measurements. Additional 
clinical biochemistry shall be employed, where necessary, to extend the 
investigation of observed effects, e.g., analyses of lipids, hormones, 
acid/base balance, and cholinesterase activity.
    (ii) The following examinations shall initially be performed on the 
high concentration and control groups only:
    (A) Ophthalmological examination, using an ophthalmoscope or 
equivalent suitable equipment, shall be made prior to exposure to the 
test substance and at the termination of the study. If changes in the 
eyes are detected, all animals shall be examined.
    (B) Urinalysis is not required on a routine basis, but shall be done 
when there is an indication based on expected and/or observed toxicity.
    (iii) Preservation by whole-body perfusion of fixative into the 
anaesthetized animal for lung histology of ten animals from the 90-day 
study population for each experimental and control group.
    (6) Gross pathology. With the exception of the whole body perfusion-
fixed test animals cited in paragraph (d)(1)(ii)(A) of this section, all 
rodents shall be subjected to a full gross necropsy which includes 
examination of the external surface of the body, all orifices and the 
cranial, thoracic, and abdominal cavities and their contents. Gross 
pathology shall be performed on the following organs and tissues:
    (i) The liver, kidneys, lungs, adrenals, brain, and gonads, 
including uterus, ovaries, testes, epididymides, seminal vesicles (with 
coagulating glands), and prostate, constitute the group of target organs 
for histology and shall be weighed as soon as possible after dissection 
to avoid drying. In addition, for other than rodent test species, the 
thyroid with parathyroids,

[[Page 582]]

when present, shall also be weighed as soon as possible after dissection 
to avoid drying.
    (ii) The following organs and tissues, or representative samples 
thereof, shall be preserved in a suitable medium for possible future 
histopathological examination: All gross lesions; lungs--which shall be 
removed intact, weighed, and treated with a suitable fixative to ensure 
that lung structure is maintained (perfusion with the fixative is 
considered to be an effective procedure); nasopharyngeal tissues; 
brain--including sections of medulla/pons, cerebellar cortex, and 
cerebral cortex; pituitary; thyroid/parathyroid; thymus; trachea; heart; 
sternum with bone marrow; salivary glands; liver; spleen; kidneys; 
adrenals; pancreas; reproductive organs: uterus; cervix; ovaries; 
vagina; testes; epididymides; prostate; and, if present, seminal 
vesicles; aorta; (skin); gall bladder (if present); esophagus; stomach; 
duodenum; jejunum; ileum; cecum; colon; rectum; urinary bladder; 
representative lymph node; (mammary gland); (thigh musculature); 
peripheral nerve/tissue; (eyes); (femur--including articular surface); 
(spinal cord at three levels--cervical, midthoracic, and lumbar); and 
(zymbal and exorbital lachrymal glands).
    (7) Histopathology. Histopathology shall be performed on the 
following organs and tissues from all rodents:
    (i) All gross lesions.
    (ii) Respiratory tract and other organs and tissues, listed in 
paragraph (d)(6)(ii) of this section (except organs/tissues in 
parentheses), of all animals in the control and high dose groups.
    (iii) The tissues mentioned in parentheses, listed in paragraph 
(d)(6)(ii) of this section, if indicated by signs of toxicity or target 
organ involvement.
    (iv) Lungs of animals in the low and intermediate dose groups shall 
also be subjected to histopathological examination, primarily for 
evidence of infection since this provides a convenient assessment of the 
state of health of the animals.
    (v) Lungs and trachea of the whole-body perfusion-fixed test animals 
cited in paragraph (d)(1)(ii)(A) of this section are examined for 
inhaled particle distribution.
    (e) Interpretation of results. All observed results, quantitative 
and incidental, shall be evaluated by an appropriate statistical method. 
The specific methods, including consideration of statistical power, 
shall be selected during the design of the study.
    (f) Test report. In addition to the reporting requirements as 
specified under Sec. Sec. 79.60 and 79.61(e), the following individual 
animal data information shall be reported:
    (1) Date of death during the study or whether animals survived to 
termination.
    (2) Date of observation of each abnormal sign and its subsequent 
course.
    (3) Individual body weight data, and group average body weight data 
vs. time.
    (4) Feed consumption data, when collected.
    (5) Hematological tests employed and all results.
    (6) Clinical biochemistry tests employed and all results.
    (7) Necropsy findings.
    (8) Type of stain/fixative and procedures used in preparing tissue 
samples.
    (9) Detailed description of all histopathological findings.
    (10) Statistical treatment of the study results, where appropriate.
    (g) References. For additional background information on this test 
guideline, the following references should be consulted.
    (1) 40 CFR 798.2450, Inhalation toxicity.
    (2) 40 CFR 798.2675, Oral Toxicity with Satellite Reproduction and 
Fertility Study.
    (3) General Statement of Work for the Conduct of Toxicity and 
Carcinogenicity Studies in Laboratory Animals (revised April, 1987/
modifications through January, 1990) appendix G, National Toxicology 
Program--U.S. Dept. of Health and Human Services (Public Health 
Service), P.O. Box 12233, Research Triangle Park, NC 27709.

[59 FR 33093, June 27, 1994, as amended at 63 FR 63793, Nov. 17, 1998]



Sec. 79.63  Fertility assessment/teratology.

    (a) Purpose. Fertility assessment/teratology is an in vivo study 
designed to provide information on potential health hazards to the fetus 
arising

[[Page 583]]

from the mother's repeated inhalation exposure to vehicle/engine 
emissions before and during her pregnancy. By including a mating of test 
animals, the study provides preliminary data on the effects of repeated 
vehicle/engine emissions exposure on gonadal function, conception, and 
fertility. Since this is a one-generation test that ends with 
examination of full-term fetuses, but not of live pups, it is not 
capable of determining effects on reproductive development which would 
only be detected in viable offspring of treated parents.
    (b) Definitions. For the purposes of this section, the following 
definitions apply:
    Developmental toxicity means the ability of an agent to induce in 
utero death, structural or functional abnormalities, or growth 
retardation after contact with the pregnant animal.
    Estrous cycle means the periodic recurrence of the biological phases 
of the female reproductive system which prepare the animal for 
conception and the development of offspring. The phases of the estrous 
cycle for a particular animal can be characterized by the general 
condition of the cells present in the vagina and the presence or absence 
of various cell types.
    Vaginal cytology evaluation means the use of wet vaginal cell smears 
to determine the phase of a test animal's estrous cycle and the 
potential for adverse exposure effects on the regularity of the animal's 
cycle. In the rat, common cell types found in the smears correlate well 
with the various stages of the estrous cycle and to changes occurring in 
the reproductive tract.
    (c) Principle of the test method. (1) For a two week period before 
exposures start, daily vaginal cell smears are examined from a surplus 
of female test animals to identify and cull those females which are 
acyclic. After culling, testers shall randomly assign at each exposure 
concentration (including unexposed) a minimum of twenty-five females for 
breeding and fifteen non-bred females for later histologic evaluation. 
Test animals shall be exposed by inhalation to graduated concentrations 
of the test atmosphere for a minimum of six hours per day over the next 
13 weeks. Males and females in both test and control groups are mated 
after nine weeks of exposure. Exposures for pregnant females continue 
through gestation day 15, while exposures for males and all non-pregnant 
females shall continue for the full exposure period.
    (2) Beginning two weeks before the start of the mating period, daily 
vaginal smears resume for all to-be-bred females to characterize their 
estrous cycles. This will continue for four weeks or until a rat's 
pregnancy is confirmed, i.e., day 0, by the presence of sperm in the 
cell smear. On pregnancy day 20, shortly before the expected date of 
delivery, each pregnant female is sacrificed, her uterus removed, and 
the contents examined for embryonic or fetal deaths, and live fetuses. 
At the end of the exposure period, males and all non-pregnant females 
shall be weighed, and various organs and tissues, as appropriate, shall 
be removed and weighed, fixed with stain, and sectioned for viewing 
under a light microscope.
    (3) This assay may be done separately or in combination with the 
subchronic toxicity study, pursuant to the provisions in Sec. 79.62.
    (d) Limit test. If a test at one dose level of the highest 
concentration that can be achieved while maintaining a particle size 
distribution with a mass median aerodynamic diameter (MMAD) of 4 
micrometers ([micro]m) or less, using the procedures described in 
section 79.60 of this part produces no observable toxic effects and if 
toxicity would not be expected based upon data of structurally related 
compounds, then a full study using three dose levels might not be 
necessary. Expected human exposure though may indicate the need for a 
higher dose level.
    (e) Test procedures--(1) Animal selection--(i) Species and strain. 
The rat is the preferred species. Strains with low fecundity shall not 
be used and the candidate species shall be characterized for its 
sensitivity to developmental toxins. If another rodent species is used, 
the tester shall provide justification for its selection.
    (ii) Animals shall be a minimum of 10 weeks old at the start of the 
exposure period.

[[Page 584]]

    (iii) Number and sex. Each test and control group shall have a 
minimum of 25 males and 40 females. In order to ensure that sufficient 
pups are produced to permit meaningful evaluation of the potential 
developmental toxicity of the test substance, twenty pregnant test 
animals are required for each exposure and control level.
    (2) Observation period. The observation period shall be 13 weeks, at 
a minimum.
    (3) Concentration levels and concentration selection. (i) To select 
the appropriate concentration levels, a pilot or trial study may be 
advisable. Since pregnant animals have an increased minute ventilation 
as compared to non-pregnant animals, it is recommended that the trial 
study be conducted in pregnant animals. Similarly, since presumably the 
minute ventilation will vary with progression of pregnancy, the animals 
should be exposed during the same period of gestation as in the main 
study. It is not always necessary, though, to carry out a trial study in 
pregnant animals. Comparisons between the results of a trial study in 
non-pregnant animals, and the main study in pregnant animals will 
demonstrate whether or not the test substance is more toxic in pregnant 
animals. In the trial study, the concentration producing embryonic or 
fetal lethalities or maternal toxicity should be determined.
    (ii) The highest concentration level shall induce some overt 
maternal toxicity such as reduced body weight or body weight gain, but 
not more than 10 percent maternal deaths.
    (iii) The lowest concentration level shall not produce any grossly 
observable evidence of either maternal or developmental toxicity.
    (4) Inhalation exposure. (i) All data developed within this study 
shall be in accordance with good laboratory practice provisions under 
Sec. 79.60.
    (ii) The general conduct of this study shall be in accordance with 
the vehicle emissions inhalation exposure guideline in Sec. 79.61.
    (iii) Pregnant females shall be exposed to the test atmosphere on 
each and every day between (and including) the first and fifteenth day 
of gestation.
    (f) Test performance--(1) Study conduct. Directions specific to this 
study are:
    (i) The duration of exposure shall be at least six hours daily, 
allowing appropriate additional time for chamber equilibrium.
    (ii) Where an exposure chamber is used, its design shall minimize 
crowding of the test animals. This is best accomplished by individual 
caging.
    (iii) Pregnant animals shall not be subjected to beyond the minimum 
amount of stress. Since whole-body exposure appears to be the least 
stressful mode of exposure, it is the preferred method. In general 
oronasal or head-only exposure, which is sometimes used to avoid 
concurrent exposure by the dermal or oral routes, is not recommended 
because of the associated stress accompanying the restraining of the 
animals. However, there may be specific instances where it may be more 
appropriate than whole-body exposure. The tester shall provide 
justification/reasoning for its selection.
    (iv) Measurements shall be made at least every other day of food 
consumption for all animals in the study. Males and females shall be 
weighed on the first day of exposure and 2-3 times per week thereafter, 
except for pregnant dams.
    (v) The test animal housing, mating, and exposure chambers shall be 
operated on a twenty-four hour lighting schedule, with twelve hours of 
light and twelve hours of darkness. Test animal exposure shall only 
occur during the light portion of the cycle.
    (vi) Signs of toxicity shall be recorded as they are observed 
including the time of onset, degree, and duration.
    (vii) Females showing signs of abortion or premature delivery shall 
be sacrificed and subjected to a thorough macroscopic examination.
    (viii) Animals that die or are euthanized because of morbidity will 
be necropsied promptly.
    (2) Vaginal cytology. (i) For a two week period before the mating 
period starts, each female in the to-be-bred population shall undergo a 
daily saline vaginal lavage. Two wet cell smears from this lavage shall 
be examined daily for each subject to determine a baseline pattern of 
estrus. Testers shall

[[Page 585]]

avoid excessive handling and roughness in obtaining the vaginal cell 
samples, as this may induce a condition of pseudo-pregnancy in the test 
animals.
    (ii) This will continue for four weeks or until day 0 of a rat's 
pregnancy is confirmed by the presence of sperm in the cell smear.
    (3) Mating and fertility assessment. (i) Beginning nine weeks after 
the start of exposure, each exposed and control group female (exclusive 
of the histology group females) shall be paired during non-exposure 
hours with a male from the same exposure concentration group. Matings 
shall continue for a period of two weeks, or until all mated females are 
determined to be pregnant. Mating pairs shall be clearly identified.
    (ii) Each morning, including weekends, cages shall be examined for 
the presence of a sperm plug. When found, this shall mark gestation day 
0 and pregnancy shall be confirmed by the presence of sperm in the day's 
wet vaginal cell smears.
    (iii) Two weeks after mating is begun, or as females are determined 
to be pregnant, bred animals are returned to pre-mating housing. Daily 
exposures continues through gestation day 15 for all pregnant females or 
through the balance of the exposure period for non-pregnant females and 
all males.
    (iv) Those pairs which fail to mate shall be evaluated in the course 
of the study to determine the cause of the apparent infertility. This 
may involve such procedures as additional opportunities to mate with a 
proven fertile partner, histological examination of the reproductive 
organs, and, in males, examination of the spermatogenic cycles. The 
stage of estrus for each non-pregnant female in the breeding group will 
be determined at the end of the exposure period.
    (4) All animals in the histology group shall be subject to 
histopathologic examination at the end of the study's exposure period.
    (g) Treatment of results. (1) All observed results, quantitative and 
incidental, shall be evaluated by an appropriate statistical method. The 
specific methods, including consideration of statistical power, shall be 
selected during the design of the study.
    (2) Data and reporting. In addition to the reporting requirements 
specified under Sec. Sec. 79.60 and 79.61, the final test report must 
include the following information:
    (i) Gross necropsy. (A) All animals shall be subjected to a full 
necropsy which includes examination of the external surface of the body, 
all orifices, and the cranial, thoracic, and abdominal cavities and 
their contents. Special attention shall be directed to the organs of the 
reproductive system.
    (B) The liver, kidneys, adrenals, pituitary, uterus, vagina, 
ovaries, testes, epididymides and seminal vesicles (with coagulating 
glands), and prostate shall be weighed wet, as soon as possible after 
dissection, to avoid drying.
    (i) At the time of sacrifice on gestation day 20 or at death during 
the study, each dam shall be examined macroscopically for any structural 
abnormalities or pathological changes which may have influenced the 
pregnancy.
    (ii) The contents of the uterus shall be examined for embryonic or 
fetal deaths and the number of viable fetuses. Gravid uterine weights 
need not be obtained from dead animals where decomposition has occurred. 
The degree of resorption shall be described in order to help estimate 
the relative time of death.
    (iii) The number of corpora lutea shall be determined in each 
pregnant dam.
    (iv) Each fetus shall be weighed, all weights recorded, and mean 
fetal weights determined.
    (v) Each fetus shall be examined externally and the sex determined.
    (vi) One-half of the rat fetuses in each litter shall be examined 
for skeletal anomalies, and the remaining half shall be examined for 
soft tissue anomalies, using appropriate methods.
    (ii) Histopathology. (A) Histopathology on vagina, uterus, ovaries, 
testes, epididymides, seminal vesicles, and prostate as appropriate for 
all males and histology group females in the control and high 
concentration groups and for all animals that died or were euthanized 
during the study. If abnormalities or equivocal results are seen in any 
of these organs/tissues, the same organ/tissue from test animals in

[[Page 586]]

lower concentration groups shall be examined.

    Note: Testes, seminal vesicles, epididymides, and ovaries, at a 
minimum, shall be examined in perfusion-fixed (pressure or gravity 
method) test subjects, when available.

    (B) All gross lesions in all study animals shall be examined.
    (C) As noted under mating procedures, reproductive organs of animals 
suspected of infertility shall be subject to microscopic examination.
    (D) The following organs and tissues, or representative samples 
thereof, shall be preserved in a suitable medium for future 
histopathological examination: all gross lesions; vagina; uterus; 
ovaries; testes; epididymides; seminal vesicles; prostate; liver; and 
kidneys/adrenals.
    (3) Evaluation of results. (i) The findings of a developmental 
toxicity study shall be evaluated in terms of the observed effects and 
the exposure levels producing effects. It is necessary to consider the 
historical developmental toxicity data on the species/strain tested.
    (ii) There are several criteria for determining a positive result 
for reproductive/teratologic effects; a statistically significant dose-
related decrease in the weight of the testes for treated subjects over 
control subjects, a decrease in neonatal viability, a significant change 
in the presence of soft tissue or skeletal abnormalities, or an 
increased rate of embryonic or fetal resorption or death. Other 
criteria, e.g., lengthening of the estrous cycle or the time spent in 
any one stage of estrus, changes in the proportion of viable male vs 
female fetuses or offspring, the number and type of cells in vaginal 
smears, or pathologic changes found during gross or microscopic 
examination of male or female reproductive organs may be based upon 
detection of a reproducible and statistically significant positive 
response for that evaluation parameter. A positive result indicates 
that, under the test conditions, the test substance does induce 
reproductive organ or fetal toxicity in the test species.
    (iii) A test substance which does not produce either a statistically 
significant dose-related change in the reproductive organs or cycle or a 
statistically significant and reproducible positive response at any one 
of the test points may not induce reproductive organ toxicity in this 
test species, but further investigation , e.g., to establish absorption 
and bioavailability of the test substance, should be considered.
    (h) Test report. In addition to the reporting requirements as 
specified under 40 CFR 79.60 and the vehicle emissions inhalation 
toxicity guideline as published in 40 CFR 79.61, the following specific 
information shall be reported:
    (1) Individual animal data. (i) Time of death during the study or 
whether animals survived to termination.
    (ii) Date of onset and duration of each abnormal sign and its 
subsequent course.
    (iii) Feed and body weight data.
    (iv) Necropsy findings.
    (v) Male test subjects.
    (A) Testicle weight, and body weight: testicle weight ratio.
    (B) Detailed description of all histopathological findings, 
especially for the testes and the epididymides.
    (vi) Female test subjects.
    (A) Uterine weight data.
    (B) Beginning and ending collection dates for vaginal cell smears.
    (C) Estrous cycle length compared within and between groups 
including mean cycle length for groups.
    (D) Percentage of time spent in each stage of cycle.
    (E) Stage of estrus at time of mating/sacrifice and proportion of 
females in estrus between concentration groups.
    (F) Detailed description of all histopathological findings, 
especially for uterine/ovary samples.
    (vii) Pregnancy and litter data. Toxic response data by exposure 
level, including but not limited to, indices of fertility and time-to-
mating, including the number of days until mating and the number of full 
or partial estrous cycles until mating.
    (A) Number of pregnant animals,
    (B) Number and percentage of live fetuses, resorptions.
    (viii) Fetal data. (A) Numbers of each sex.
    (B) Number of fetuses with any soft tissue or skeletal 
abnormalities.
    (2) Type of stain/fixative and procedures used in preparing tissue 
samples.

[[Page 587]]

    (3) Statistical treatment of the study results.
    (i) References. For additional background information on this test 
guideline, the following references should be consulted.
    (1) 40 CFR 798.2675, Oral Toxicity with Satellite Reproduction and 
Fertility Study.
    (2) 40 CFR 798.4350, Inhalation Developmental Toxicity Study.
    (3) Chapin, R.E. and J.J. Heindel (1993) Methods in Toxicology, Vol. 
3, Parts A and B: Reproductive Toxicology, Academic Press, Orlando, FL.
    (4) Gray, L.E., et al. (1989) ``A Dose-Response Analysis of 
Methoxychlor-Induced Alterations of Reproductive Development and 
Function in the Rat'' Fund. App. Tox. 12, 92-108.
    (5) Leblond, C.P. and Y. Clermont (1952) ``Definition of the Stages 
of the Cycle of the Seminiferous Epithelium of the Rat.'' Ann. N. Y. 
Acad. Sci. 55:548-73.
    (6) Morrissey, R.E., et al. (1988) ``Evaluation of Rodent Sperm, 
Vaginal Cytology, and Reproductive Organ Weight Data from National 
Toxicology Program 13-week Studies.'' Fundam. Appl. Toxicol. 11:343-358.
    (7) Russell, L.D., Ettlin, R.A., Sinhattikim, A.P., and Clegg, E.D 
(1990) Histological and Histopathological Evaluation of the Testes, 
Cache River Press, Clearwater, FL.

[59 FR 33093, June 27, 1994, as amended at 61 FR 36513, July 11, 1996]



Sec. 79.64  In vivo micronucleus assay.

    (a) Purpose. The micronucleus assay is an in vivo cytogenetic test 
which uses erythrocytes in the bone marrow of rodents to detect chemical 
damage to the chromosomes or mitotic apparatus of mammalian cells. As 
the erythroblast develops into an erythrocyte (red blood cell), its main 
nucleus is extruded and may leave a micronucleus in the cell body; a few 
micronuclei form under normal conditions in blood elements. This assay 
is based on an increase in the frequency of micronucleated erythrocytes 
found in bone marrow from treated animals compared to that of control 
animals. The visualization of micronuclei is facilitated in these cells 
because they lack a main nucleus.
    (b) Definitions. For the purposes of this section the following 
definitions apply:
    Micronuclei mean small particles consisting of acentric fragments of 
chromosomes or entire chromosomes, which lag behind at anaphase of cell 
division. After telophase, these fragments may not be included in the 
nuclei of daughter cells and form single or multiple micronuclei in the 
cytoplasm.
    Polychromatic erythrocyte (PCE) means an immature red blood cell 
that, because it contains RNA, can be differentiated by appropriate 
staining techniques from a normochromatic erythrocyte (NCE), which lacks 
RNA. In one to two days, a PCE matures into a NCE.
    (c) Test method--(1) Principle of the test method. (i) Groups of 
rodents are exposed by the inhalation route for a minimum of 6 hours/day 
over a period of not less than 28 days to three or more concentrations 
of a test substance in air. Groups of animals are sacrificed at the end 
of the exposure period and femoral bone marrow is extracted. The bone 
marrow is then smeared onto glass slides, stained, and PCEs are scored 
for micronuclei. Researchers may need to run a trial at the highest 
tolerated concentration of the test atmosphere to optimize the sample 
collection time for micronucleated cells.
    (ii) This assay may be done separately or in combination with the 
subchronic toxicity study, pursuant to the provisions in Sec. 79.62.
    (2) Species and strain. (i) The rat is the recommended test animal. 
Other rodent species may be used in this assay, but use of that species 
will be justified by the tester.
    (ii) If a strain of mouse is used in this assay, the tester shall 
sample peripheral blood from an appropriate site on the test animal, 
e.g., the tail vein, as a source of normochromatic erythrocytes. Results 
shall be reported as outlined later in this guideline with 
``normochromatic'' interchanged for ``polychromatic'', where specified.
    (3) Animal number and sex. At least five female and five male 
animals per

[[Page 588]]

experimental/sample and control group shall be used. The use of a single 
sex or a smaller number of animals shall be justified.
    (4) Positive control group. A single concentration of a compound 
known to produce micronuclei in vivo is adequate as a positive control 
if it shows a significant response at any one time point; additional 
concentration levels may be used. To select an appropriate concentration 
level, a pilot or trial study may be advisable. Initially, one 
concentration of the test substance may be used, the maximum tolerated 
dose or that producing some indication of toxicity, e.g., a drop in the 
ratio of polychromatic to normochromatic erythrocytes. Intraperitoneal 
injection of 1,2-dimethyl-benz-anthracene or benzene are examples of 
positive control exposures. A concentration of 50-80 percent of an LD50 
may be a suitable guide.
    (d) Test performance--(1) Inhalation exposure. (i) All data 
developed within this study shall be in accordance with good laboratory 
practice provisions under Sec. 79.60.
    (ii) The general conduct of this study shall be in accordance with 
the vehicle emissions inhalation exposure guideline in Sec. 79.61.
    (2) Preparation of slides and sampling times. Within twenty-four 
hours of the last exposure, test animals will be sacrificed. One femur 
from each test animal will be removed and placed in fetal bovine serum. 
The bone marrow is removed, cells processed, and two bone marrow smears 
are made for each animal on glass microscope slides. The slides are 
stained with acridine- orange (AO) or another appropriate stain (Giemsa 
+ Wright's, etc.) and examined under a microscope.
    (3) Analysis. Slides shall be coded for study before microscopic 
analysis. At least 1,000 first-division erythrocytes per animal shall be 
scored for the incidence of micronuclei. Sexes will be analyzed 
separately.
    (e) Data and report--(1) Treatment of results. In addition to the 
reporting requirements specified under Sec. Sec. 79.60 and 79.61, the 
final test report must include the criteria for scoring micronuclei. 
Individual data shall be presented in a tabular form including both 
positive and negative controls and experimental groups. The number of 
polychromatic erythrocytes scored, the number of micronucleated 
erythrocytes, the percentage of micronucleated cells, and, where 
applicable, the percentage of micronucleated erythrocytes shall be 
listed separately for each experimental and control animal. Absolute 
numbers shall be included if percentages are reported.
    (2) Interpretation of data. (i) There are several criteria for 
determining a positive response, one of which is a statistically 
significant dose-related increase in the number of micronucleated 
polychromatic erythrocytes. Another criterion may be based upon 
detection of a reproducible and statistically significant positive 
response for at least one of the test substance concentrations.
    (ii) A test substance which does not produce either a statistically 
significant dose-related increase in the number of micronucleated 
polychromatic erythrocytes or a statistically significant and 
reproducible positive response at any one of the test points is 
considered nonmutagenic in this system.
    (3) Test evaluation. (i) Positive results in the micronucleus test 
provide information on the ability of a chemical to induce micronuclei 
in erythrocytes of the test species under the conditions of the test. 
This damage may have been the result of chromosomal damage or damage to 
the mitotic apparatus.
    (ii) Negative results indicate that under the test conditions the 
test substance does not produce micronuclei in the bone marrow of the 
test species.
    (f) Test report. In addition to the reporting recommendations as 
specified under Sec. 79.60, the following specific information shall be 
reported:
    (1) Test atmosphere concentration(s) used and rationale for 
concentration selection.
    (2) Rationale for and description of treatment and sampling 
schedules, toxicity data, negative and positive controls.
    (3) Historical control data (negative and positive), if available.
    (4) Details of the protocol used for slide preparation.
    (5) Criteria for identifying micronucleated erythrocytes.

[[Page 589]]

    (6) Micronucleus analysis by animal and by group for each 
concentration (sexes analyzed separately).
    (i) Ratio of polychromatic to normochromatic erythrocytes.
    (ii) Number of polychromatic erythrocytes with micronuclei.
    (iii) Number of polychromatic erythrocytes scored.
    (7) Statistical methodology chosen for test analysis.
    (g) References. For additional background information on this test 
guideline, the following references should be consulted.
    (1) 40 CFR 798.5395, In Vivo, Mammalian Bone Marrow Cytogenetics 
Tests: Micronucleus Assay.
    (2) Cihak, R. ``Evaluation of Benzidine by the Micronucleus Test.'' 
Mutation Research, 67: 383-384 (1979).
    (3) Evans, H.J. ``Cytological Methods for Detecting Chemical 
Mutagens.'' Chemical Mutagens: Principles and Methods for Their 
Detection, Vol. 4. Ed. A. Hollaender (New York and London: Plenum Press, 
1976) pp. 1-29.
    (4) Heddle, J.A., et al. ``The Induction of Micronuclei as a Measure 
of Genotoxicity. A Report of the U.S. Environmental Protection Agency 
Gene-Tox Program.'' Mutation Research, 123:61-118 (1983).
    (5) Preston, J.R. et al. ``Mammalian In Vivo and In Vitro 
Cytogenetics Assays: Report of the Gene-Tox Program.'' Mutation 
Research, 87:143-188 (1981).
    (6) Schmid, W. ``The micronucleus test for cytogenetic analysis'', 
Chemical Mutagens, Principles and Methods for their Detection. Vol. 4 
Hollaender A, (Ed. A ed. (New York and London: Plenum Press, (1976) pp. 
31-53.
    (7) Tice, R.E., and Al Pellom ``User's guide: Micronucleus assay 
data management and analysis system'', NTIS Order no. PB-90-212-598AS.



Sec. 79.65  In vivo sister chromatid exchange assay.

    (a) Purpose. The in vivo sister chromatid exchange (SCE) assay 
detects the ability of a chemical to enhance the exchange of DNA between 
two sister chromatids of a duplicating chromosome. The most commonly 
used assays employ mammalian bone marrow cells or peripheral blood 
lymphocytes, often from rodent species.
    (b) Definitions. For the purposes of this section, the following 
definitions apply:
    C-metaphase means a state of arrested cell growth typically seen 
after treatment with a spindle inhibitor, i.e., colchicine.
    Sister chromatid exchange means a reciprocal interchange of the two 
chromatid arms within a single chromosome. This exchange is visualized 
during the metaphase portion of the cell cycle and presumably requires 
the enzymatic incision, translocation and ligation of at least two DNA 
helices.
    (c) Test method--(1) Principle of the test method. (i) Groups of 
rodents are exposed by the inhalation route for a minimum of 6 hours/day 
over a period of not less than 28 days to three or more concentrations 
of a test substance in air. Groups of animals are sacrificed at the end 
of the exposure period and blood lymphocyte cell cultures are prepared 
from study animals. Cell growth is suspended after a time and cells are 
harvested, fixed and stained before scoring for SCEs. Researchers may 
need to run a trial at the highest tolerated concentration of the test 
atmosphere to optimize the sample collection time for second division 
metaphase cells.
    (ii) This assay may be done separately or in combination with the 
subchronic toxicity study, pursuant to the provisions in Sec. 79.62.
    (2) Description. (i) The method described here employs peripheral 
blood lymphocytes (PBL) of laboratory rodents exposed to the test 
atmosphere.
    (ii) Within twenty-four hours of the last exposure, test animal 
lymphocytes are obtained by heart puncture and duplicate cell cultures 
are started for each animal. Cultures are grown in bromo-deoxyuridine 
(BrdU), and then a spindle inhibitor (e.g., colchicine) is added to 
arrest cell growth. Cells are harvested, fixed, and stained and their 
chromosomes are scored for SCEs.
    (3) Species and strain. The rat is the recommended test animal. 
Other rodent species may be used in this assay, but use of that species 
will be justified by the tester.

[[Page 590]]

    (4) Animal number and sex. At least five female and five male 
animals per experimental and control group shall be used. The use of a 
single sex or different number of animals shall be justified.
    (5) Positive control group. A single concentration of a compound 
known to produce SCEs in vivo is adequate as a positive control if it 
shows a significant response at any one time point; additional 
concentration levels may be used. To select an appropriate concentration 
level, a pilot or trial study may be advisable. Initially, one 
concentration of the test substance may be used, the maximum tolerated 
dose or that producing some indication of toxicity as evidenced by 
animal morbidity (including death) or target cell toxicity. 
Intraperitoneal injection of 1,2-dimethyl-benz-anthracene or benzene are 
examples of positive control exposures. A concentration of 50-80 percent 
of an LD50 would also be a suitable guide.
    (6) Inhalation exposure. (i) All data developed within this study 
shall be in accordance with good laboratory practice provisions under 
Sec. 79.60.
    (ii) The general conduct of this study shall be in accordance with 
the vehicle emissions inhalation exposure guideline in Sec. 79.61.
    (d) Test performance--(1) Treatment. At the conclusion of the 
exposure period, all test animals are anaesthetized and heart punctures 
are performed. Lymphocytes are isolated over a Ficoll gradient and 
replicate cell cultures are started for each animal. After some 21 
hours, the cells are treated with BrdU and returned to incubation. The 
following day, a spindle inhibitor (e.g., colchicine) is added to arrest 
cell growth in c-metaphase. Cells are harvested 4 hours later and 
second-division metaphase cells are washed and fixed in methanol:acetic 
acid, stained, and chromosome preparations are scored for SCEs.
    (2) Staining method. Staining of slides to reveal SCEs can be 
performed according to any of several protocols. However, the 
fluorescence plus Giemsa method is recommended.
    (3) Number of cells scored. (i) A minimum of 25 well-stained, 
second-division metaphase cells shall be scored for each animal for each 
cell type.
    (ii) At least 100 consecutive metaphase cells shall be scored for 
the number of first, second, and third division metaphases for each 
animal for each cell type.
    (iii) At least 1000 consecutive PBL's shall be scored for the number 
of metaphase cells present.
    (iv) The number of cells to be analyzed per animal shall be based 
upon the number of animals used, the negative control frequency, the 
pre-determined sensitivity and the power chosen for the test. Slides 
shall be coded before microscopic analysis.
    (e) Data and report--(1) Treatment of results. In addition to the 
reporting requirements specified under Sec. Sec. 79.60 and 61, data 
shall be presented in tabular form, providing scores for both the number 
of SCE for each metaphase. Differences among animals within each group 
shall be considered before making comparisons between treated and 
control groups.
    (2) Statistical evaluation. Data shall be evaluated by appropriate 
statistical methods.
    (3) Interpretation of results. (i) There are several criteria for 
determining a positive result, one of which is a statistically 
significant dose-related increase in the number of SCE. Another 
criterion may be based upon detection of a reproducible and 
statistically significant positive response for at least one of the test 
concentrations.
    (ii) A test substance which does not produce either a statistically 
significant dose-related increase in the number of SCE or a 
statistically significant and reproducible positive response at any one 
of the test concentrations is considered not to induce rearrangements of 
DNA segments in this system.
    (iii) Both biological and statistical significance shall be 
considered together in the evaluation.
    (4) Test evaluation. (i) A positive result in the in vivo SCE assay 
for either, or both, the lung or lymphocyte cultures indicates that 
under the test conditions the test substance induces reciprocal 
interchanges of DNA in duplicating chromosomes from lung or lymphocyte 
cells of the test species.

[[Page 591]]

    (ii) Negative results indicate that under the test conditions the 
test substance does not induce reciprocal interchanges in lung or 
lymphocyte cells of the test species.
    (5) Test report. In addition to the reporting recommendations as 
specified under Sec. Sec. 79.60 and 79.61, the following specific 
information shall be reported:
    (i) Test concentrations used, rationale for concentration selection, 
negative and positive controls;
    (ii) Toxic response data by concentration;
    (iii) Schedule of administration of test atmosphere, BrdU, and 
spindle inhibitor;
    (iv) Time of harvest after administration of BrdU;
    (v) Identity of spindle inhibitor, its concentration and timing of 
treatment;
    (vi) Details of the protocol used for cell culture and slide 
preparation;
    (vii) Criteria for scoring SCE;
    (viii) Replicative index, i.e., [percent 1st division + (2 x percent 
2nd division) + (3 x percent 3rd division) metaphases]/100; and
    (ix) Mitotic activity, i.e.,  of metaphases/1000 cells.
    (f) References. For additional background information on this test 
guideline, the following references should be consulted.
    (1) 40 CFR 798.5915, In vivo Sister Chromatid Exchange Assay.
    (2) Kato, H. ``Spontaneous Sister Chromatid Exchanges Detected by a 
BudR-Labeling Method.'' Nature, 251:70-72 (1974).
    (4) Kligerman, A. D., et al. ``Sister Chromatid Exchange Analysis in 
Lung and Peripheral Blood Lymphocytes of Mice Exposed to Methyl 
Isocyanate by Inhalation.'' Environmental Mutagenesis 9:29-36 (1987).
    (5) Kligerman, A.D., et al., ``Cytogenetic Studies of Rodents 
Exposed to Styrene by Inhalation'', IARC Monographs no. 127 ``Butadiene 
and Styrene: Assesment of Health Hazards'' (Sorsa, et al., eds), pp 217-
224, 1993.
    (6) Kligerman, A., et al., ``Cytogenetic Studies of Mice Exposed to 
Styrene by Inhalation.'', Mutation Research, 280:35-43, 1992.
    (7) Wolff, S., and P. Perry. ``Differential Giemsa Staining of 
Sister Chromatids and the Study of Sister Chromatid Exchanges Without 
Autoradiography.'' Chromosoma 48: 341-53 (1974).



Sec. 79.66  Neuropathology assessment.

    (a) Purpose. (1) The histopathological and biochemical techniques in 
this guideline are designed to develop data in animals on morphologic 
changes in the nervous system associated with repeated inhalation 
exposures to motor vehicle emissions. These tests are not intended to 
provide a detailed evaluation of neurotoxicity. Neuropathological 
evaluation should be complemented by other neurotoxicity studies, e.g. 
behavioral and neurophysiological studies and/or general toxicity 
testing, to more completely assess the neurotoxic potential of an 
exposure.
    (2) [Reserved]
    (b) Definition. Neurotoxicity (NTX) or a neurotoxic effect is an 
adverse change in the structure or function of the nervous system 
following exposure to a chemical substance.
    (c) Principle of the test method. (1) Laboratory rodents are exposed 
to one of several concentration levels of a test atmosphere for at least 
six hours daily over a period of 90 days. At the end of the exposure 
period, the animals are anaesthetized, perfused in situ with fixative, 
and tissues in the nervous system are examined grossly and prepared for 
microscopic examination. Starting with the highest dosage level, tissues 
are examined under the light microscope for morphologic changes, until a 
no-observed-adverse-effect level is determined. In cases where light 
microscopy has revealed neuropathology, the NOAEL may be confirmed by 
electron microscopy.
    (2) The tests described herein may be combined with any other 
toxicity study, as long as none of the requirements of either are 
violated by the combination. Specifically, this assay may be combined 
with a subchronic toxicity study, pursuant to provisions in Sec. 79.62.
    (d) Limit test. If a test at one dose level of the highest 
concentration that can be achieved while maintaining a particle size 
distribution with a mass median aerodynamic diameter (MMAD) of 4 
micrometers ([micro]m) or less, using the

[[Page 592]]

procedures described in paragraph (a) of this section, produces no 
observable toxic effects and if toxicity would not be expected based 
upon data of structurally related compounds, then a full study using 
three dose levels might not be necessary. Expected human exposure though 
may indicate the need for a higher dose level.
    (e) Test procedures--(1) Animal selection--(i) Species and strain. 
Testing shall be performed in the species being used in other NTX tests. 
A standard strain of laboratory rat is recommended. The choice of 
species shall take into consideration such factors as the comparative 
metabolism of the chemical and species sensitivity to the toxic effects 
of the test substance, as evidenced by the results of other studies, the 
potential for combined studies, and the availability of other toxicity 
data for the species.
    (ii) Age. Animals shall be at least ten weeks of age at the start of 
exposure.
    (iii) Sex. Both sexes shall be used unless it is demonstrated that 
one sex is refractory to the effects of exposure.
    (2) Number of Animals. A minimum of ten animals per group shall be 
used. The tissues from each animal shall be examined separately.
    (3) Control Groups. (i) A concurrent control group, exposed to 
clean, filtered air only, is required.
    (ii) The laboratory performing the testing shall provide positive 
control data, e.g., results from repeated acrylamide exposure, as 
evidence of the ability of their histology procedures to detect 
neurotoxic endpoints. Positive control data shall be collected at the 
time of the test study unless the laboratory can demonstrate the 
adequacy of historical data for the planned study.
    (iii) A satellite group of 10 female and 10 male test subjects shall 
be treated with the highest concentration level for the duration of the 
exposure and observed thereafter for reversibility, persistence, or 
delayed occurrence of toxic effects during a post-treatment period of 
not less than 28 days.
    (4) Inhalation exposure. (i) All data developed within this study 
shall be in accordance with good laboratory practice provisions under 
Sec. 79.60.
    (ii) The general conduct of this study shall be in accordance with 
the vehicle emissions inhalation exposure guideline in Sec. 79.61.
    (5) Study conduct--(i) Observation of animals. All toxicological 
(e.g., weight loss) and neurological signs (e.g., motor disturbance) 
shall be recorded frequently enough to observe any abnormality, and not 
less than weekly.
    (ii) The following is a minimal list of measures that shall be 
noted:
    (A) Body weight;
    (B) Subject's reactivity to general stimuli such as removal from the 
cage or handling;
    (C) Description, incidence, and severity of any convulsions, 
tremors, or abnormal motor movements in the home cage;
    (D) Descriptions and incidence of posture and gait abnormalities 
observed in the home cage; and
    (E) Description and incidence of any unusual or abnormal behaviors, 
excessive or repetitive actions (stereotypies), emaciation, dehydration, 
hypotonia or hypertonia, altered fur appearance, red or crusty deposits 
around the eyes, nose, or mouth, and any other observations that may 
facilitate interpretation of the data.
    (iii) Sacrifice of animals--(A) General. The goal of the techniques 
outlined for sacrifice of animals and preparation of tissues is 
preservation of tissue morphology to simulate the living state of the 
cell.
    (B) Perfusion technique. Animals shall be perfused in situ by a 
generally recognized technique. For fixation suitable for light or 
electronic microscopy, saline solution followed by buffered 2.5 percent 
glutaraldehyde or buffered 4.0 percent paraformaldehyde, is recommended. 
While some minor modifications or variations in procedures are used in 
different laboratories, a detailed and standard procedure for vascular 
perfusion may be found in the text by Zeman and Innes (1963), Hayat 
(1970), and Spencer and Schaumburg (1980) under paragraph (g) of this 
section. A more sophisticated technique is described by Palay and Chan-
Palay (1974) under paragraph (g) of this section. In addition, the lungs 
shall be instilled with fixative via the trachea during the fixation 
process in order to

[[Page 593]]

preserve the lungs and achieve whole-body fixation.
    (C) Removal of brain and cord. After perfusion, the bony structure 
(cranium and vertebral column) shall be exposed. Animals shall then be 
stored in fixative-filled bags at 4 C for 8-12 hours. The cranium and 
vertebral column shall be removed carefully by trained technicians 
without physical damage of the brain and cord. Detailed dissection 
procedures may be found in the text by Palay and Chan-Palay (1974) under 
paragraph (g) of this section. After removal, simple measurement of the 
size (length and width) and weight of the whole brain (cerebrum, 
cerebellum, pons-medulla) shall be made. Any abnormal coloration or 
discoloration of the brain and cord shall also be noted and recorded.
    (D) Sampling. Cross-sections of the following areas shall be 
examined: The forebrain, the center of the cerebrum, the midbrain, the 
cerebellum, and the medulla oblongata; the spinal cord at the cervical 
swelling (C3-C6), and proximal sciatic nerve (mid-
thigh and sciatic notch) or tibial nerve (at knee). Other sites and 
tissue elements (e.g., gastrocnemius muscle) shall be examined if deemed 
necessary. Any observable gross changes shall be recorded.
    (iv) Specimen storage. Tissue samples from both the central and 
peripheral nervous system shall be further immersion fixed and stored in 
appropriate fixative (e.g., 10 percent buffered formalin for light 
microscopy; 2.5 percent buffered gluteraldehyde or 4.0 percent buffered 
paraformaldehyde for electron microscopy) for future examination. The 
volume of fixative versus the volume of tissues in a specimen jar shall 
be no less than 25:1. All stored tissues shall be washed with buffer for 
at least 2 hours prior to further tissue processing.
    (v) Histopathology examination--(A) Fixation. Tissue specimens 
stored in 10 percent buffered formalin may be used for this purpose. All 
tissues must be immersion fixed in fixative for at least 48 hours prior 
to further tissue processing.
    (B) Dehydration. All tissue specimens shall be washed for at least 1 
hour with water or buffer, prior to dehydration. (A longer washing time 
is needed if the specimens have been stored in fixative for a prolonged 
period of time.) Dehydration can be performed with increasing 
concentration of graded ethanols up to absolute alcohol.
    (C) Clearing and embedding. After dehydration, tissue specimens 
shall be cleared with xylene and embedded in paraffin or paraplast. 
Multiple tissue specimens (e.g. brain, cord, ganglia) may be embedded 
together in one single block for sectioning. All tissue blocks shall be 
labelled showing at least the experiment number, animal number, and 
specimens embedded.
    (D) Sectioning. Tissue sections, 5 to 6 microns in thickness, shall 
be prepared from the tissue blocks and mounted on standard glass slides. 
It is recommended that several additional sections be made from each 
block at this time for possible future needs for special stainings. All 
tissue blocks and slides shall be filed and stored in properly labeled 
files or boxes.
    (E) Histopathological techniques. The following general testing 
sequence is proposed for gathering histopathological data:
    (1) General staining. A general staining procedure shall be 
performed on all tissue specimens in the highest treatment group. 
Hematoxylin and eosin (H&E) shall be used for this purpose. The staining 
shall be differentiated properly to achieve bluish nuclei with pinkish 
background.
    (2) Peripheral nerve teasing. Peripheral nerve fiber teasing shall 
be used. Detailed staining methodology is available in standard 
histotechnological manuals such as AFIP (1968), Ralis et al. (1973), and 
Chang (1979) under paragraph (g) of this section. The nerve fiber 
teasing technique is discussed in Spencer and Schaumberg (1980) under 
paragraph (g) of this section. A section of normal tissue shall be 
included in each staining to assure that adequate staining has occurred. 
Any changes shall be noted and representative photographs shall be 
taken. If a lesion(s) is observed, the special techniques shall be 
repeated in the next lower treatment group until no further lesion is 
detectable.
    (F) Examination. All stained microscopic slides shall be examined 
with a

[[Page 594]]

standard research microscope. Examples of cellular alterations (e.g., 
neuronal vacuolation, degeneration, and necrosis) and tissue changes 
(e.g., gliosis, leukocytic infiltration, and cystic formation) shall be 
recorded and photographed.
    (f) Data collection, reporting, and evaluation. In addition to 
information meeting the requirements stated under 40 CFR 79.60 and 
79.61, the following specific information shall be reported:
    (1) Description of test system and test methods. (i) A description 
of the general design of the experiment shall be provided. This shall 
include a short justification explaining any decisions where 
professional judgment is involved such as fixation technique and choice 
of stains; and
    (ii) Positive control data from the laboratory performing the test 
that demonstrate the sensitivity of the procedures being used. 
Historical data may be used if all essential aspects of the experimental 
protocol are the same.
    (2) Results. All observations shall be recorded and arranged by test 
groups. This data may be presented in the following recommended format:
    (i) Description of signs and lesions for each animal. For each 
animal, data must be submitted showing its identification (animal 
number, treatment, dose, duration), neurologic signs, location(s) nature 
of, frequency, and severity of lesion(s). A commonly-used scale such as 
1 + , 2 + , 3 + , and 4 + for degree of severity ranging from very 
slight to extensive may be used. Any diagnoses derived from neurologic 
signs and lesions including naturally occurring diseases or conditions, 
shall also be recorded;
    (ii) Counts and incidence of lesions, by test group. Data shall be 
tabulated to show:
    (A) The number of animals used in each group, the number of animals 
displaying specific neurologic signs, and the number of animals in which 
any lesion was found; and
    (B) The number of animals affected by each different type of lesion, 
the average grade of each type of lesion, and the frequency of each 
different type and/or location of lesion.
    (iii) Evaluation of data. (A) An evaluation of the data based on 
gross necropsy findings and microscopic pathology observations shall be 
made and supplied. The evaluation shall include the relationship, if 
any, between the animal's exposure to the test atmosphere and the 
frequency and severity of any lesions observed; and
    (B) The evaluation of dose-response, if existent, for various groups 
shall be given, and a description of statistical method must be 
presented. The evaluation of neuropathology data shall include, where 
applicable, an assessment in conjunction with any other neurotoxicity 
studies, electrophysiological, behavioral, or neurochemical, which may 
be relevant to this study.
    (g) References. For additional background information on this test 
guideline, the following references should be consulted.
    (1) 40 CFR 798.6400, Neuropathology.
    (2) AFIP Manual of Histologic Staining Methods. (New York: McGraw-
Hill (1968).
    (3) Chang, L.W. A Color Atlas and Manual for Applied Histochemistry. 
(Springfield, IL: Charles C. Thomas, 1979).
    (4) Dunnick, J.K., et.al. Thirteen-week Toxicity Study of N-Hexane 
in B6C3F1 Mice After Inhalation Exposure (1989) Toxicology, 57, 163-172.
    (5) Hayat, M.A. ``Vol. 1. Biological applications,'' Principles and 
techniques of electron microscopy. (New York: Van Nostrand Reinhold, 
1970).
    (6) Palay S.L., Chan-Palay, V. Cerebellar Cortex: Cytology and 
Organization. (New York: Springer-Verlag, 1974).
    (7) Ralis, H.M., Beesley, R.A., Ralis, Z.A. Techniques in 
Neurohistology. (London: Butterworths, 1973).
    (8) Sette, W. ``Pesticide Assessment Guidelines, Subdivision F, 
Neurotoxicity Test Guidelines.'' Report No. 540/09-91-123 U.S. 
Environmental Protection Agency 1991 (NTIS  PB91-154617).
    (9) Spencer, P.S., Schaumburg, H.H. (eds). Experimental and Clinical 
Neurotoxicology. (Baltimore: Williams and Wilkins, 1980).

[[Page 595]]

    (10) Zeman, W., Innes, J.R.M. Craigie's Neuroanatomy of the Rat. 
(New York: Academic, 1963).

[59 FR 33093, June 27, 1994, as amended at 63 FR 63793, Nov. 17, 1999]



Sec. 79.67  Glial fibrillary acidic protein assay.

    (a) Purpose. Chemical-induced injury of the nervous system, i.e., 
the brain, is associated with astrocytic hypertrophy at the site of 
damage (see O'Callaghan, 1988 in paragraph (e)(3) in this section). 
Assays of glial fibrillary acidic protein (GFAP), the major intermediate 
filament protein of astrocytes, can be used to document this response. 
To date, a diverse variety of chemical insults known to be injurious to 
the central nervous system have been shown to increase GFAP. Moreover, 
increases in GFAP can be seen at concentrations below those necessary to 
produce cytopathology as determined by routine Nissl stains (standard 
neuropathology). Thus it appears that assays of GFAP represent a 
sensitive approach for documenting the existence and location of 
chemical-induced injury of the central nervous system. Additional 
functional, histopathological, and biochemical tests are necessary to 
assess completely the neurotoxic potential of any chemical. This 
biochemical test is intended to be used in conjunction with 
neurohistopathological studies.
    (b) Principle of the test method. (1) This guideline describes the 
conduct of a radioimmunoassay for measurement of the amount of GFAP in 
the brain of vehicle emission-exposed and unexposed control animals. It 
is based on modifications (O'Callaghan & Miller 1985 in paragraph 
(e)(5), O'Callaghan 1987 in paragraph (e)(1) of this section) of the 
dot-immunobinding procedure described by Jahn et al. (1984) in paragraph 
(e)(2) of this section. Briefly, brain tissue samples from study animals 
are assayed for total protein, diluted in dot-immunobinding buffer, and 
applied to nitrocellulose sheets. The spotted sheets are then fixed, 
blocked, washed and incubated in anti-GFAP antibody and [I\125\] Protein 
A. Bound protein A is then quantified by gamma spectrometry. In lieu of 
purified protein standards, standard curves are constructed from 
dilution of a single control sample. By comparing the immunoreactivity 
of individual samples (both control and exposed groups) with that of the 
sample used to generate the standard curve, the relative 
immunoreactivity of each sample is obtained. The immunoreactivity of the 
control groups is normalized to 100 percent and all data are expressed 
as a percentage of control. A variation on this radioimmunoassay 
procedure has been proposed (O'Callaghan 1991 in paragraph (e)(4) of 
this section) which uses a ``sandwich'' of GFAP, anti-GFAP, and a 
chromophore in a microtiter plate format enzyme-link immunosorbent assay 
(ELISA). The use of this variation shall be justified.
    (2) This assay may be done separately or in combination with the 
subchronic toxicity study, pursuant to the provisions of Sec. 79.62.
    (c) Test procedure--(1) Animal selection--(i) Species and strain. 
Test shall be performed on the species being used in concurrent testing 
for neurotoxic or other health effect endpoints. This will generally be 
a species of laboratory rat. The use of other rodent or non-rodent 
species shall be justified.
    (ii) Age. Based on other concurrent testing, young adult rats shall 
be used. Study rodents shall not be older than ten weeks at the start of 
exposures.
    (iii) Number of animals. A minimum of ten animals per group shall be 
used. The tissues from each animal shall be examined separately.
    (iv) Sex. Both sexes shall be used unless it is demonstrated that 
one sex is refractory to the effects.
    (2) Materials. The materials necessary to perform this study are 
[I\125\] Protein A (2-10 [micro]Ci/[micro]g), Anti-sera to GFAP, 
nitrocellulose paper (0.1 or 0.2 [micro]m pore size), sample application 
template (optional; e.g., ``Minifold II'', Schleicher & Schuell, Keene, 
NH), plastic sheet incubation trays.
    (3) Study conduct. (i) All data developed within this study shall be 
in accordance with good laboratory practice provisions under Sec. 
79.60.
    (ii) Tissue Preparation. Animals are euthanized 24 hours after the 
last exposure and the brain is excised from the skull. On a cold 
dissecting platform, the following six regions are dissected

[[Page 596]]

freehand: cerebellum; cerebral cortex; hippocampus; striatum; thalamus/
hypothalamus; and the rest of the brain. Each region is then weighed and 
homogenized in 10 volumes of hot (70-90 C) 1 percent (w/v) sodium 
dodecyl sulfate (SDS). Homogenization is best achieved through sonic 
disruption. A motor driven pestle inserted into a tissue grinding vessel 
is a suitable alternative. The homogenized samples can then be stored 
frozen at -70 C for at least 4 years without loss of GFAP content.
    (iii) Total Protein Assay. Aliquots of the tissue samples are 
assayed for total protein using the method of Smith et al. (1985) in 
paragraph (e)(7) of this section. This assay may be purchased in kit 
form (e.g., Pierce Chemical Company, Rockford, IL).
    (iv) Sample Preparation. Dilute tissue samples in sample buffer (120 
mM KCl, 20 mM NaCl, 2 mM MgCl2), 5 mM Hepes, pH 7.4, 0.7 
percent Triton X-100) to a final concentration of 0.25 mg total protein 
per ml (5 [micro]g/20 [micro]l).
    (v) Preparation of Standard Curve. Dilute a single control sample in 
sample buffer to give at least five standards, between 1 and 10 [micro]g 
total protein per 20 [micro]l. The suggested values of total protein per 
20 [micro]l sample buffer are 1.25, 2.50, 3.25, 5.0, 6.25, 7.5, 8.75, 
and 10.0 [micro]g.
    (vi) Preparation of Nitrocellulose Sheets. Nitrocellulose sheets of 
0.1 or 0.2 micron pore size are rinsed by immersion in distilled water 
for 5 minutes and then air dried.
    (vii) Sample Application. Samples can be spotted onto the 
nitrocellulose sheets free-hand or with the aid of a template. For free-
hand application, draw a grid of squares approximately 2 centimeters by 
2 centimeters (cm) on the nitrocellulose sheets using a soft pencil. 
Spot 5-10 [micro]l portions to the center of each square for a total 
sample volume of 20 [micro]l. For template aided sample application a 
washerless microliter capacity sample application manifold is used. 
Position the nitrocellulose sheet in the sample application device as 
recommended by the manufacturer and spot a 20 [micro]l sample in one 
application. Do not wet the nitrocellulose or any support elements prior 
to sample application. Do not apply vacuum during or after sample 
application. After spotting samples (using either method), let the 
sheets air dry. The sheets can be stored at room temperature for several 
days after sample application.
    (viii) Standard Incubation Conditions. These conditions have been 
described by Jahn et al. (1984) in paragraph (e)(2) of this section. All 
steps are carried out at room temperature on a flat shaking platform 
(one complete excursion every 2-3 seconds). For best results, do not use 
rocking or orbital shakers. Perform the following steps in enough 
solution to cover the nitrocellulose sheets to a depth of 1 cm.
    (A) Incubate 20 minutes in fixer (25 percent (v/v) isopropanol, 10 
percent (v/v) acetic acid).
    (B) Discard fixer, wash several times in deionized water to 
eliminate the fixer, and then incubate for 5 minutes in Tris-buffered 
saline (TBS): 200 mM NaCL, 60 mM Tris-HCl to pH 7.4.
    (C) Discard TBS and incubate 1 hour in blocking solution (0.5 
percent gelatin (w/v)) in TBS.
    (D) Discard blocking solution and incubate for 2 hours in antibody 
solution (anti-GFAP antiserum diluted to the desired dilution in 
blocking solution containing 0.1 percent Triton X-100). Serum anti-
bovine GFAP, which cross reacts with GFAP from rodents and humans, can 
be obtained commercially (e.g., Dako Corp.) and used at a dilution of 
1:500.
    (E) Discard antibody solution, and wash in 4 changes of TBS for 5 
minutes each time. Then wash in TBS for 10 minutes.
    (F) Discard TBS and incubate in blocking solution for 30 minutes.
    (G) Discard blocking solution and incubate for 1 hour in Protein A 
solution ([I\125\]-labeled Protein A diluted in blocking solution 
containing 0.1 percent Triton X-100, sufficient to produce 2000 counts 
per minute (cpm) per 10 [micro]l of Protein A solution).
    (H) Remove Protein A solution (it may be reused once). Wash in 0.1 
percent Triton X-100 in TBS (TBSTX) for 5 minutes, 4 times. Then wash in 
TBSTX for 2-3 hours for 4 additional times. An overnight wash in a 
larger volume can be used to replace the last 4 washes.

[[Page 597]]

    (I) Hang sheets to air-dry. Cut out squares or spots and count 
radioactivity in a gamma counter.
    (ix) Expression of data. Compare radioactivity counts for samples 
obtained from control and treated animals with counts obtained from the 
standard curve. By comparing the immunoreactivity (counts) of each 
sample with that of the standard curve, the relative amount of GFAP in 
each sample can be determined and expressed as a percent of control.
    (d) Data Reporting and Evaluation--(1) Test Report. In addition to 
information meeting the requirements stated under 40 CFR 79.60, the 
following specific information shall be reported:
    (i) Body weight and brain region weights at time of sacrifice for 
each subject tested;
    (ii) Indication of whether each subject survived to sacrifice or 
time of death;
    (iii) Data from control animals and blank samples; and
    (iv) Statistical evaluation of results;
    (2) Evaluation of Results. (i) Results shall be evaluated in terms 
of the extent of change in the amount of GFAP as a function of treatment 
and dose. GFAP assays (of any brain region) from a minimum of 6 samples 
typically will result in a standard error of the mean of [5 percent. In 
this case, a chemically-induced increase in GFAP of 115 percent of 
control is likely to be statistically significant.
    (ii) The results of this assay shall be compared to and evaluated 
with any relevant behavioral and histopathological data.
    (e) References. For additional background information on this test 
guideline the following references should be consulted.
    (1) Brock, T.O and O'Callaghan, J.P. 1987. Quantitative changes in 
the synaptic vesicle proteins, synapsin I and p38 and the astrocyte 
specific protein, glial fibrillary acidic protein, are associated with 
chemical-induced injury to the rat central nervous system, J. Neurosci. 
7:931-942.
    (2) Jahn, R., Schiebler, W. Greengard, P. 1984. A quantitative dot-
immunobinding assay for protein using nitrocellulose membrane filters. 
Proc. Natl. Acad. Sci. U.S.A. 81:1684-1687.
    (3) O'Callaghan, J.P. 1988. Neurotypic and gliotypic protein as 
biochemical markers of neurotoxicity. Neurotoxicol. Teratol. 10:445-452.
    (4) O'Callaghan, J.P. 1991. Quantification of glial fibrillary 
acidic protein: comparison of slot-immunobinding assays with a novel 
sandwich ELISA. Neurotoxicol. Teratol. 13:275-281.
    (5) O'Callaghan, J.P. and Miller, D.B. 1985. Cerebellar hypoplasia 
in the Gunn rat is associated with quantitative changes in neurotypic 
and gliotypic proteins. J. Pharmacol. Exp. Ther. 234:522-532.
    (6) Sette, W.F. ``Pesticide Assessment Guidelines, Subdivision `F', 
Hazard Evaluation: Human and Domestic Animals, Addendum 10, 
Neurotoxicity, Series 81, 82, and 83'' US-EPA, Office of Pesticide 
Programs, EPA-540/09-91-123, March 1991.
    (7) Smith, P.K., Krohn, R.I., Hermanson, G.T., Mallia, A.K., 
Gartner, F.H., Provenzano, M.D., Fujimoto, E.K., Goeke, N.M., Olson, 
B.J., Klenk, D.C. 1985. Measurement of protein using bicinchoninic acid. 
Annal. Biochem. 150:76-85.



Sec. 79.68  Salmonella typhimurium reverse mutation assay.

    (a) Purpose. The Salmonella typhimurium histidine (his) reversion 
system is a microbial assay which measures his- [rarr] his\ + 
\ reversion induced by chemicals which cause base changes or frameshift 
mutations in the genome of the microorganism Salmonella typhimurium.
    (b) Definitions. For the purposes of this section, the following 
definitions apply:

    Base pair mutagen means an agent which causes a base change in DNA. 
In a reversion assay, this change may occur at the site of the original 
mutation or at a second site in the chromosome.
    Frameshift mutagen is an agent which causes the addition or deletion 
of single or multiple base pairs in the DNA molecule.
    Salmonella typhimurium reverse mutation assay detects mutation in a 
gene of a histidine-requiring strain to produce a histidine independent 
strain of this organism.


[[Page 598]]


    (c) Reference substances. These may include, but need not be limited 
to, sodium azide, 2-nitrofluorene, 9-aminoacridine, 2-aminoanthracene, 
congo red, benzopurpurin 4B, trypan blue or direct blue 1.
    (d) Test method--(1) Principle. Motor vehicle combustion emissions 
from fuel or additive/base fuel mixtures are, first, filtered to trap 
particulate matter and, then, passed through a sorbent resin to trap 
semi-volatile gases. Bacteria are separately exposed to the extract from 
both the filtered particulates and the resin-trapped organics. Assays 
are conducted using both test mixtures with and without a metabolic 
activation system and exposed cells are plated onto minimal medium. 
After a suitable period of incubation, revertant colonies are counted in 
test cultures and compared to the number of spontaneous revertants in 
unexposed control cultures.
    (2) Description. Several methods for performing the test have been 
described. The procedures described here are for the direct plate 
incorporation method and the azo-reduction method. Among those used are:
    (i) Direct plate incorporation method;
    (ii) Preincubation method;
    (iii) Azo-reduction method;
    (iv) Microsuspension method; and
    (v) Spiral assay.
    (3) Strain selection--(i) Designation. Five tester strains shall be 
used in the assay. At the present time, TA1535, TA1537, TA98, and TA100 
are designated as tester strains. The fifth strain will be chosen from 
the pool of Salmonella strains commonly used to determine the degree to 
which nitrated organic compounds, i.e., nitroarenes, contribute to the 
overall mutagenic activity of a test substance. TA98/1,8-DNP6 
or other suitable Rosenkranz nitro-reductase resistant strains will be 
considered acceptable. The choice of the particular strain is left to 
the discretion of the researcher. However, the researcher shall justify 
the use of the selected bacterial tester strains.
    (ii) Preparation and storage of bacterial tester strains. Recognized 
methods of stock culture preparation and storage shall be used. The 
requirement of histidine for growth shall be demonstrated for each 
strain. Other phenotypic characteristics shall be checked using such 
methods as crystal violet sensitivity and resistance to ampicillin. 
Spontaneous reversion frequency shall be in the range expected as 
reported in the literature and as established in the laboratory by 
historical control values.
    (iii) Bacterial growth. Fresh cultures of bacteria shall be grown up 
to the late exponential or early stationary phase of growth 
(approximately 108-109 cells per ml).
    (4) Exogenous metabolic activation. Bacteria shall be exposed to the 
test substance both in the presence and absence of an appropriate 
exogenous metabolic activation system. For the direct plate 
incorporation method, the most commonly used system is a cofactor-
supplemented postmitochondrial fraction prepared from the livers of 
rodents treated with enzyme-inducing agents, such as Aroclor 1254. For 
the azo-reduction method, a cofactor- supplemented postmitochondrial 
fraction (S-9) prepared from the livers of untreated hamsters is 
preferred. For this method, the cofactor supplement shall contain flavin 
mononucleotide, exogenous glucose 6-phosphate dehydrogenase, NADH and 
excess of glucose-6-phosphate.
    (5) Control groups--(i) Concurrent controls. Concurrent positive and 
negative (untreated) controls shall be included in each experiment. 
Positive controls shall ensure both strain responsiveness and efficacy 
of the metabolic activation system.
    (ii) Strain specific positive controls shall be included in the 
assay. Examples of strain specific positive controls are as follows:
    (A) Strain TA1535, TA100: sodium azide;
    (B) TA98: 2-nitrofluorene (without activation), 2-anthramine (with 
activation);
    (C) TA1537: 9-aminoacridine; and
    (D) TA98/1,8-DNP6: benzo(a)pyrene (with activation).
    The papers by Claxton et al., 1991 and 1992 in paragraph (g) in this 
section will provide helpful information for the selection of positive 
controls.
    (iii) Positive controls to ensure the efficacy of the activation 
system. The positive control reference substances for

[[Page 599]]

tests including a metabolic activation system shall be selected on the 
basis of the type of activation system used in the test. 2-
Aminoanthracene is an example of a positive control compound in plate-
incorporation tests using postmitochondrial fractions from the livers of 
rodents treated with enzyme-inducing agents such as Aroclor-1254. Congo 
red is an example of a positive control compound in the azo-reduction 
method. Other positive control reference substances may be used.
    (iv) Class-specific positive controls. The azo-reduction method 
shall include positive controls from the same class of compounds as the 
test agent wherever possible.
    (6) Sampling the test atmosphere. (i) Extracts of test emissions are 
collected on Teflon -coated glass fiber filters using an exhaust 
dilution setup. The particulates are extracted with dichloromethane 
(DCM) using Soxhlet extraction techniques. Extracts in DCM can be stored 
at dry ice temperatures until use.
    (ii) Gaseous hydrocarbons passing through the filter are trapped by 
a porous, polymer resin, like XAD-2/styrene-divinylbenzene, or an 
equivalent product. Methylene chloride is used to extract the resin and 
the sample is evaporated to dryness before storage or use.
    (iii) Samples taken from this material are then used to expose the 
cells in this assay. Final concentration of extracts in solvent/vehicle, 
or after solvent exchange, shall not interfere with cell viability or 
growth rate. The paper by Stump (1982) in paragraph (g) of this section 
is useful for preparing extracts of particulate and semi-volatile 
organic compounds from diesel and gasoline exhaust stream.
    (iv) Exposure concentrations. (A) The test should initially be 
performed over a broad range of concentrations. Among the criteria to be 
taken into consideration for determining the upper limits of test 
substance concentration are cytotoxicity and solubility. Cytotoxicity of 
the test chemical may be altered in the presence of metabolic activation 
systems. Toxicity may be evidenced by a reduction in the number of 
spontaneous revertants, a clearing of the background lawn or by the 
degree of survival of treated cultures. Relatively insoluble samples 
shall be tested up to the limits of solubility. The upper test chemical 
concentration shall be determined on a case by case basis.
    (B) Generally, a maximum of 5 mg/plate for pure substances is 
considered acceptable. At least 5 different concentrations of test 
substance shall be used with adequate intervals between test points.
    (C) When appropriate, a single positive response shall be confirmed 
by testing over a narrow range of concentrations.
    (e) Test performance. All data developed within this study shall be 
in accordance with good laboratory practice provisions under Sec. 
79.60.
    (1) Direct plate incorporation method. When testing with metabolic 
activation, test solution, bacteria, and 0.5 ml of activation mixture 
containing an adequate amount of postmitochondrial fraction shall be 
added to the liquid overlay agar and mixed. This mixture is poured over 
the surface of a selective agar plate. Overlay agar shall be allowed to 
solidify before incubation. At the end of the incubation period, 
revertant colonies per plate shall be counted. When testing without 
metabolic activation, the test sample and 0.1 ml of a fresh bacterial 
culture shall be added to 2.0 ml of overlay agar.
    (2) Azo-reduction method. When testing with metabolic activation, 
0.5 ml of activation mixture containing 150 [micro]l of 
postmitochondrial fraction and 0.1 ml of bacterial culture shall be 
added to a test tube kept on ice. 0.1 ml of test solution shall be 
added, and the tubes shall be incubated with shaking at 30 C for 30 
minutes. At the end of the incubation period, 2.0 ml of agar shall be 
added to each tube, the contents mixed and poured over the surface of a 
selective agar plate. Overlay agar shall be allowed to solidify before 
incubation. At the end of the incubation period, revertant colonies per 
plate shall be counted. For tests without metabolic activation, 0.5 ml 
of buffer shall be used in place of the 0.5 ml of activation mixture. 
All other procedures shall be the same as those used for the test with 
metabolic activation.

[[Page 600]]

    (3) Other methods/modifications may also be appropriate.
    (4) Media. An appropriate selective medium with an adequate overlay 
agar shall be used.
    (5) Incubation conditions. All plates within a given experiment 
shall be incubated for the same time period. This incubation period 
shall be for 48-72 hours at 37 C.
    (6) Number of cultures. All plating shall be done at least in 
triplicate.
    (f) Data and report--(1) Treatment of results. Data shall be 
presented as number of revertant colonies per plate, revertants per 
kilogram (or liter) of fuel, and as revertants per kilometer (or mile, 
or brake-horsepower/hour, as appropriate) for each replicate and dose. 
These same measures shall be recorded on both the negative and positive 
control plates. The mean number of revertant colonies per plate, 
revertants per kilogram (or liter) of fuel, and revertants per kilometer 
(or mile, or brake-horsepower/hour), as well as individual plate counts 
and standard deviations shall be presented for the test substance, 
positive control, and negative control plates.
    (2) Statistical evaluation. Data shall be evaluated by appropriate 
statistical methods. Those methods shall include, at a minimum, means 
and standard deviations of the reversion data.
    (3) Interpretation of results. (i) There are several criteria for 
determining a positive result, one of which is a statistically 
significant dose-related increase in the number of revertants. Another 
criterion may be based upon detection of a reproducible and 
statistically significant positive response for at least one of the test 
substance concentrations.
    (ii) A test substance which does not produce either a statistically 
significant dose-related increase in the number of revertants or a 
statistically significant and reproducible positive response at any one 
of the test points is considered nonmutagenic in this system.
    (iii) Both biological and statistical significance shall be 
considered together in the evaluation.
    (4) Test evaluation. (i) Positive results from the Salmonella 
typhimurium reverse mutation assay indicate that, under the test 
conditions, the test substance induces point mutations by base changes 
or frameshifts in the genome of this organism.
    (ii) Negative results indicate that under the test conditions the 
test substance is not mutagenic in Salmonella typhimurium.
    (5) Test report. In addition to the reporting recommendations as 
specified under 40 CFR 79.60, the following specific information shall 
be reported:
    (i) Sampling method(s) used and manner in which cells are exposed to 
sample solution;
    (ii) Bacterial strains used;
    (iii) Metabolic activation system used (source, amount and 
cofactor); details of preparation of postmitochondrial fraction;
    (iv) Concentration levels and rationale for selection of 
concentration range;
    (v) Description of positive and negative controls, and 
concentrations used, if appropriate;
    (vi) Individual plate counts, mean number of revertant colonies per 
plate, number of revertants per kilometer (or mile, or brake-horsepower/
hour), and standard deviation; and
    (vii) Dose-response relationship, if applicable.
    (g) References. For additional background information on this test 
guideline, the following references should be consulted.
    (1) 40 CFR 798.5265, The Salmonella typhimurium reverse mutation 
asay.
    (2) Ames, B.N., McCann, J., Yamasaki, E. ``Methods for detecting 
carcinogens and mutagens with the Salmonella/mammalian microsome 
mutagenicity test,'' Mutation Research 31:347-364 (1975).
    (3) Huisingh, J.L., et al.,``Mutagenic and Carcinogenic Potency of 
Extracts of Diesel and Related Environmental Emissions: Study Design, 
Sample Generation, Collection, and Preparation''. In: Health Effects of 
Diesel Engine Emissions, Vol. II, W.E. Pepelko, R., M., Danner and N. A. 
Clarke (Eds.), US EPA, Cincinnati, EPA-600/9-80-057b, pp. 788-800 
(1980).
    (4) [Reserved]
    (5) Claxton, L.D., Allen, J., Auletta, A., Mortelmans, K., Nestmann, 
E., Zeiger, E. ``Guide for the Salmonella

[[Page 601]]

typhimurium/mammalian microsome tests for bacterial mutagenicity'' 
Mutation Research 189(2):83-91 (1987).
    (6) Claxton, L., Houk, V.S., Allison, J.C., Creason, J., 
``Evaluating the relationship of metabolic activation system 
concentrations and chemical dose concentrations for the Salmonella 
Spiral and Plate Assays'' Mutation Research 253:127-136 (1991).
    (7) Claxton, L., Houk, V.S., Monteith, L.G., Myers, L.E., Hughes, 
T.J., ``Assessing the use of known mutagens to calibrate the Salmonella 
typhimurium mutagenicity assay: I. Without exogenous activation.'' 
Mutation Research 253:137-147 (1991).
    (8) Claxton, L., Houk, V.S., Warner, J.R., Myers, L.E., Hughes, 
T.J., ``Assessing the use of known mutagens to calibrate the Salmonella 
typhimurium mutagenicity assay: II. With exogenous activation.'' 
Mutation Research 253:149-159 (1991).
    (9) Claxton, L., Creason, J., Lares, B., Augurell, E., Bagley, S., 
Bryant, D.W., Courtois, Y.A., Douglas, G., Clare, C.B., Goto, S., 
Quillardet, P., Jagannath, D.R., Mohn, G., Neilsen, P.A., Ohnishi, Y., 
Ong, T., Pederson, T.C., Shimizu, H., Nylund, L., Tokiwa, H., Vink, 
I.G.R., Wang, Y., Warshawsky, D., ``Results of the IPCS Collaborative 
Study on Complex Mixtures'' Mutation Research 276:23-32 (1992).
    (10) Claxton, L., Douglas, G., Krewski, D., Lewtas, J., Matsushita, 
H., Rosenkranz, H., ``Overview, conclusions, and recommendations of the 
IPCS Collaborative Study on Complex Mixtures'' Mutation Research 276:61-
80 (1992).
    (11) Houk, V.S., Schalkowsky, S., and Claxton, L.D., ``Development 
and Validation of the Spiral Salmonella Assay: An Automated Approach to 
Bacterial Mutagenicity Testing'' Mutation Research 223:49-64 (1989).
    (12) Jones, E., Richold, M., May, J.H., and Saje, A. ``The 
Assessment of the Mutagenic Potential of Vehicle Engine Exhaust in the 
Ames Salmonella Assay Using a Direct Exposure Method'' Mutation Research 
97:35-40 (1985).
    (13) Maron, D., and Ames, B. N., Revised methods for the Salmonella 
mutagenicity test, Mutation Research, 113:173-212 (1983).
    (14) Prival, M.J., and Mitchell, V.D. ``Analysis of a method for 
testing azo dyes for mutagenic activity in Salmonella typhimurium in the 
presence of flavin mononucleotide and hamster liver S-9,'' Mutation 
Research 97:103-116 (1982).
    (15) Rosenkranz, H.S., et.al. ``Nitropyrenes: Isolation, 
identification, and reduction of mutagenic impurities in carbon black 
and toners'' Science 209:1039-43 (1980).
    (16) Stump, F., Snow, R., et.al., ``Trapping gaseous hydrocarbons 
for mutagenic testing'' SAE Technical Paper Series, No. 820776 (1982).
    (17) Vogel, H.J., Bonner, D.M. ``Acetylornithinase of E. coli: 
partial purification and some properties,'' Journal of Biological 
Chemistry. 218:97-106 (1956).

[59 FR 33093, June 27, 1994, as amended at 61 FR 36513, July 11, 1996]

[[Page 603]]



                              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 605]]



                    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 606]]

    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 607]]

      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 608]]

     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 609]]

        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 610]]

         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 611]]

        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 612]]

       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 613]]

         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 614]]

       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 615]]

                           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 616]]

        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 617]]

      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 618]]

        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 619]]

                       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 620]]

       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 621]]

        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 622]]

         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 623]]

                       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 625]]





           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 626]]

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 627]]

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 628]]

  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 629]]

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 630]]

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 631]]

  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 632]]

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 633]]

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 634]]

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 635]]



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
72 Authority citation revised......................................48378
72.2 Amended.......................................................17305
    72.2 Amended...................................................48378
72.13 (a) introductory text revised; (a)(5) and (b) added..........17306
75.2 (d) removed...................................................17306
75.4 (b)(2), (c)(2), (d) introductory text, (1) and (e) revised....17306
    75.4 (e)(1) introductory text and (2) revised..................50132
75.6 (a) introductory text, (48) and (f)(3) revised; (a)(38), (43) 
        and (44) removed; (g) added................................17307
75.10 (d)(1) and (3) amended.......................................17308
75.11 (f) correctly added; CFR correction..........................18415
75.15 Removed......................................................17308
75.20 (a)(5)(i), (c)(1) introductory text, (ii) and (iii) revised; 
        (b) introductory text amended; (c)(1)(vi), (9) and 
        (d)(2)(ix) removed.........................................17308
75.21 (a)(3) revised; (f) and (g) added............................17308
75.22 (a) introductory text, (5)(iv) and (b) introductory text 
        revised; (a)(5)(v) added; (a)(7) and (b)(5) through (8) 
        removed....................................................17310
75.24 (d) revised..................................................17311
75.31 (a) and (b) revised..........................................17311
75.32 (a) introductory text amended................................17311
75.33 Heading, Table 1 and footnotes revised.......................17311
75.34 (a)(2)(ii) revised; (d) amended..............................17312
75.38 Removed......................................................17312
75.39 Removed......................................................17312
75.47 (b)(2) revised; (b)(3) abd (c) removed.......................17312
75.53 (e)(1)(i)(E), (iv) introductory text, (x), (g)(1)(i)(A), 
        (C), (E), (F), (iii) introductory text, (v)(F), (G), 
        (vi)(H), (I), (h)(2)(i) and (5) revised; (g)(1)(vi)(J) 
        added......................................................17312
75.57 (a)(5), (6) and Table 4a revised; (a)(7) added; (i) and (j) 
        removed....................................................17313
75.58 (b)(3) and (d)(4)(ii) revised; (d)(4)(iii) added.............17314
75.59 (a)(1) introductory text, (iii), (3) introductory text, (5) 
        introductory text, (ii) introductory text, (L), 
        (5)(iii)(F), (G), (6) introductory text, (9) introductory 
        text, (vi), (12)(iv)(E), (F), (c) introductory text, 
        (d)(3)(x) and (xi) revised; (a)(5)(iii)(H), (9)(x), (xi), 
        (12)(iv)(G), (15), (b)(6), (d)(3)(xii), (xiii) and (4) 
        added; (a)(7)(vii), (viii) heading, (x), (14) and (e) 
        removed; (f) redesignated as new (e).......................17315

[[Page 636]]

75.60 (b)(8) removed...............................................17316
75.61 (a)(1) introductory text and (8) revised; (a)(5) 
        introductory text amended..................................17316
75.62 (d) added....................................................17316
75.63 (d) added....................................................17317
75.64 (a)(5), (7)(xi), (xii)(D) and (g) revised; (a)(7)(xiii) 
        added; (a)(127) redesignated as (a)(12)....................17317
75.80--75.84 (Subpart I) Removed...................................17317
75 Appendix A amended..............................................17317
    Appendix B amended.............................................17321
    Appendix D amended.............................................17324
    Appendices E and F amended; Appendix K removed.................17325
    Appendix D heading corrected...................................20536
    75 Appendix D heading revised..................................50133
78.1 (b)(13) through (16) added....................................48378
78.2 Revised.......................................................48379
78.3 (a)(1)(iii), (3)(ii), (4)(ii), (5)(ii), (6)(ii), (7)(ii), 
        (8)(ii), (9)(ii) and (b)(3)(i) amended; (a)(10) and 
        (d)(11) added..............................................48379
78.4 (a) amended; (a) redesignated as (a)(1)(iii); (a)(1) 
        introductory text, (i) and (ii) added; (a)(2) revised......48379
78.5 (a) amended...................................................48379
78.12 (a) amended..................................................48379

                                  2012

40 CFR
                                                                   77 FR
                                                                    Page
Chapter I
75.6 (a)(50) added..................................................2460
75 Appendices A, D and F amended....................................2460

                                  2013

                       (No regulations published)

                                  2014

40 CFR
                                                                   79 FR
                                                                    Page
Chapter I
79.5 (a) and (b) introductory text revised.........................23630

                                  2015

40 CFR
                                                                   80 FR
                                                                    Page
Chapter I
73.35 (b)(2)(ii) and (iii) correctly removed; CFR correction.......22116

                                  2016

   (Regulations published from January 1, 2016, through July 1, 2016)

40 CFR
                                                                   81 FR
                                                                    Page
Chapter I
75.16 (b)(1)(ii)(A) and (B) removed; CFR correction................10508
75 Appendix A amended; CFR correction..............................10508


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